A copy of this preliminary base PREP prospectus has been filed with the securities regulatory authorities in each of the provinces of Canada but has not yet become final for the purpose of the sale of securities. Information contained in this preliminary base PREP prospectus may not be complete and may have to be amended. The securities may not be sold until a receipt for the base PREP prospectus is obtained from the securities regulatory authorities.

This prospectus has been filed under procedures in each of the provinces of Canada that permit certain information about these securities to be determined after the prospectus has become final and that permit the omission of that information from this prospectus. The procedures require the delivery to purchasers of a supplemented PREP prospectus containing the omitted information within a specified period of time after agreeing to purchase any of these securities. All of the information contained in the supplemented PREP prospectus that is not contained in the base PREP prospectus will be incorporated by reference into the base PREP prospectus as of the date of the supplemented PREP prospectus.

No securities regulatory authority has expressed an opinion about these securities and it is an offence to claim otherwise. These securities have not been and will not be registered under the United States Securities Act of 1933, as amended (the "U.S. Securities Act"), or any state securities laws. Accordingly, these securities may not be offered or sold within the United States unless registered under the U.S. Securities Act and applicable state securities laws or except pursuant to exemptions from the registration requirements of the U.S. Securities Act and applicable state securities laws and in accordance with the Underwriting Agreement (as defined herein). This prospectus constitutes a public offering of these securities only in those jurisdictions where they may be lawfully offered for sale and only by persons permitted to sell these securities. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any of the securities offered hereby within the United States. See "Plan of Distribution".

PRELIMINARY BASE PREP PROSPECTUS

Initial Public Offering and Secondary Offering September 24, 2020

Topaz Energy Corp.

$252,500,000 • Common Shares

Topaz Energy Corp. ("Topaz" or the "Company") is a unique royalty and energy infrastructure company focused on generating free cash flow growth and paying reliable and sustainable dividends to its shareholders, through its strategic relationship with Canada's largest natural gas producer, Tourmaline Oil Corp. ("Tourmaline" or the "Selling Shareholder"), an investment grade senior Canadian E&P company, and leveraging industry relationships to execute complementary acquisitions from other high-quality energy companies, while maintaining its commitment to environmental, social and governance best practices.

The Topaz royalty and energy infrastructure revenue streams are generated primarily from assets operated by natural gas producers with some of the lowest GHG emissions intensity in the Canadian senior upstream sector, including Tourmaline, which has received awards for environmental sustainability and conservation efforts. Certain of these producers have set long-term emissions reduction targets and continue to invest in green technology to improve environmental sustainability.

The Company's high-quality assets and associated revenues are comprised of:

(i) gross overriding royalty interests (the "Royalty Assets") on approximately 2.3 million gross acres of developed and undeveloped lands from which the Company receives royalty production revenue based on the associated natural gas, crude oil and condensate production and market indexed pricing (the "Royalty Production Revenue"); and
(ii) non-operated ownership interests in four natural gas processing plants with cumulative natural gas processing capacity of approximately 175 MMcf/d from which the Company is entitled to receive processing revenue from natural gas processing services provided to customers on a fee-for-service basis, the majority of which is subject to long-term fixed fee take-or-pay agreements (the "Processing Revenue"); and a contracted interest in a portion of third-party revenue generated from facilities owned by Tourmaline through fee-for-service agreements with third parties to which Tourmaline is a party for the processing and handling of petroleum and related operations (the "Other Income") (collectively, the "Infrastructure Assets").

The Company's business model is designed to provide investors with exposure to the best attributes from each of the royalty and energy infrastructure segments: (i) Royalty Production Revenue (net of a 1% marketing fee on the developed lands) with no associated operating or capital costs and underpinned by Tourmaline's self-funded development; (ii) Processing Revenue with minimal associated operating and capital costs and underpinned by longterm take-or-pay contracts with high-quality counterparties; (iii) Other Income with no associated operating or capital costs; (iv) modest corporate overhead costs; (v) long-term horizon before income tax would be payable; and (vi) transparent outlook to the Company's opportunistic growth prospects. Topaz's unique, low risk, income-oriented business model positions the Company to be a partner of choice for high quality operators seeking to access capital to achieve their business plans in the current environment. See "The Company's Business".

See "Investment Highlights".

The Company and the Selling Shareholder are offering for sale an aggregate of • common shares (the "Common Shares") in the capital of the Company consisting of a treasury offering (the "Treasury Offering") by the Company of • Common Shares for gross proceeds of $217.5 million and a secondary offering (the "Secondary Offering", and together with the Treasury Offering, the "Offering") of • Common Shares held by the Selling Shareholder for gross proceeds of $35 million at a price of $• per Common Share (the "Offering Price"). Topaz will not receive any proceeds from the Secondary Offering. See "Principal Shareholders and Selling Shareholder". It is anticipated that the Offering Price will be between $13.00 and $15.00 per Common Share. Based on the estimated price range, between 16,834,000 and 19,424,000 Common Shares will be offered pursuant to the Offering. If the Over-Allotment Option (as defined below) is exercised in full, based on the estimated price range, between an additional 2,175,000 and 2,509,650 Common Shares will be sold by the Company. See "Plan of Distribution" and "Principal Shareholders and Selling Shareholder".

Upon Closing, the Selling Shareholder will own •% of the outstanding Common Shares (•% if the Over-Allotment Option is exercised in full). The Selling Shareholder has certain contractual rights relating to, among other things, the nomination of directors, consenting to certain transactions by the Company and participation in future securities offerings by the Company. See "Agreements with Tourmaline and Other Counterparties", "Plan of Distribution", "Principal Shareholders and Selling Shareholder" and "Risk Factors – Risks Relating to the Company's Relationship with Tourmaline".

The Offering is being underwritten by Peters & Co. Limited ("Peters & Co.") and Scotia Capital Inc. ("Scotia Capital") (together, the "Lead Underwriters"), BMO Nesbitt Burns Inc., National Bank Financial Inc., RBC Dominion Securities Inc., CIBC World Markets Inc., TD Securities Inc., Desjardins Securities Inc., Stifel Nicolaus Canada Inc., ATB Capital Markets Inc., Canaccord Genuity Corp., Industrial Alliance Securities Inc., Raymond James Ltd., and Tudor, Pickering, Holt & Co. Securities – Canada, ULC (collectively with the Lead Underwriters, the "Underwriters"). See "Plan of Distribution".

	Price: $•	per Common Share
	Price to thePublic(1)	Underwriters'Commissions	Net Proceeds tothe Company(2)	Net Proceeds to theSelling Shareholder(3)
Per Common Share	$•	$•	$•	$•
Total Offering(4)(5)	$•	$•	$•	$•

Notes:

(1) The Offering Price has been determined by negotiation between the Company, the Selling Shareholder and the Underwriters.
(2) After deducting the Underwriters' Commissions payable by the Company but before deducting the expenses of the Offering. The expenses of the Offering are estimated to be approximately $3 million and will be paid by the Company out of the proceeds of the Treasury Offering.
(3) After deducting the Underwriters' Commissions payable by the Selling Shareholder but before deducting the expenses of the Secondary Offering. The Selling Shareholder will be responsible for the payment of the Underwriters' Commissions payable in respect of Common Shares sold by the Selling Shareholder. As the incremental expenses of the Secondary Offering are not anticipated to be material, the Company has agreed to pay the expenses associated with the Secondary Offering and, as a result, the Selling Shareholder will not pay any expenses of the Offering other than the Underwriters' Commissions in respect of the Secondary Offering. See "Use of Proceeds" and "Principal Shareholders and Selling Shareholders".
(4) Assumes no exercise of the Over-Allotment Option.
(5) The Company has agreed to grant to the Underwriters an over-allotment option, exercisable, in whole or in part, at the sole discretion of the Underwriters, for a period of 30 days (the "Over-Allotment Option") from the closing of the Offering (the "Closing"), to purchase up to an additional • Shares (the "Over-Allotment Shares"), representing 15% of the aggregate number of Common Shares sold under the Treasury Offering. The Over-Allotment Shares will be sold on the same terms as set out above solely to cover over-allotments, if any, and for market stabilization purposes. If the Over-Allotment Option is exercised in full, the total "Price to the Public", "Underwriters' Commissions" and "Net Proceeds to the Company" will be approximately $• million, $• million and $• million, respectively. This prospectus

qualifies the distribution of the Over-Allotment Option. A purchaser who acquires Common Shares forming part of the Underwriters' over-allocation position acquires those securities under this prospectus, regardless of whether the over-allocation position is ultimately filled through the exercise of the Over- Allotment Option or secondary market purchases. See "Plan of Distribution".

The following table sets out the number of Common Shares that may be issued to the Underwriters pursuant to the exercise of the Over- Allotment Option.

Maximum Number of
Underwriters' Position	Securities Available	Exercise Period	Exercise Price ($)
Over-Allotment Option………………………………	• Common Shares	Up to 30 daysfollowing Closing	• per CommonShare

Unless otherwise indicated, all information in this prospectus assumes that the Over-Allotment Option will not be exercised.

The Company has applied to have the Common Shares listed on the Toronto Stock Exchange (the "TSX") under the symbol "TPZ". Listing is subject to the approval of the TSX in accordance with its original listing requirements. The TSX has not conditionally approved the Company's listing application and there is no assurance that the TSX will approve the listing application. Closing is conditional upon the Common Shares being approved for listing on the TSX. See "Plan of Distribution".

In connection with the Offering, the Underwriters may over-allocate or effect transactions which stabilize, maintain or otherwise affect the market price of the Common Shares at levels other than those which otherwise might prevail on the open market. The Underwriters may offer the Common Shares at a price lower than that stated above. Any such reduction in price will not affect the proceeds received by the Company or the Selling Shareholder. See "Plan of Distribution".

The Underwriters, as principals, conditionally offer the Common Shares offered under this prospectus, subject to prior sale, if, as and when sold and delivered by the Company, or in the case of the Selling Shareholder, if, as and when sold and delivered by the Selling Shareholder to, and accepted by, the Underwriters in accordance with the conditions contained in the Underwriting Agreement referred to under "Plan of Distribution" and subject to the approval of certain legal matters on behalf of the Selling Shareholder and the Company by Burnet, Duckworth & Palmer LLP and on behalf of the Underwriters by Torys LLP.

Subscriptions will be received subject to rejection or allotment in whole or in part and the Underwriters reserve the right to close the subscription books at any time without notice. It is expected that Closing will occur on or about •, 2020 or such later date as the Selling Shareholder, the Company and the Lead Underwriters may agree, but in any event not later than •, 2020. The Common Shares offered under this prospectus are to be taken up by the Underwriters, if at all, on or before a date not later than 42 days after the date of the receipt for the final prospectus.

Except in certain limited circumstances, no certificates representing Common Shares will be issued to purchasers in the Offering. Instead, on the date of Closing, the purchasers of Common Shares will have their securities registered in the name of CDS Clearing and Depository Services Inc. or its nominee ("CDS") and electronically deposited with CDS. Purchasers of Common Shares will receive only a customer confirmation from the Underwriter or other registered dealer who is a CDS participant and from or through whom a beneficial interest in the Common Shares is acquired.

There is currently no market through which the Common Shares may be sold and purchasers may not be able to resell Common Shares purchased under this prospectus. This may affect the pricing of the Common Shares in the secondary market, the transparency and availability of trading prices, the liquidity of the Common Shares and the extent of issuer regulation. An investment in the Common Shares is speculative and is subject to a number of risks that should be considered by a prospective investor. The Company's business is subject to certain of the risks normally encountered in the oil and natural gas industry and the risks associated with royalty interests and energy infrastructure assets in particular. See "Risk Factors".

A return on an investment in the Common Shares is not comparable to the return on an investment in a fixedincome security. The recovery by shareholders of their initial investment is at risk, and the anticipated return on that investment is based on many performance assumptions. Although the Company intends to pay quarterly dividends to shareholders of the majority of its cash flow, those cash dividends may be reduced or suspended. The actual amount of cash distributed to shareholders, if any, will depend on numerous factors including: (i) the earnings of the Company; (ii) financial requirements for the Company's operations; (iii) the satisfaction by the Company of liquidity and solvency tests in the ABCA (as defined herein); and (iv) any agreements relating to the Company's indebtedness that restrict the declaration and payment of dividends. The payment of dividends is not guaranteed and the amount and timing of any dividends payable is at the discretion of the Board. In addition, the market value of the Common Shares may decline if the Company is unable to meet its target cash dividend in the future, which decline may be significant. See "Risk Factors".

It is important for purchasers of Common Shares to consider the particular risk factors that may affect the industry in which they are investing and, therefore, the stability of the dividends that shareholders receive. See, for example, "Risk Factors — Risks Relating to the Company's Business, Industry and Operating Environment".

Scotia Capital is, directly or indirectly, an affiliate of a bank which is a lender to the Company and each of Scotia Capital, BMO Nesbitt Burns Inc., CIBC World Markets Inc., National Bank Financial Inc., TD Securities Inc. and ATB Capital Markets Inc. is, directly or indirectly, an affiliate of a lender to the Selling Shareholder. In addition, a director of the Company is a director of an affiliate of ATB Capital Markets Inc. Consequently, under applicable Canadian Securities Laws (as defined herein), the Selling Shareholder and the Company may be considered to be a connected issuer to such Underwriters. See "Relationships Among the Company, the Selling Shareholder and Certain Underwriters".

Topaz is incorporated under the ABCA and the head office of the Company is located at Suite 3100, 250 6th Avenue SW, Calgary, Alberta T2P 3H7 and registered office of the Company is located at Suite 2400, 525 8th Avenue SW, Calgary, Alberta T2P 1G1.

IMPORTANT ADVISORY 8
PRESENTATION OF INFORMATION8
ELIGIBILITY FOR INVESTMENT9
GLOSSARY10
ABBREVIATIONS17
NOTICE TO INVESTORS 19
PROSPECTUS SUMMARY30
THE COMPANY'S BUSINESS52
INVESTMENT HIGHLIGHTS55
GROWTH STRATEGY62
THE COMPANY'S ASSETS 63
THE COMPANY 73
RESERVES AND OTHER OIL AND GAS INFORMATION 75
AGREEMENTS WITH TOURMALINE AND OTHER COUNTERPARTIES86
DESCRIPTION OF SHARE CAPITAL 96
USE OF PROCEEDS 97
PROCEEDS TO THE SELLING SHAREHOLDER97
SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND PRODUCTION INFORMATION98
ANALYSIS OF ADJUSTED PRO FORMA REVENUE, EBITDA AND EBITDA MARGIN 100
CAPITALIZATION 103
OPTIONS TO PURCHASE SECURITIES103
CREDIT FACILITY103
DIVIDEND POLICY 104
MANAGEMENT'S DISCUSSION AND ANALYSIS104
DIRECTORS AND EXECUTIVE OFFICERS124
CORPORATE GOVERNANCE129
EXECUTIVE COMPENSATION136
PLAN OF DISTRIBUTION145
RELATIONSHIPSAMONGTHECOMPANY,THESELLINGSHAREHOLDERAND	CERTAIN
UNDERWRITERS148
PRINCIPAL SHAREHOLDERS AND SELLING SHAREHOLDER149
PRIOR SALES 150
PROMOTER 151
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS151
THE INDUSTRY 151
RISK FACTORS 167
EXEMPTIONS FROM CERTAIN DISCLOSURE REQUIREMENTS 188
LEGAL PROCEEDINGS AND REGULATORY ACTIONS190
AUDITORS, TRANSFER AGENT AND REGISTRAR190
EXPERTS190
MATERIAL CONTRACTS191
RIGHTS OF WITHDRAWAL AND RESCISSION191
CERTIFICATE OF THE ISSUERCP-1
CERTIFICATE OF THE PROMOTER CP-2
CERTIFICATE OF THE UNDERWRITERSCP-3

APPENDICES

APPENDIX "A"	-FINANCIAL STATEMENTS
APPENDIX "B"	SUPPLEMENTAL INFORMATION REGARDING THE TOURMALINE GORR-LANDS
APPENDIX "C"	-FORM 51-101F2 REPORTS ON RESERVES DATA BY INDEPENDENTQUALIFIED RESERVES EVALUATOR
APPENDIX "D"	FORM 51-101F3 REPORTS OF MANAGEMENT AND DIRECTORS ON OIL AND-GAS DISCLOSURE
APPENDIX "E"	AUDIT COMMITTEE MANDATE AND TERMS OF REFERENCE-
APPENDIX "F"	BOARD OF DIRECTORS' MANDATE-

IMPORTANT ADVISORY

A prospective investor should read this entire prospectus and consult the prospective investor's own professional advisors to assess the income tax, legal, risk factors and other aspects of their investment in the Common Shares.

A prospective investor should rely only on the information contained in this prospectus and should not rely on some parts of this prospectus to the exclusion of others. None of, the Company, the Selling Shareholder or any of the Underwriters has authorized anyone to provide investors with additional or different information.

None of the Selling Shareholder, the Company or any of the Underwriters is offering to sell the Common Shares in any jurisdiction where an offer or sale is not permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of the Common Shares. The Company's business, financial condition, results of operations and prospects may have changed since the date of this prospectus.

For investors outside of Canada, none of the Selling Shareholder, the Company or any of the Underwriters has done anything that would permit the Offering or possession or distribution of this prospectus in any jurisdiction where action for that purpose is required, other than in Canada. Investors are required to inform themselves about, and to observe any restrictions relating to, the Offering and the distribution of this prospectus.

Prospective investors are urged to carefully read the information under the headings "Notice to Investors" and "Risk Factors" in this prospectus.

PRESENTATION OF INFORMATION

For the purposes of this prospectus, unless the context otherwise requires:

(i) "Topaz" refers to the Company from November 14, 2019 after giving effect to the sale of the E&P Assets pursuant to the E&P Asset Disposition and the acquisition of the Initial Assets pursuant to the Initial Acquisition when the Company commenced its royalty and energy infrastructure operations; and
(ii) "Exshaw" refers to the Company prior to November 14, 2019 prior to giving effect to the sale of the E&P Assets pursuant to E&P Asset Disposition and the acquisition of the Initial Assets pursuant to the Initial Acquisition when the Company discontinued its upstream petroleum and natural gas exploration and production operations.

Certain other terms used in this prospectus but not defined herein are defined in NI 51-101 and CSA 51-324 and, unless the context otherwise requires, have the same meanings herein as in NI 51-101 or CSA 51-324, as applicable. For additional definitions relating to oil and gas information, see "Reserves and Other Oil and Gas Information — Notes and Definitions".

Words importing the singular include the plural and vice versa and words importing any gender include all genders. A reference to an agreement means the agreement, as it may be amended, supplemented or restated from time to time.

Unless otherwise indicated, all references to "$" or "dollars" refer to Canadian dollars and all references to "US$" or "U.S. dollars" refer to United States dollars.

Figures, columns and rows presented in tables provided in this prospectus may not add due to rounding.

Unless otherwise indicated or the context otherwise requires, information contained in this prospectus assumes that the Over-Allotment Option has not been exercised.

This prospectus includes a summary description of certain material agreements of the Company. See "Material Contracts". The summary description discloses attributes that the Company considers material to an investor in the Common Shares but is not complete and is qualified in its entirety by reference to the terms of the material agreements, which will be filed with the applicable Canadian securities regulatory authorities and available on SEDAR. Investors are encouraged to read the full text of such material agreements.

All references in this prospectus to Management are to the persons who are identified in this prospectus as the executive officers of the Company. See "Directors and Executive Officers". All statements in this prospectus made by or on behalf of Management are made in such persons' capacities as executive officers of the Company and not in their personal capacities.

ELIGIBILITY FOR INVESTMENT

In the opinion of Burnet, Duckworth & Palmer LLP, counsel to the Company and the Selling Shareholder, and Torys LLP, counsel to the Underwriters, based on the current provisions of the Tax Act, and subject to the provisions of any particular plan, provided that the Common Shares are listed on a "designated stock exchange", as defined in the Tax Act (which currently includes the TSX), the Common Shares will, at the time of Closing, be a "qualified investment" under the Tax Act for a trust governed by a registered retirement savings plan ("RRSP"), registered retirement income fund ("RRIF"), a deferred profit sharing plan, a registered education savings plan ("RESP"), a registered disability savings plan ("RDSP") and a tax free savings account ("TFSA").

Notwithstanding that the Common Shares may be a qualified investment, if a common share is a "prohibited investment" for a RRSP, RRIF, RESP, RDSP or TFSA (each a "Registered Plan"), the annuitant under the RRSP or RRIF, the subscriber of the RESP, or the holder of the RDSP or TFSA (as applicable) (each a "Controlling Individual") may be subject to a penalty tax under the Tax Act. A common share will not be a "prohibited investment" in respect of a Registered Plan provided that the Controlling Individual: (i) deals at arm's length with the Company for purposes of the Tax Act and (ii) does not have a "significant interest" in the Company (within the meaning of the Tax Act). In addition, a common share will generally not be a "prohibited investment" for a Registered Plan if the common share is an "excluded property" (as defined in the Tax Act) for such Registered Plan. Controlling Individuals should consult with their own tax advisors regarding whether common shares would be prohibited investments.

GLOSSARY

In this prospectus, unless otherwise indicated or the context otherwise requires, the following terms have the indicated meanings. This is not an exhaustive list of defined terms used in this prospectus and additional terms are defined throughout.

"2019 Equity Financing" means the private placement by the Company of 20,850,506 Common Shares at a price of $10.00 per Common Share for gross proceeds of $208.5 million on November 14, 2019;

"2020 Equity Financing" means the private placement by the Company of 13,208,296 Common Shares at a price of $11.00 per Common Share for gross proceeds of $145.3 million, of which 11,690,131 Common Shares were issued on June 29, 2020 and 1,518,165 Common Shares were issued on July 6, 2020;

"ABCA" means the Business Corporations Act (Alberta) and the regulations thereunder, as amended from time to time;

"Advantage" means Advantage Oil & Gas Ltd., a Canadian intermediate, natural gas and liquids development and production company with significant operated assets in the Montney resource play in Western Canada;

"AECO" means the physical storage and trading hub for natural gas on TC Energy's Alberta Transmission System, which is the delivery point for the various benchmark Alberta index prices;

"AER" means the Alberta Energy Regulator;

"affiliate" or "associate" has the meaning ascribed thereto in the Securities Act (Alberta), as amended from time to time;

"Alberta Deep Basin" means an area within the WCSB, located approximately 250 km west of Edmonton, Alberta;

"Alternative Financial Statements" means the financial statements with respect to the Initial Assets included in this prospectus in Appendix "A" and identified as the Alternative Financial Statements and being comprised of the Initial Acquisition Operating Statements and the Topaz Pro Forma Operating Statements (each as defined in Appendix "A");

"ARC Board Nomination Rights Agreement" means the board nomination rights agreement dated June 29, 2020 among the Company, ARC Energy Fund 9 and Tourmaline entered into in connection with ARC Energy Fund 9's subscription for Common Shares pursuant to the 2020 Equity Financing, as further described under "Directors and Executive Officers";

"ARC Energy Fund 9" means, collectively, ARC Energy Fund 9 Canadian Limited Partnership, ARC Energy Fund 9 United States Limited Partnership, ARC Energy Fund 9 International Limited Partnership and ARC Capital 9 Limited Partnership, in each case a limited partnership formed under the laws of the Province of Alberta;

"ARC Financial" means ARC Financial Corp.;

"ARC Participation Rights Agreement" means the participation rights agreement dated June 29, 2020 between the Company and ARC Energy Fund 9 entered into in connection with ARC Energy Fund 9's subscription for Common Shares pursuant to the 2020 Equity Financing, as further described under "Plan of Distribution";

"Banshee CO&O Agreement" means the agreement for the construction, ownership and operation of the Banshee Gas Plant entered into on September 1, 2020 between the Company and Tourmaline;

"Banshee Gas Plant" means the approximately 155 MMcf/day capacity Banshee Gas Processing Facility located at 15-12-50-21W5 and all related infrastructure and equipment;

"Banshee Gas Plant Acquisition" means the acquisition by the Company of a 25% ownership interest in the Banshee Gas Plant from Tourmaline completed on September 1, 2020 for total cash consideration of $52.5 million, before customary adjustments;

"Banshee Gas Plant Acquisition Agreement" means the purchase and sale agreement entered into on September 1, 2020 between Tourmaline and Topaz pursuant to which Topaz acquired its 25% ownership interest in the Banshee Gas Plant;

"Banshee Volume Commitment Agreement" means the annual take-or-pay volume commitment agreement (Banshee Facility) entered into on September 1, 2020 between Tourmaline and Topaz;

"Board" means the board of directors of the Company;

"Brazeau CO&O Agreement" means the agreement for the construction, ownership and operation of the Brazeau Gas Plant entered into on November 14, 2019 between Tourmaline and Topaz;

"Brazeau Gas Plant" means the Brazeau Gas Plant Complex, consisting of one processing train and associated equipment located on the 15-36-044-15W5 site and one compressor station and associated equipment located on the 16-36-044-15W5 site;

"Brazeau Volume Commitment Agreement" means the annual take-or-pay volume commitment agreement (Brazeau Facility) entered into on November 14, 2019 between Tourmaline and Topaz;

"business day" means a day other than a Saturday, Sunday or a day on which the principal chartered banks located at Calgary, Alberta are not open for business;

"Canadian Securities Laws" means the securities legislation or ordinance and regulations thereunder of each province of Canada and the rules, instruments, policies and orders of each Canadian securities regulator made thereunder;

"CDS" means CDS Clearing and Depository Services Inc. or its nominee;

"Clearwater GORR Acquisition" means the acquisition by the Company of the Clearwater GORR Interest completed on September 1, 2020;

"Clearwater GORR Agreement" means the gross overriding royalty agreement entered into on September 1, 2020 relating to the Clearwater GORR Acquisition;

"Clearwater GORR Interest" means the Company's 4% gross overriding royalty interest in approximately 76,800 gross acres of undeveloped land in the Clearwater area of Alberta, as specified in the Clearwater GORR Agreement, which the Company acquired from an arm's length E&P company pursuant to the Clearwater GORR Acquisition;

"Clearwater GORR Lands" means certain lands and interests located in Alberta to which the Clearwater GORR Interest relates as set forth and described in the Clearwater GORR Agreement, or so much of those rights as remain subject to the Clearwater GORR Agreement and the applicable title documents at the relevant time, and includes the petroleum substances within, upon, under or attributed to those lands;

"Closing" means the closing of the Offering;

"Common Shares" means the common shares in the capital of the Company;

"COVID-19" means the novel coronavirus named COVID-19 and the associated pandemic;

"Credit Facility" means the credit facility described under "Credit Facility";

"Deloitte" means Deloitte LLP, independent qualified reserves evaluators;

"E&P" means oil and gas exploration and production;

"E&P Asset Disposition" means the disposition by the Company to Tourmaline of the E&P Assets completed on November 12, 2019;

"E&P Asset Disposition Agreement" means the asset purchase and sale agreement entered into on November 12, 2019 between the Company and Tourmaline;

"E&P Assets" means all of the Company's exploration and production assets including its petroleum and natural gas rights, tangibles and miscellaneous interests;

"E&P Historical Financial Statements" has the meaning given to such term under the heading "Exemptions From Certain Disclosure Requirements" in this prospectus;

"EIA" means the United States Energy Information Administration;

"ESG" means environmental, social and governance;

"Exemptive Relief" means the exemption, to be evidenced by a receipt for the final prospectus granted by or on behalf of each of the securities commissions or similar regulatory authorities in each of the provinces of Canada, relating to, among other things, the Alternative Financial Statements and certain supplemental financial and production information relating to the Initial Assets, as more particularly described under "Exemptions from Certain Disclosure Requirements";

"Form 41-101F1" means Form 41-101F1 – Information Required in a Prospectus of NI 41-101;

"Freehold Mineral Tax" means an annual tax levied by the Government of Alberta on the value of petroleum and natural gas production from non-government owned lands within Alberta;

"G&A" means general and administrative expense;

"GAAP" means generally accepted accounting principles in Canada, which for Canadian reporting issuers is IFRS, as in effect from time to time;

"GHG" means greenhouse gas;

"Glacier Gas Plant" means the 400 MMcf/d Glacier Gas Plant located at 05-02-076-12W6 servicing the Montney resource play and all related infrastructure and other equipment and tangible depreciable property located within the area lease limits, as well as certain acid gas pipelines and acid gas disposal wells related thereto, and including all liquids handling infrastructure associated with the plant which is required for the extraction and storage of hydrocarbon liquids;

"Glacier Gas Plant Acquisition" means the acquisition by the Company of a 12.5% ownership interest in the Glacier Gas Plant from Advantage completed on July 2, 2020 for total cash consideration of $100 million, before customary adjustments;

"Glacier Gas Plant Acquisition Agreement" means the purchase and sale agreement entered into on April 9, 2020 between Advantage and Topaz pursuant to which Topaz acquired its 12.5% ownership interest in the Glacier Gas Plant;

"Glacier O&O Agreement" means the agreement for the ownership and operation of the Glacier Gas Plant entered into on July 1, 2020 between Advantage and Topaz**;**

"Glacier Volume Commitment Agreement" means the take-or-pay volume commitment agreement entered into on July 1, 2020 between Advantage and Topaz;

"GLJ" means GLJ Petroleum Consultants Ltd., independent qualified reserves evaluators;

"GLJ Price Forecast" means the published GLJ January 1, 2020 price forecast;

"GORR" means gross overriding royalty;

"GORR Interests" means, collectively, the Tourmaline GORR Interest and the Clearwater GORR Interest;

"GORR Lands" means, collectively, the Tourmaline GORR Lands and the Clearwater GORR Lands;

"Governance Agreement" means the governance agreement between Tourmaline and the Company dated November 14, 2019, as further described under "Agreements with Tourmaline and Other Counterparties — Governance Agreement";

"gross" means: (i) in relation to wells, the total number of wells in which the Company has a royalty interest; and (ii) in relation to properties, the total area in which the Company has a royalty interest. As all of the Company's interests in reserves and production are royalty interests with no associated working interests, the Company has no gross reserves or production;

"hydrocarbons" means solid, liquid or gas made up of compounds of carbon and hydrogen in varying proportions;

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

"Infrastructure Assets" means, collectively, the: (i) the Initial Facility Interests; (ii) the Company's interests in the Banshee Gas Plant and the Glacier Gas Plant, together with the Banshee Volume Commitment Agreement and Glacier Volume Commitment Agreement; and (iii) the TPF Revenue Interest;

"Initial Acquisition" means the acquisition by the Company of its formative royalty and infrastructure assets, the Initial Assets, from Tourmaline completed on November 14, 2019 for consideration consisting of $194.5 million in cash and 58,049,494 Common Shares;

"Initial Acquisition Agreements" means, collectively, the Initial Assets Purchase and Sale Agreement and the Initial Assets Ancillary Agreements entered into in connection with the Initial Acquisition, as further described under "Agreements with Tourmaline and Other Counterparties — Agreements Relating to the Initial Acquisition — Initial Acquisition Agreements";

"Initial Acquisition Historical Financial Statements" has the meaning given to such term under the heading "Exemptions From Certain Disclosure Requirements" in this prospectus;

"Initial Acquisition Operating Statements" has the meaning given to such term under the heading "Exemptions From Certain Disclosure Requirements" in this prospectus;

"Initial Assets" means the assets acquired pursuant to the Initial Acquisition being: (i) the Tourmaline GORR Interest; (ii) the Initial Facility Interests; and (iii) the TPF Revenue Interest;

"Initial Assets Ancillary Agreements" means, collectively, the Tourmaline GORR Agreement, the TPF Revenue Interest Agreement, the Initial Facilities Volume Commitment Agreements and the Initial Facilities CO&O Agreements;

"Initial Assets Purchase and Sale Agreement" means the royalty, facilities and revenue interest sale agreement entered into on November 14, 2019 between Tourmaline and Topaz;

"Initial Facilities" means, together, the Musreau Gas Plant and the Brazeau Gas Plant;

"Initial Facilities CO&O Agreements" means, together, the Brazeau CO&O Agreement and the Musreau CO&O Agreement;

"Initial Facilities Volume Commitment Agreements" means, together, the Brazeau Volume Commitment Agreement and the Musreau Volume Commitment Agreement;

"Initial Facility Interests" means: (i) an undivided forty-five percent (45%) interest in each of the Initial Facilities and all miscellaneous interests pertaining thereto; and (ii) the interest in and to the commitment and delivery of certain take-or-pay volumes by Tourmaline to the Company under and pursuant to the Initial Facilities Volume Commitment Agreements;

"Investor Liquidity Agreement" means the investor liquidity agreement between Tourmaline and the Company dated November 14, 2019, as further described under "Agreements with Tourmaline — Investor Liquidity Agreement";

"Lead Underwriters" has the meaning set out on the face page of this prospectus;

"LMR" has the meaning set out under "The Industry – Regulatory Authorities and Environmental Regulations – Liability Management Rating Program";

"LNG" means liquefied natural gas;

"Management" means, collectively, the executive officers of the Company;

"Management Services Agreement" means the management services agreement between Tourmaline and the Company dated November 14, 2019 and as amended on May 20, 2020 and August 31, 2020, as further described under "Agreements with Tourmaline and Other Counterparties — Management Services Agreement";

"McDaniel" means McDaniel & Associates Consultants Ltd., independent qualified reserves evaluators;

"McDaniel Price Forecast" means the published McDaniel January 1, 2020 price forecast;

"Montney" means the Montney formation, a stratigraphic zone in the WCSB, extending from Grande Prairie, Alberta to approximately 100 km northwest of Fort St. John, NEBC;

"Musreau CO&O Agreement" means the agreement for the construction, ownership and operation of the Musreau Gas Plant entered into on November 14, 2019 between the Company and Tourmaline;

"Musreau Gas Plant" means the Musreau Gas Plant Complex, consisting of two processing trains and associated equipment located on the 08-13-062-06W6 and 09-13-062-06W6 sites;

"Musreau Volume Commitment Agreement" means the annual take-or-pay volume commitment agreement (Musreau Facility) entered into on November 14, 2019 between Tourmaline and Topaz;

"NEBC Montney" means an area within the WCSB, located on the west flank of the Peace River High in NEBC focused on the Triassic Montney;

"net" means in relation to the Company's interest in production or reserves, its royalty interest share. As all of the Company's interests in reserves and production are royalty interests with no associated working interests, the Company has no net interest in relation to wells or properties;

"NGL" means those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons;

"NI 41-101" means National Instrument 41-101 — General Prospectus Requirements;

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

"NI 52-109" means National Instrument 52-109 — Certification of Disclosure in Issuers' Annual and Interim Filings;

"NI 52-110" means National Instrument 52-110 — Audit Committees;

"NI 58-101" means National Instrument 58-101 — Disclosure of Corporate Governance Practices;

"NP 58-201" means National Policy 58-201 — Corporate Governance Guidelines;

"NYMEX" means the New York Mercantile Exchange;

"NYMEX Pricing" means, as of any date of determination with respect to any month (i) for crude oil, the closing settlement price for the Light, Sweet Crude Oil (WTI) futures contract for such month, and (ii) for natural gas, the closing settlement price for the Natural Gas (Henry Hub) futures contract for such month, in each case as published by NYMEX on its website currently located at www.nymex.com, or any successor thereto (as such price may be corrected or revised from time to time by the NYMEX in accordance with its rules and regulations);

"Offering" means the distribution of Common Shares pursuant to this prospectus;

"Option" means an option to acquire a Common Share granted pursuant to the Option Plan;

"Option Plan" means the share option plan of the Company;

"Other Income" means the other income generated by way of the TPF Revenue Interest, as calculated under "Notice to Investors – Revenue Calculation Methodology";

"Peace River High Triassic Oil Complex" means an area within the WCSB, located on the Alberta portion of the Peace River High at Spirit River –Mulligen –Earring, Alberta;

"person" means and includes individuals, companies, corporations, limited partnerships, general partnerships, joint stock companies, limited liability companies, joint ventures, associations, trusts, banks, trust companies, pension funds, and other organizations, whether or not legal entities, and governments and agencies and political subdivisions thereof;

"petroleum" means a naturally occurring mixture consisting predominantly of hydrocarbons in the gaseous, liquid or solid phase, and as referenced in this prospectus, includes oil and NGL;

"petroleum substances" means condensate, crude oil, natural gas, NGL or any of them, but excluding NGL (other than condensate and pentanes) for purposes of the Tourmaline GORR Agreement;

"Processing Revenue" means the revenue generated by the Company's non-operated ownership interests in the Banshee Gas Plant, Brazeau Gas Plant, Glacier Gas Plant and Musreau Gas Plant, as calculated under "Notice to Investors – Revenue Calculation Methodology";

"resource-style plays" means an accumulation of hydrocarbons known to exist over a large areal expanse and/or thick vertical section;

"Royalty Assets" means the GORR Interests;

"Royalty Production Revenue" means the revenue generated from the GORR Interests on GORR Lands, as calculated under "Notice to Investors – Revenue Calculation Methodology";

"royalty share" means the gross volume of petroleum substances comprising the Tourmaline GORR Interest;

"SEDAR" means the System for Electronic Document Analysis and Retrieval;

"shareholder" means a holder of Common Shares;

"Sproule" means Sproule Associates Ltd., independent qualified reserves evaluators;

"Sproule Price Forecast" means the published Sproule January 1, 2020 price forecast;

"subsidiary" has the meaning ascribed thereto in the ABCA;

"Tax Act" means the Income Tax Act (Canada) and the regulations thereunder, as amended from time to time;

"Topaz Financial Statements" means the Company's audited financial statements and accompanying notes included in this prospectus in Appendix "A" and identified as the Topaz Financial Statements;

"Topaz Pro Forma Operating Statements" means the Company's pro forma operating statements and accompanying notes included in this prospectus in Appendix "A" and identified as the Topaz Pro Forma Operating Statements;

"Topaz Reserve Report" means the independent engineering evaluation of the crude oil, natural gas and NGL reserves relating to the Tourmaline GORR Lands prepared by GLJ and Deloitte with an effective date of December 31, 2019 and a preparation date of March 2, 2020;

"Tourmaline Consolidated Reserve Report" means the report of GLJ dated effective December 31, 2019, with a preparation date of February 25, 2020 (the "Tourmaline GLJ Reserve Report") and the report of Deloitte dated effective December 31, 2019, with a preparation date of February 25, 2020 (the "Tourmaline Deloitte Reserve Report"), which are contained in the consolidated report of GLJ dated effective December 31, 2019, with a preparation date of February 25, 2020;

"Tourmaline Credit Facilities" has the meaning given to such term under the heading "Relationships Among the Company, the Selling Shareholder and Certain Underwriters";

"Tourmaline GORR Agreement" means the gross overriding royalty agreement entered into on November 14, 2019 between Tourmaline and Topaz;

"Tourmaline GORR Interest" means the non-convertible gross overriding royalty, being an interest in Tourmaline's working interest in the petroleum substances within, upon, or attributed to, the Tourmaline GORR Lands, granted by Tourmaline to Topaz pursuant to the Tourmaline GORR Agreement, being a royalty share as follows: for crude oil and condensate, 2.5%; and for natural gas: 4% until December 31, 2021 and 3% from and after January 1, 2022;

"Tourmaline GORR Lands" means certain lands and interests located primarily in Alberta and British Columbia to which the Tourmaline GORR Interest relates as set forth and described in the Tourmaline GORR Agreement, or so much of those rights as remain subject to the Tourmaline GORR Agreement and Tourmaline's title documents at the relevant time, and includes the petroleum substances within, upon, under or attributed to those lands;

"TPF Facilities" means the various natural gas processing plants, crude oil batteries, water disposal facilities pipelines, compressor stations and miscellaneous facilities where petroleum substances are handled pursuant to the TPF Handling Agreements;

"TPF Handling Agreements" means the agreements in existence as at November 14, 2019 and those agreements entered into from and after November 14, 2019, whether for Tourmaline's sole account or with third parties, and which apply to the handling of petroleum substances owned by third parties at the TPF Facilities;

"TPF Revenue" means all third-party revenues that Tourmaline is entitled to receive that are attributable to the handling of petroleum substances under the TPF Handling Agreements;

"TPF Revenue Interest" means Topaz's contractual interest pursuant to the TPF Revenue Interest Agreement in and to (i) 100% of the first $16,000,000 of TPF Revenue received by Tourmaline, and (ii) 70% of the TPF Revenue received by Tourmaline in excess of $16,000,000, in each calendar year, as further described under "Agreements with Tourmaline and Other Counterparties — Agreements Relating to the Initial Acquisition — Initial Acquisition Agreement Acquisition — TPF Revenue Interest Agreement";

"TPF Revenue Interest Agreement" means the Topaz TPF revenue interest agreement entered into on November 14, 2019 between Tourmaline and Topaz in respect of the TPF Revenue Interest;

"TSX" means the Toronto Stock Exchange;

"Underwriters" has the meaning set out on the face page of this prospectus;

"Underwriting Agreement" means the underwriting agreement between the Company, the Selling Shareholder and the Underwriters dated •, 2020, as further described under "Plan of Distribution"; and

"United States" or "U.S." means the United States of America, its territories and possessions, any state of the United States and the District of Columbia.

ABBREVIATIONS

In this prospectus, the following abbreviations have the meanings set forth below. This is not an exhaustive list of abbreviations used in this prospectus and additional terms are defined throughout.

Crude Oil and Natural Gas Liquids
Bbls/d or Bbl/d	barrels of oil per day
Bbls or Bbl	barrels of oil
Boe	barrel of oil equivalent
Boe/d	barrel of oil equivalent per day
$/Bbl	Canadian dollars per barrel of oil
$/Boe	Canadian dollars per barrel of oil equivalent
Mbbls	thousand barrels
MBoe	thousand barrels of oil equivalent
Mbbls/d	thousand barrels of oil per day
MMbbls	million barrels of oil
MMboe	million barrels of oil equivalent
MMboe/d	million barrels of oil equivalent per day
NGL	natural gas liquids; provided that when used with
	respect to the Company's reserves associated with or
	production from the Tourmaline GORR Lands, NGL
	includes only condensate and pentane and no other
	natural gas liquids

Natural Gas

Bcf	billion cubic feet
cf	cubic feet
Mcf	thousand cubic feet
Mcf/d	thousand cubic feet per day
Mcfe	thousand cubic feet of gas equivalent
Mcfe/d	thousand cubic feet of gas equivalent per day
MMbtu	million British thermal units
MMcf	million cubic feet

million cubic feet per day
million cubic feet of gas equivalent
million cubic feet of gas equivalent per day
Canadian dollars per thousand cubic feet
Canadian dollars per million British thermal units
Gigajoule
Gigajoules per day
Canadian dollar per gigajoule
trillion cubic feet

Other

API	American Petroleum Institute
CO2	Carbon dioxide
km	Kilometres
km2	square kilometres
$, $Cdn, Cdn$ or $dollars	Canadian dollars
$000s or M$	thousand dollars
NEBC	north east British Columbia
MM$	million dollars
$US or US$	United States dollars
2D	two dimensional
3D	three dimensional
Vol/d	volumes per day

NOTICE TO INVESTORS

About this Prospectus

General

Prospective investors are urged to carefully read the information under this heading and under the headings "Important Advisory", "Presentation of Information" and "Risk Factors" in this prospectus.

For an explanation of certain terms and abbreviations used in this prospectus and not otherwise defined, reference is made to the "Glossary" and "Abbreviations".

In this prospectus, unless otherwise indicated, all dollar amounts are expressed in Canadian dollars.

Use of Industry Specific Terminology

This prospectus contains a number of references to industry specific terminology that is commonly used in the oil and gas royalty and energy infrastructure businesses and is also used by the Company in this prospectus. In particular, and without limitation to the terms described or defined elsewhere in this prospectus, this prospectus contains references to gross overriding royalty interests, plays, gas processing facilities, take-or-pay contracts and throughput.

Gross overriding royalty interests are royalty interests that burden the working interests of a lease and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. These types of royalty interests typically remain in effect until the associated lease expires.

Plays are drilling programs targeted at regionally distributed natural gas or crude oil accumulations.

Gas processing facilities purify hydrocarbons by removing contaminants from hydrocarbon streams, some of which— NGL, in particular—have independent value and are an important source of revenue for producers and marketers of petroleum products. NGL are heavier components of natural gas (such as ethane, propane, butanes and pentanes) that are separated from a hydrocarbon stream (typically in a vapor phase) in liquid form. This can occur in a field plant or processing facility through condensation or absorption, among other methods. Once separated, NGL can be stored and shipped in a liquid state and have many important uses, including use as an input for petrochemical plants, heating, and fuels.

Take-or-pay contracts refers to a form of contract in which the payor is obligated to pay regardless of whether or not the payor uses the services, volumes or capacity available under the contract.

Throughput means, with respect to a gas plant, the amount of inlet volumes processed on a daily basis (including any off-load or reprocessed volumes).

Certain Reserves Data and Other Oil and Gas Information

The determination of oil and gas reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved, probable and possible reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods is required to properly use and apply reserves definitions.

The qualitative certainty levels referred to in the definitions of proved, probable and possible reserves are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and
(b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A 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 the COGE Handbook.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed nonproducing. 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.

In this prospectus:

(a) the discounted and undiscounted net present value of future net revenues attributable to reserves do not represent the fair market value of reserves;
(b) there is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, NGL and natural gas reserves provided in this prospectus are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and NGL reserves may be greater than or less than the estimates provided in this prospectus;
(c) 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; and
(d) Boes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf : 1 Bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

All crude oil, natural gas and NGL reserves and other information with respect to the Tourmaline GORR Lands in this prospectus have been prepared and are presented in accordance with NI 51-101. See "Reserves and Other Oil and Gas Information — Notes and Definitions" for additional information.

All acreage information with respect to the GORR Lands in this prospectus has been presented on a gross acre basis. For the Tourmaline GORR Lands and the Clearwater GORR Lands, gross acres refer to the total acres on which the Company holds the Tourmaline GORR Interest and the Clearwater GORR Interest, respectively. Gross acres for the GORR Lands do not account for the Company's ownership interest in the lands, which is the royalty interest held by the Company on such lands. The presentation of gross acres for the GORR Lands is consistent with the presentation by certain of the Company's peers that hold a royalty interest on lands leased to or by third parties.

All references in this prospectus to "working interest" means the right granted to a lessee of a property to explore for and produce petroleum and/or natural gas on the leased lands, upon which such lessee bears the operating costs, capital costs, environmental liabilities or reclamation obligations associated with petroleum and natural gas development.

Forward-Looking Statements

This prospectus contains forward-looking statements and forward-looking information (collectively, "forwardlooking statements") that relate to the Company's current expectations and views of future events. The forwardlooking statements are contained principally in the sections of this prospectus entitled "Prospectus Summary", "The Company's Business", "Investment Highlights", "Growth Strategy", "Reserves and Other Oil and Gas Information", "Use of Proceeds", "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin", "Management's Discussion and Analysis" and "Risk Factors". These forward-looking statements relate to future events or the Company's future performance. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or performance (often, but not always, through the use of words or phrases such as "will likely result", "are expected to", "expects", "will continue", "is anticipated", "anticipates", "believes", "estimated", "intends", "plans", "forecast", "projection", "strategy", "objective" and "outlook") are not historical facts and may be forward-looking statements and may involve estimates, assumptions and uncertainties which could cause actual results or outcomes to differ materially from those expressed in such forward-looking statements. No assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this prospectus should not be unduly relied upon. These statements speak only as of the date of this prospectus. In addition, this prospectus may contain forward-looking statements attributed to third-party industry sources. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the information and factors discussed throughout this prospectus.

In particular and without limitation, this prospectus contains forward-looking statements pertaining to the following:

the Company's objective of generating free cash flow growth at a relatively low-risk and low cost to the Company, and the proposed manner of achieving this objective;
the estimated amount of cash flow of the Company (including the components thereof and potential future increases in the amount of cash flow) and the related anticipated payout ratio of the Company;
the long-term impact of COVID-19 on the Company's business, financial position, results of operations and/or cash flows;
the Company's estimated free cash flow margin;
the anticipated Offering Price, size of the Offering and use of proceeds of the Offering not being specified with certainty;
the Company's dividend policy, the funding of such dividends, the amounts expected to be paid under that policy currently and in the future and the anticipated timing of payment of such dividends;
the Company's business and growth strategy and anticipated sources of future income including as described under "Investment Highlights" and "Growth Strategy" and the possibility that the Board may vary that strategy in the future;
the expectation that the Company will be able to grow its revenue, actively maintain and manage its Royalty Assets and Infrastructure Assets and achieve external growth by selectively pursuing strategic business development opportunities;
the expectation that the Company's counterparties will continue to develop its Royalty Assets;
the estimated volumes and future net revenues related to the Company's crude oil, natural gas and NGL reserves and expectations regarding the ability of the Company to add to reserves through third-party development activities and acquisitions undertaken by the Company;
projected petroleum and natural gas production levels and certain costs and expenses associated with the Royalty Assets and the Infrastructure Assets;
projected financial and petroleum and natural gas production information associated with the Tourmaline GORR Lands;
the amount and timing of anticipated royalty payments to be received from Tourmaline in respect of the Tourmaline GORR Lands and that revenues from the Tourmaline GORR Lands will provide a significant portion of the Company's revenue;
the amount and timing of anticipated payments of Processing Revenue and Other Income to be received from Tourmaline and other counterparties in respect of the Infrastructure Assets and that revenues from the Infrastructure Assets will provide a significant portion of the Company's revenue;
the performance and creditworthiness of the Company's counterparties including the counterparties to the Tourmaline GORR Agreement, the Banshee Volume Commitment Agreement, the Brazeau Volume Commitment Agreement, the Musreau Volume Commitment Agreement and the Glacier Volume Commitment Agreement;
the anticipation that there will be no operating costs, capital costs, environmental liabilities or reclamation obligations associated with petroleum and natural gas development incurred by the Company on the Tourmaline GORR Lands;
the performance and characteristics of the Royalty Assets;
that third-party development activity on the Royalty Assets is anticipated to provide continued new sources of petroleum and natural gas royalty revenue for the Company in future years, with new wells and production therefrom reducing the rate at which production and royalty revenue would otherwise decline;
plans for and timing of the development of the reserves and undeveloped lands associated with the Royalty Assets;
the timing and amount of capital expenditure programs and well drilling activity by third parties on the Royalty Assets;
the volume of natural gas delivered pursuant to variable processing fee commercial agreements associated with the Infrastructure Assets;
the volume of natural gas and crude oil processed and handled, and the amount of revenue generated in connection with the contracted interest for the Other Income;
utilization rates and throughputs of the Infrastructure Assets;
operational matters, including potential hazards inherent in the Company's operations and the effectiveness of third-party health, safety, environmental and integrity programs;
decommissioning, abandonment and reclamation costs;
anticipated future crude oil, natural gas and NGL prices and currency, exchange and interest rates;
supply and demand for petroleum and natural gas;
the tax horizon and taxability of the Company;
treatment under governmental regulatory regimes, environmental legislation and tax laws;
the amount expected to be drawn by the Company under the Credit Facility on Closing; and
expected future director and Management compensation levels, including grants or awards to be made pursuant to the Company's long-term incentive plans.

With respect to forward-looking statements contained in this prospectus, assumptions have been made regarding, among other things:

Tourmaline's level of ownership of Common Shares following Closing;
the ability of the working interest owners on the Royalty Assets including Tourmaline to maintain or increase production and reserves from these properties;
the ability and willingness of the Company's counterparties with respect to the Royalty Assets and the Infrastructure Assets to comply with, and the Company to enforce, contractual provisions in order to receive payments in respect of the Royalty Assets and the Infrastructure Assets;
the ability of the working interest owners on the Royalty Assets and the operators of the Infrastructure Asset to operate in a safe, efficient and effective manner;
the timely receipt of any required regulatory approvals by the working interest owners of the Royalty Assets and the operators of the Infrastructure Assets;
the willingness and financial capability of the working interest owners on the Royalty Assets to continue to develop and invest additional capital in the Royalty Assets and to obtain financing on acceptable terms, or at all, to fund capital expenditures;
field production rates, decline rates and the well performance and characteristics of the Royalty Assets;
the ability to replace and increase crude oil, natural gas and NGL reserves and production associated with the GORR Lands through acquisitions and third-party development;
the timing, cost and ability of third parties to access, maintain or expand necessary facilities and/or secure adequate product transportation and storage;
for royalty payments taken-in-kind by the Company, if any, the ability of the Company or a thirdparty marketer to successfully market the Company's in-kind petroleum and natural gas products;
surface rights access being granted to third parties on the GORR Lands;
the level of costs and expenses to be incurred by the Company, including with respect to interest, general and administrative expenses and income tax expenses;
the ability of the Company to obtain and retain qualified staff, equipment and services in a timely and cost efficient manner;
the absence of any material litigation or claims against the Company;
the general stability of the economic and political environment and the regulatory framework regarding royalties, taxes and environmental matters in the jurisdictions in which the Company has an interest in oil and natural gas properties; and
future crude oil, natural gas and NGL prices and currency, exchange and interest rates.

The information in this prospectus, including the Company's actual results, could differ materially from those anticipated in the forward-looking statements as a result of the risk factors set forth below and included elsewhere in this prospectus:

the GORR Lands will not be developed by third parties in the manner anticipated by the Company;
non-compliance with contract terms or payment or delivery delinquencies in respect of the Royalty Assets or the Infrastructure Assets, including the credit risk associated with such third parties;
volatility in the demand, supply and market prices for crude oil, natural gas and NGL;
risks of health epidemics, pandemics and similar outbreaks, including COVID-19, which may have sustained material adverse effects on the Company's business, financial position, results of operations and/or cash flows;
long-term reliance on third parties as operators and working interest owners on the GORR Lands and co-owners and operators of the Infrastructure Assets as well as to provide necessary services to the Company;
liabilities inherent in petroleum and natural gas operations and the processing of natural gas and NGL;
uncertainties associated with estimating crude oil, natural gas and NGL reserves and future production levels;
increased costs incurred by the Company or the working interest owners on the GORR Lands;
competition for, among other things, third-party capital and acquisitions of additional assets;
incorrect assessments of the value of future acquisitions;
risks related to the environment and changing environmental laws in relation to the operations conducted on the GORR Lands and the Infrastructure Assets;
geological, technical, drilling, processing and handling issues associated with petroleum and natural gas development activities by third parties;
risks arising from co-ownership of facilities including reliance on third-party operators;
changes in the performance or creditworthiness of counterparties;
risks and liabilities associated with the processing and handling of dangerous goods;
climate change risks, including the effects of unusual weather and natural catastrophes;
regulatory and market compliance and other costs associated with climate change;
reputational risks;
technology and security risks, including cybersecurity;
disruptions in production, including work stoppages or other labour difficulties, or disruptions in the transportation network on which the Company is reliant;
technical and processing problems, including the availability of equipment and access to properties;
claims made or legal actions brought or realized against the Company or its properties or assets;
a failure by the Company to hire or retain key personnel;
a decrease or elimination of the payment of dividends by the Company as a result of a Board determination or restrictions under applicable agreements or corporate laws;
general economic, market and business conditions;
changes in tax or environmental laws or royalty or incentive programs relating to the oil and natural gas industry; and
the other factors discussed under "Risk Factors".

Since actual results or outcomes could differ materially from those expressed in any forward-looking statements made by or on behalf of the Company, investors should not place undue reliance on any such forward-looking statements. Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described can be profitably produced in the future. Readers are cautioned that the foregoing lists of factors are not exhaustive. Further, any forward-looking statement is made only as of the date of this prospectus, and none of the Selling Shareholder, the Company or the Underwriters undertake any obligation to update or revise any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events, except as required by Canadian Securities Laws. New factors emerge from time to time, and it is not possible for the Company and/or the Selling Shareholder to predict all of these factors or to assess in advance the impact of each such factor on the Company's business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement.

The forward-looking statements contained in this prospectus are expressly qualified by the foregoing cautionary statements. Investors should read this entire prospectus and consult their own professional advisors to ascertain and assess the income tax, legal, risk factors and other aspects of their investment in the Common Shares.

COVID-19

In December 2019, COVID-19 surfaced in Wuhan, China and has since spread to over 200 countries and territories and infections have been reported around the world. The World Health Organization declared a global emergency on January 30, 2020 with respect to the outbreak and subsequently characterized it as a pandemic on March 11, 2020. In response to the pandemic, governmental authorities in Canada and internationally have introduced various recommendations and measures to try to limit the pandemic, including travel restrictions, border closures, nonessential business closures, quarantines, self-isolations, shelters-in-place and social distancing. COVID-19 and the response of governmental authorities to try to limit it are having a significant impact on the private sector and individuals, including unprecedented business, employment and economic disruptions.

The Company has been closely monitoring developments related to COVID-19. COVID-19 and other macroeconomic conditions around the world have contributed to a drastic decrease in global oil and liquids demand since the beginning of 2020. These events have resulted in significant price volatility of oil and liquids prices and increased economic uncertainty. Natural gas prices have also been very volatile, however, in recent months, the forward curve for both AECO and NYMEX Pricing has been strengthening which has helped to offset some of the impact of the significant decrease in oil and liquids prices. While there has been little to no disruption to date to the Company's business, the oil and condensate prices Topaz receives for its oil and condensate royalty revenue have been affected by the weakness in crude oil prices with the price of WTI dropping from US$50.54/Bbl in February 2020 to US$30.45/Bbl in March 2020 before collapsing even further in April and May 2020. Fortunately for the Company, the Company has been somewhat insulated by virtue of its royalty and infrastructure business model and the royalty production mix consisting of over 90% natural gas. During this continuing period of uncertainty, the Company is committed to maintaining its strong balance sheet and financial liquidity. At this time, the extent to which COVID-19 may continue to affect the Company is uncertain; however, it is possible that COVID-19 may have further adverse effects on commodity prices, the Company's business and income streams, results of operations and financial condition depending on the severity and duration of the pandemic. In response to COVID-19, the Company is following all applicable rules and regulations as set out by the relevant health authorities. The Company's staff have been able to adapt to the new work environment without significant disruptions.

Marketing Materials

The "template version" of any "marketing materials" (as such terms are defined in NI 41-101) utilized by the Underwriters in connection with the Offering to be incorporated by reference into the final prospectus is not part of the final prospectus to the extent that the contents of the template version of the marketing materials have been modified or superseded by a statement contained in the final prospectus. The template version of any marketing materials filed on SEDAR after the date of the final prospectus and before the termination of the distribution pursuant to the Offering (including any amendments to, or an amended version of, the template version of the marketing materials) will be deemed to be incorporated by reference into the final prospectus.

Financial Statements

The Company's financial statements included in Appendix "A" to this prospectus have been prepared in accordance with IFRS other than the Initial Acquisition Operating Statements which are prepared in accordance with the financial reporting framework specified in section 3.17 of National Instrument 52-107 - Acceptable Accounting Principles and Auditing Standards for Predecessor Statements or Primary Business Statements that are an Operating Statement.

Exemptive Relief

The Company has applied for the Exemptive Relief with respect to the Alternative Financial Statements. The supplemental production, oil and gas reserves and operational information with respect to the Tourmaline GORR Lands and the infrastructure assets owned as at the effective date of December 31, 2019 are included in Appendix "B" to this prospectus have been prepared and are presented in accordance with the terms of the Exemptive Relief. See "Exemptions from Certain Disclosure Requirements".

Non-GAAP Financial Measures

In addition to using financial measures prescribed by IFRS, references are made in this prospectus or the documents incorporated by reference herein to "adjusted pro forma revenue", "adjusted pro forma EBITDA", "adjusted pro forma EBITDA margin", "cash flow", "free cash flow", "free cash flow margin", "payout ratio", "yield", "EBITDA", "EBITDA margin", "operating income", "adjusted working capital" and "net debt (cash)" which are measures that do not have any standardized meaning as prescribed by IFRS.

Management uses these terms for its own performance measures and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash necessary to fund dividends and a portion of its future growth expenditures or to repay debt. Accordingly, investors are cautioned that the non-GAAP financial measures may not be comparable to similarly defined measures presented by other entities and should not be considered in isolation nor as an alternative to net income (loss) from continuing operations or other financial information determined in accordance with GAAP as an indication of the Company's performance. In addition, except as the context otherwise requires, the Company's reference to "revenue" throughout this prospectus refers to the sum of total revenue and other income.

"Adjusted pro forma revenue" is used in the table under the heading "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin" to represent the estimated pro forma Royalty Production Revenue, Processing Revenue and Other Income from all of Topaz's GORR Interests and Infrastructure Assets, had the interests, assets and their associated contracts been in place effective January 1, 2018, and as the revenue and other income would be determined in accordance with IFRS. See "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin".

"Adjusted pro forma EBITDA" is used in the table under the heading "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin" to represent the estimated pro forma EBITDA from all of Topaz's GORR Interests and Infrastructure Assets, had the interests, assets and the associated contracts been in place effective January 1, 2018, and as the revenue, other income and expenses would be determined in accordance with IFRS. See "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin". "Adjusted pro forma EBITDA" is defined as adjusted pro forma operating income plus any realized hedging gains, less general and administrative expenses and any realized hedging losses.

"Adjusted pro forma EBITDA Margin" is used in the table under the heading "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin" to represent the estimated pro forma profitability from all of Topaz's GORR Interests and Infrastructure Assets, had the interests, assets and the associated contracts been in place effective January 1, 2018, as the revenue, other income and expenses would be determined in accordance with IFRS. See "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin". "Adjusted pro forma EBITDA Margin" is defined as Adjusted Pro Forma EBITDA divided by Adjusted Pro Forma Revenue (expressed as a percentage of Adjusted Pro Forma Revenue).

"EBITDA" is defined as operating income plus any realized hedging gains, less general and administrative expenses and any realized hedging losses. "EBITDA margin" is defined as EBITDA divided by total revenue and other income (expressed as a percentage of total revenue and other income).

References to "free cash flow" are to the amount of cash estimated to be available for dividends to shareholders in accordance with the dividend policy of the Company described in this prospectus. See "Dividend Policy." "Free cash flow" is defined as cash flow less capital expenditures. References to "free cash flow margin" are to the proportion of the sum of total revenue and other income that is retained by a company to be available for dividends to shareholders. "Free cash flow margin" is defined as free cash flow divided by the sum of total revenue and other income (expressed as a percentage of the sum of total revenue and other income).

References to "payout ratio" are to cash dividends paid or estimated to be paid by the Company to shareholders divided by cash flow. Free cash flow, free cash flow margin and payout ratio are measures generally used by dividend-paying Canadian entities as indicators of financial performance and capacity.

"Yield" as used in the documents incorporated by reference in this prospectus is calculated by dividing the annualized dividend anticipated to be paid per Common Share by the offering price of the Common Shares hereunder. Yield is a measure commonly used by dividend and distribution-paying Canadian entities as an indicator of financial return, and Management believes that prospective investors may consider yield when assessing an investment in the Common Shares. Prospective investors are cautioned that the yield on the Common Shares is not comparable to a yield in the context of bonds or other fixed income securities, where in the latter case, investors are entitled to a full return of the principal amount of debt on maturity in addition to a return on investment through interest payments at a predetermined level. See "Risk Factors - Risks Relating to the Offering and Common Shares - Cash Dividend Payments are Not Guaranteed".

Measures including "cash flow", "operating income", "adjusted working capital" and "net debt (cash)" are used to evaluate the profitability and financial liquidity of the Company. "Cash flow" is defined as cash from (used in) operations before changes in non-cash working capital, "operating income" is defined as revenue and other income, less operating and marketing expenses. "Adjusted working capital" is current assets less current liabilities, adjusted for financial instruments and "net debt (cash)" is total debt outstanding less adjusted working capital. See "Selected Historical and Pro Forma Financial and Production Information" and "Management's Discussion & Analysis".

The terms "adjusted EBITDA", "interest expense", "consolidated senior secured debt" and "total debt" for purposes of the financial covenants are defined as follows for purposes of the Company's financial covenants under the Credit Facility: "adjusted EBITDA" is net income or loss from continuing operations, excluding extraordinary items, plus interest expense, income taxes and the capital portion of any finance lease received, and adjusted for non-cash items and gains or losses on dispositions; "interest expense" is the total interest expense with respect to all outstanding indebtedness; "consolidated senior secured debt" is all total debt that is secured in priority or equivalent to any Credit Facility obligations and "total debt" is the aggregate principal amount of all debt; all of which are determined in accordance with GAAP. A copy of the agreement relating to the Credit Facility is available on SEDAR at www.sedar.com under the Company's profile. See "Credit Facility".

See "Risk Factors — Risks Relating to the Offering and Common Shares — Cash Dividend Payments are Not Guaranteed".

Market, Independent Third-Party and Industry Data

Certain market, independent third-party and industry data contained in this prospectus is based upon information from government or other independent industry publications and reports or based on estimates derived from such publications and reports. Government and industry publications and reports generally indicate that they have obtained their information from sources believed to be reliable, but none of the Company, the Selling Shareholder or any of the Underwriters has conducted its own independent verification of such information. This prospectus also includes certain data, including production, well count estimates, capital expenditures and other operational results, derived from public filings made by independent third parties. While the Company and the Selling Shareholder believe this data to be reliable, market and industry data is subject to variations and cannot be verified with complete certainty due to limits on the availability and reliability of raw data, the voluntary nature of the data gathering process and other limitations and uncertainties inherent in any statistical survey. None of the Company, the Selling Shareholder or any of the Underwriters has independently verified any of the data from independent third-party sources referred to in this prospectus or ascertained the underlying assumptions relied upon by such sources.

Information Regarding Public Issuer Counterparties

Certain information contained in this prospectus relating to the Company's public issuer counterparties and the nature of their respective businesses is taken from and based solely upon information published by such issuers. None of the Company, the Selling Shareholder (to the extent such information does not pertain to the Selling Shareholder) or the Underwriters have independently verified the accuracy or completeness of any such information.

Credit Ratings

Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. Credit ratings are not recommendations to purchase, hold or sell securities and do not address the market price or suitability of a specific security for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.

Processing Capacity Volume Figures

The processing capacity of the gas processing plants referred to in this prospectus are reported on an inlet volume capacity basis. Inlet volumes will be more than the sales volumes ultimately processed at facilities due to fuel consumption and customary shrinkage, which occurs during transportation and processing.

(1) Topaz's income streams include Royalty Production Revenue, Processing Revenue and Other Income. Royalty Production Revenue(1) is calculated as the product of: monthly royalty production volume, gross overriding royalty rate and market index price. Royalty Production Revenue is calculated on a separate basis for each commodity produced as those inputs are described in the GORR Agreements.
(2) Other Income(2) is calculated as the product of: volume processed or handled per day, processing or handling fee per unit, and number of days. The inputs are pursuant to the TPF Handling Agreements third-party processing and handling contracts between Tourmaline and the third parties who deliver their products to the TPF Facilities.
(3) Processing Revenue(3) is calculated as the product of: volume (Mcf) of natural gas delivered to the applicable facility per day, processing fee per Mcf, number of days and the Company's ownership interests in such facility, as those inputs are described in the Initial Facilities Volume Commitment Agreements, Initial Facilities CO&O Agreements, Glacier Volume Commitment Agreement, Glacier CO&O Agreement, Banshee Volume Commitment Agreement and Banshee CO&O Agreement.

PROSPECTUS SUMMARY

The following is a summary of the principal features of the Company and the Offering and should be read together with the more detailed information and financial data and statements appearing elsewhere in this prospectus. Reference is made to the "Glossary" and "Abbreviations" for the meaning of certain defined terms and abbreviations.

Summary of the Offering

Selling Shareholder:	Tourmaline Oil Corp.
Issuer:	Topaz Energy Corp.
Proposed TSX Symbol:	"TPZ".
Offering:	$252.5 million ($285 million if the Over-Allotment Option is exercised infull). See "Plan of Distribution".
Treasury Offering:	$217.5 million ($250 million if the Over-Allotment Option is exercised infull). See "Plan of Distribution".
Secondary Offering:	$35 million. See "Plan of Distribution".
Over-Allotment Option:	The Company has granted to the Underwriters the Over-Allotment Option,exercisable at the Underwriters' sole discretion at any time, in whole or inpart, from time to time, until 30 days after Closing, to purchase, at theOffering Price, up to an additional •Common Shares, representing 15% ofthe aggregate number of Common Shares offered by the Company under thisprospectus, to cover over-allotments, if any, and for market stabilizationpurposes. See "Plan of Distribution" and "Principal Shareholders andSelling Shareholder".
Common Shares:	Each Common Share entitles the holder to one vote at all meetings ofshareholders and, subject to the rights of holders of preferred shares of theCompany, to receive any dividend declared by the Company on the CommonShares and to receive the remaining property of the Company upondissolution. See "Description of Share Capital".
Common Shares OutstandingFollowing Closing:	•Common Shares outstanding following Closing (•Common Shares if theOver-Allotment Option is exercised in full).
Use of Proceeds:	Topaz expects to receive approximately $•million in net proceeds from theTreasury Offering, after deducting the Underwriters' Commissions payableby the Company to the Underwriters in connection with the TreasuryOffering and the estimated expenses of the Offering, which are expected tobe $3 million.
	Topaz intends to use the net proceeds from the Treasury Offering foradditional royalty and energy infrastructure acquisitions as well as forworking capital and general corporate purposes.
	Topaz will not receive any of the proceeds from the Secondary Offering.
	See "Use of Proceeds".

Retained Interest: Upon Closing, Tourmaline will own •% of the outstanding Common Shares (•% if the Over-Allotment Option is exercised in full). See "Principal Shareholders and Selling Shareholder".

Dividend Policy: Topaz intends to use the majority of its free cash flow to pay dividends to shareholders and the Company has a long-term payout ratio target of 60- 90%. The Board has established a dividend policy pursuant to which the Company intends to pay an annual dividend in the amount of $0.80 per Common Share on a quarterly ($0.20 per share) basis**,** which represented a payout ratio of approximately 84% for the six months ended June 30, 2020. The Company declared a dividend of $0.20 per share, to shareholders of record on September 15, 2020, to be paid on September 30, 2020. Following Closing, the next scheduled dividend will be for the quarter ending December 31, 2020 and is expected to be paid on or about December 31, 2020 to shareholders of record on December 15, 2020 in the amount of $0.20 per Common Share. The payment of dividends is not guaranteed and the amount and timing of any dividends payable is at the discretion of the Board. See "Dividend Policy" and "Risk Factors — Risks Relating to the Offering and Common Shares — Cash Dividend Payments are Not Guaranteed".

Standstill: The Company has agreed that, subject to certain exceptions, it will not, directly or indirectly, without the prior written consent of the Underwriters, which consent shall not be unreasonably withheld, issue, or offer, grant any option, warrant or other right to purchase or agree to issue or sell, or otherwise lend, transfer, assign, pledge or dispose of, in a public offering or by way of private placement or otherwise, any equity securities of the Company or other securities convertible into, exchangeable for, or exercisable into Common Shares or other equity securities of the Company, or agree to do any of the foregoing or publicly announce any intention to do any of the foregoing, for a period of 180 days from the date of Closing. See "Plan of Distribution — Standstill".

Risk Factors: An investment in Common Shares is subject to a number of risk factors that should be considered carefully by a prospective investor. Cash dividends by the Company are not guaranteed and will be based, in part, upon the earnings of the Company, which are susceptible to a number of risks. These risks and other risks associated with an investment in the Common Shares include, but are not limited to: (i) risks related to the Company's business, industry and operating environment, including: dependence on working interest owners and/or operators of the GORR Lands and Infrastructure Assets; third-party exploration, development and production risks; reserves estimates associated with the GORR Lands; marketability and price of crude oil and natural gas; risks related to the accessibility, availability, proximity and capacity of gathering, processing and pipeline systems; the Company's limited operating history, transition and management of growth and reliance on key personnel; and estimates of future cash flow and financial and production information; (ii) risks relating to the Company's relationship with Tourmaline, including: Tourmaline's ability to exert significant influence on the Company through its voting rights, pursuant to the terms of the Governance Agreement and the provision of certain services by Tourmaline to the Company under the Management Services Agreement; conflicts of interests with Tourmaline; the ability to recover indemnification from Tourmaline under the Initial Acquisition Agreement and other agreements; and future changes in the relationship with Tourmaline; and (iii) risks relating to the Offering and the Common Shares, including: the absence of a public market for the Common Shares; potential volatility in the market price of the Common Shares; that cash dividends on the Common Shares are not guaranteed and could fluctuate; and the negative impact of additional sales or issuances of Common Shares.

Prospective investors should carefully consider the information set forth under the heading "Risk Factors" and the other information included in this prospectus before deciding to invest in Common Shares.

The Company's Business

Topaz's objective is to generate free cash flow growth through indirect oil and gas and infrastructure investment at a relatively low-risk and low cost to the Company. Topaz seeksto achieve this objective by selectively pursuing strategic business development opportunities with high-quality partners that are accretive to Topaz. Topaz's investment strategy is expected to enable the Company's strategic partners to advance their own growth, resulting in enhanced sustainability for Topaz.

The Company's high-quality assets and associated revenues are comprised of:

(i) the Royalty Assets, which generate the Company's Royalty Production Revenue; and
(ii) the Infrastructure Assets, which generate the Company's Processing Revenue and Other Income.

The Company's business model is designed to provide investors with exposure to among the best attributes from each of the royalty and energy infrastructure segments: (i) Royalty Production Revenue (net of a 1% marketing fee on the developed lands) with no associated operating or capital costs and underpinned by Tourmaline's self-funded development; (ii) Processing Revenue with minimal associated operating and maintenance capital costs and underpinned by long-term take-or-pay contracts with high-quality counterparties; (iii) Other Income with no associated operating or capital costs; (iv) modest corporate overhead costs; (v) long-term horizon before income tax would be payable; and (vi) transparent outlook to the Company's opportunistic growth prospects.

See "The Company's Business" and "Growth Strategy".

Strategic Relationships with High-Quality Counterparties

The Company has strategic relationships with high-quality counterparties that have medium to large-scale, low cost and reliable business models with strong ESG profiles, significant growth potential and capital discipline.

A key part of Topaz's long-term business strategy is seeking alignment with counterparties who are low-cost operators with significant land holdings and long-term growth prospects in prolific exploration and production regions or plays. The Company's counterparties are characterized by having strategic locations, size, concentration and other attributes in order to achieve operating cost, reserve recovery, deliverability and production efficiencies through medium to large-scale, repeatable capital exploration and development programs. Topaz's unique, low risk, income-oriented business model positions the Company to be a partner of choice for high quality operators seeking to access capital to achieve their business plans in the current environment.

Tourmaline

Tourmaline is an investment grade Canadian senior E&P company focused on providing strong and predictable longterm growth and a steady return to shareholders through an aggressive exploration, development, production and acquisition program in the WCSB by building its extensive asset base in its three core exploration and production areas and exploiting and developing these areas to increase reserves, production and cash flows at an attractive return on invested capital. Tourmaline seeks to execute this strategy by: aggressively drilling and developing its extensive undeveloped land position; adopting and employing advanced drilling and completion techniques; pursuing strategic acquisitions with significant potential synergies; undertaking wildcat exploration drilling for new pool discoveries and enhancing returns by focusing on operational and cost efficiencies. Tourmaline also uses principally 3D seismic data to identify drilling locations for multi-stage fracture stimulations of vertical and horizontal wells. As publicly stated by Tourmaline, it strives to be one of the lowest cost producers in the WCSB in order to accomplish its business strategy in volatile economic and commodity price environments.

Advantage

Advantage is engaged in the business of natural gas, oil, and liquids exploitation, development, acquisition and production in the Province of Alberta. Advantage's current exploitation and development program is focused on its liquids-rich natural gas and oil Montney resources in the Glacier, Valhalla, Pipestone/Wembley and Progress areas of Alberta. Although Advantage has a significant capital development program, it also actively evaluates growth opportunities through crude oil and natural gas asset acquisitions, as well as through corporate acquisitions. Advantage has indicated that it plans to target acquisitions that support and augment its Montney development and long-term strategy.

See "The Company's Business – Strategic Relationships with High-Quality Counterparties".

Investment Highlights

Management believes that an investment in the Common Shares provides investors with a number of unique benefits and opportunities that arise from a free cash flow generating royalty and energy infrastructure business that is underpinned by its strategic relationship with the largest natural gas producer in Canada, Tourmaline, an investment grade senior Canadian E&P company, with an award-winning track record of environmental sustainability and among the lowest GHG emissions intensity in the Canadian senior upstream sector, and that the following competitive strengths highlight Topaz's low-cost, scalable business model.

Unique large-scale exposure to high-quality royalty and infrastructure assets

The Company has strategically selected and located GORR and infrastructure assets underpinned by low cost, sustainable E&P operations. Topaz will be uniquely positioned as the only publicly-traded royalty and infrastructure company with 2019 adjusted pro forma revenue composition of approximately 50% from the GORR Interests and 50% from the Infrastructure Assets. With GORR Interests on approximately 2.3 million gross acres and 175 MMcf/d of plant ownership interest, the Company's asset base is substantial. The GORR Interests are principally associated with Tourmaline, the largest natural gas producer in Canada and among the lowest cost producers in North America with an award-winning track record of environmental sustainability and among the lowest GHG emissions intensity in the Canadian senior upstream sector. Tourmaline provides transparent disclosure in its public disclosure that provides Topaz with insight into organic growth from the Tourmaline GORR Interest. The Company's Infrastructure Assets are comprised of non-operated working interests, with associated long-term fixed take-or-pay contracts, in three natural gas processing facilities operated by Tourmaline and one operated by Advantage. The Company considers Tourmaline and Advantage to be high quality counterparties due to their track records of environmental sustainability, efficient growth and strong operational execution, conservative capitalization and quality of oil and natural gas assets and strong management and corporate governance. Topaz has a balanced portfolio of stable infrastructure revenue and a growing base of GORR production with commodity price upside.

(1) See "GORR Lands".
(2) See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Glacier Gas Plant Acquisition".
(3) See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Banshee Gas Plant Acquisition".
(4) See "Clearwater GORR Interest".
(5) See "Analysis of Adjusted Pro Forma Revenue, EBTIDA and EBITDA Margin".
(6) See "Notice to Investors – Non-GAAP Financial Measures".

Strategic relationship with investment grade rated sponsor underpins strong growth prospects

Tourmaline is prominent in Canada's premium gas plays, consistently providing long-term growth guidance and has delivered production and reserves growth through organic development and acquisitions since its inception in 2008. Tourmaline's production is significantly weighted to natural gas and Tourmaline is currently Canada's largest natural gas producer with an award-winning track record of environmental sustainability and among the lowest GHG emissions intensity in the Canadian senior upstream sector. In addition to producing assets, Tourmaline also maintains an estimated 1.2 million gross acres of undeveloped land, upon which its management team has identified over 14,000 future drilling locations on the Tourmaline GORR Lands, which includes 2,225 booked locations on the Tourmaline GORR Lands included in the Tourmaline Consolidated Reserve Report. Tourmaline owns and operates its critical processing facilities which enables its business to benefit from low-cost, sustainable operations resilient to commodity price volatility. Tourmaline's exploration and production business is well established with 1.5 Bcf/d of processing capacity, a strong balance sheet and a strong LMR of 9.53 at September 5, 2020 which enables it to direct the majority of its capital investment toward further development and growth of its business. Tourmaline's average production for the first six months of 2020 was 303,860 Boe/d and Tourmaline currently forecasts annual average production of between 305,000 and 310,000 Boe/d for 2020, with an estimated exit 2020 production between 322,500 and 327,500 Boe/d. Tourmaline reported 2.6 billion Boe of reserves at December 31, 2019. As at August 31, 2020, Tourmaline's aggregate borrowing capacity was approximately $2.9 billion and on September 9, 2020 it announced it was assigned an issuer rating of BBB with a stable trend from DBRS Limited. This public investment grade credit rating validates the overall financial health of Tourmaline as a stable, low-risk, senior Canadian E&P company.

Topaz's royalty business is differentiated from its competitors given it currently has only one primary royalty payor; furthermore, Tourmaline provides transparent disclosure, has a proven track record of delivering value to its shareholders through the growth of its business and has the scale/cost profile for self-funded growth and free cash flow generation. Topaz anticipates that the Tourmaline GORR Interest will generate growth through Tourmaline's further development of existing acreage with potential future upside provided through exposure to commodity prices. Topaz's strategic relationship with Tourmaline provides potential acquisition growth opportunities for Topaz. See "Growth Strategy".

(1) As of August 31, 2020.
(2) August 25, 2020 Bloomberg consensus.
(3) Inventory life at a 2020 pace of development. See "Notice to Investors – Forward-Looking Statements".
(4) Based on information provided to the Company by Tourmaline.
(5) Source: Tourmaline Consolidated Reserve Report*.* See Appendix "B" to this prospectus.
(6) Tourmaline drilling inventory on the Tourmaline GORR Lands of 14,145 locations based on Tourmaline internal estimate which includes 2,225 booked locations derived from the Tourmaline Consolidated Reserve Report.
(7) Assumes a $217.5 million Treasury Offering and a $35 million Secondary Offering at $14 per share; does not include dilutive securities (Options).

Ability to strategically execute M&A in an opportunity rich environment

The Company's business model is supported by its conservative capital structure which has a net positive cash position an undrawn $125 million credit facility, and significant free cash flow which, together, provide financial flexibility. See "Credit Facility". Management expects that the Company will utilize its credit facility for transactional purposes and its business model is focused on maintaining low to no leverage. Topaz's business model and financial position uniquely positions the Company to strategically execute M&A in the current, opportunity rich environment. The Company is focused on leveraging strategic relationships with existing and prospective high-quality counterparties to acquire additional low risk, stable and predictable revenue generating assets which are accretive to the Company while maintaining a strong ESG profile. See "Growth Strategy".

Predictable, high free cash flow margin supports attractive, sustainable dividend

The Company's revenue is generated through its ownership of royalty and infrastructure assets. The Royalty Production Revenue provides a significant and predictable free cash flow margin as the only associated cost is a 1% marketing fee paid to Tourmaline who currently markets the volume on behalf of Topaz. The Company is entitled to receive a gross royalty on production without incurring the related operating, finding and development, maintenance and other capital costs, including environmental liabilities or reclamation obligations that are typically associated with petroleum and natural gas development. The Company expects that the free cash flow margin attributed to its Tourmaline GORR Interest will continue to be 99%, after taking into account the marketing fee paid to Tourmaline to market its royalty production volume. Based on Tourmaline's consistent production growth since its inception in 2008 and its recent financial and operational performance, the Company anticipates its royalty production volume to grow over time. The Tourmaline GORR Interest provides potential additional revenue growth through commodity price exposure. The Company's Processing Revenue, which includes long-term fixed take-or-pay commitments, provides stable revenue that is resilient to commodity price volatility and is only modestly burdened by operating and capital costs. Topaz's revenue composition and low cost structure generates stable free cash flow, which supports a reliable and sustainable dividend, with Topaz's target payout ratio being 60 to 90%.

(1) Topaz Free Cash Flow Margin for the six months ended June 30, 2020 is 89%. See "Selected Historical and Pro Forma Financial and Production Information". "Free Cash Flow Margin (by revenue stream) is calculated using the audited financial results for the six months ended June 30, 2020 and does not include corporate level G&A, interest expense or realized gains/losses on financial instruments.

(2) See "Notice to Investors – Non-GAAP Financial Measures".

(1) See "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin".
(2) Share issuance assumed at $14 per Common Share for the calculation of Pro Forma dividend.
(3) Infrastructure Revenue includes Processing Revenue and Other Income.
(4) Adjusted Pro Forma EBITDA, with Royalty Production Revenue adjusted to reflect realized commodity prices received for oil and condensate (C$35.92/bbl and C$44.30/bbl, respectively, for the six months ended June 30, 2020). For illustrative purposes only, the Royalty Production Revenue is also adjusted to present illustrative results using different AECO prices as shown.

Environmental, social and governance (ESG) focus and leadership

Topaz has established strong ESG focused business practices and is committed to continuous improvement regarding its current business and future acquisitions. The Topaz royalty and energy infrastructure revenue streams are generated primarily from assets operated by natural gas producers with some of the lowest GHG emissions intensity in the Canadian senior upstream sector, including Tourmaline, which has received awards for environmental sustainability and conservation efforts. Certain of these producers have set long-term emissions reduction targets and continue to invest in green technology to improve environmental sustainability. Topaz has developed strategic investment criteria, underpinned by alignment with high quality counterparties as Topaz believes that financial strength and size are fundamental to providing environmental leadership which enables investment in new technology and operational scale to make positive and meaningful environmental impacts. The Company has established the following attributes which provide the foundation for a sustainable business:

Majority of revenue from counterparties with strong environmental performance and among the lowest GHG emissions intensity in the Canadian senior upstream sector;
The Company and its Board are attentive to diversity and independence; Topaz has established an independent valuation framework whereby potential transactions between Topaz and Tourmaline are reviewed and approved exclusively by independent directors using comparable third-party and/or market transactions to assess the business and valuation characteristics of the potential transaction. See "Corporate Governance – Meetings of Independent Directors";
Its executive compensation structure is directly aligned with its shareholders;
Topaz has no direct oil and gas production and therefore alignment with industry ESG leaders is paramount to its ESG foundation and further supports Topaz's focus on counterparty quality as it evaluates future growth opportunities;
Topaz's Infrastructure Assets are relatively new and Topaz aligns its business with operators who Management believes follow industry best practice maintenance, environmental and health and safety protocols; and
Topaz is principally exposed to high-quality, long-life, lower emission natural gas assets. The majority of Topaz's revenue is generated indirectly through natural gas production; by displacing coal, natural gas is one of the best ways to reduce global CO2 emissions. (1)

(1) Source: EIA website (https://www.eia.gov/tools/faqs/faq.php?id=73&t=11).

Experienced, aligned management and board of directors

The Company's management and directors have a strong track record of creating shareholder value. The Company's executive officers have combined, relevant experience of over 36 years in the oil and gas industry, including significant experience in growth and development of public companies through organic growth and mergers and acquisitions. The members of the Board have a broad range of experience in managing and overseeing publicly-listed companies and developing long-term industry relationships, including expertise in a diverse range of fields including exploration and production; capital markets, corporate finance and investment; accounting; environmental, social and governance; business development and strategy; and human resources. Both Management and members of the Board have extensive prior experience in actively developing and managing energy assets in public companies. Topaz's management and board of directors are strongly aligned with Topaz, with insider representation, excluding Tourmaline, of approximately 9.5% of Topaz, before giving effect to the Offering.(1) See "Directors and Executive Officers".

Note:

(1) Represents 8,836,156 Common Shares owned by shareholders represented by Board members, ARC Energy Fund 9 and Canoe Financial as well as officers and directors of Topaz and Tourmaline.

Proactively Monitoring and Managing its royalty and energy infrastructure assets

The Company intends to proactively monitor and manage its portfolio of royalty and energy infrastructure assets through:

Compliance Programs**:** The Company will benefit from a defined compliance process, including a well-organized audit program designed to ensure: (i) working interest owner compliance with GORR contract terms, including monitoring of expiring Crown leases; (ii) fulfillment of contractual obligations by third parties; and (iii) accurate accounting and

collection of Royalty Production Revenue, Processing Revenue and Other Income by the Company. Management has significant experience working in the petroleum and natural gas industry and plans to hire technical accounting staff with extensive experience in the reporting, calculation and payment of production volumes to manage its compliance and accounting audit processes. The technical accounting staff are expected to have experience in using applications to merge public data related to wells, production and facility volumes by petroleum substances and posted commodity prices, with specific contract terms. Compliance audit reviews are expected to be completed on a regular basis to ensure that the Company's counterparties are compliant with their contractual obligations. The use of technology by the Company will be an effective and efficient tool for managing large amounts of data and is expected to minimize general and administrative costs for the Company. Furthermore, the Company's existing GORR and infrastructure contractual arrangements are structured to result in a low administrative burden to the Company given that they are based upon market indexed pricing with no deductions provided to the operators (GORR) and supported by long-term, fixed take-or-pay commitments (infrastructure). The Company intends to structure future potential contractual agreements in a similar manner.

Strong Relationship Management**:** As the Company is an indirect investor in petroleum and natural gas development, the need for strong relationships with counterparties is important for Topaz's growth. Building and maintaining industry relationships to foster mutual respect and understanding will assist the Company in the resolution of compliance related matters and enhance the Company's ability to gain knowledge, data and insight into development of the Royalty Assets and capacity utilization of its Infrastructure Assets, and is expected to contribute towards securing new capital investment by third parties and future acquisition opportunities. Management's extensive experience, including industry relationships developed to date in the petroleum and natural gas industry, will strategically benefit Topaz's sustainability.

See "Investment Highlights".

Investors should review the additional information relating to forward-looking statements and the risks associated with the business, financial condition, results of operations and prospects of the Company under the headings "Notice to Investors – Forward-Looking Statements" and "Risk Factors" in this prospectus.

Growth Strategy

Topaz seeks to achieve its objective of generating high free cash flow growth through indirect oil and gas and energy infrastructure investment by selectively pursuing strategic business development opportunities that are relatively lowrisk and accretive to the Company. Topaz focuses its growth strategy in the following primary areas.

Organic Growth of Royalty Production Revenue from the Royalty Assets

The Company anticipates that it will generate increased Royalty Production Revenue supported by its strategic, aligned relationship with Tourmaline. Tourmaline provides transparent disclosure, has a proven track record of delivering value to its shareholders through the growth of its business and has the scale and cost profile for self-funded growth and free cash flow generation. Topaz anticipates that the Tourmaline GORR Interest will generate growth through Tourmaline's continued self-funded development of existing acreage with potential future upside provided through its exposure to primarily natural gas commodity prices.

Pursue Accretive Strategic Acquisitions

The Company is focused on acquiring additional low-risk, stable and predictable revenue generating assets which are accretive to Topaz, through leveraging its strategic relationships with its existing and prospective high-quality counterparties while maintaining a strong ESG profile. Management considers a number of factors in the evaluation of potential strategic investments, including but not limited to:

Asset quality**:** royalty interest acquisitions that have substantial resources and low-risk organic growth potential and infrastructure acquisitions that service high quality, low-risk, resources in order to ensure sustainability and surety of long-term revenue streams;

Disciplined capital allocation**:** investment return focused on continually improving sustainability to support long-term growth of the dividend; and

Potential to incentivize drilling activity: the Company will utilize various structure arrangements such as drilling commitments with fit-for-purpose terms (including customized royalty rates, obligations, commitment periods and incentives), tailored to the varying risk levels inherent in thirdparty exploration or development activity, in an effort to enhance the economics available to such counterparties. Through such arrangements, the Company expects to be able to stimulate activity on incremental GORR lands acquired and generate additional revenue for the Company.

Topaz will pursue royalty and energy infrastructure acquisitions from Tourmaline and other high-quality counterparties as a part of its growth strategy which could include:

Assets that may be acquired by Tourmaline in the future: As the largest producer of natural gas in Canada with a strong balance sheet and ample liquidity, Tourmaline is well positioned to be an industry consolidator, providing a pipeline of potential future royalty or infrastructure asset sales to Topaz;

Additional Tourmaline assets: Interests in assets acquired by Tourmaline subsequent to the formation of Topaz in November 2019 or opportunities to acquire ownership of certain infrastructure that Topaz does not have existing ownership interest in. Since Topaz's formation in November 2019, Tourmaline has acquired over 210,000 net acres of prospective acreage, on which Topaz does not own gross overriding royalty interests. To support its strong commitment to ESG, Topaz has established an independent valuation framework to assess potential transactions with Tourmaline; and

Third-party assets: Topaz will continue to opportunistically pursue royalty and infrastructure acquisitions with other high-quality counterparties. Topaz has developed strategic investment criteria and will pursue royalty interest acquisitions that have substantial resources, operated by high quality counterparties, which have organic growth potential. Topaz will pursue high quality infrastructure acquisitions, partnering with operators to secure long-term take-or-pay contracts which generate stable revenues.

See "Growth Strategy".

The Company's Assets

Strategic Location of the Assets

The Company's primary assets are strategically located in the most geologically prolific areas within the WCSB: the Alberta Deep Basin, the NEBC Montney and the Peace River High Triassic Complex. Topaz's royalty production is sourced from these three areas, with natural gas comprising over 90% of its total royalty production. Topaz's Infrastructure Assets process natural gas in the Alberta Deep Basin and the Montney. Topaz has significant exposure to economic natural gas assets, complemented by the remainder of its production volume which is comprised of light oil and condensate which incur significantly lower production costs than heavy oil. The Company also owns a gross overriding royalty on future production from undeveloped land strategically located in the Clearwater area in Alberta, which is a rapidly emerging oil play with appealing economic and environmental characteristics including decreased land usage with the use of multi-leg drilling, and minimal water and no sand requirements as the completion operations do not require fracture stimulation.

In the Alberta Deep Basin, Tourmaline has drilled over 800 gross natural gas wells since inception. Tourmaline is the largest producer in the Alberta Deep Basin with 2020 average production estimated at approximately 163,000-168,000 Boe/d. Tourmaline's goal is to be one of the lowest-cost, most efficient operators in the Alberta Deep Basin, and Tourmaline plans to optimize and systematically continue to further reduce costs of operating the Alberta Deep Basin assets. To date, Tourmaline has drilled over 450 Montney multi-stage fracture-stimulated horizontal natural gas wells in NEBC. Tourmaline's 2020 – 2021 two-year development plan for the Gundy CK Montney asset includes continuing to apply drilling and completion practices developed in the Groundbirch/Sunrise/Dawson area in order to continue to reduce development costs, improve efficiencies and raise estimated ultimate recoveries (EUR). Tourmaline's Montney drill and complete capital costs are amongst the lowest in the industry. Tourmaline has drilled over 340 horizontal oil wells to date in the Peace River High Triassic Complex and plans to continue to utilize new technology to improve efficiencies. The continued advancement of technology and cost reduction initiatives is beneficial for Topaz as it results in capital development efficiency leading to higher potential growth of its royalty production asset base.

Set forth below is a map outlining the location of the Company's assets.

See "The Company's Assets – Strategic Location of the Company's Assets".

Description of the Royalty Assets

Topaz has identified value drivers for its royalty business which it believes to be important success factors for sustainability and profitability. These include the quality of the underlying acreage (prospective and de-risked being primary important attributes), profitable assets (low cost and resilient to commodity price fluctuations), production growth (ample resource and working interest owner financial capacity to fund resource and production development), strong mineral rights (GORR interests which survive until land expiry), outlook transparency (the ability to confidently ascertain continued resource and production development), and favorable commodity exposure (supportive supply and demand fundamentals). Topaz believes that its royalty business has unique competitive advantages that encompass each of these value drivers.

The Royalty Production Revenue provides the Company with high margin free cash flow as the Company is entitled to receive a royalty on production on the Royalty Assets without incurring the related operating, finding and development, maintenance and other capital costs, environmental liabilities or reclamation obligations typically associated with petroleum and natural gas development.

See "The Company's Assets – Description of the Royalty Assets".

Description of the Infrastructure Assets

Topaz has identified value drivers for its energy infrastructure business which it believes to be important success factors for sustainability and profitability. These include fixed revenue contracts (guaranteed revenue streams which provide dividend sustainability), financially strong counterparties (creditworthiness to limit financial exposure and financial liquidity to fund future development which in turn provides long-term utilization of its energy infrastructure assets), attractive resources (economically viable petroleum and natural gas resources to ensure long-term asset utilization), strong assets (newly constructed, technologically advanced and low cost), growth potential (significant, economically viable underlying resources to support feedstock growth), and sustainability (low cost, commodity price resilient production). Topaz believes that its energy infrastructure business has unique competitive advantages that encompass each of these value drivers.

Topaz has (i) non-operated ownership interests in four natural gas processing plants in the WCSB with cumulative natural gas processing capacity of approximately 175 MMcf/d which are supported in part by long-term fixed fee takeor-pay commitments, and (ii) a contracted interest in a portion of certain third-party revenue generated at facilities owned by Tourmaline pursuant to crude oil and natural gas processing and handling agreements with third parties to which Tourmaline is a party. These interests generate the Processing Revenue and Other Income, respectively.

Topaz incurs its proportionate share of operating and capital costs, environmental liabilities and reclamation obligations with respect to the Infrastructure Assets underlying the Processing Revenue, other than with respect to the Glacier Gas Plant for which Advantage has agreed to incur the operating and maintenance capital expenditures for the duration of the Glacier Gas Plant Volume Commitment Agreement, which is fifteen years from July 1, 2020, as described further under "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Glacier Plant Acquisition". Topaz is not responsible for operating or capital costs, environmental liabilities or reclamation obligations with respect to any of the facilities underlying the Other Income.

The Company is entitled to receive third-party revenue, including but not limited to, processing, compression and water handling revenue, generated at multiple facilities owned by Tourmaline pursuant to the TPF Handling Agreements. These facilities include natural gas processing plants, crude oil batteries, pipelines, water disposal facilities, compressor stations and other miscellaneous facilities associated with the handling of crude oil, natural gas and natural gas liquids. The facilities are located across all three of Tourmaline's core operating areas and are operated by Tourmaline. Topaz does not have an ownership interest in the underlying assets.

See "The Company's Assets – Description of the Infrastructure Assets".

The Company

Topaz's current business was established in November 2019 with the acquisition of the Initial Assets pursuant to the Initial Assets Purchase and Sale Agreement for consideration consisting of $194.5 million in cash and 58,049,494 Common Shares. The cash portion of the consideration of the Initial Acquisition was funded by the 2019 Equity Financing.

Prior to the completion of the Initial Acquisition, the Company (named Exshaw Oil Corp. before November 8, 2019) was a subsidiary of Tourmaline engaged in the upstream oil and gas exploration and production business since 2006. On November 12, 2019, the Company completed the E&P Asset Disposition resulting in the sale of all of the E&P Assets to Tourmaline.

On July 2, 2020, the Company completed the Glacier Gas Plant Acquisition, acquiring a 12.5% ownership interest in the Glacier Gas Plant for cash consideration of $100.0 million, before customary adjustments. In connection with the Glacier Gas Plant Acquisition, the Company and Advantage entered into the Glacier Volume Commitment Agreement, a 15-year volume take-or-pay commitment agreement whereby the Company earns a fixed natural gas processing fee of $0.66/Mcf for a fixed volume of 50 MMcf/d (representing 100% of Topaz's share of capacity in the Glacier Gas Plant), which equates to incremental annual cash flow of $12.0 million for the Company. The Company is not responsible for operating or maintenance capital costs for its proportionate share of ownership in the Glacier Gas Plant during the term of the 15-year Glacier Volume Commitment Agreement.

In early July 2020, the Company completed the 2020 Equity Financing. Proceeds from the 2020 Equity Financing were used to finance a portion of the Glacier Gas Plant Acquisition as well as the Banshee Gas Plant Acquisition and the Clearwater GORR Acquisition.

On September 1, 2020, the Company completed the Banshee Gas Plant Acquisition, acquiring a 25% ownership interest in the Banshee Gas Plant for cash consideration of $52.5 million, before customary adjustments. In connection with the Banshee Gas Plant Acquisition, the Company and Tourmaline entered into the Banshee Volume Commitment Agreement, a 15-year volume commitment agreement whereby the Company earns a fixed natural gas processing fee of $0.60/Mcf for a fixed take-or-pay volume of 25 MMcf/d, which equates to incremental annual cash flow of $5.5 million for the Company. The Company also generates Processing Revenue attributed to natural gas processing services provided to Tourmaline, on a fee-for-service basis in respect of its remaining share of plant capacity. Any processing revenue attributable to natural gas processing services provided to third parties (excluding Tourmaline) is allocated to the Company pursuant to the TPF Revenue Interest Agreement. The Company is responsible for its 25% ownership interest share of operating and maintenance capital costs incurred for the Banshee Gas Plant.

On September 1, 2020, the Company completed the Clearwater GORR Acquisition acquiring the Clearwater GORR Interest.

The following diagram illustrates the organizational structure and approximate Common Share ownership of the Company on Closing.

Note:

(1) Assumes no exercise of the Over-Allotment Option. If the Over-Allotment Option is exercised in full, Tourmaline will hold •% of the issued and outstanding Common Shares, with public shareholders holding •%.

The Company's head office is located at Suite 3100, 250 6th Avenue SW, Calgary, Alberta T2P 3H7 and its registered office is located at Suite 2400, 525 8th Avenue SW, Calgary, Alberta T2P 1G1.

See "The Company".

Summary of Reserves Associated with the Tourmaline GORR Lands

The summary of reserves data set forth below is based upon an evaluation by GLJ and Deloitte as set forth in the Topaz Reserve Report. An average of the GLJ Price Forecast, Sproule Price Forecast and McDaniel Price Forecast was used in the Topaz Reserve Report. The reserves data summarizes the crude oil, natural gas and NGL reserves associated with the Tourmaline GORR Lands and the net present values of future net revenue for those reserves and the Infrastructure Assets (excluding the Company's interests in the Glacier Gas Plant and the Banshee Gas Plant, as those interests were acquired subsequent to the effective date of the Topaz Reserve Report) using forecast prices and costs. References to NGL in the reserves data includes only condensate and pentane as other NGL are excluded from the Tourmaline GORR Interest. The reserves data complies with the requirements of NI 51-101. Actual crude oil, natural gas and NGL reserves may be greater than or less than the estimates provided in the Topaz Reserve Report. See "Reserves and Other Oil and Gas Information" and "Risk Factors". Also, as the Company does not hold any working interests in the Tourmaline GORR Lands, the Company will not be responsible for any capital costs associated with the Tourmaline GORR Lands and, as such, the evaluation of reserves data does not include any undeveloped reserves.

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2019 Forecast Prices and Costs(1)

	Light & Medium CrudeOil		Conventional NaturalGas		Shale Natural Gas		Natural Gas Liquids		Total Oil Equivalent
Reserves Category	CompanyGross(Mbbls)	CompanyNet(Mbbls)	CompanyGross(MMcf)	CompanyNet(MMcf)	CompanyGross(MMcf)	CompanyNet(MMcf)	CompanyGross(Mbbls)	CompanyNet(Mbbls)	CompanyGross(MBoe)	CompanyNet(MBoe)
Proved Producing	0	356	0	55,002	0	30,580	0	890	0	15,509
Proved Developed Non-Producing	0	48	0	3,128	0	6,778	0	143	0	1,842
Proved Undeveloped	0	0	0	0	0	0	0	0	0	0
TotalProved	0	403	0	58,130	0	37,358	0	1,033	0	17,351
Total Probable	0	183	0	18,089	0	12,557	0	361	0	5,652
Total Proved Plus Probable	0	586	0	76,220	0	49,915	0	1,394	0	23,003

* Numbers may not add due to rounding.

(1) Gross reserves represent the working interest share before deduction of any royalty obligations and without including any royalty interests.

(2) Net reserves represent the working interest share after deduction of royalty obligations, plus royalty interests in production or reserves.

(3) The Company differs from typical oil and natural gas producers in that all of its interests in reserves are royalty interests with no associated working interests. As a result, there are no gross reserves associated with the Tourmaline GORR Lands, which may hinder comparison of the Company's reserves with others in the oil and natural gas industry.

(4) Conventional natural gas includes by-products but excluding solution gas.

(5) Light and medium crude oil includes solution gas and other by-products.

Notes:

Net Present Values of Future Net Revenue ($000s)

	Before Income Taxes Discounted at(%/year)					After Income Taxes Discounted at (2)(%/year)				Unit Value BeforeIncome TaxDiscountedat 10%/year
Reserves Category	0	5	10	15	20	0	5	10	15	20	($/Boe)	($/Mcfe)
Proved Producing	680,305	500,168	394,088	325,888	279,035	680,305	500,168	394,088	325,888	279,035	25.41	4.24
Proved Developed Non-Producing	53,566	40,353	32,534	27,428	23,842	53,566	40,353	32,534	27,428	23,842	17.66	2.94
Proved Undeveloped	0	0	0	0	0	0	0	0	0	0	0.00	0.00
Total Proved	733,871	540,521	426,622	353,315	302,878	733,871	540,521	426,622	353,315	302,878	24.59	4.10
Total Probable	202,485	100,818	61,139	42,144	31,589	202,485	100,818	61,139	42,144	31,589	10.82	1.80
Total Proved Plus Probable
	936,357	641,339	487,761	395,459	334,467	936,357	641,339	487,761	395,459	334,467	21.20	3.53

Notes:

(1) Numbers may not add due to rounding.

(2) The after-tax net present value of the Company's oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider the Company's tax situation, or tax planning. It does not provide an estimate of the value at the company level for Tourmaline which may be significantly different.

Selected Historical and Pro Forma Financial and Production Information

The following selected historical financial information relating to the Initial Assets has been derived from the Topaz Financial Statements.

	Three months ended	Six months ended	Nov. 14 to
($000s except per share amounts)	June 30, 2020	June 30, 2020	Dec. 31, 2019(1)
Royalty production revenue	$ 11,935	$ 26,449	$ 9,832
Processing revenue	5,296	11,264	2,943
Other income	2,789	5,066	1,408
Realized loss on financial instruments	(188)	(188)	─
Unrealized loss on financial instruments	(637)	(552)	─
	19,195	42,039	14,183
Expenses
Operating	1,016	1,871	481
Marketing	122	212	98
General and administrative	1,249	2,243	1,331
Share-based compensation	204	353	25
Finance	62	64	2
Depletion and depreciation	18,612	41,805	11,671
	21,265	46,548	13,608
Net income (loss) from continuing operations	(2,070)	(4,509)	575
Deferred tax recovery	(945)	(2,150)	(78)
Net income (loss) from continuing operations	(1,125)	(2,359)	653

		$ (350)
17,385	38,205	12,273
17,445	38,265	12,273
		87%
159	271	2
16,000	32,000	─
$0.20	$0.40	─
		12,271
		87%
93%	84%	─
		697,234
148,745	148,745	20,767
149,180	149,180	20,767
(149,180)	(149,180)	(20,767)
	$24,23488%17,22687%793,323	$38,18490%37,93489%793,323

Selected Historical Financial Information from Continuing Operations**(1)** ($000s except per share amounts and %)

(1) Topaz commenced its current operations November 14, 2019, all subsequent financial results are presented as continuing operations. The Company's financial results prior to November 14, 2019 are presented as discontinued operations. Refer to the Topaz Financial Statements.
(2) See "Notice to Investors - Non-GAAP Financial Measures".
(3) Statement of financial position information is as of end of period.
(4) Weighted average Common Shares outstanding during the period.

See "Exemptions from Certain Disclosure Requirements".

The Alternative Financial Statements are comprised of: (i) the audited operating statements of Tourmaline containing the operating statements for the Initial Assets for the years ended December 31, 2017 and 2018 and the period from January 1, 2019 to November 13, 2019. The audited operating statements of Tourmaline present Tourmaline's gross historical interest in the assets comprising the Initial Assets, without adjustment to reflect the newly-created interests acquired by Topaz in such assets on November 14, 2019 pursuant to the Asset Acquisition (the "Initial Acquisition Operating Statements"); and (ii) the unaudited pro forma operating statements of Topaz that give effect to the acquisition of the Initial Acquisition Assets as if the Initial Assets were acquired on January 1 of each of 2019, 2018 and 2017 (the "Topaz Pro Forma Operating Statements"). The Topaz Pro Forma Operating Statements were derived from the Initial Acquisition Operating Statements to begin with the Initial Assets' gross petroleum and natural gas revenue, royalty expenses, other income, operating expenses and operating income included in the audited operating statements of Tourmaline for the period from January 1, 2019 to November 13, 2019 and for the years ended December 31, 2018 and 2017. The gross operating results were then adjusted to remove the petroleum and natural gas production revenue and royalties, as well as the working interest share of operating expenses and other income retained by Tourmaline, in order to calculate the net operating results attributed to the Initial Assets. Finally, the net operating results were adjusted to account for the petroleum and natural gas royalty interest and the take-or-pay volume commitment contractual arrangements which were entered in conjunction with the acquisition of the Initial Assets, as if the agreements had been in place effective January 1, of each year (see the Topaz Pro Forma Operating Statements included in Appendix "A" to this prospectus).

Selected Pro Forma Financial Information for the Initial Assets

The following selected pro forma financial information relating to the Initial Assets has been derived from the Topaz Pro Forma Operating Statements.

($000s)	Year endedDecember 31, 2019	Year endedDecember 31, 2018	Year endedDecember 31, 2017
Royalty production revenue	52,957	44,290	49,375
Processing revenue	21,587	21,793	21,654
Other income	13,219	20,310	21,401
	87,763	86,393	92,430
Expenses
Operating	(3,809)	(3,280)	(2,933)
Operating income	83,954	83,113	89,497

Selected Pro Forma Production Information for the Initial Assets

The following selected pro forma financial information relating to the Initial Assets has been derived from the Topaz Pro Forma Operating Statements.

	Year endedDecember 31, 2019	Year endedDecember 31, 2018	Year endedDecember 31, 2017
Average royalty production
Natural gas (Mcf/d)	56,514	52,182	48,834
Oil & condensate (Bbl/d)	691	621	515
Total (Boe/d)	10,110	9,318	8,654
Royalty production weighting (% natural gas)	93%	93%	94%
Realized commodity prices
Natural gas ($/Mcf)	$1.78	$1.52	$2.18
Oil ($/Bbl)	$65.65	$62.66	$58.64
Condensate ($/Bbl)	$69.03	$75.85	$65.23

Investors should read the above information together with: (i) the Alternative Financial Statements, including the related notes included in Appendix "A" to this prospectus; (ii) the supplemental production, oil and gas reserves and operational information in respect of the Tourmaline GORR Lands, which are prepared in accordance with the terms of the Exemptive Relief and included in Appendix "B" to this prospectus; and (iii) the sections entitled "Risk Factors" and "Management's Discussion and Analysis" included elsewhere in this prospectus.

Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin

The following summary has been prepared by the Company to provide management's best estimate of the revenue, other income, EBITDA and EBITDA margin that would have been generated by the Company's GORR Interests and Infrastructure Assets, had the interests, assets and their underlying contracts been in place effective January 1 of each year, subject to the adjustments noted below ("Adjusted Pro Forma Revenue", "Adjusted Pro Forma EBITDA", and "Adjusted Pro Forma EBITDA Margin", respectively). The Company's assumptions in preparing the foregoing analysis are set out in the notes below the table. Although many of these adjustments are estimates and are not objectively determinable, the Company believes that the table represents a reasonable estimate of the Company's revenue, other income, EBITDA and EBITDA margin for the years ended December 31, 2018 and 2019, had the interests, assets and their underlying contracts been in place effective January 1 of each year.

For the year ended Dec. 31, 2019($000s)	Pro FormaTopaz(1)	Glacier Gas PlantAcquisition(2)	Banshee Gas PlantAcquisition(3)	AdjustedPro Forma(4)
Royalty production revenue	$52,957	─	─	$52,957
Processing revenue	21,587	12,045	7,884	41,516
Other income	13,219	─	─	13,219
	87,763	12,045	7,884	107,692
Expenses
Operating expense	3,809	─	1,035	4,844
Net operating income	83,954	12,045	6,849	102,848
Adjusted Pro Forma EBITDA Adjustments:
Marketing expense(5)				530
General and administrative expense(6)				5,000
Total				5,530
Adjusted Pro Forma EBITDA(7)				97,318
Adjusted Pro Forma EBITDA Margin(8)				90%

(1) See the Topaz Pro Forma Operating Statements which were derived from (i) the Initial Acquisition Operating Statements, which reflect the gross petroleum and natural gas revenue, royalty expenses, other income, operating expenses and operating income for the period ending December 31, 2019; (ii) the Topaz Financial Statements; and (iii) the Initial Acquisition Agreements. Together, the information was then adjusted to reflect the estimated financial results had the Initial Acquisition Agreements been in place effective January 1 of each year. The pro forma Topaz amounts may not be indicative of the results that would have occurred if the events reflected had been in effect on the dates indicated, or of the results which may be obtained in the future (see the Topaz Pro Forma Operating Statements included in Appendix "A" to this prospectus).
(2) Pursuant to the Glacier Gas Plant Acquisition Agreement, Advantage has committed 50 MMcf/d take-or-pay volumes at a fixed fee of $0.66/Mcf for 15 years. Topaz will receive fixed annual Processing Revenue of approximately $12.0 million per year for the duration of the contract. Pursuant to the Glacier O&O Agreement, Advantage is responsible for all operating and maintenance capital expenditures for the duration of the Glacier Volume Commitment Agreement. See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Glacier Gas Plant Acquisition".
(3) Pursuant to the Banshee Gas Plant Acquisition Agreement, Tourmaline has committed 25 MMcf/d take-or-pay volumes at a fixed fee of $0.60/Mcf for 15 years. Topaz will receive fixed annual Processing Revenue of approximately $5.5 million per year. In addition, interruptible volume utilizing Topaz's remaining share of capacity is subject to a processing fee of $0.50/Mcf. Based on current and historical throughput volume of the Banshee Gas Plant for the past three years, Topaz estimated throughput of approximately 153 MMcf/d which results in annual incremental Processing Revenue of $2.4 million. Pursuant to the Banshee CO&O Agreement, Topaz and Tourmaline are responsible for capital and operating costs in proportion to their respective ownership interests, which for Topaz is 25%. Based on actual historical operating expenses incurred by Tourmaline in 2019 for the operation of the Banshee Gas Plant, Topaz's 25% share would be approximately $1.0 million. See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Banshee Gas Plant Acquisition".
(4) The Adjusted Pro Forma revenue, EBITDA and EBITDA margin may not be indicative of the results that would have occurred if the events reflected had been in effect on the dates indicated, or of the results which may be obtained in the future, however they provide Management's best estimate of the financial results of operations, had the Initial Acquisition Agreements, Glacier Gas Plant Acquisition Agreement and Banshee Gas Plant Acquisition Agreement all been in place effective January 1 of each year. See "Notice to Investors – Non-GAAP Financial Measures".
(5) The Company pays a marketing fee to Tourmaline in an amount equal to 1% of the royalty share proceeds as the royalty production volume is marketed with Tourmaline's production volume. The Company can elect to take in-kind its share of royalty production, if desired, at which time it would not be required to pay a marketing fee.
(6) Represents estimated annual G&A of $5.0 million per year, based in part on the actual G&A expenditures incurred during the six months ended June 30, 2020, plus estimated expenses for additional regulatory and reporting costs that the Company will incur on a continuing basis related to the requirements of the Company becoming a reporting issuer after Closing.
(7) Adjusted pro forma EBITDA represents the estimated pro forma EBITDA from the GORR Interests and Infrastructure Assets, had the interests, assets and the associated contracts been in place effective January 1 of each year, and as the revenue, other income and expenses would be determined in accordance with IFRS. See "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin". "Adjusted pro forma EBITDA" is defined as adjusted pro forma operating income plus any realized hedging gains less general and administrative expenses and any realized hedging losses. See "Notice to Investors – Non-GAAP Financial Measures".
(8) Adjusted pro forma EBITDA Margin is defined as Adjusted Pro Forma EBITDA divided by Adjusted Pro Forma Revenue (expressed as a percentage of Adjusted Pro Forma Revenue). See "Notice to Investors – Non-GAAP Financial Measures".

For the year ended Dec. 31, 2018($000s)	Pro FormaTopaz(1)	Glacier Gas PlantAcquisition(2)	Banshee Gas PlantAcquisition(3)	AdjustedPro Forma(4)
Royalty production revenue	$44,290	─	─	$44,290
Processing revenue	21,793	12,045	7,884	41,722
Other income	20,310	─	─	20,310
	86,393	12,045	7,884	106,322
Expenses
Operating expense	3,280	─	1,069	4,349
Net operating income	83,113	12,045	6,815	101,973
Adjusted Pro Forma EBITDA Adjustments:
Marketing expense(5)				443
General and administrative expense(6)				5,000
Total				5,443
Adjusted Pro Forma EBITDA(7)				96,530
Adjusted Pro Forma EBITDA Margin(8)				91%

(1) See the Topaz Pro Forma Operating Statements which were derived from (i) the Initial Acquisition Operating Statements, which reflect the gross petroleum and natural gas revenue, royalty expenses, other income, operating expenses and operating income for the period ending December 31, 2018; (ii) the Topaz Financial Statements; and (iii) the Initial Acquisition Agreements. Together, the information was then adjusted to reflect the estimated financial results had the Initial Acquisition Agreements been in place effective January 1 of each year. The pro forma Topaz amounts may not be indicative of the results that would have occurred if the events reflected had been in effect on the dates indicated, or of the results which may be obtained in the future (see the Pro Forma Operating Statements included in Appendix "A" to this prospectus).
(2) Pursuant to the Glacier Gas Plant Acquisition Agreement, Advantage will commit 50 MMcf/d take-or-pay volumes at a fixed fee of $0.66/Mcf for 15 years. Topaz will receive fixed annual Processing Revenue of approximately $12.0 million per year for the duration of the contract. Pursuant to the Glacier O&O Agreement, Advantage is responsible for all operating and maintenance capital expenditures for the duration of the Glacier Volume Commitment Agreement. See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Glacier Gas Plant Acquisition".
(3) Pursuant to the Banshee Gas Plant Acquisition Agreement, Tourmaline will commit 25 MMcf/d take-or-pay volumes at a fixed fee of $0.60/Mcf for 15 years. Topaz will receive fixed annual Processing Revenue of approximately $5.5 million per year. In addition, interruptible volume utilizing Topaz's remaining share of capacity is subject to a processing fee of $0.50/Mcf. Based on current and historical throughput volume of the Banshee Gas Plant for the past three years, Topaz estimated throughput of approximately 153 MMcf/d which results in annual incremental Processing Revenue of $2.4

million. Pursuant to the Banshee CO&O Agreement, Topaz and Tourmaline are responsible for capital and operating costs in proportion to their respective ownership interests, which for Topaz is 25%. Based on actual historical operating expenses incurred by Tourmaline in 2018 for the operation of the Banshee Gas Plant, Topaz's 25% share would be approximately $1.1 million. See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Banshee Gas Plant Acquisition".

(4) The Adjusted Pro Forma revenue, EBITDA and EBITDA margin may not be indicative of the results that would have occurred if the events reflected had been in effect on the dates indicated, or of the results which may be obtained in the future, however they provide management's best estimate of the financial results of operations, had the Initial Acquisition Agreements, Glacier Gas Plant Acquisition Agreement and Banshee Gas Plant Acquisition Agreement all been in place effective January 1 of each year. See "Notice to Investors – Non-GAAP Financial Measures".
(5) The Company pays a marketing fee to Tourmaline in an amount equal to 1% of the royalty share proceeds as the royalty production volume is marketed with Tourmaline's production volume. The Company can elect to take in-kind its share of royalty production, if desired, at which time it would not be required to pay a marketing fee.
(6) Represents estimated annual G&A of $5.0 million per year, based in part on the actual G&A expenditures incurred during the six months ended June 30, 2020, plus estimated expenses for additional regulatory and reporting costs that the Company will incur on a continuing basis related to the requirements of the Company becoming a reporting issuer after Closing.
(7) Adjusted pro forma EBITDA represents the estimated pro forma EBITDA from the GORR Interests and Infrastructure Assets, had the interests, assets and the associated contracts been in place effective January 1 of each year, and as the revenue, other income and expenses would be determined in accordance with IFRS. See "Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin". "Adjusted pro forma EBITDA" is defined as adjusted pro forma operating income plus any realized hedging gains less general and administrative expenses and any realized hedging losses. See "Notice to Investors – Non-GAAP Financial Measures".
(8) Adjusted pro forma EBITDA Margin is defined as Adjusted Pro Forma EBITDA divided by Adjusted Pro Forma Revenue (expressed as a percentage of Adjusted Pro Forma Revenue). See "Notice to Investors – Non-GAAP Financial Measures".

Relationship with Tourmaline

Following Closing, Tourmaline will continue to own the majority of the outstanding Common Shares. The Company has entered into the Governance Agreement with Tourmaline, pursuant to which Tourmaline has certain contractual rights relating to, among other things, the nomination of directors of the Company. See "Agreements with Tourmaline and Other Counterparties – Governance Agreement". Each director of the Company, including nominees of Tourmaline, is expected to comply with all applicable provisions of the ABCA relating to conflicts of interest. The Company and Tourmaline will be subject to all applicable corporate and securities laws with respect to related party transactions, conflicts of interest and use of material non-public information. The Company and Tourmaline have also entered into the Management Services Agreement pursuant to which Tourmaline provides or arranges for the provision of certain management and administrative services required by the Company, subject to termination in certain circumstances. See "Agreements with Tourmaline and Other Counterparties – Management Services Agreement". The interests of Tourmaline may conflict with those of other shareholders. See "Risk Factors – Risks Relating to the Company's Relationship with Tourmaline".

THE COMPANY'S BUSINESS

Overview

Topaz is a unique royalty and energy infrastructure company focused on generating free cash flow growth and paying reliable and sustainable dividends to its shareholders, through its strategic relationship with Canada's largest natural gas producer, Tourmaline, an investment grade senior Canadian E&P company, and leveraging industry relationships to execute complementary acquisitions from other high-quality energy companies, while maintaining its commitment to ESG best practices.

The Company's high-quality assets and associated revenues are comprised of:

(i) the Royalty Assets, which generate the Company's Royalty Production Revenue; and
(ii) the Infrastructure Assets, which generate the Company's Processing Revenue and Other Income.

The Company's business model is designed to provide investors with exposure to among the best attributes from each of the royalty and energy infrastructure segments: (i) Royalty Production Revenue (net of a 1% marketing fee on the developed lands) with no associated operating or capital costs and underpinned by Tourmaline's self-funded development; (ii) Processing Revenue with minimal associated operating and maintenance capital costs and underpinned by long-term takeor-pay contracts with high-quality counterparties; (iii) Other Income with no associated operating or capital costs; (iv) modest corporate overhead costs; (v) long-term horizon before income tax would be payable; and (vi) transparent outlook to the Company's opportunistic growth prospects.

Topaz does not directly conduct upstream petroleum and natural gas exploration and development operations.

The vast majority of the Company's GORR Interests and Infrastructure Assets are operated by Tourmaline while the Glacier Gas Plant is operated by Advantage. The Clearwater GORR Interest is operated by an arm's length E&P company. Topaz considers these operators high-quality as their business models are focused on ownership and operatorship of critical processing facilities which contributes to low-cost, sustainable exploration and production operations. Tourmaline has an investment grade credit rating. The combination of high-quality geographic location and high-quality counterparties, which have the financial strength to develop their resources, provides the foundation for the sustainability of Topaz's business model. See "The Company's Assets – Strategic Location of the Company's Assets" and "Strategic Relationships with High-Quality Counterparties" below.

Topaz's objective is to generate free cash flow growth through indirect oil and gas and infrastructure investment at a relatively low-risk and low cost to the Company. Topaz seeks to achieve this objective by selectively pursuing strategic business development opportunities with high-quality partners that are accretive to Topaz. Topaz's investment strategy is expected to enable the Company's strategic partners to advance their own growth, resulting in enhanced sustainability for Topaz. See "Growth Strategy".

Strategic Relationships with High-Quality Counterparties

Tourmaline

Tourmaline is an investment grade Canadian senior E&P company focused on providing strong and predictable long-term growth and a steady return to shareholders through an aggressive exploration, development, production and acquisition program in the WCSB by building its extensive asset base in its three core exploration and production areas and exploiting and developing these areas to increase reserves, production and cash flows at an attractive return on invested capital. Tourmaline seeks to execute this strategy by: aggressively drilling and developing its extensive undeveloped land position; adopting and employing advanced drilling and completion techniques; pursuing strategic acquisitions with significant potential synergies; undertaking wildcat exploration drilling for new pool discoveries and enhancing returns by focusing on operational and cost efficiencies. Tourmaline also uses principally 3D seismic data to identify drilling locations for multistage fracture stimulations of vertical and horizontal wells. As publicly stated by Tourmaline, it strives to be one of the lowest cost producers in the WCSB in order to accomplish its business strategy in volatile economic and commodity price environments.

Tourmaline commenced active operations in the fall of 2008 with the objective of building a successful Canadian crude oil and natural gas exploration, development and production company with a long-term business strategy similar to that of Duvernay Oil Corp. ("Duvernay") and Berkley Petroleum Corp. ("Berkley"), companies previously founded and managed by certain key members of Tourmaline's senior management team. Through a series of strategic acquisitions, farm-ins, joint ventures and land acquisitions combined with its active capital exploration and development program, Tourmaline has assembled an extensive undeveloped land position with a large, multi-year drilling inventory and operating control of important natural gas processing and transportation infrastructure in three core long-term growth areas – the Alberta Deep Basin, NEBC Montney and the Peace River High Triassic Oil Complex. See "The Company's Assets – Strategic Location of the Company's Assets".

To date, Tourmaline has raised approximately $4.0 billion through private placement equity financings and public offerings, approximately $375.2 million of which was raised from Tourmaline's directors, officers, employees and their associates, and strategically completed a number of asset and corporate acquisitions, cumulatively valued at $3.7 billion which have added approximately 80,000 Boe/d and over 1.7 million gross acres of land (approximately 1.2 million, net acres) to cost-effectively build its current production and extensive land position. The acquisitions have complemented an aggressive exploration, development and production program that is intended to be Tourmaline's primary long-term growth engine.

Tourmaline has grown its production significantly since its inception from average annual production of 3,455 Boe/d in 2009 to 290,865 Boe/d in 2019. Tourmaline has had continued production growth over the last two years. Tourmaline's average annual production has increased from 265,044 Boe/d in 2018 to 290,865 Boe/d in 2019 and averaging 303,860 Boe/d for the first six months of 2020. Tourmaline currently forecasts annual average production of 305,000 to 310,000 Boe/d for 2020, with an estimated exit 2020 production between 322,500 and 327,500 Boe/d. Tourmaline's year-end 2019 proved developed producing reserves of 527.4 MMboe were up 34% over year-end 2018 when including 2019 annual production of 106.2 MMboe, total proved reserves of 1.294 billion boe were up 16% over 2018 when including 2019 annual production and proven and probable reserves of 2.602 billion boe were up 10% when including 2019 annual production. After 11 years of operation, Tourmaline now has 12.3 Tcf of proven and probable natural gas reserves and 553 million barrels of proven and probable oil, condensate, and NGL reserves (January 1, 2020). Since inception, Tourmaline's production has been significantly weighted to natural gas and it is currently the largest natural gas producer in Canada. The production and reserves growth can be attributed primarily to Tourmaline's exploration and development activities, and from acquisitions of producing properties. In addition to Tourmaline's significant land production and reserves portfolio, Tourmaline owns and operates its critical processing facilities which enables its business to benefit from low-cost, sustainable operations that are resilient to commodity price volatility. Tourmaline's exploration and production business is well established with 1.5 Bcf/d of processing capacity.

Tourmaline's business strategy is to maximize shareholder value by increasing reserves, production and cash flows through the exploitation and development of a continually growing asset base and is focused on low cost operations in order to withstand fluctuations in commodity prices. Tourmaline manages its costs by adopting technology and best practices to find the most efficient way to operate while demonstrating strong financial metrics, including production growth, balance sheet management and low operating costs. Tourmaline does this all in a responsible manner that not only respects people and the environment but exceeds the most stringent government regulations in Canada. Tourmaline prudently manages its commodity risk by diversifying the markets where its natural gas is sold throughout North America including: Alberta, British Columbia, California, Chicago (Illinois) and Ontario. For the year ended December 31, 2019, Tourmaline posted record capital efficiency of $8,650/Boe/d (excluding acquisitions and dispositions) – a 23% improvement over 2018 while continuing to effectively manage its all-in cash costs (operating, transportation, general and administrative and financing). With its well-established, free cash flow generating business, Tourmaline has the resources to continue to invest in new technology and set meaningful targets in order to continue to reduce costs and improve its ESG profile. Tourmaline has amongst the lowest GHG emissions intensity (CO2/Boe) amongst Canadian senior oil and gas producers. Recently, it was recognized for its environmental sustainability efforts as the recipient of two awards for its water, conservation and diesel displacement programs.

Tourmaline has a strong Liability Management Rating of 9.53 at September 5, 2020 and a well-established infrastructure portfolio which enables it to direct the majority of its capital investment toward further development and growth of its business.

As at August 31, 2020, Tourmaline's aggregate borrowing capacity was approximately $2.9 billion and on September 9, 2020 it announced it had been assigned an issuer rating of BBB with a stable trend from DBRS Limited. This public investment grade credit rating helps validate the overall financial health of Tourmaline as a stable, low-risk, senior Canadian E&P company. As at August 31, 2020, $1.78 billion was drawn on the Tourmaline Credit Facilities, resulting in approximately $1.1 billion of available borrowing capacity. Tourmaline's divestiture of the Initial Assets to Topaz monetized a portion of its substantial-intrinsic value in its significant infrastructure complex and its low-cost profitable business. The combination of Tourmaline's available borrowing capacity, the proceeds from the Initial Acquisition as well as the Secondary Offering and potential future sales of Common Shares provide it with financial flexibility for potential consolidation activities within its three existing operated core complexes to continue its growth trajectory.

Tourmaline continues to evaluate potential acquisitions of all types of petroleum and natural gas and other energy-related assets and companies as part of its ongoing acquisition program. Tourmaline is regularly in the process of evaluating several potential acquisitions at any time, which individually or together could be material. Tourmaline cannot predict whether any current or future opportunities will result in one or more acquisitions for Tourmaline.

Advantage

On an annual basis, Advantage has had continued production growth over the last two years. Advantage's average annual production has increased from 41,651 Boe/d in 2018 to 44,334 Boe/d in 2019 and 45,864 Boe/d in the first six months of 2020. Advantage's production is primarily weighted to natural gas (over 90%). The production growth can be attributed primarily to Advantage's exploration and development activities. In 2018 Advantage generated cash from operating activities of $149.2 million which increased to $156.1 million in 2019. Advantage's capital expenditures were $201.1 million in 2018 and $184.9 million in 2019. Advantage has had continued reserves growth over the last two years. Total proved plus probable reserves increased from 432.2 MMboe at December 31, 2018 to 465.7 MMboe at December 31, 2019, and total proved increased from 325.1 MMboe to 352.8 MMboe, respectively.

Advantage operates and owns 87.5% of the Glacier Gas Plant, which is utilized to process the majority of Advantage's Montney production. During the second quarter of 2018, Advantage completed a significant expansion of the plant, which increased raw gas processing capacity from 250 MMcf/d to 400 MMcf/d with propane plus (C3+) liquids handling capacity increased to 6,800 Bbls/d. Advantage's stated business strategy is focused on low cost operations in order to withstand fluctuations in commodity prices and it maintains a low cost operating structure due in part to the ownership of its significant processing facilities.

Advantage is attentive to its ESG profile and monitors GHG emissions emitted by the Glacier Gas Plant operations. Advantage has carbon capture and storage CO2 sequestration projects in place at the Glacier facility. Advantage has a topdecile LMR ratio of 25.45 at September 5, 2020 and well-established processing infrastructure which enables it to focus its capital investment on further development and growth of its business.

INVESTMENT HIGHLIGHTS

Investment Highlights

Unique large-scale exposure to high-quality royalty and infrastructure assets

(1) See "GORR Lands".
(2) See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Glacier Gas Plant Acquisition".
(3) See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Banshee Gas Plant Acquisition".
(4) See "Clearwater GORR Interest".
(5) See "Analysis of Adjusted Pro Forma Revenue, EBTIDA and EBITDA Margin".
(6) See "Notice to Investors – Non-GAAP Financial Measures".

Strategic relationship with investment grade rated sponsor underpins strong growth prospects

Tourmaline is prominent in Canada's premium gas plays, consistently providing long-term growth guidance and has delivered production and reserves growth through organic development and acquisitions since its inception in 2008. Tourmaline's production is significantly weighted to natural gas and Tourmaline is currently Canada's largest natural gas producer with an award-winning track record of environmental sustainability and among the lowest GHG emissions intensity in the Canadian senior upstream sector. In addition to producing assets, Tourmaline also maintains an estimated 1.2 million gross acres of undeveloped land, upon which its management team has identified over 14,000 future drilling locations on the Tourmaline GORR Lands, which includes 2,225 booked locations on the Tourmaline GORR Lands included in the Tourmaline Consolidated Reserve Report. Tourmaline owns and operates its critical processing facilities which enables its business to benefit from low-cost, sustainable operations resilient to commodity price volatility. Tourmaline's exploration and production business is well established with 1.5 Bcf/d of processing capacity, a strong balance sheet and a strong LMR of 9.53 at September 5, 2020 which enables it to direct the majority of its capital investment toward further development and growth of its business. Tourmaline's average production for the first six months of 2020 was 303,860 Boe/d and Tourmaline currently forecasts annual average production of between 305,000 and 310,000 Boe/d for 2020, with an estimated exit 2020 production between 322,500 and 327,500 Boe/d. As at August 31, 2020, Tourmaline reported 2.6 billion Boe of reserves at December 31, 2019. Tourmaline's aggregate borrowing capacity was approximately $2.9 billion and on September 9, 2020 it announced it was assigned an issuer rating of BBB with a stable trend from DBRS Limited. This public investment grade credit rating validates the overall financial health of Tourmaline as a stable, low-risk, senior Canadian E&P company.

(1) As of August 31, 2020.
(2) August 25, 2020 Bloomberg consensus.
(3) Inventory life at a 2020 pace of development. See "Notice to Investors – Forward-Looking Statements".
(4) Based on information provided to the Company by Tourmaline.
(5) Source: Tourmaline Consolidated Reserve Report*.* See Appendix "B" to this prospectus.
(6) Tourmaline drilling inventory on the Tourmaline GORR Lands of 14,145 locations based on Tourmaline internal estimate which includes 2,225 booked locations derived from the Tourmaline Consolidated Reserve Report.
(7) Assumes a $217.5 million Treasury Offering and a $35 million Secondary Offering at $14 per share; does not include dilutive securities (Options).

Ability to strategically execute M&A in an opportunity rich environment

Predictable, high free cash flow margin supports attractive, sustainable dividend

The Company's revenue is generated through its ownership of royalty and infrastructure assets. The Royalty Production Revenue provides a significant and predictable free cash flow margin as the only associated cost is a 1% marketing fee paid to Tourmaline who currently markets the volume on behalf of Topaz. The Company is entitled to receive a gross royalty on production without incurring the related operating, finding and development, maintenance and other capital costs, including environmental liabilities or reclamation obligations that are typically associated with petroleum and natural gas development. The Company expects that the free cash flow margin attributed to its Tourmaline GORR Interest will continue to be 99%, after taking into account the marketing fee paid to Tourmaline to market its royalty production volume. Based on Tourmaline's consistent production growth since its inception in 2008 and its recent financial and operational performance, the Company anticipates its royalty production volume to grow over time. The Tourmaline GORR Interest provides potential additional revenue growth through commodity price exposure. The Company's Processing Revenue, which includes longterm fixed take-or-pay commitments, provides stable revenue that is resilient to commodity price volatility and is only modestly burdened by operating and capital costs. Topaz's revenue composition and low cost structure generates stable free cash flow, which supports a reliable and sustainable dividend, with Topaz's target payout ratio being 60 to 90%.

Notes:

(2) See "Notice to Investors – Non-GAAP Financial Measures".

	TopazDividend Policy		2019 Illustrative AdjustedPro Forma Revenue 1				2019 Illustrative AdjustedPro Forma EBITDA 1,4
$\cdot$ H1 2020 payout ratio of 84%			$150				$150
• Topaz has a target payout ratio of$60 - 90%$			$125		$118	$127$15	$125			$117
• Quarterly dividend of $0.20 / share			$\overline{\Sigma}_{\text{5}}$ $100	$107$10	$13		$100	$96	$107
TopazHedging Policy			Illustrative Revenue$75	$31$11	$39$11	$46$11	Illustrative EBITDA ($M)$75
Financial derivative contracts$\bullet$used to insulate a portion ofroyalty production			$50$25		$55M Adjusted Pro FormaInfrastructure Revenue 1,3		$50
Not expected to exceed 50% or $>$ 2$\bullet$years			SO 1				$25
	Gas Hedging Summary			$2.00	$2.50Illustrative AECO ($/mcf)	$3.00	$0	$2.00	$2.50	$3.00
Gas (AECO 5A GJ)	H 2 202014,200 mcf/d	20219.500 mcf/d						EBITDA	Illustrative AECO ($/mcf)
Avg Gas Volume Hedged		CTop Up Gas GORR (1% to Dec. 31, 2021)Base Gas GORR (3%)				2020 Estimated Annual Dividend
Average Price ($/mcf)	$1.91	$2.25		Base Liquids GORR (2.5%)■ Infrastructure Revenue				Pro Forma IPO Annual Dividend (before deployment of IPO

(1) See "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin".
(2) Share issuance assumed at $14 per Common Share for the calculation of Pro Forma dividend.
(3) Infrastructure Revenue includes Processing Revenue and Other Income.
(4) Adjusted Pro Forma EBITDA, with Royalty Production Revenue adjusted to reflect realized commodity prices received for oil and condensate (C$35.92/Bbl and C$44.30/Bbl, respectively, for the six months ended June 30, 2020). For illustrative purposes only, the Royalty Production Revenue is also adjusted to present illustrative results using different AECO prices as shown.

Environmental, social and governance (ESG) focus and leadership

• Majority of revenue from counterparties with strong environmental performance and among the lowest GHG emissions intensity in the Canadian senior upstream sector;

The Company and its Board are attentive to diversity and independence; Topaz has established an independent valuation framework whereby potential transactions between Topaz and Tourmaline are reviewed and approved exclusively by independent directors using comparable third-party and/or market transactions to assess the business and valuation characteristics of the potential transaction. See "Corporate Governance – Meetings of Independent Directors";
Its executive compensation structure is directly aligned with its shareholders;
Topaz has no direct oil and gas production and therefore alignment with industry ESG leaders is paramount to its ESG foundation and further supports Topaz's focus on counterparty quality as it evaluates future growth opportunities;
Topaz's Infrastructure Assets are relatively new and Topaz aligns its business with operators who Management believes follow industry best practice maintenance, environmental and health and safety protocols; and
Topaz is principally exposed to high-quality, long-life, lower emission natural gas assets. The majority of Topaz's revenue is generated indirectly through natural gas production; by displacing coal, natural gas is one of the best ways to reduce global CO2 emissions. (1)

(1) Source: EIA website (https://www.eia.gov/tools/faqs/faq.php?id=73&t=11).

Experienced, aligned management and board of directors

Note:

(1) Represents 8,836,156 Common Shares owned by shareholders represented by Board members, ARC Energy Fund 9 and Canoe Financial as well as officers and directors of Topaz and Tourmaline.

Proactively Monitoring and Managing its royalty and energy infrastructure assets

The Company intends to proactively monitor and manage its portfolio of royalty and energy infrastructure assets through:

Compliance Programs**:** The Company will benefit from a defined compliance process, including a well-organized audit program designed to ensure: (i) working interest owner compliance with GORR contract terms, including monitoring of expiring Crown leases; (ii) fulfillment of contractual obligations by third parties; and (iii) accurate accounting and collection of Royalty Production Revenue, Processing Revenue and Other Income by the Company. Management has significant experience working in the petroleum and natural gas industry and plans to hire technical accounting staff with extensive experience in the reporting, calculation and payment of production volumes to manage its compliance and accounting audit processes. The technical accounting staff are expected to have experience in using applications to merge public data related to wells, production and facility volumes by petroleum substances and posted commodity prices, with specific contract terms. Compliance audit reviews are expected to be completed on a regular basis to ensure that the

Company's counterparties are compliant with their contractual obligations. The use of technology by the Company will be an effective and efficient tool for managing large amounts of data and is expected to minimize general and administrative costs for the Company. Furthermore, the Company's existing GORR and infrastructure contractual arrangements are structured to result in a low administrative burden to the Company given that they are based upon market indexed pricing with no deductions provided to the operators (GORR) and supported by long-term, fixed take-orpay commitments (infrastructure). The Company intends to structure future potential contractual agreements in a similar manner.

GROWTH STRATEGY

Growth Strategy

Topaz seeks to achieve its objective of generating high free cash flow growth through indirect oil and gas and energy infrastructure investment by selectively pursuing strategic business development opportunities that are relatively low-risk and accretive to the Company. Topaz focuses its growth strategy in the following primary areas.

Organic Growth of Royalty Production Revenue from the Royalty Assets

The Company anticipates that it will generate increased Royalty Production Revenue supported by its strategic, aligned relationship with Tourmaline. Tourmaline provides transparent disclosure, has a proven track record of delivering value to its shareholders through the growth of its business and has the scale and cost profile for selffunded growth and free cash flow generation. Topaz anticipates that the Tourmaline GORR Interest will generate growth through Tourmaline's continued self-funded development of existing acreage with potential future upside provided through its exposure to primarily natural gas commodity prices.

Pursue Accretive Strategic Acquisitions

Counterparty quality**:** alignment with high quality counterparties with a strong track record of environmental sustainability, as Topaz believes that financial strength and size are fundamental to providing low-risk, stable and predictable revenue generating assets. Topaz may consider various factors in evaluating counterparty quality, including: balance sheet strength, viability of business model, environmental liability coverage, and capital allocation;

Asset quality**:** royalty interest acquisitions that have substantial resources and low-risk organic growth potential and infrastructure acquisitions that service high quality, low-risk, resources in order to ensure sustainability and surety of long-term revenue streams;

Disciplined capital allocation**:** investment return focused on continually improving sustainability to support long-term growth of the dividend; and

Potential to incentivize drilling activity: the Company will utilize various structure arrangements such as drilling commitments with fit-for-purpose terms (including customized royalty rates, obligations, commitment periods and incentives), tailored to the varying risk levels inherent in third-party exploration or development activity, in an effort to enhance the economics available to such counterparties. Through such arrangements, the Company expects to be able to stimulate activity on incremental GORR lands acquired and generate additional revenue for the Company.

Topaz will pursue royalty and energy infrastructure acquisitions from Tourmaline and other high-quality counterparties as a part of its growth strategy which could include:

Assets that may be acquired by Tourmaline in the future: As the largest producer of natural gas in Canada with a strong balance sheet and ample liquidity, Tourmaline is well positioned to be an industry consolidator, providing a pipeline of potential future royalty or infrastructure asset sales to Topaz;

Additional Tourmaline assets: Interests in assets acquired by Tourmaline subsequent to the formation of Topaz in November 2019 or opportunities to acquire ownership of certain infrastructure that Topaz does not have existing ownership interest in. Since Topaz's formation in November 2019, Tourmaline has acquired over 210,000 net acres of prospective acreage, on which Topaz does not own gross overriding royalty interests. To support its strong commitment to ESG, Topaz has established an independent valuation framework to assess potential transactions with Tourmaline; and

Third-party assets: Topaz will continue to opportunistically pursue royalty and infrastructure acquisitions with other high-quality counterparties. Topaz has developed strategic investment criteria and will pursue royalty interest acquisitions that have substantial resources, operated by high quality counterparties, which have organic growth potential. Topaz will pursue high quality infrastructure acquisitions, partnering with operators to secure long-term take-or-pay contracts which generate stable revenues.

THE COMPANY'S ASSETS

Strategic Location of the Company's Assets

Set forth below is a map outlining the location of the Company's assets.

Description of the Royalty Assets

Overview

Tourmaline GORR Interest

Topaz holds the Tourmaline GORR Interest in approximately 2.2 million gross acres of Tourmaline GORR Lands, all of which are Crown or freehold mineral title lands (2,248,413 gross acres and 1,940,248 net acres as at June 30, 2020). The Tourmaline GORR Lands are operated by Tourmaline and are situated within three areas: (i) the Alberta Deep Basin; (ii) NEBC Montney; and (iii) the Peace River High Triassic Complex.

Pursuant to the Tourmaline GORR Interest, Topaz holds a 4% gross overriding royalty interest on natural gas production from the Tourmaline GORR Lands until December 31, 2021; with a 3% gross overriding royalty interest on natural gas thereafter; and a 2.5% gross overriding royalty interest on crude oil and condensate production from the Tourmaline GORR Lands. The commodity prices for natural gas, oil and condensate are based on market index prices in the month of production. Specifically, the Company's royalty share of natural gas production is priced using the AECO (5A) index, its share of crude oil production is priced using the Peace Sour (PSO) benchmark and condensate production is priced using the Namao/Peace C5+ benchmark. The royalty production volumes are currently marketed with Tourmaline's volume and the Company pays a marketing fee to Tourmaline in an amount equal to 1% of the royalty share proceeds. Revenue is generally received by the Company two months after the natural gas, oil and condensate are produced. The Company can elect to take its share of the royalty production volume in-kind, if desired. The Company expects that the free cash flow margin attributed to the Tourmaline GORR Interest will continue to be 99%, after taking into account the marketing fee paid to Tourmaline to market its royalty production volume.

Clearwater GORR Interest

Topaz holds a 4% gross overriding royalty interest on all future production from the Clearwater GORR Lands (approximately 76,800 gross acres of undeveloped land in the Clearwater area) acquired pursuant to the Clearwater GORR Acquisition. The acquisition agreement includes a contractual commitment by the royalty payor to drill two multi-leg horizontal oil wells on the lands no later than February 28, 2021. The contractual commitment may be extended upon mutual agreement by Topaz and the royalty payor. There is currently no production, revenue or reserves attributable to the Clearwater GORR Interest.

Description of the Tourmaline GORR Lands

The following is a description of Tourmaline's three core long-term growth areas – the Alberta Deep Basin, NEBC Montney and Peace River High Triassic Oil Complex.

Alberta Deep Basin

The Alberta Deep Basin core area is a multi-objective tight natural gas sand play area with up to 15 separate lower Cretaceous liquids-rich natural-gas-charged sand reservoirs. Tourmaline's target exploration and production area is in that portion of the Alberta Deep Basin where the entire lower Cretaceous stratigraphic section is gas saturated with no mobile formation water. The primary vehicle for accessing the extensive reserves in these stacked sandstones is multi-stage fracture stimulation in both horizontal and vertical well-bores. Tourmaline utilizes 3D seismic data to select the majority of its drilling locations, and management of Tourmaline believes it is an industry leader in adopting and continually adapting the improving drilling and completion technologies. These two factors allow Tourmaline to consistently deliver a significant portion of the highest productivity gas wells in the province on an annual basis. The majority of Tourmaline's working interest lands have already received approval for down-spacing at four wells per section per zone or formation or reservoir.

Certain formations within the lower Cretaceous stack of tight sand reservoirs in the Alberta Deep Basin are more amenable to horizontal drilling (including the Cardium, Viking, Wilrich, Fahler and Notikewin Formations). Accordingly, each section in the Alberta Deep Basin core area is expected to include on average two to three targeted multi-stage stimulated horizontal wells in Tourmaline's long-term development plan. Tourmaline management estimates that up to 6,492 gross horizontal drilling locations exist on its Alberta Deep Basin holdings on the Tourmaline GORR Lands which are currently being assessed as part of the ongoing drilling program. These horizontal drilling locations have been included in Tourmaline's development drilling inventory. Future evaluation of these multiple resource plays is an important component of the 2020 capital exploration and development program, with approximately 80 gross horizontal wells currently planned. Tourmaline has been targeting the more condensate and NGL rich formations (Cardium, Viking and Fahler) with horizontal drilling over the past two years. In addition, on the Tourmaline GORR Lands, Tourmaline has 2,373 vertical development locations, including 450 gross outer foothills thrust belt vertical wells with geologic and economic parameters similar to those of the horizontal inventory.

Tourmaline currently has ownership interests in thirteen natural gas plants in the Alberta Deep Basin, seven of which (the Wild River 14-20, the Hinton 6-32, the Anderson 1-9, the Edson 4-17, the Ansell 1-34, the Oldman 10-24 and the Sundance 15-7) are 100% owned and operated by Tourmaline. In aggregate, Tourmaline has in excess of 1 Bcf/d of natural gas processing capability within this plant network. Tourmaline's goal is to be one of the lowest-cost, most efficient operators in the Alberta Deep Basin, and Tourmaline plans to optimize and systematically continue to further reduce costs of operating the Alberta Deep Basin assets.

In the Alberta Deep Basin, Tourmaline, since inception, has drilled over 800 gross natural gas wells and intends to drill approximately 80 additional gross wells in 2020. Tourmaline is the largest producer in the Alberta Deep Basin with 2020 average production estimated by Tourmaline to average between 163,000 and 168,000 Boe/d. Tourmaline's land holdings at December 31, 2019 in the core area were approximately 2,500 gross sections. Year-end 2019 proved plus probable reserves attributed to the Tourmaline GORR Lands were 1,016.5 MMboe in the Alberta Deep Basin, with approximately 765 gross future drilling locations recognized on the Tourmaline GORR Lands in the Tourmaline Consolidated Reserve Report.

NEBC Montney

Tourmaline's second core area on the west flank of the Peace River High in NEBC is focused on liquids rich natural gas in the Triassic Montney formation. Industry participants have been pursuing Triassic Montney plays and reservoirs in the WCSB for over four decades. Exploration and production of the Montney has evolved over time from conventional reservoirs pursued with vertical wells in the south east portion of the play area in Alberta to unconventional Montney reservoirs in the Peace River Arch area of Alberta and NEBC. Technological developments, including the drilling of horizontal multi-stage fracture stimulation wells, have allowed access to the thickest, highest pressured and highest deliverability fine grained sandstone reservoirs of the Montney in the NEBC play area. It is in the Groundbirch/Sunrise/Dawson area of the Peace River Arch where senior management of Tourmaline gained extensive experience with Duvernay and where Tourmaline concentrated its initial Montney exploration and production program.

Tourmaline has assembled its large Montney position primarily through multiple acquisitions completed between 2009 and 2019. Late in 2016, Tourmaline completed the largest property acquisition in Tourmaline's history which included a new property in NEBC, adding 6,200 Boe/d of initial production, over 100 sections of land and 1,600 new Montney drilling locations in the Gundy CK area, which is northwest of Tourmaline's existing Sunrise/Dawson/Sundown complex. Both the original Sunrise/Dawson complex and Gundy CK contain liquid-rich sweet natural gas in the Montney, allowing for lower, long-term operating costs compared to the majority of Montney focussed competitors pursuing sour gas. In NEBC, Tourmaline is one of the largest resource play participants, with an inventory of approximately 3,454 gross horizontal Montney development drilling locations on the Tourmaline GORR Lands. To date, Tourmaline has drilled over 450 Montney multi-stage fracture-stimulated horizontal natural gas wells in NEBC with approximately 100 additional gross Montney horizontal wells planned for 2020. Tourmaline's 2020 – 2021 two year development plan for the Gundy CK Montney asset includes continuing to apply drilling and completion practices developed in the Groundbirch/Sunrise/Dawson area in order to continue to reduce development costs, improve efficiencies and raise estimated ultimate recoveries (EUR). Tourmaline has amongst the lowest Montney drill and complete capital costs in the industry.

Complementing this growing Montney drilling inventory in NEBC is a series of high-deliverability/low-operating cost, sweet Mississippian, Kiskatinaw and Wabamun natural gas pools. Management believes that these deeper pools also have considerable exploration and production potential and will be the subject of ongoing exploration and development, the ultimate timing of which is dependent on a natural gas price recovery. Tourmaline owns and operates six significant natural gas processing facilities with aggregate capacity of 525 MMcf/d with related gas gathering systems and NGL handling infrastructure in the NEBC complex, including a new 200 MMcf/d facility built and commissioned at Gundy in 2019 in order to efficiently processes the liquids-rich natural gas produced as a result of ongoing development in the Gundy Creek area including installation of an ethane rejection deep-cut gas processing facility. To further support Tourmaline's development plans in the area, Tourmaline is also planning an additional 200 MMcf/d expansion of the Gundy facility for early 2022. Production from the NEBC Montney complex in 2020 is estimated by Tourmaline to average between 120,000 and 125,000 Boe/d including approximately 600 MMcf/d of natural gas and the remainder comprised of associated NGL, condensate and crude oil. As at December 31, 2019, Tourmaline holds approximately 310 gross sections of Montney rights in the core area (294 gross sections related to the Tourmaline GORR Lands) with 1,335.2 MMboe of proved plus probable reserves related to the Tourmaline GORR Lands evaluated by the independent reserve engineers at December 31, 2019, including approximately 936 gross future drilling locations recognized in the Tourmaline Consolidated Reserve Report related to the Tourmaline GORR Lands.

Peace River High Triassic Oil Complex

The third core area on the Alberta portion of the greater Peace River High is Tourmaline's exploration and production complex at Spirit River-Mulligan-Earring, Alberta. The majority of the current production in the complex is derived from oil and natural gas-charged reservoirs of the Triassic Charlie Lake formation. Tourmaline has a large inventory of vertical and horizontal development drilling prospects in the Charlie Lake and Montney formations as well as attractive plays in several other formations with 2020 average production estimated at 20,000 Boe/d. Tourmaline has drilled over 340 horizontal oil wells to date and plans an additional approximately 15 gross horizontals through 2020. As at December 31, 2019, Tourmaline has a defined inventory of 1,192 future Charlie Lake horizontals (gross) and 634 Montney horizontal locations (gross) on the Tourmaline GORR Lands and continues to delineate new discoveries in the Charlie Lake and Triassic Montney formations.

Proved plus probable reserves in the area at December 31, 2019 are estimated to be 241.9 MMboe including approximately 524 gross future drilling locations on the Tourmaline GORR Lands recognized in the Tourmaline Consolidated Reserve Report. Tourmaline currently owns and operates two significant oil batteries capable of handling 48,000 bpd of fluids and the associated natural gas is delivered to a third-party for processing. Tourmaline also has an owned and operated 60 MMcf/d sour gas processing facility at Spirit River.

Drilling Locations and Additional Information Regarding the Tourmaline GORR Lands

This prospectus discloses Tourmaline's drilling locations, as at December 31, 2019, in four categories: (i) proved undeveloped locations; (ii) probable undeveloped locations; (iii) unbooked locations; and (iv) an aggregate total of (i), (ii) and (iii). Of the 14,145 (gross) locations, 1,183 are proved undeveloped locations, 38 are proved non-producing locations, 1,004 are probable undeveloped locations and 11,920 are unbooked locations. Proved undeveloped locations, proved nonproducing locations, probable undeveloped locations and probable non-producing locations are booked and derived from the Tourmaline Consolidated Reserve Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal estimates based on Tourmaline's prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources (including contingent and prospective). Unbooked locations have been identified by management as an estimation of Tourmaline's multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that Tourmaline will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which Tourmaline will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. For additional information relating solely to the Tourmaline GORR Lands acquired pursuant to the Initial Acquisition (including production, oil and gas reserves and operational information), see Appendix "B". The information contained in Appendix "B" is presented pursuant to, and in accordance with, the terms of the Exemptive Relief. See "Exemptions from Certain Disclosure Requirements".

Description of the Clearwater GORR Lands

The Clearwater area is an emerging play in the Lower Cretaceous Clearwater and Spirit River Formations in central Alberta, geographically located approximately between Nipisi Lake and Marten Hills. Drilling technology uses closely spaced open hole multi-lateral wells (currently four to eight) produced through one production string therefore not having to use hydraulic fracturing or thermal technologies. With multiple legs, the relatively high permeability Clearwater reservoir is capable of producing economic volumes of 14–24° API gravity oil on primary production.

Description of the Infrastructure Assets

Overview

Topaz has (i) non-operated ownership interests in four natural gas processing plants in the WCSB with cumulative natural gas processing capacity of approximately 175 MMcf/d which are supported in part by long-term fixed fee take-or-pay commitments, and (ii) a contracted interest in a portion of certain third-party revenue generated at facilities owned by Tourmaline pursuant to crude oil and natural gas processing and handling agreements with third parties to which Tourmaline is a party. These interests generate the Processing Revenue and Other Income, respectively.

Musreau Gas Plant

The Company has a 45% ownership interest in the Musreau Gas Plant. The Musreau Gas Plant was commissioned by Tourmaline in 2010 and expanded in three phases to reach 120 MMcf/d raw gas and 4,600 Bbl/d liquids handling capacity by 2014. The plant consists of two processing trains and a separate compressor station that can offload any excess gas volumes to the Pembina Musreau facility.

The Musreau Gas Plant processes a portion of Tourmaline's Alberta Deep Basin gas production in the area gathered through a network of Tourmaline-owned pipelines. Additional third-party volumes are also processed at the Musreau Gas Plant pursuant to certain third-party contracts, for which Topaz is entitled to receive processing revenue in proportion to its ownership interest in the Musreau Gas Plant. See "Description of the Tourmaline GORR Lands – Alberta Deep Basin" for information related to the underlying resources and production processed at the Musreau Gas Plant.

Brazeau Gas Plant

The Company has a 45% ownership interest in the Brazeau Gas Plant. The Brazeau Gas Plant was commissioned by Tourmaline in 2016 and has 70 MMcf/d raw gas and 2,200 Bbl/d liquids handling capacity. The plant consists of one processing train and a separate compressor station that can offload any excess gas volumes to the Keyera Brazeau East facility. There is additional space on the lease to accommodate a future processing train if required.

The Brazeau Gas Plant processes production from Tourmaline's Alberta Deep Basin area, including its assets at Columbia, Brazeau, Peco, and Stolberg through a network of Tourmaline-owned pipelines. Additional third-party volumes are also processed at the Brazeau Gas Plant, for which Topaz is entitled to receive processing revenue in proportion to its ownership interest in the Brazeau Gas Plant. See "Description of the Tourmaline GORR Lands – Alberta Deep Basin" for information related to the underlying resources and production processed at the Brazeau Gas Plant.

Glacier Gas Plant

The Company has a 12.5% ownership interest in the Glacier Gas Plant. The Glacier Gas Plant is a relatively new facility whereby staged construction began in 2010, and it was expanded in six phases to reach 400 MMcf/d raw gas and 6,800 Bbl/d of liquids capacity in 2018. The Glacier Gas Plant features innovative design, high operating run-times, zero venting, and state-of-the-art automation technology. Complemented by an acid gas sequestration project, it continues to be a key element of Advantage's leading operating cost structure and extremely low carbon emissions intensity. At a raw natural gas throughput capability of 400 MMcf/d, the Glacier Gas Plant is within the top 10 producer-owned gas plants in Alberta by capacity. Diligent management of plant operations and use of new technology have resulted in lower emission generation as compared to cumulative emissions from other Canadian reporting companies with similarly classified facilities.

The Glacier Gas Plant is Advantage's sole plant and processes all of Advantage's Montney production through a network of pipelines, compressor stations and liquids hubs.

Banshee Gas Plant

The Company has a 25% ownership interest in the Banshee Gas Plant. The Banshee Gas Plant was commissioned by Tourmaline in 2011 and expanded to reach 155 MMcf/d raw gas and 2,875 Bbl/d liquids handling capacity in 2014. The plant consists of two processing trains and the site can accommodate a third processing train in the future, if required.

The Banshee Gas Plant processes production from Tourmaline's Alberta Deep Basin assets at Basing, Minehead, Ansell and Lambert through a network of Tourmaline-owned pipelines. Additional third-party volumes are also processed at the Banshee Gas Plant, all of which are subject to the TPF Revenue Interest Agreement. See "Description of the Tourmaline GORR Lands – Alberta Deep Basin" for information related to the underlying resources and production processed at the Banshee Gas Plant.

Assets Relating to the Other Income

North American Outlook for Natural Gas

Topaz actively follows the North American natural gas market supply and demand fundamentals and believes that the improving supply and demand fundamentals in both the Alberta, Canada and North American natural gas market as well as the environmental benefits of natural gas relative to coal powered energy provide a sustainable foundation for its business strategy.

Over the past fifteen years, North America has experienced the "shale gas revolution" as the development of new technologies such as horizontal drilling, hydraulic fracturing and innovative well completion techniques has opened up access to vast amounts of natural gas reserves that were once considered inaccessible. Between 2016 and 2019 the natural gas market was characterized by robust supply growth in both dry gas basins and associated gas growth from oil basins exceeding demand growth as the U.S. transitioned from being a net importer of natural gas to near self-sufficiency with a corresponding drop in natural gas imports from Canada. Total U.S. production as tracked by the EIA grew from 71 Bcf/d exiting 2016 to 96 Bcf/d in the fourth quarter of 2019. While LNG exports also grew from 1 Bcf/d to 9 Bcf/d in the same period, exports and local demand were not enough to balance the supply growth and Henry Hub natural gas prices fell from averaging US$3.00/MMbtu in 2017 to under US$2.00/MMbtu through the first half of 2020; however, the application of new technologies has also driven down the cost for drilling, developing and producing these resources, softening the economic impact to the natural gas industry. In contrast, the second half of 2020 has been characterized by rapidly improving gas prices as the market recalibrates to (i) lower associated natural gas supply from oil-weighted basins that have been impacted by low crude oil prices, and (ii) anticipation of the market entering a long-term period of unprecedented demand growth. This expected demand growth is attributable to accelerated retirements of coal-fired power generation facilities, increased demand for natural gas for petrochemical production and the oil sands and increased natural gas exports to Mexico and the rest of the world via both pipelines and LNG shipping. The size of the resource in North America is significant and not all the gas will be developed as the reserve quality and supply costs vary between basins, but the tightening of supply demand fundamentals is expected to provide sufficient underlying price support to ensure that the best operators in the best basins will continue to be able to economically develop their resource at attractive levels of return.

Due to lower oil prices resulting from COVID-19 demand impacts and supply growth, oil-directed drilling has dramatically reduced in 2020 and associated gas production has gone from several years of strong growth, into a decline. In the EIA's "September 2020 Short Term Energy Outlook" they forecast "U.S. dry natural gas production will average 89.9 Bcf/d in 2020 and monthly average production will fall from a record 96.2 Bcf/d in November 2019 to 85.5 Bcf/d in February 2021, before increasing slightly. Natural gas production declines the most in the Permian region, where the EIA expects low crude oil prices will reduce associated natural gas output from oil-directed rigs. The EIA's forecast of dry natural gas production in the United States averages 86.6 Bcf/d in 2021. The EIA forecasts production to begin rising in the second quarter of 2021 in response to higher natural gas and crude oil prices". (1)

This sizable change in supply is occurring at the same time that global and domestic demand for natural gas is improving following the modest impacts of COVID-19. The EIA estimates that domestic natural gas consumption for 2020 will be 82.7 Bcf/d, just 2.7% lower than the 2019 consumption, with the largest decline being attributed to lower industrial consumption. The stated reason for the decline in industrial consumption was reduced manufacturing activity. LNG exports were more impacted by COVID-19 and international supply and demand, falling from 9.5 Bcf/d in March to 3 Bcf/d in July; however exports have started to increase again this fall, and the EIA forecasts "that U.S. LNG exports will return to pre-COVID levels by November 2020 and will average more than 9 Bcf/d from December 2020 through February 2021". (1)

The net result of these forces is that the domestic and export demand for natural gas in 2021 is returning to 2019 levels while the domestic supply of natural gas has fallen by over 10%. In order to balance supply and demand, much stronger natural gas prices are needed in order to reduce some local power burn consumption of natural gas through gas-to-coal switching in the power stack, and to incentivize more natural gas drilling activity to increase supply. The improvement in forward natural gas prices has begun to occur as LNG demand has become more certain. The EIA forecasts that "rising domestic demand and demand for LNG exports heading into winter, combined with reduced production, will cause Henry Hub spot prices to rise to a monthly average of US$3.40/MMBtu in January 2021. EIA expects that monthly average spot prices will remain higher than US$3.00/MMBtu for all of 2021, averaging US$3.19/MMBtu for the year, up from a forecast average of US$2.16/MMBtu in 2020". (1)

Topaz is specifically exposed to the AECO (5A) monthly index price in Alberta, which has its own local supply and demand dynamics that interplay with the broader North American natural gas dynamics. After years of wide basis differentials to Henry Hub, averaging over US$1.00/MMbtu between 2017 and 2018, AECO basis differentials have tightened to under US$1.00/MMbtu as export capacity has increased and local supply has decreased. In June, the AER provided a forecast that Alberta natural gas supply could decline greater than 300 MMcf/d in 2020 as compared to 2019 while demand is set to "grow annually by an average of 2.5%, increasing by nearly 28% overall by 2029 relative to 2019. Growth is primarily expected to be attributed to increasing demand from the oil sands and electricity generation sectors, particularly with the retirement of coal-fired generators and the increase in coal-to-gas conversions". (2) Management believes that with growing demand and now two consecutive years of lower supply and activity, local AECO natural gas markets appear to be tightening. With tightening natural gas fundamentals in the broad North American natural gas market, combined with additional tightening in the local AECO natural gas market, Topaz believes that it is well positioned to enhance its sustainability and profitability.

Notes:

(1) Source: "US Energy Information Administration (EIA) September 2020 Short Term Energy Outlook".
(2) Source: "Alberta Energy Regulator ST98: Alberta Energy Outlook Report".

THE COMPANY

History of the Company

On September 1, 2020, the Company completed the Banshee Gas Plant Acquisition, acquiring a 25% ownership interest in the Banshee Gas Plant for cash consideration of $52.5 million, before customary adjustments. In connection with the Banshee Gas Plant Acquisition, the Company and Tourmaline entered into the Banshee Volume Commitment Agreement, a 15-year volume commitment agreement whereby the Company earns a fixed natural gas processing fee of $0.60/Mcf for a fixed takeor-pay volume of 25 MMcf/d, which equates to incremental annual cash flow of $5.5 million for the Company. The Company also generates Processing Revenue attributed to natural gas processing services provided to Tourmaline, on a fee-for-service basisin respect of its remaining share of plant capacity. Any processing revenue attributable to natural gas processing services provided to third parties (excluding Tourmaline) is allocated to the Company pursuant to the TPF Revenue Interest Agreement. The Company is responsible for its 25% ownership interest share of operating and maintenance capital costs incurred for the Banshee Gas Plant.

On September 1, 2020, the Company completed the Clearwater GORR Acquisition acquiring the Clearwater GORR Interest.

Corporate Structure

The Company was incorporated under the ABCA under the name "1274560 Alberta Ltd." on October 13, 2006 and on October 19, 2006, amended its articles to change its name to "Exshaw Oil Corp." On November 8, 2019, the Company amended its articles to change its name to "Topaz Energy Corp." and on November 12, 2019, amended and restated its articles to: amend the rights, privileges, restrictions and conditions of the Common Shares; amend the designation of its Preferred Shares, issuable in series, to "First Preferred Shares"; create a class of shares designated as "Second Preferred Shares", issuable in series; effect a consolidation of the Common Shares on a 74.48896:1 basis; and set the maximum number of directors at 12 (minimum three).

The following diagram illustrates the organizational structure and approximate Common Share ownership of the Company on Closing.

Note:

The Company's head office is located at Suite 3100, 250 6th Avenue SW, Calgary, Alberta T2P 3H7 and its registered office is located at Suite 2400, 525 8th Avenue SW, Calgary, Alberta T2P 1G1.

The Company presently has two full-time employees with additional personnel and services provided pursuant to the Management Services Agreement.

Tax Pools

As at June 30, 2020, the Company had $881.0 million of federal tax pools (December 31, 2019 - $915.0 million). The Company has non-capital losses of approximately $340.6 million (December 31, 2019 - $355.0 million) which may be applied against future income for Canadian tax purposes. These non-capital losses expire in 2025 and onwards.

Dividend Policy

For a description of the Company's business, see "The Company's Business".

RESERVES AND OTHER OIL AND GAS INFORMATION

Disclosure of Reserves Data

In accordance with NI 51-101, the reserves data associated with the Tourmaline GORR Lands set forth below is based upon an evaluation by GLJ and Deloitte as set forth in the Topaz Reserve Report. An average of the GLJ Price Forecast, Sproule Price Forecast and McDaniel Price Forecast was used in the Topaz Reserve Report. The effective date of the information provided in the Topaz Reserve Report is December 31, 2019 and the Topaz Reserve Report has a preparation date of March 2, 2020.

The Topaz Reserve Report evaluated, as at December 31, 2019, the crude oil, natural gas and NGL reserves associated with the Tourmaline GORR Lands, as well as the net operating income attributed to the Infrastructure Assets (excluding the Company's interests in the Glacier Gas Plant and the Banshee Gas Plant, as those interests were acquired subsequent to the effective date of the Topaz Reserve Report) which includes Processing Revenue (excluding Processing Revenue from the Company's interests in the Glacier Gas Plant and the Banshee Gas Plant), operating expenses, turnaround maintenance expenses, abandonment and reclamation costs and Other Income attributed to its energy infrastructure assets and contractual agreements, respectively. References to NGL in the reserves data includes only condensate and pentane as other NGL are excluded from the Tourmaline GORR Interest. The tables below summarize the reserves and the net present value of future net revenue attributable to the reserves as evaluated in the Topaz Reserve Report based on the average of the GLJ Price Forecast, Sproule Price Forecast and McDaniel Price Forecast cost assumptions and supplied operating expenses. The tables summarize the data contained in the Topaz Reserve Report and, as a result, may contain slightly different numbers than such report due to rounding. Also due to rounding, certain columns may not add exactly.

The net present value of future net revenue attributable to the reserves and Infrastructure Assets (excluding the Company's interests in the Glacier Gas Plant and Banshee Gas Plant) is stated without provision for interest costs, but after providing for Processing Revenue (excluding Processing Revenue from the Company's interests in the Glacier Gas Plant and the Banshee Gas Plant), operating expenses, turnaround maintenance expenses, abandonment and reclamation costs and Other Income. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to the reserves estimated by Topaz Reserve Report represent the fair market value of the reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery estimates of the reserves provided herein are estimates only and there is no guarantee that the reserves, as estimated, will be recovered. Actual reserves may be greater than or less than the estimates provided herein.

In preparing the Topaz Reserve Report, GLJ and Deloitte relied on certain information provided by the Company and Tourmaline and third parties associated with the Tourmaline GORR Lands, which included working and net revenue interest data, public data, well information, geological information, reservoir studies, estimates of on-stream dates, contract information, current hydrocarbon product prices, operating cost data, financial data and future development and operating plans for the Tourmaline GORR Lands, as applicable. Other engineering, historical production, geological or economic data required to conduct the evaluations and upon which the Topaz Reserve Report is based was obtained from public records and from non- confidential files. The extent and character of ownership and the accuracy of all factual data supplied for the independent evaluation, from all sources, was accepted by GLJ and Deloitte as represented.

The Report on Reserves Data by each of GLJ and Deloitte in Form 51-101F2 and the Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached to this prospectus as Appendix "C" and Appendix "D", respectively.

All evaluations and reviews of future net cash flow 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 cash flow shown below is representative of the fair market value of properties. There can be no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of crude oil, natural gas and NGL reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.

GLJ and Deloitte were engaged by the Company to provide an evaluation of proved and probable reserves. All of the reserves associated with the Tourmaline GORR Lands are located in the Provinces of Alberta and British Columbia. Additionally, as the Company does not hold any working interests in the Tourmaline GORR Lands, the Company will not be responsible for any capital costs associated with the Tourmaline GORR Lands and, as such, the evaluation of reserves data does not include any undeveloped reserves.

Summary of Reserves

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2019 Forecast Prices and Costs(1)

	Light & Medium CrudeOil		Conventional NaturalGas		Shale Natural Gas		Natural Gas Liquids		Total Oil Equivalent
Reserves Category	CompanyGross(Mbbls)	CompanyNet(Mbbls)	CompanyGross(MMcf)	CompanyNet(MMcf)	CompanyGross(MMcf)	CompanyNet(MMcf)	CompanyGross(Mbbls)	CompanyNet(Mbbls)	CompanyGross(MBoe)	CompanyNet(MBoe)
Proved Producing	0	356	0	55,002	0	30,580	0	890	0	15,509
Proved Developed Non-Producing	0	48	0	3,128	0	6,778	0	143	0	1,842
Proved Undeveloped	0	0	0	0	0	0	0	0	0	0
TotalProved	0	403	0	58,130	0	37,358	0	1,033	0	17,351
Total Probable	0	183	0	18,089	0	12,557	0	361	0	5,652
Total Proved Plus Probable	0	586	0	76,220	0	49,915	0	1,394	0	23,003

* Numbers may not add due to rounding.

Notes:

(1) Gross reserves represent the working interest share before deduction of any royalty obligations and without including any royalty interests.
(2) Net reserves represent the working interest share after deduction of royalty obligations, plus royalty interests in production or reserves.
(3) The Company differs from typical oil and natural gas producers in that all of its interests in reserves are royalty interests with no associated working interests. As a result, there are no gross reserves associated with the Tourmaline GORR Lands, which may hinder comparison of the Company's reserves with others in the oil and natural gas industry.
(4) Conventional natural gas includes by-products but excluding solution gas.
(5) Light and medium crude oil includes solution gas and other by-products.

	Net Present Value of Future NetRevenue Before Income Taxes Discounted at (%/year)

Reserves Category	0%	5%	10%	15%	20%
			($ thousands)
Proved
Developed Producing	680,305	500,168	394,088	325,888	279,035
Developed Non-Producing	53,566	40,353	32,534	27,428	23,842
Undeveloped	0	0	0	0	0
Total Proved Developed	733,871	540,521	426,622	353,315	302,878
Total Probable Developed	202,485	100,818	61,139	42,144	31,589
Total Proved Plus Probable	936,357	641,339	487,761	395,459	334,467
Developed

Summary of Net Present Values of Future Net Revenue

* Numbers may not add due to rounding.

	Net Present Value of Future NetRevenue After Income Taxes Discounted at (%/year)
Reserves Category	0%	5%	10%	15%	20%
			($ thousands)
Proved
Developed Producing	680,305	500,168	394,088	325,888	279,035
Developed Non-Producing	53,566	40,353	32,534	27,428	23,842
Undeveloped	0	0	0	0	0
Total Proved Developed	733,871	540,521	426,622	353,315	302,878
Total Probable Developed	202,485	100,818	61,139	42,144	31,589
Total Proved Plus Probable	936,357	641,339	487,761	395,459	334,467
Developed

* Numbers may not add due to rounding.

Additional Information Concerning Future Net Revenue (Undiscounted) as of December 31, 2019

Reserves Category	Revenue	OperatingCosts	Future NetRevenueBefore IncomeTax	Future NetRevenueAfterIncomeTax(3)
Proved Producing	727,237	46,931	680,305	680,305
Proved Developed Non-Producing	55,228	1,662	53,566	53,566
Proved Undeveloped……………	0	0	0	0
Total Proved……………………	782,465	48,594	733,871	733,871
Total Probable……………………	216,759	14,274	202,485	202,485
Total Proved Plus Probable………	999,225	62,868	936,357	936,357

* Numbers may not add due to rounding

Notes:

(1) No development costs or abandonment and reclamation costs are associated with the estimated future net revenue from the reserves attributed to the Tourmaline GORR Lands as the Company does not hold any working interests in the Tourmaline GORR Lands and will not be responsible for such costs. No development costs are associated with the Company's Infrastructure Assets; turnaround maintenance expenses are included in operating costs. Provisions for abandonment and reclamation costs associated with the Infrastructure Assets (excluding the Company's interests in the Glacier Gas Plant and Banshee Gas Plant) were considered to be immaterial once factoring in the useful lives of the assets as well as abandonment and reclamation cost estimates.

(2) No provision for income taxes was required after incorporating the estimated value of the Company's tax pools. See "Tax Pools".

		Future NetRevenue BeforeIncome Taxes	Unit Value(discounted at10%/year)(2)
Reserves Category	Production Type(1)	(discounted at10%/year)($000s)	($/Boe)	($/Mcfe)
Proved Producing	Light and Medium Crude Oil	41,164	36.98	6.16
	Conventional Natural Gas	265,904	30.33	5.06
	Shale Natural Gas	87,019	15.46	2.58
	Total	394,088	25.41	4.24
Proved	Light and Medium Crude Oil	44,747	35.49	5.92
	Conventional Natural Gas	273,684	29.73	4.95
	Shale Natural Gas	108,191	15.72	2.62
	Total	426,622	24.59	4.10
Proved Plus Probable	Light and Medium Crude Oil	51,570	29.03	4.84
	Conventional Natural Gas	305,342	25.41	4.24
	Shale Natural Gas	130,849	14.20	2.37
	Total	487,761	21.20	3.53

Future Net Revenue by Production Group as of December 31, 2019

Notes:

(1) Includes by-products which for Topaz are only condensate and pentane (which are immaterial), but excluding solution gas.

(2) The unit value is calculated by dividing the discounted Future Net Revenue by net reserves for the principal product of the production group. Presented as $/Mcf for natural gas and $/Bbl for crude oil. Presented as $/Boe for total.

For future net revenue of the total proved reserves, discounted at 10%, 10.5% of the revenue is from light and medium and tight crude oil and 89.5% is from natural gas. For the total proved plus probable reserves, 10.6% of the revenue is from light and medium and tight crude oil and 89.4% is from natural gas.

Notes and Definitions

In the tables set forth above and elsewhere in this prospectus, the following notes and other definitions are applicable.

Reserve Categories

The determination of crude oil, natural gas and NGL reserves involves the preparation of estimates that have an inherent degree of associated uncertainty. Categories of proved, probable and possible reserves have been established to reflect the level of these uncertainties and to provide an indication of the probability of recovery.

The estimation and classification of reserves requires the application of professional judgment combined with geological and engineering knowledge to assess whether or not specific reserves classification criteria have been satisfied. Knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods are required to properly use and apply reserves definitions.

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

analysis of drilling, geological, geophysical and engineering data;
the use of established technology; and

• specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed. Reserves are classified according to the degree of certainty associated with the estimates.

"Proved reserves" are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

"Probable reserves" are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Each of the reserves categories may be divided into developed and undeveloped categories.

"Developed reserves" are those reserves that are expected to be recovered from existing wells and installed facilities, or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

"Developed producing reserves" are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

"Developed non-producing reserves" are those reserves that either have not been on production, or have previously been on production but are shut-in and the date of resumption of production is unknown.

"Undeveloped reserves" are those reserves expected to be recovered from known accumulations where a significant expenditure (e.g., when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (proved, probable, possible) to which they are assigned.

In multi-well pools, it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to sub-divide the developed reserves for the pool between developed producing and developed non-producing. This allocation is 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.

Levels of Certainty for Reported Reserves

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 estimates are presented. Reported reserves should target the following levels of certainty under a specific set of economic conditions:

at least a 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves;
at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves; and
at least a 10% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable plus possible reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates are prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

Pricing Assumptions — Forecast Prices and Costs

GLJ employed the following pricing, inflation rate and exchange rate assumptions based on an average of the GLJ Price Forecast, Sproule Price Forecast and McDaniel Price Forecast in estimating reserves data using forecast prices and costs.

Summary of Pricing and Inflation Rate Assumptions Forecast Prices and Costs (1)

		Crude Oil and Natural Gas Liquids Pricing
				NYMEX WTI NearMonth Futures ContractCrude Oil at Cushing,Oklahoma	BrentBlend	MSW,LightCrude Oil	Bow RiverCrude Oil	WCSCrude Oil	HeavyCrude Oil	Light SourCrude Oil	MediumCrude Oil			Alberta Natural Gas Liquids(Then Current Dollars)
Year	Inflation(2)%	CAD/USDExchangeRate$US/$Cdn(3)	Constant2020$$US/Bbl	ThenCurrent$US/Bbl	Crude OilFOBNorth SeaThenCurrent$US/Bbl	(40 API,0.3%S) atEdmontonThenCurrent$Cdn/Bbl	StreamQuality atHardistyThenCurrent$Cdn/Bbl	StreamQuality atHardistyThenCurrent$Cdn/Bbl	Proxy (12API) atHardistyThenCurrent$Cdn/Bbl	(35 API,1.2%S) atCromerThenCurrent$Cdn/Bbl	(29 API,2.0%S) atCromerThenCurrent$Cdn/Bbl	SpecEthane$Cdn/Bbl	EdmontonPropane$Cdn/Bbl	EdmontonButane$Cdn/Bbl	EdmontonC5+StreamQuality$Cdn/Bbl
2020	0.0	0.7600	61.00	61.00	66.33	72.64	58.43	57.57	51.23	72.16	70.22	6.42	26.36	42.09	76.83
2021	1.7	0.7700	62.70	63.75	67.94	76.06	63.00	62.35	56.11	75.23	73.15	7.41	29.80	47.03	79.82
2022	2.0	0.7850	63.82	66.18	70.06	78.35	64.99	64.33	57.72	77.50	74.95	8.33	32.94	50.66	82.30
2023	2.0	0.7850	64.20	67.91	71.66	80.71	66.91	66.23	59.45	79.83	77.19	8.65	34.00	52.21	84.72
2024	2.0	0.7850	64.40	69.48	73.27	82.64	68.65	67.96	61.09	81.76	79.05	8.98	34.89	53.48	86.71
2025	2.0	0.7850	64.58	71.07	74.57	84.60	70.41	69.72	62.75	83.69	80.92	9.24	35.78	54.77	88.73
2026	2.0	0.7850	64.75	72.68	76.22	86.57	72.20	71.49	64.43	85.66	82.82	9.46	36.69	56.07	90.77
2027	2.0	0.7850	64.84	74.24	77.83	88.49	73.91	73.19	66.04	87.57	84.66	9.67	37.57	57.32	92.76
2028	2.0	0.7850	64.84	75.73	79.36	90.31	75.53	74.80	67.55	89.37	86.40	9.89	38.41	58.50	94.65
2029	2.0	0.7850	64.85	77.24	80.92	92.17	77.17	76.43	69.08	91.21	88.17	10.12	39.26	59.71	96.57
2030	2.0	0.7850	64.85	78.79	82.54	94.01	78.72	77.96	70.47	93.04	89.94	10.35	40.11	60.90	98.53
2031	2.0	0.7850	64.85	80.36	84.19	95.89	80.29	79.52	71.87	94.90	91.74	10.56	40.91	62.12	100.50
2032	2.0	0.7850	64.84	81.97	85.87	97.81	81.90	81.11	73.31	96.80	93.57	10.77	41.73	63.36	102.51
2033	2.0	0.7850	64.84	83.61	87.59	99.76	83.54	82.73	74.78	98.73	95.44	10.98	42.56	64.63	104.56
2034	2.0	0.7850	64.85	85.28	89.35	101.76	85.21	84.39	76.27	100.71	97.35	11.20	43.42	65.92	106.65
2035	2.0	0.7850	64.85	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr

	Natural Gas and Sulphur Pricing
							Alberta Plant Gate		Saskatchewan Plant Gate			British Columbia
		NYMEX Henry HubNear Month Contract	Midwest Price	AECO/NIT		Spot
	Constant2020 $$US/	Then Current	@ ChicagoThen Current$US/	SpotThen Current$Cdn/	Dawn Price@ Ontario ThenCurrent	Constant 2020$$Cdn/	Then Current$Cdn/	ARP $Cdn/	SaskEnergy$Cdn/	Spot$Cdn/	Sumas Spot$US/	WestcoastStation 2$Cdn/	Spot PlantGate$Cdn/
Year	MMbtu	$US/MMbtu	MMbtu	MMbtu	$US/MMbtu	MMbtu	MMbtu	MMbtu	MMbtu	MMbtu	MMbtu	MMbtu	MMbtu
2020	2.62	2.62	2.53	2.04	2.58	1.82	1.82	1.83	1.93	2.49	2.16	1.66	1.41
2021	2.82	2.87	2.78	2.32	2.82	2.07	2.10	2.11	2.21	2.72	2.44	1.99	1.74
2022	2.95	3.06	2.96	2.62	3.01	2.30	2.39	2.40	2.50	2.89	2.72	2.31	2.07
2023	2.99	3.17	3.07	2.71	3.12	2.35	2.48	2.50	2.60	2.88	2.83	2.46	2.21
2024	3.01	3.24	3.15	2.81	3.20	2.39	2.58	2.59	2.70	2.98	2.90	2.56	2.31
2025	3.02	3.32	3.23	2.89	3.27	2.41	2.66	2.67	2.77	3.06	2.98	2.66	2.42
2026	3.02	3.39	3.30	2.96	3.34	2.42	2.72	2.74	2.84	3.13	3.05	2.73	2.48
2027	3.02	3.46	3.36	3.03	3.41	2.43	2.78	2.80	2.91	3.20	3.12	2.80	2.54
2028	3.02	3.52	3.43	3.10	3.48	2.44	2.85	2.87	2.98	3.27	3.18	2.87	2.61
2029	3.02	3.60	3.50	3.17	3.55	2.45	2.92	2.94	3.05	3.34	3.26	2.93	2.68
2030	3.02	3.67	3.58	3.24	3.62	2.46	2.99	3.00	3.12	3.41	3.33	3.00	2.74
2031	3.02	3.74	3.65	3.30	3.69	2.46	3.05	3.07	3.18	3.48	3.39	3.06	2.80
2032	3.02	3.81	3.72	3.37	3.77	2.46	3.11	3.13	3.24	3.55	3.46	3.12	2.85
2033	3.02	3.89	3.80	3.43	3.84	2.46	3.17	3.19	3.30	3.62	3.54	3.19	2.91
2034	3.02	3.97	3.87	3.50	3.92	2.46	3.23	3.25	3.37	3.70	3.61	3.25	2.97
2035	3.02	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	2.46	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr

Notes:

(1) Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by GLJ in the Topaz Reserve Report, were an average of forecast prices and costs published by Sproule as at December 31, 2019 and GLJ and McDaniel as at January 1, 2020 (each of which is available on their respective websites at www.sproule.com, www.gljpc.com, and www.mcdan.com).
(2) Inflation rates used for forecasting prices and costs.
(3) Exchange rates used to generate the benchmark reference prices in this table.
(4) During the year ended December 31, 2019, the historical weighted average prices realized in respect of the production associated with the Tourmaline GORR Lands, including realized gains and losses on Tourmaline's financial instruments, in respect of its production were: natural gas – $2.59/Mcf; NGL – $15.33/Bbl; and oil and condensate – $68.50/Bbl. Tourmaline's overall weighted average price received on an oil equivalent basis was $20.04/Boe.

Reserves Reconciliation

The reserves information presented in this prospectus has been summarized from the Topaz Reserve Report. The Topaz Reserve Report was prepared by GLJ for the Company. As there was no evaluation report in respect of the Tourmaline GORR Lands available to the Company for the year ended December 31, 2018, pursuant to the applicable provisions of NI 51-101, a reserves reconciliation is not required to be disclosed.

Significant Factors or Uncertainties

The process of estimating reserves is complex. It requires significant judgments and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting crude oil and natural gas prices and costs change. The reserve estimates contained herein are based on current production forecasts, prices and economic conditions. The reserves were evaluated by GLJ and Deloitte, each an independent qualified reserves evaluator.

As circumstances change and additional data becomes available, reserve estimates also change. Estimates made 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 governmental restrictions.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing economic or regulatory environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end crude oil and natural gas prices and reservoir performance. Such revisions can be either positive or negative. See "Risk Factors — Risks Relating to the Company's Business, Industry and Operating Environment — Reserves Estimates".

Future Development Costs

As funding for future development costs will be the responsibility of the working interest owners on the applicable properties, and as the Company does not hold any working interests in the Tourmaline GORR Lands, the Company will not be responsible for any development costs on the Tourmaline GORR Lands and cannot advise as to the sources and costs of funding future development or the impact thereof on disclosed reserves or future net revenue.

Abandonment and Reclamation Costs

The Company has no reclamation obligations in respect of the Tourmaline GORR Lands as these are the responsibility of the working interest owner. The Company is responsible for its working interest share of reclamation obligations associated with Topaz's infrastructure assets however the net present value of the Company's share of abandonment and reclamation costs were considered to be immaterial once factoring in the useful lives of the assets as well as the relevant abandonment and reclamation cost estimates. The undiscounted, uninflated total future liability at June 30, 2020 is estimated at $0.7 million ($0.7 million at December 31, 2019). See the Topaz Financial Statements included in Appendix "A" to this prospectus.

Oil and Natural Gas Properties and Wells

The following table summarizes the gross number of wells located on the Tourmaline GORR Lands in which the Company holds a royalty interest, all of which are located in Alberta and British Columbia and all of which are onshore. As the Company does not hold any working interests in the GORR Lands, the net number of wells located on the Tourmaline GORR Lands is nil.

		Natural Gas	Oil
Area	Producing	Non-Producing(1)	Producing	Non-Producing(1)
Alberta	1,765	356	331	119
British Columbia	443	166	1	-
TOTAL	2,208	522	332	119

(1) As royalty revenue payable by Tourmaline is based on producing wells located on the Tourmaline GORR Lands, the Company does not have information from third parties on non-producing wells located on the Tourmaline GORR Lands.

Properties with No Attributed Reserves

The following table summarizes the gross acres with no attributed reserves that form part of the Tourmaline GORR Lands as at December 31, 2019 and the net acres with no attributable reserves for which Tourmaline's rights to explore, develop and exploit are expected to expire within one year. All such lands are located in British Columbia and Alberta.

	Tourmaline GORR Lands(1)
		Gross Acres expiring
(thousands of acres)	Gross Acres(2)	within one year(2)
Alberta	1,151,937	294,378
British Columbia	48,878	19,233
Total	1,200,815	313,611

Notes:

(1) Properties with different formations under the same surface area and subject to separate leases have been calculated on an aerial basis, and as such have only been counted once.
(2) As the Company does not hold any working interests in the Tourmaline GORR Lands, the net acres associated with the Tourmaline GORR Lands and net acres expiring within one year are nil.

The maximum area for which the Company expects the rights to explore, develop and exploit to expire within the next year is 294,378 acres in Alberta and 19,233 acres in British Columbia. The expiring acreage is continuously being evaluated by Tourmaline and it is expected that attempts will be made by Tourmaline to maintain its rights on the acreage and mitigate expiries through land swaps, asset dispositions or drilling to maintain the lease. There are no material work commitments necessary to maintain these properties.

Tax Horizon

As at June 30, 2020, the Company had federal tax pools of $881.0 million which include non-capital losses of approximately $340.6 million. See "Tax Pools". The statutory corporate income tax rate applicable to the Company is approximately 25%. A corporation's taxable income is based on total revenue, other income and expenses. The Company does not expect to pay Canadian income tax prior to 2029. This estimate will be impacted by, among other factors, royalty production volumes, commodity prices, development activities on the properties in which it holds GORR interests, processing volume, processing fees, amount and term of fixed take-or-pay commitments, third-party processing and handling volumes and fees, operating costs, interest rates, changes in tax laws and the Company's other business activities. Changes in these factors from estimates used by Topaz could result in the Company paying income taxes earlier than expected.

Costs Incurred

There were no acquisition, development or exploration costs incurred in respect of the Tourmaline GORR Lands for the year ended December 31, 2019.

Production Estimates

The following table discloses for each product type the gross and net volume of production estimated by GLJ for the year ended December 31, 2020 in the estimates of gross and net proved and gross probable reserves disclosed above under the heading "Reserves and Other Oil and Gas Information — Disclosure of Reserves Data".

		Natural Gas
	Conventional				Light and Medium
	Natural Gas		Shale Gas(3)		Crude Oil		NGL
Reserves Category	Gross(1)(3)	Net(2)(3)	Gross(1)(3)	Net(2)(3)	Gross(1)(3)	Net(2)(3)	Gross(1)(3)	Net(2)(3)
	(Mcf/d)	(Mcf/d)	(Mcf/d)	(Mcf/d)	(Bbls/d)	(Bbls/d)	(Bbls/d)	(Bbls/d)
Proved		32,118		20,903		209		513
Probable		1,282		1,156		2		28
Total Proved Plus Probable		33,399		22,059		211		541

(1) All of the Company's interests in reserves are royalty interests with no associated working interests. As a result, there are is no gross production associated with the Tourmaline GORR Lands.
(2) Net production represents the Company's royalty interests.
(3) Including by-products but excluding solution gas.
(4) No field accounts for more than 20% of the production estimate.

Production History Relating to the Tourmaline GORR Lands

Tourmaline Production History

The following tables summarize certain information in respect of Tourmaline's average production, product prices received, royalties paid, operating expenses and resulting netback from the Tourmaline GORR Lands for the periods indicated below:

	Quarter Ended2019(1)(2)(3)
	March 31	June 30	September 30	December 31
Average Daily Production(4)
Light and Medium Crude Oil (Bbl/d)	24,438	23,395	24,056	27,832
Conventional Natural Gas (Mcf/d)	1,015,357	957,066	917,294	925,580
Shale Natural Gas (Mcf/d)	423,855	414,259	485,174	514,166
NGL (Bbl/d)(3)	29,127	28,598	31,777	32,054
Combined (Boe/d)	293,434	280,547	289,578	299,844
Average Price Received
Light and Medium Crude Oil ($/Bbl)	62.29	75.49	71.92	65.08
Conventional Natural Gas ($/Mcf)	3.82	2.24	2.04	3.05
Shale Natural Gas ($/Mcf)	3.02	1.67	1.60	2.26
NGL ($/Bbl)(3)	23.93	9.29	12.74	15.58
Combined ($/Boe)	25.15	17.37	16.52	21.01
Royalties Paid
Light and Medium Crude Oil ($/Bbl)	5.79	7.19	6.93	6.65
Conventional Natural Gas ($/Mcf)(5)	0.02	(0.05)	(0.08)	(0.03)
Shale Natural Gas ($/Mcf)	0.31	0.08	0.01	0.07
NGL ($/Bbl)(3)	1.93	0.89	1.25	1.62
Combined ($/Boe)	1.20	0.63	0.47	0.82
Production Costs (includes transportation)
Light and Medium Crude Oil ($/Bbl)	14.74	12.96	13.97	14.19
Conventional Natural Gas ($/Mcf)	1.21	1.19	1.23	1.32
Shale Natural Gas ($/Mcf)	1.30	1.35	1.13	1.04
NGL ($/Bbl)(6)(3)	-	-	-	-
Combined ($/Boe)	7.30	7.14	6.95	7.19
Netback Received ($/Boe)(7)	16.65	9.60	9.10	13.00

Notes:

(1) Represents gross production and includes Exshaw from January 1, 2019 to October 31, 2019 and also includes Topaz from November 1, 2019 to December 31, 2019 (without reduction to reflect the 26% third-party minority interest in Topaz).

(2) Numbers may not add due to rounding.

(3) For the purposes of this disclosure, condensate has been combined with Light and Medium Crude Oil as the associated revenues and certain costs of condensate are similar to Light and Medium Crude Oil. Accordingly, NGL in this disclosure exclude condensate. The Tourmaline GORR Interest includes natural gas, crude oil, condensate and pentane and does not include other NGL production. Accordingly, no NGL are applicable to Topaz.
(4) Before deduction of royalties.
(5) Includes royalty reductions for the quarters ended March 31, June 30, September 30 and December 31 of $0.11/Mcf, $0.13/Mcf, $0.14/Mcf and $0.14/Mcf, respectively, relating to the entire Alberta Gas Cost Allowance credits received by Tourmaline.
(6) NGL volumes are derived from natural gas production, as such all the related operating costs are attributed to the production of natural gas.
(7) Netbacks are calculated by subtracting royalties and production costs from revenues.

The following table sets forth the average daily production volumes for the year ended December 31, 2019 for each of the important fields, aggregated by area, comprising the Tourmaline GORR Lands.

Area	Light Crude Oiland MediumCrude Oil(Bbl/d)	NGL(Bbl/d)	ConventionalNatural Gas(Mcf/d)	Shale Natural Gas(Mcf/d)	Total(boe/d)
Alberta Deep Basin	6,594	19,220	893,004	-	174,648
Other Alberta properties	7,933	1,249	60,474	-	19,261
British Columbia properties	10,410	9,932	-	459,682	96,956
Total(1)(2)	24,937	30,401	953,478	459,682	290,865

Notes:

(1) Includes the Company from January 1, 2019 to November 10, 2019.

(2) For the purposes of this disclosure, condensate has been combined with Light and Medium Crude Oil as the associated revenues and certain costs of condensate are similar to Light and Medium Crude Oil. Accordingly, NGL in this disclosure exclude condensate.

Tourmaline's production from the Tourmaline GORR Lands for the year ended December 31, 2019 was 8.6% light and medium crude oil (including condensate), 10.5% NGL, 54.6% conventional natural gas and 26.3% shale natural gas.

For the year ended December 31, 2019, approximately 37.3% of Tourmaline's gross revenue from the Tourmaline GORR Lands was derived from crude oil production (including NGL), 45.9% was derived from conventional natural gas production and 16.7% was derived from shale natural gas production.

Topaz Production History (royalty production)

The following tables summarize certain information in respect of Topaz's average royalty production, product prices received, marketing expenses and administrative expenses and resulting netback from the Tourmaline GORR Lands for the periods indicated below:

	Period or Quarter Ended(1)(2)(3)
	November 14 toDecember 31,2019	Three MonthsEnded March31, 2020	Three MonthsEnded June 30,2020
Average Daily Royalty Production(4)
Light and Medium Crude Oil (Bbl/d)	766	766	715
Conventional Natural Gas (Mcf/d)	37,163	37,520	34,399
Shale Natural Gas (Mcf/d)	20,968	20,152	20,657
Combined (Boe/d)	10,455	10,378	9,891
Average Product Price Received
Light and Medium Crude Oil ($/Bbl)	72.82	53.53	29.17
Conventional Natural Gas ($/Mcf)	2.56	2.05	2.00
Shale Natural Gas ($/Mcf)	2.56	2.05	2.00

	Period or Quarter Ended(1)(2)(3)
	November 14 toDecember 31,2019	Three MonthsEnded March31, 2020	Three MonthsEnded June 30,2020
Combined ($/Boe)	19.59	15.37	13.26
Administrative Costs
Light and Medium Crude Oil ($/Bbl)	0.36	0.28	0.24
Conventional Natural Gas ($/Mcf)	0.06	0.05	0.04
Shale Natural Gas ($/Mcf)	0.06	0.05	0.04
Combined ($/Boe)	0.36	0.28	0.24
Netback Received ($/Boe)(5)	19.23	15.09	13.02

(1) Represents Topaz's royalty share of production.
(2) Numbers may not add due to rounding.
(3) For the purposes of this disclosure, Light and Medium Crude Oil includes condensate as the associated revenues are similar and also includes immaterial revenues associated with pentane. The Tourmaline GORR Interest does not include other NGL production. Accordingly, no NGL have been included in this disclosure.
(4) No royalties are attributable to Topaz's share of royalty production.
(5) Netbacks are calculated by subtracting marketing expenses and estimated administrative costs from revenues. Topaz does not incur production or operating costs however Topaz pays a 1% marketing fee to Tourmaline as the Company's royalty production is marketed with the royalty payor's production and administrative costs include estimated expenses associated with accounting functions necessary to administer and collect royalty payments and are allocated to natural gas and oil based on each product's share of total product revenue.

AGREEMENTS WITH TOURMALINE AND OTHER COUNTERPARTIES

Agreements Relating to the E&P Asset Disposition

In conjunction with the E&P Asset Disposition, the Company and Tourmaline entered into the E&P Asset Disposition Agreement pursuant to which the Company sold the E&P Assets to Tourmaline for cash consideration of $285 million.

The purchase by Tourmaline of the E&P Assets was on an "as is, where is" basis, except for the express and limited representations, warranties and indemnities contained in the E&P Asset Disposition Agreement.

Subject to certain limitations, the Company and Tourmaline are liable to and indemnified one another for losses and liabilities suffered, sustained, paid or incurred as a direct result of any act, omission, circumstance or other matter arising out of, resulting from, attributable to or connected with any representations or warranties contained in the E&P Asset Disposition Agreement being untrue or incorrect or of a breach by either party of any of its respective covenants contained in the E&P Asset Disposition Agreement that were required to be performed or complied with at the closing time, provided that, no party will have any liability under the E&P Asset Disposition Agreement for any losses and liabilities or claims in respect of which a party, absent fraud, does not provide written notice thereof in reasonable detail to the other party within the 12-month period immediately following closing of the E&P Asset Disposition. As of the date hereof, no such notice has been provided or received by the Company.

In addition, Tourmaline agreed in the E&P Asset Disposition Agreement to be liable for, and indemnify the Company and its related persons, for all direct losses and liabilities of whatsoever nature or kind suffered, sustained, paid or incurred by Topaz or any of Topaz's related persons: (i) arising out of, resulting from, attributable to or connected with the E&P Assets, including the ownership or operation of the E&P Assets or under or in respect of the title and operating documents and any and all accounts receivable, accounts payable and any adjustments or prior period adjustments thereunder; or (ii) pertaining to the lands, wells, pipelines or any other tangibles, including any and all environmental liabilities, in each case whether any such losses and liabilities or claims arise out of, result from, are attributable to or are connected with events occurring before, on or after the effective time of the E&P Asset Disposition, whether known or unknown, except in respect of any losses and liabilities or claims arising out of, resulting from, attributable to or connected with taxes on income or capital gains accruing, attributable to or connected with events occurring prior to the effective time of the E&P Asset Disposition. The foregoing assumption of liability and indemnity of Tourmaline applies without limit and without regard to the negligence of Topaz or any of Topaz's related persons.

Agreements Relating to the Initial Acquisition

Initial Acquisition Agreements

In conjunction with the Initial Acquisition, the Company and Tourmaline entered into the Initial Acquisition Agreements pursuant to which the Company acquired all of the Initial Assets from Tourmaline.

The Initial Acquisition Agreements are comprised of: (i) the Initial Assets Purchase and Sale Agreement and (ii) the Initial Assets Ancillary Agreements, which include the Tourmaline GORR Agreement, the TPF Revenue Interest Agreement, the Initial Facilities Volume Commitment Agreements and the Initial Facilities CO&O Agreements.

Initial Assets Purchase and Sale Agreement

Pursuant to the Initial Assets Purchase and Sale Agreement, Topaz acquired the Tourmaline GORR Interest, the Initial Facility Interests and the TPF Revenue. Interest from Tourmaline for consideration consisting of $194.5 million in cash and 58,049,494 Common Shares.

The purchase by Topaz of the Initial Assets was on an "as is, where is" basis, except for the express representations, warranties and indemnities contained in the Initial Assets Purchase and Sale Agreement.

Subject to certain limitations, the Company and Tourmaline have agreed to be liable to and indemnify each other for claims that may be brought against the other or losses and liabilities that the other suffers a result of a breach of a representation or warranty or covenant of such party in the Initial Assets Purchase and Sale Agreement provided that Topaz is not liable or required to indemnify Tourmaline in respect of claims or losses and liabilities which are caused by the gross negligence or willful misconduct of Tourmaline or its representatives or are matters or things for which Topaz is entitled to indemnification by Tourmaline under the Initial Assets Purchase and Sale Agreement.

In addition, Topaz agreed that, subject to certain exceptions, from and after closing of the Initial Acquisition, it will be liable and indemnify Tourmaline for all claims or losses and liabilities that Tourmaline suffers, sustains, pays or incurs which arise out of any matter or thing occurring, accruing or arising on and after the closing date of the Initial Acquisition and which relates to the Initial Facility Interests and in respect of all past, present and future environmental liabilities related to the Initial Facilities, provided that a party is not liable for a breach of a representation and warranty in the Initial Assets Purchase and Sale Agreement unless notice of such breach is provided prior to November 14, 2020 or to the extent the loss is reimbursed by insurance carried by such party.

Tourmaline GORR Agreement

Pursuant to the Tourmaline GORR Agreement, Tourmaline granted the Tourmaline GORR Interest to Topaz out of Tourmaline's working interest in the Tourmaline GORR Lands, being an undivided interest in and to the petroleum substances within, upon or under the Tourmaline GORR Lands equal to 2.5% for crude oil and condensate, and 4% for natural gas until December 31, 2021 and 3% thereafter, free and clear of all encumbrances and deductions except as specified in the Tourmaline GORR Agreement.

Insofar as Topaz does not take its royalty share of petroleum substances in-kind, Topaz has appointed Tourmaline as its agent for the handling and disposition of its royalty share. Tourmaline has agreed to dispose of those petroleum substances on behalf of Topaz by selling them at market price (defined in the Tourmaline GORR Agreement by reference to third-party market indices and price quotations), or purchasing them for its own account, and in either case deducting therefrom a marketing fee of 1% of the proceeds. The market price, for the purposes of the Tourmaline GORR Agreement, is reflective of current month market indices in Alberta. Specifically, the Company's royalty share of natural gas production is priced using the AECO (5A) index, its royalty share of crude oil production is priced using Peace Sour (PSO) benchmark and its royalty share of condensate production is priced using the Namao/Peace C5+ benchmark.

Tourmaline has agreed to hold the petroleum substances attributable to the Tourmaline GORR Interest and the royalty share proceeds therefrom, net of a marketing fee of 1% of the royalty share proceeds, as trustee for Topaz and subject to the terms of the Tourmaline GORR Agreement. If not taken in-kind by Topaz, the royalty share of petroleum substances produced from the Tourmaline GORR Lands will be free and clear of any and all deductions whatsoever for costs and expenses incurred to the point of sale, other than the marketing fee.

Subject to the provisions of the Tourmaline GORR Agreement, Topaz may, on a minimum of 120 days notice to Tourmaline, revoke the agency established in the Tourmaline GORR Agreement and elect to take delivery of all or a portion of its royalty share of petroleum substances and separately dispose of the same.

Unless otherwise agreed to by Topaz, to the extent Topaz elects to take delivery of all or a portion of its royalty share of petroleum substances in-kind but fails to take possession of the same, Tourmaline may sell such royalty share as agent for Topaz; however, in such circumstance Tourmaline may only sell the petroleum substances comprising Topaz's royalty share under an arrangement that, as it affects those petroleum substances, is terminable at any time on not greater than one month's notice by Topaz to Tourmaline without an early termination penalty or other cost or such other notice period as is common for the nature of the transaction.

Tourmaline may commingle the royalty share of proceeds with its own funds, but notwithstanding such commingling, Tourmaline is deemed to be holding the royalty share proceeds in trust for Topaz. Tourmaline must remit to Topaz all funds accruing to Topaz on account of the Tourmaline GORR Interest on or before the 25th day of the calendar month next following the calendar month in which those funds were received by Tourmaline.

Topaz has a lien on Tourmaline's working interest in the Tourmaline GORR Lands, the wells and equipment thereon and the petroleum substances within, upon or under the Tourmaline GORR Lands or produced therefrom. Both the Tourmaline GORR Interest and the lien are interests in land that attach to Tourmaline's title documents and the lien is a charge and encumbrance against Tourmaline's working interest, and its successors and assigns with respect to all or any portion of Tourmaline's working interest. The lien does not preclude a party entering into any bona fide financing that requires a pledge or the granting of security.

In the event of the failure by Tourmaline to pay the Tourmaline GORR Interest or any other amounts owing to Topaz under the Tourmaline GORR Agreement within 5 business days of receiving notice of such default, in addition to any other right or remedy that Topaz may have under the Tourmaline GORR Agreement or at law, Topaz has the right to: (a) charge interest on any unpaid amounts at the prime rate of Tourmaline's primary bank plus 2%; (b) set-off against any amount unpaid by Tourmaline, any sums due or accruing to Tourmaline or any affiliate from Topaz under any agreement between Topaz and Tourmaline or any affiliate of Tourmaline; (c) maintain an action or actions for such unpaid amounts and interest thereon on a continuing basis as such amounts are payable, but not paid, as if the obligation to pay such amounts and the interest thereon were liquidated demands due and payable on the relevant date such amounts were due to be paid, without any right or resort to set-off or counter-claim by Tourmaline; (d) immediately commence to take in-kind all or a portion of the petroleum substances comprising the Tourmaline GORR Interest; and (e) exercise Topaz's lien and treat the payment default as an immediate and automatic assignment to Topaz of the proceeds of sale attributed to its royalty share of the petroleum substances from the Tourmaline GORR Lands, and give notice to purchasers of petroleum substances from Tourmaline requiring them to pay the proceeds of sale of its royalty share of petroleum substances from Tourmaline GORR Lands directly to Topaz's agent, which may be Topaz, and such purchasers of petroleum substances will be entitled to rely upon notice from Topaz to such effect and to thereafter pay the proceeds of sale accordingly.

If Tourmaline becomes subject to an insolvency event, Topaz may immediately commence to take in-kind all or a portion of the petroleum substances comprising the Tourmaline GORR Interest in accordance with the provisions of the Tourmaline GORR Agreement.

Tourmaline has agreed to keep and maintain true and correct books, records and accounts showing credits and charges under the Tourmaline GORR Agreement and the kind and quantity of petroleum substances produced from and attributed to the Tourmaline GORR Lands, and the disposition of Topaz's royalty share and Topaz has the right to audit Tourmaline's books, records and accounts, including production accounting and marketing records, with respect to the production, disposition or sale of the Tourmaline GORR Interest within 24 months next following the end of the applicable calendar year.

The Tourmaline GORR Agreement provides that except for Topaz's rights and obligations in the Tourmaline GORR Agreement with respect to Topaz's right to take its royalty share in-kind, Topaz is not liable for any of the duties and obligations arising in respect of the Tourmaline GORR Lands or under any of Tourmaline's title documents.

Pursuant to the Tourmaline GORR Agreement, Tourmaline has agreed to conduct operations on the Tourmaline GORR Lands in accordance with good operating practices but has the exclusive control and authority over development of, and recovery of petroleum substances from, the Tourmaline GORR Lands and lands pooled or unitized therewith, including, without limitation, making all decisions respecting whether, when and how to drill, complete, equip, produce, suspend, abandon and shut-in wells, whether and when to conduct maintenance activities and whether to elect to convert royalties to working interests. Nothing contained in the Tourmaline GORR Agreement imposes any obligation, expressed or implied, on Tourmaline to explore or develop the Tourmaline GORR Lands.

Tourmaline has agreed to indemnify and save Topaz, its affiliates and each of their respective directors, officers, employees, servants and agents, harmless from and against, all claims that may be brought against any of them or any and all losses and liabilities that any of them may suffer, sustain, pay or incur, by reason of any matter or thing arising out of or in any way attributable to the operations carried on by or on behalf of Tourmaline on or in connection with the Tourmaline GORR Lands, including in respect of any and all Environmental Liabilities (as defined in the Tourmaline GORR Agreement).

Tourmaline has agreed to: (a) not discriminate against petroleum substances produced or producible from the Tourmaline GORR Lands in the production and marketing thereof because they are subject to the Tourmaline GORR Interest and to use reasonable efforts to produce petroleum substances from a well subject to the Tourmaline GORR Interest equitably with production from any diagonally or laterally offsetting well producing from the same pool as such well, insofar as Tourmaline or an affiliate has an interest in the offsetting well; and (b) at its own cost, subject to the provisions of the Tourmaline GORR Agreement, take such actions as may be reasonably necessary to maintain its title documents pertaining to the Tourmaline GORR Lands in good standing provided that this does not, however, obligate Tourmaline to conduct any drilling, geophysical or geological operation for the Tourmaline GORR Lands or to pay compensatory royalty to maintain a title document, as it pertains to the Tourmaline GORR Lands, in full force and effect where the requirement to conduct such operation or to pay compensatory royalty may be avoided by the surrender of lands subject to the affected title document to the issuer thereof. Tourmaline may surrender, terminate or let expire any title documents pertaining to the Tourmaline GORR Lands that Tourmaline, in its sole discretion, determines not to develop or that Tourmaline determines are not capable of producing petroleum substances in paying quantities.

Topaz may transfer or assign the Tourmaline GORR Interest in whole or part, with the consent of Tourmaline not to be unreasonably withheld, conditioned or delayed. If Tourmaline disposes of all or any part of its working interest in the Tourmaline GORR Lands or any of them, it continues to be bound by, and is required to observe and perform all of the covenants and terms of the Tourmaline GORR Agreement as if there had been no disposition until such time as the party acquiring such interest is bound by, or deemed to be bound by the Tourmaline GORR Agreement insofar as they relate to the interest transferred or assigned. Upon the party acquiring such interest being bound or deemed to be bound by the Tourmaline GORR Agreement with respect to the interest transferred or assigned, Tourmaline shall be released and discharged from any and all liability and obligations thereafter accruing under the Tourmaline GORR Agreement relating to the Tourmaline GORR Lands, insofar as they relate to the interest so transferred or assigned.

TPF Revenue Interest Agreement

Pursuant to the TPF Revenue Interest Agreement, Tourmaline has agreed to contribute and dedicate the TPF Revenue received by Tourmaline to Topaz for each calendar year during the term of the TPF Revenue Interest Agreement as follows: (a) 100% of the first $16,000,000 of TPF Revenue received by Tourmaline; and (b) 70% of the TPF Revenue received by Tourmaline in excess of the $16,000,000 (collectively, the "TPF Revenue Interest").

Subject to certain limitations, Tourmaline is only required to account to Topaz for TPF Revenue actually received by Tourmaline. In connection therewith, Tourmaline agrees to use reasonable commercial efforts to realize, demand, recover, collect and enforce the payment by third parties of amounts owing to Tourmaline under the TPF Handling Agreements.

Tourmaline has agreed not to compromise, settle or waive the payment obligations of any third-party under a TPF Handling Agreement if the amount owing thereunder exceeds an agreed amount without the prior written consent of Topaz, which consent may not be unreasonably withheld, conditioned or delayed.

Tourmaline has the right to commingle the TPF Revenue with its own funds, but notwithstanding such commingling, Tourmaline is deemed to hold such TPF Revenue in trust for Topaz. Tourmaline will remit to Topaz all funds received by Tourmaline and accruing to Topaz on account of the TPF Revenue Interest on or before the 25th day of the calendar month next following the calendar month in which those funds were received by Tourmaline.

In the event of the failure by Tourmaline to pay the TPF Revenue or any other amounts owing to Topaz under the TPF Revenue Interest Agreement within 5 business days of receiving notice of such default, in addition to any other right or remedy that Topaz may have under the TPF Revenue Interest Agreement or at law, Topaz has the right to: (a) charge interest on any unpaid amounts at the prime rate of Tourmaline's primary bank plus 2%; (b) set-off against any amount unpaid by Tourmaline, any sums due or accruing to Tourmaline or any affiliate (other than Topaz) from Topaz under TPF Revenue Interest Agreement or any other agreement between Topaz and Tourmaline or any affiliate of Tourmaline (other than Topaz); (c) maintain an action or actions for such unpaid amounts and interest thereon on a continuing basis as such amounts are payable, but not paid, as if the obligation to pay such amounts and the interest thereon were liquidated demands due and payable on the relevant date such amounts were due to be paid, without any right or resort to set-off or counter-claim by Tourmaline;

Tourmaline has agreed to keep and maintain true and correct books, records and accounts of the TPF Revenue under the TPF Revenue Interest Agreement and Topaz has a number of audit and inspection rights thereunder.

Pursuant to the TPF Revenue Interest Agreement, Tourmaline has exclusive control and authority over the operation and maintenance of the TPF Facilities, the administration of the TPF Handling Agreements and the negotiation and entry into new TPF Handling Agreements at the TPF Facilities. Accordingly, Topaz is not liable for any of the duties and obligations arising in respect of the TPF Handing Agreements, the provision of handling services thereunder or the administration thereof, the TPF Facilities or the operation thereof, Tourmaline's financial obligations pertaining to the TPF Facilities or the operation thereof or any environmental liabilities pertaining to the TPF Facilities or the operation thereof.

The TPF Revenue Interest Agreement provides that: (a) the TPF Handling Agreements are short-term contracts that may be terminated by either party thereto with notice; (b) Tourmaline has no obligation to maintain the TPF Handling Agreements in place or provide handling services to third parties under the TPF Handling Agreements beyond the date of expiration or termination of such TPF Handling Agreements; and (c) the TPF Revenue Interest relates solely to Tourmaline's interest in the TPF Facilities from time to time, and there are no restrictions on the ability of Tourmaline to reduce its interest in the TPF Facilities or otherwise, to require a third-party assignee of any of Tourmaline's interest in the TPF Facilities to assume any obligations of Tourmaline under TPF Revenue Interest Agreement.

In accordance with the TPF Revenue Interest Agreement, Tourmaline has agreed to indemnify and save Topaz, its directors, officers, employees, servants and agents, harmless from and against, all claims that may be brought against any of them or any and all losses and liabilities that any of them may suffer, sustain, pay or incur, by reason of any matter or thing arising out of or in any way attributable to: (i) the TPF Handling Agreements, (ii) the provision of handling services thereunder and the administration thereof; (iii) the TPF Facilities and the operation thereof; (iv) all financial obligations pertaining to the TPF Facilities and the operation thereof; and (v) all environmental liabilities pertaining to the TPF Facilities and the operation thereof.

Topaz may transfer or assign its interest in the TPF Revenue Interest Agreement in whole or part. Tourmaline may assign all or any portion of its interest in any of the TPF Facilities, in its sole discretion, without assigning a corresponding interest in the TPF Revenue Interest Agreement to the assignee and without the consent of Topaz.

Unless otherwise agreed to by both parties, the TPF Revenue Interest Agreement remains in effect until a date that is the earliest of: (a) with respect to any particular TPF Handling Agreement or TPF Facility, upon the termination or expiry of that TPF Handling Agreement in accordance with its terms or the date on which Tourmaline no longer has an ownership interest in that TPF Facility (whichever occurs earlier); and (b) in its entirety, the date that Tourmaline no longer has an ownership interest in any of the TPF Facilities.

Initial Facilities Volume Commitment Agreements

Pursuant to the Initial Facilities Volume Commitment Agreements, Tourmaline has agreed, during each year of the term of the agreements, to deliver prescribed volumes of petroleum substances produced from wells in which Tourmaline has a beneficial ownership interest to the applicable Initial Facility. The take-or-pay volume commitment for each year is equal to a daily committed volume (which varies by facility) multiplied by the number of operational days in that year. Tourmaline has agreed to pay a fixed fee per MMcf in respect of the annual volume commitment. The daily committed volume and fixed fee in respect of each Initial Facility are as follows: Brazeau: 17.5 MMcf/d - $0.70/Mcf; and Musreau: 32.5 MMcf/d - $0.70/Mcf. If the volumes actually delivered by Tourmaline to the applicable facility in any month are less than the monthly volume commitment, Tourmaline is required to pay to Topaz an amount equal to the fixed fee per MMcf for the applicable facility multiplied by the amount of the deficit volumes.

For the purposes of calculating the annual volume commitment, the number of days in a given year will be reduced to account for days on which Tourmaline is unable to deliver the daily committed volume to the applicable facility as a result of force majeure or outage (subject to a maximum of 15 outage days per year).

Topaz has the right to audit Tourmaline's books, records and accounts with respect to payments made to Topaz and deductions taken from the volumes received by Topaz under the Initial Facilities Volume Commitment Agreements.

The Initial Facilities Volume Commitment Agreements commenced on November 14, 2019 and terminate on November 14, 2034.

If either party assigns an interest in the applicable Initial Facility, such party must assign a corresponding interest in the applicable Initial Facilities Volume Commitment Agreement to the same assignee. Neither party may otherwise assign the Initial Facilities Volume Commitment Agreements or any interest in the Initial Facilities Volume Commitment Agreement to any third-party.

Initial Facilities CO&O Agreements

The Initial Facilities CO&O Agreements have substantially similar terms. These agreements outline, among other things, the operating procedure for the applicable facility, which is the operating procedure contained in the 1999 Petroleum Joint Venture Association (PJVA) Model Construction, Ownership and Operating Agreement, subject to the elections and modification made to such document as stipulated in the applicable Initial Facilities CO&O Agreements. The purpose of the Initial Facilities CO&O Agreements is to document the terms of ownership of the Initial Facilities, the allocation of facility costs, provide terms for the operation of the facility and set out the basis upon which a share of the facility products will be allocated and distributed to each person delivering petroleum substances to the facility. Tourmaline and Topaz are the only parties to the Initial Facilities CO&O Agreements, as they are the only owners of the Initial Facilities.

Pursuant to the Initial Facilities CO&O Agreements, Tourmaline has been designated as the initial operator of the Initial Facilities.

The Initial Facilities CO&O Agreements also specify the order of capacity utilization within the facilities. In particular, all petroleum substances delivered to the applicable facility by Tourmaline are allocated to Topaz's ownership share of capacity up to a maximum volume equal to the committed volume specified in the applicable Initial Facilities Volume Commitment Agreement. Thereafter, petroleum substances delivered by Tourmaline and third parties are allocated to both Topaz and Tourmaline in proportion to their respective ownership interests, and Topaz is entitled to a processing fee applicable to all volumes delivered to the facility which utilize its ownership capacity (including those volumes delivered by Tourmaline and by third parties). As a result of this volume allocation methodology, Topaz earns Processing Revenue on all volume delivered to the applicable facility until its share of the capacity in the facility is full. The Initial Facilities CO&O Agreements also set out the order of cutbacks in the event that the applicable facility cannot handle all inlet substances delivered on a day and specify that the volumes delivered by Tourmaline pursuant to the Initial Facilities Volume Commitment Agreements and which utilize Topaz's capacity have the highest priority and are last to be cutback.

Pursuant to the Initial Facilities CO&O Agreements, Topaz and Tourmaline are responsible for capital and operating costs in proportion to their ownership interest, which for Topaz is 45%.

The full text of the Initial Acquisition Agreements are available on SEDAR at www.sedar.com under the Company's profile.

Agreements Relating to the Glacier Plant Acquisition

In conjunction with the Glacier Gas Plant Acquisition, the Company and Advantage entered into the Glacier Gas Plant Acquisition Agreement, the Glacier Volume Commitment Agreement and the Glacier O&O Agreement. These agreements are substantially similar in all material respects to the Initial Assets Purchase and Sale Agreement (as it relates to the Initial Facilities), the Initial Facilities Volume Commitment Agreements and the Initial Facilities CO&O Agreements, respectively, except: (a) the purchase price for the Glacier Gas Plant was cash consideration of $100 million, before customary adjustments; (b) the Glacier Volume Commitment Agreement commenced on July 1, 2020 and terminates on July 1, 2035; (c) the daily committed take-or-pay volume and fixed fee in respect of the Glacier Gas Plant are 50 MMcf/d and $0.66/Mcf, respectively; (d) for the purposes of calculating the annual take-or-pay volume commitment, the number of days in a given year is not reduced to account for days on which Advantage is unable to deliver the daily committed volume as a result of force majeure or outage; and (e) pursuant to the Glacier O&O Agreement, Advantage is responsible for all operating and maintenance capital expenditures for the duration of the Glacier Volume Commitment Agreement, which is fifteen years, and thereafter Topaz and Advantage are responsible for maintenance capital and operating costs in proportion to their respective ownership interests, which for Topaz is 12.5%. During the term of the Glacier Volume Commitment Agreement, in the event of a proposed enlargement or modification to the Glacier Gas Plant, the Company has the right but not the obligation to participate and if it does not participate, the enlargement or modification will be implemented as a new functional unit, to the extent that it is reasonably feasible to do so (and in no event will Topaz's share of capacity in the plant be reduced below 50 MMcf/d). Advantage has been designated as the initial operator of the Glacier Gas Plant.

Agreements Relating to the Banshee Gas Plant Acquisition

In conjunction with the Banshee Gas Plant Acquisition the Company and Tourmaline entered into the Banshee Gas Plant Acquisition Agreement, the Banshee Volume Commitment Agreement and the Banshee CO&O Agreement. These agreements are substantially similar to the Initial Assets Purchase and Sale Agreement (as it relates to the Initial Facilities), the Initial Facilities Volume Commitment Agreements and the Initial Facilities CO&O Agreements except: (a) the purchase price for the Banshee Gas Plant was cash consideration of $52.5 million, before customary adjustments; (b) the Banshee Volume Commitment Agreement commenced on September 1, 2020 and terminates on August 31, 2035; (c) the daily committed volume and fixed fee in respect of the Banshee Gas Plant are 25 MMcf/d and $0.60/Mcf, respectively; (d) interruptible volume utilizing Topaz's remaining share of capacity is subject to a processing fee of $0.50/Mcf; and (e) pursuant to the Banshee CO&O Agreement, Topaz and Tourmaline are responsible for capital and operating costs in proportion to their respective ownership interests, which for Topaz is 25%. Tourmaline has been designated as the initial operator of the Banshee Gas Plant. All revenue generated from natural gas processing services provided to third parties (excluding Tourmaline) at the Banshee Gas Plant is allocated to Topaz pursuant to the TPF Revenue Interest Agreement.

Management Services Agreement

In conjunction with the Initial Acquisition, the Company and Tourmaline entered into the Management Services Agreement pursuant to which Tourmaline has agreed to provide or arrange for the provision of certain management and administrative services required by the Company for an aggregate monthly fee initially set at $0.2 million and scheduled to be reduced by 25% per quarter through 2020, and reimbursement of associated out-of-pocket costs and expenses until December 31, 2020, subject to earlier termination in certain circumstances and subject to extension upon mutual agreement of the parties.

During the three and six months ended June 30, 2020, the Company paid $0.5 million and $1.1 million, respectively, in respect of the Management Services Agreement which were in the normal course of operations. The services provided under the Management Services Agreement and the associated fees are scheduled to be reduced on a quarterly basis through 2020 as the Company adds its own personnel and administrative functions.

The full text of the Management Services Agreement is available on SEDAR at www.sedar.com under the Company's profile.

Governance Agreement

In conjunction with the Initial Acquisition, the Company and Tourmaline entered into the Governance Agreement that governs various aspects of their relationship.

Under the Governance Agreement, Tourmaline is entitled to nominate the greater of two and 33.33% of the members of the Board (rounded up to the next whole number, if applicable) for so long as the percentage of outstanding Common Shares (on a non-diluted basis) beneficially owned directly or indirectly by Tourmaline is not less than 10% of the issued and outstanding Common Shares. The nominees of Tourmaline to the Board may be directors, officers or employees of Tourmaline or its affiliates, or other persons, at Tourmaline's discretion. Subject to any requirements of the ABCA, Tourmaline is entitled to nominate for appointment or election to the Board a replacement director for any vacancy on the Board, provided Tourmaline remains, at that time, entitled to appoint such director.

If an individual nominated by Tourmaline fails to be elected by the shareholders as a director of the Board, Tourmaline shall have the right to designate such individual as an observer of the Board (a "Board Observer"). The Board Observer shall be entitled to: (i) receive notice of and to attend meetings of the Board; (ii) take part in discussions and deliberations of matters brought before the Board; (iii) receive notices, consents, minutes, documents and other information and materials that are sent to members of the Board; and (iv) receive copies of any written consent resolutions proposed to be adopted by the Board, including any resolution as approved, each at substantially the same time and in substantially the same manner as the members of the Board, except that the Board Observer shall not be entitled to vote on any matters brought before the Board. The Board Observer will also not be entitled to any compensation from the Company, except that reasonable out-of-pocket expenses of the Board Observer shall be reimbursed by the Company.

To the fullest extent permitted by law, the Company will indemnify all current and former nominees of Tourmaline appointed to the Board and Board Observers and their heirs and legal representatives, against all costs, charges and expenses, including an amount paid to settle any action or satisfy a judgment, reasonably incurred by him or her in respect of any civil, criminal, administrative, investigative or other proceeding in which the individual is involved because of that association with the Company if he or she: (i) acted honestly and in good faith with a view to the best interests of the Company; and (ii) in the case of a criminal or administrative action or proceeding that is enforced by a monetary penalty, had reasonable grounds for believing that his or her conduct was lawful.

Under the Governance Agreement, the Company has also provided Tourmaline with certain rights to participate in future offerings of securities by the Company. Provided Tourmaline beneficially owns, directly or indirectly, not less than 10% of the issued and outstanding Common Shares and subject to limited exceptions, if the Company proposes to, or reasonably anticipates that it will, issue any Common Shares (the "Offered Securities") or other securities convertible into or exercisable or exchangeable for Offered Securities (the "Convertible Securities"), the Company will promptly first offer Tourmaline the opportunity to subscribe for and acquire that number of Offered Securities or Convertible Securities equal in amount to Tourmaline's then outstanding proportionate interest in the Common Shares or any such lesser amount as Tourmaline may elect to subscribe for at the subscription price as determined by the Board. If any of the Offered Securities or Convertible Securities are not subscribed for by Tourmaline within the applicable periods provided for in the Governance Agreement, the Company may proceed to offer such unsubscribed Offered Securities or Convertible Securities within the period of 60 days after the expiration of such applicable period to any person, provided the price at which such Offered Securities or Convertible Securities are issued is not less than the subscription price offered to Tourmaline and the terms of payment for such Offered Securities or Convertible Securities are not more favourable to such person than the terms of payment offered to Tourmaline.

The foregoing rights will also apply to any debt securities or securities convertible into debt securities issued by the Company on the basis that Tourmaline shall be offered the right to subscribe for up to that percentage of the total aggregate principal amount of debt securities or number of securities convertible into debt securities to be issued equal to the percentage of outstanding Common Shares then beneficially owned by Tourmaline. Furthermore, such rights will apply to any Offered Securities issued by the Company for proceeds other than cash, including in connection with any acquisition, business combination or similar transaction, and Tourmaline shall be offered the right to subscribe for such number of Common Shares or Convertible Securities, at a market-based price, to entitle Tourmaline to maintain its proportionate ownership of Common Shares, or such lesser amount as Tourmaline may elect. Tourmaline will also be entitled to subscribe for, no more than once per fiscal quarter and at a market-based price, such number of additional Common Shares to allow Tourmaline to maintain its proportionate ownership of Common Shares, or such lesser amount as Tourmaline may determine, after giving effect to issuances of Common Shares by the Company pursuant to compensation plans or similar plans.

The Governance Agreement provides that, for so long as Tourmaline beneficially owns not less than 35% of the issued and outstanding Common Shares and subject to certain exceptions, the Company will be required to seek Tourmaline's prior written consent to: (i) issue any Common Shares, other equity or voting securities of the Company or any Convertible Securities, or to otherwise modify the capitalization of the Company; (ii) undertake a material change in the business of the Company; (iii) increase the size of the Credit Facility, create additional credit facilities or incur alternative indebtedness, in each case in aggregate in excess of $20 million in any one fiscal year; or (iv) become party to or engage in any hedging, swap, derivative or similar agreements or activities.

For so long as Tourmaline is required to consolidate the results of operations and financial position of, or account for its investment in, the Company, the Company will provide Tourmaline with certain financial, reserves and resources and other information and data with respect to the Company and its business, properties, financial positions, results of operations and prospects, as may reasonably be required by Tourmaline to meet its reporting obligations. In addition, the Company will be obligated to, among other things: (i) maintain effective disclosure controls and procedures and to comply with applicable securities laws; (ii) provide financial reports to Tourmaline in connection with each meeting of the board of directors of Tourmaline and meeting of the audit committee and reserves committee of Tourmaline; (iii) prepare all financial, reserves and resources and other information to be provided by the Company to Tourmaline or filed with any securities regulatory authority, in accordance with applicable securities laws; (iv) consult with Tourmaline as to the timing of any financial guidance or any updates to reserves or resources information in respect of the Company for a current or future period that the Company intends to publish or otherwise make public, and give Tourmaline the opportunity to review the information therein relating to the Company and to comment thereon; (v) provide Tourmaline with drafts of all reports, notices and proxy and information statements to be filed with any securities regulatory authorities and consult with Tourmaline regarding changes thereto, particularly with respect to any changes that would have an effect upon the financial statements, reserves information or related disclosure of Tourmaline; (vi) propose for appointment by its shareholders KPMG LLP and appoint GLJ Petroleum Consultants Ltd. to serve as the Company's auditors and independent qualified reserves evaluators, respectively, unless Tourmaline provides its prior written consent to the appointment of any other party as the Company's auditors or independent qualified reserves evaluators, such consent to not be unreasonably withheld; and (vii) cooperate fully, and use commercially reasonable efforts to cause the auditors and independent qualified reserves evaluators of the Company to reasonably cooperate, with Tourmaline to the extent reasonably requested by Tourmaline in the preparation of any filings made by Tourmaline with any securities regulator pursuant to applicable securities laws.

The Governance Agreement will continue in force until the earlier of (i) the date on which the Governance Agreement is terminated by the written agreement of Tourmaline and the Company; or (ii) the date on which Tourmaline beneficially owns directly or indirectly less than 10% of the issued and outstanding Common Shares (on a non-diluted basis). Certain of the rights and obligations under the Governance Agreement, other than the requirements for the Company to provide certain information to Tourmaline as described in the foregoing paragraph and certain tax-related provisions, may be assignable to a transferee of Common Shares, upon notice to the Company, other than in respect of transfers made pursuant to a public prospectus offering. See "Risk Factors – Risks Relating to the Company's Relationship with Tourmaline – Future Changes in Relationship with Tourmaline".

The full text of the Governance Agreement is available on SEDAR at www.sedar.com under the Company's profile.

Investor Liquidity Agreement

In conjunction with the Initial Acquisition, Tourmaline and the Company entered into the Investor Liquidity Agreement. The Investor Liquidity Agreement provides that Tourmaline and any direct or indirect transferee of Tourmaline who shall become party to the Investor Liquidity Agreement (each a "Holder") may, at any time and from time to time, make a written request to the Company to file a prospectus in any jurisdiction or jurisdictions of Canada (a "Demand Registration") in respect of the distribution of all or part of the Common Shares then held by the Holder ("Registrable Securities"), subject to certain restrictions as discussed below. Upon receipt by the Company of a Demand Registration, the Company will be required to use its reasonable commercial efforts to file a prospectus in order to permit the offer and sale or other disposition or distribution in Canada of all or any portion of the Registrable Securities. The Company may satisfy its obligations through the use of a shelf prospectus and applicable shelf prospectus supplements or, in the case of a private placement, a private placement memorandum, and, in connection therewith, each Holder agrees to reasonably cooperate with the Company in connection with the filing of such shelf prospectus.

The Demand Registration rights are subject to certain limitations, including that: (i) other than in respect of a shelf prospectus, the Company shall not be obligated to file a prospectus in respect of a Demand Registration within 60 days after the effective date of a previously filed prospectus; and (ii) the Company shall not be obligated to file a prospectus in respect of a Demand Registration unless the request is for a number of Registrable Securities with a market value that is equal to at least $50 million as of the date of such request for Demand Registration. If the Company declines to effect a Demand Registration pursuant to (i) or (ii) above, and if the Holder within 30 days after receipt of a notice from the Company advises that it has determined to withdraw such request for a Demand Registration, then such Demand Registration and the request therefor will be deemed to be withdrawn and such request will be deemed not to have been given for purposes of determining whether such Holder has exercised its right to a Demand Registration permitted to such Holder.

In the event that a majority of the members of the Board who have not been nominated by Tourmaline (the "Independent Directors") determine, in their good faith judgment, that any Demand Registration should not be made or continued because it would materially adversely affect a pending or proposed material acquisition, merger, amalgamation, recapitalization, consolidation, reorganization, business combination, or similar transaction, or negotiations, discussions or pending proposals with respect thereto, or would require the disclosure of material non- public information that, in the good faith judgment of a majority of the Independent Directors would have a material adverse effect on the Company and its subsidiaries taken as a whole (a "Valid Business Reason") then: (i) the Company will have the right to postpone the filing of a prospectus (or prospectus supplement, as applicable) until such Valid Business Reason no longer exists, provided that such postponement shall not extend for a period of more than 90 days after receipt of the request for such Demand Registration; or (ii) the Company may cause a prospectus (or prospectus supplement, as applicable) that has been filed pursuant to a Demand Registration request to be withdrawn, or a majority of the Independent Directors may postpone amending or supplementing any previously filed prospectus pursuant to a Demand Registration request until such Valid Business Reason no longer exists, provided that such withdrawal or postponement shall not extend for a period of more than 90 days. The Company may not exercise its rights pursuant to (i) or (ii) above more than once in any 12-month period, and the Company will give written notice of both its determination to defer filing, postpone the amendment of or withdraw a prospectus (or prospectus supplement, as applicable) and of the fact that the Valid Business Reason for such deferral, postponement or withdrawal no longer exists, in each case, promptly after the occurrence thereof.

Under certain circumstances, the Holder may revoke or withdraw a request for a Demand Registration, in whole or in part, and such Demand Registration and the request therefor may, subject to certain limitations, be deemed to be revoked or withdrawn and deemed not to have been given for purposes of determining whether such Holder has exercised its right to a Demand Registration permitted to such Holder. Further, the Company may not propose to qualify for distribution any authorized but unissued Common Shares in connection with a Demand Registration if the Holder, with the assistance of its underwriter or agent, if applicable, determines, acting reasonably, that qualifying such Common Shares for distribution exceeds the number of Common Shares that can be sold in an orderly manner in such offering within a price range acceptable to the Holder ("Demand Registration Orderly Sale Number"). The Company shall then include in such distribution: (i) first, the number of Registrable Securities requested to be included in the Demand Registration; and (ii) second, such Common Shares equal to (X) the Demand Registration Orderly Sale Number less (Y) the number of Registrable Securities requested to be included in the Demand Registration, subject to certain conditions.

If at any time the Company proposes to, or reasonably contemplates that it will, file a preliminary prospectus with respect to the distribution of any Common Shares to the public, then the Company will, at that time, give prompt notice of the proposed distribution to each Holder, which notice will offer each Holder the opportunity to qualify for distribution such number of Registrable Securities as such holder may request. The Company will use commercially reasonable efforts to include in such prospectus such Registrable Securities as the Holders may request (a "Piggy-Back Registration"), unless the Company, with the assistance of its underwriter or agent, if applicable, determines, acting reasonably, that qualifying such Piggy-Back Registration exceeds the number of Common Shares that can be sold in an orderly manner in such offering within a price range acceptable to the Company ("Piggy-Back Registration Orderly Sale Number"). The Company shall then include in such distribution: (i) first, the number of Common Shares that is proposed to be qualified for distribution by such preliminary prospectus by the Company as specified in its notice to the Holder; and (ii) second, such Registrable Securities that are equal to (X) the Piggy-Back Registration Orderly Sale Number less (Y) the number of Common Shares that are proposed to be qualified for distribution by such preliminary prospectus by the Company as specified in its notice to the Holder, subject to certain conditions.

In the case of a prospectus filed in connection with a Demand Registration, the Holder will pay all applicable fees and expenses incidental to the Company's performance of, or compliance with, the terms of the Demand Registration customarily paid by issuers or sellers of securities. In the case of a Piggy-Back Registration or the Company's participation in a Demand Registration, such fees and expenses will be allocated between the Holder(s), as applicable, and the Company in an equitable manner having regard to the proportion of the number of Common Shares sold by each relative to the total number of Common Shares sold pursuant to the prospectus.

All underwriting discounts and fees and transfer taxes attributable to a sale of Registrable Securities, and any out-of-pocket expenses of the underwriters in connection with each prospectus filed in connection with a Demand Registration or Piggy-Back Registration, other than the fees and expenses described in the preceding paragraph, will be borne by the Holder(s), as applicable, and any other participating sellers (including the Company, if applicable) in proportion to the number of Registrable Securities sold by each relative to the total number of Common Shares sold pursuant to the prospectus.

The Investor Liquidity Agreement will continue in force until the earlier of the date on which: (i) there are no longer any outstanding Registrable Securities; (ii) the Holders, collectively, beneficially own, directly or indirectly, 10% or less of the issued and outstanding Common Shares; or (iii) the Investor Liquidity Agreement is terminated by written agreement of all parties to the Investor Liquidity Agreement. Tourmaline or its assignees may assign its rights and obligations under the Investor Liquidity Agreement to a transferee of Common Shares, upon notice to all parties to the Investor Liquidity Agreement, other than in respect of transfers made pursuant to a public prospectus offering.

The full text of the Investor Liquidity Agreement is available on SEDAR at www.sedar.com under the Company's profile.

DESCRIPTION OF SHARE CAPITAL

The authorized share capital of the Company includes an unlimited number of Common Shares, an unlimited number of First Preferred Shares, issuable in series, and an unlimited number of Second Preferred Shares, issuable in series. As of September 24, 2020, 93,208,296 Common Shares and no First Preferred Shares or Second Preferred Shares were issued and outstanding.

General Description of Capital Structure

The authorized share capital of the Company consists of an unlimited number of Common Shares and an unlimited number of First Preferred Shares, issuable in series, and an unlimited number of Second Preferred Shares, issuable in series.

The following is a summary of the rights, privileges, restrictions and conditions attaching to the shares in the Company's share capital.

Common Shares

Topaz is authorized to issue an unlimited number of Common Shares. Holders of Common Shares are entitled to receive notice of and to attend and vote at all meetings of shareholders of the Company, except meetings of holders of another class of shares. Subject to the rights of the holders of First Preferred Shares and Second Preferred Shares and any other shares having priority over the Common Shares, holders of Common Shares are entitled to dividends if, as and when declared by the Board and upon liquidation, dissolution or winding-up to receive the remaining property of the Company.

First Preferred Shares

The First Preferred Shares are issuable in series and will have such rights, restrictions, conditions and limitations as the Board may from time to time determine. No First Preferred Shares have been issued.

The Company is authorized to issue an unlimited number of First Preferred Shares. Holders of First Preferred Shares are entitled, in priority to holders of Common Shares and Second Preferred Shares, to receive the amount of accumulated dividends, if any, specified as being paid preferentially to the holders of First Preferred Shares as and when declared by the Board. In the event of a liquidation, dissolution or winding-up of the Company, holders of the First Preferred Shares are entitled, in priority to the holders of the Common Shares and Second Preferred Shares, to receive a rateable share of the amount, if any, specified as being paid preferentially to the holders of First Preferred Shares.

Second Preferred Shares

The Second Preferred Shares are issuable in series and will have such rights, restrictions, conditions and limitations as the Board may from time to time determine. No Second Preferred Shares have been issued.

The Company is authorized to issue an unlimited number of Second Preferred Shares. Holders of Second Preferred Shares are entitled, subject to the preference of First Preferred Shares but in priority to holders of Common Shares, to receive the amount of accumulated dividends if any, specified as being paid preferentially to the holders of Second Preferred Shares as and when declared by the Board,

In the event of a liquidation, dissolution or winding-up of the Company, holders of the Second Preferred Shares are entitled, subject to preference accorded to holders of First Preferred Shares but in priority to the holders of the Common Shares, to receive a rateable share of the amount, if any, specified as being paid preferentially to the holders of Second Preferred Shares.

Constraints

There are currently no constraints imposed on the ownership of securities of the Company to ensure that the Company has a required level of Canadian ownership.

Ratings

The Company has not asked for, nor has it received, a stability rating, or to the knowledge of the Company, has received any other kind of rating, including, a provisional rating, from one or more approved rating organizations for securities of the Company that are outstanding and which continue in effect.

USE OF PROCEEDS

Topaz expects to receive approximately $• million in net proceeds from the Treasury Offering, after deducting that portion of the Underwriters' Commissions payable by the Company to the Underwriters in connection with the Treasury Offering of approximately $• million and the estimated expenses of the Offering of approximately $3 million. Topaz intends to use the net proceeds from the Treasury Offering for additional royalty and energy infrastructure acquisitions as well as for working capital and general corporate purposes. The aggregate net proceeds to be received by the Selling Shareholder from the sale of Common Shares pursuant to the Secondary Offering are estimated to be $• million, after deducting that portion of the Underwriters' Commissions payable by the Selling Shareholder to the Underwriters in connection with the Secondary Offering of approximately $• million. The Company will not receive any of the proceeds payable to the Selling Shareholder under the Secondary Offering. As the incremental expenses of the Secondary Offering are not anticipated to be material, the Company has agreed to pay the expenses associated with the Secondary Offering and, as a result, the Selling Shareholder will not pay any expenses of the Offering other than the Underwriters' Commissions in respect of the Secondary Offering. The Company will pay all other expenses of the Offering. See "Plan of Distribution" and "Proceeds to the Selling Shareholder".

PROCEEDS TO THE SELLING SHAREHOLDER

The net proceeds to the Selling Shareholder from the Offering will be approximately $• after deducting that portion of the Underwriters' Commissions payable by the Selling Shareholder to the Underwriters in connection with the Secondary Offering of approximately $• million. The Underwriters' Commissions payable to the Underwriters by the Selling Shareholder will be paid out of the proceeds of the Secondary Offering. See "Use of Proceeds", "Plan of Distribution" and "Principal Shareholders and Selling Shareholder".

SELECTED HISTORICAL AND PRO FORMA FINANCIAL AND PRODUCTION INFORMATION

The following selected historical financial information relating to the Initial Assets has been derived from the Topaz Financial Statements.

($000s except per share amounts)	Three months endedJune 30, 2020	Six months endedJune 30, 2020	Nov. 14 toDec. 31, 2019(1)
Royalty production revenue	$ 11,935	$ 26,449	$ 9,832
Processing revenue	5,296	11,264	2,943
Other income	2,789	5,066	1,408
Realized loss on financial instruments	(188)	(188)	─
Unrealized loss on financial instruments	(637)	(552)	─
	19,195	42,039	14,183
Expenses
Operating	1,016	1,871	481
Marketing	122	212	98
General and administrative	1,249	2,243	1,331
Share-based compensation	204	353	25
Finance	62	64	2
Depletion and depreciation	18,612	41,805	11,671
	21,265	46,548	13,608
Net income (loss) from continuing operations	(2,070)	(4,509)	575
Deferred tax recovery	(945)	(2,150)	(78)
Net income (loss) from continuing operations	(1,125)	(2,359)	653

Selected Historical Financial Information from Continuing Operations(1) ($000s except per share amounts and %)

		$ (350)
17,385	38,205	12,273
17,445	38,265	12,273
		87%
159	271	2
16,000	32,000	─
$0.20	$0.40	─
17,226	37,934	12,271
87%	89%	87%
93%	84%	─
793,323	793,323	697,234
148,745	148,745	20,767
149,180	149,180	20,767
(149,180)	(149,180)	(20,767)
	$24,23488%	$38,18490%

Notes:

(1) Topaz commenced its current operations November 14, 2019, all subsequent financial results are presented as continuing operations. The Company's financial results prior to November 14, 2019 are presented as discontinued operations. Refer to the Topaz Financial Statements.
(2) See "Notice to Investors - Non-GAAP Financial Measures".
(3) Statement of financial position information is as of end of period.
(4) Weighted average Common Shares outstanding during the period.

See "Exemptions from Certain Disclosure Requirements".

Selected Pro Forma Financial Information for the Initial Assets

The following selected pro forma financial information relating to the Initial Assets has been derived from the Topaz Pro Forma Operating Statements.

($000s)	Year endedDecember 31, 2019	Year endedDecember 31, 2018	Year endedDecember 31, 2017
Royalty production revenue	52,957	44,290	49,375
Processing revenue	21,587	21,793	21,654
Other income	13,219	20,310	21,401
	87,763	86,393	92,430
Expenses
Operating	(3,809)	(3,280)	(2,933)
Operating income	83,954	83,113	89,497

Selected Pro Forma Production Information for the Initial Assets

The following selected pro forma financial information relating to the Initial Assets has been derived from the Topaz Pro Forma Operating Statements.

	Year endedDecember 31, 2019	Year endedDecember 31, 2018	Year endedDecember 31, 2017
Average royalty production
Natural gas (Mcf/d)	56,514	52,182	48,834
Oil & condensate (Bbl/d)	691	621	515
Total (Boe/d)	10,110	9,318	8,654
Royalty production weighting (% natural gas)	93%	93%	94%
Realized commodity prices
Natural gas ($/Mcf)	$1.78	$1.52	$2.18
Oil ($/Bbl)	$65.65	$62.66	$58.64
Condensate ($/Bbl)	$69.03	$75.85	$65.23

ANALYSIS OF ADJUSTED PRO FORMA REVENUE, EBITDA AND EBITDA MARGIN

For the year ended Dec. 31, 2019($000s)	Pro FormaTopaz(1)	Glacier Gas PlantAcquisition(2)	Banshee Gas PlantAcquisition(3)	AdjustedPro Forma(4)
Royalty production revenue	$52,957	─	─	$52,957
Processing revenue	21,587	12,045	7,884	41,516
Other income	13,219	─	─	13,219
	87,763	12,045	7,884	107,692
Expenses
Operating expense	3,809	─	1,035	4,844
Net operating income	83,954	12,045	6,849	102,848
Adjusted Pro Forma EBITDA Adjustments:
Marketing expense(5)				530
General and administrative expense(6)				5,000
Total				5,530
Adjusted Pro Forma EBITDA(7)				97,318
Adjusted Pro Forma EBITDA Margin(8)				90%

Notes:

(1) See the Topaz Pro Forma Operating Statements which were derived from (i) the Initial Acquisition Operating Statements, which reflect the gross petroleum and natural gas revenue, royalty expenses, other income, operating expenses and operating income for the period ending December 31, 2019; (ii) the Topaz Financial Statements; and (iii) the Initial Acquisition Agreements. Together, the information was then adjusted to reflect the estimated financial results had the Initial Acquisition Agreements been in place effective January 1 of each year. The pro forma Topaz amounts may not be indicative of the results that would have occurred if the events reflected had been in effect on the dates indicated, or of the results which may be obtained in the future (see the Topaz Pro Forma Operating Statements included in Appendix "A" to this prospectus).
(2) Pursuant to the Glacier Gas Plant Acquisition Agreement, Advantage has committed 50 MMcf/d take-or-pay volumes at a fixed fee of $0.66/Mcf for 15 years. Topaz will receive fixed annual Processing Revenue of approximately $12.0 million per year for the duration of the contract. Pursuant to the Glacier O&O Agreement, Advantage is responsible for all operating and maintenance capital expenditures for the duration of the Glacier Volume Commitment Agreement. See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Glacier Gas Plant Acquisition".
(3) Pursuant to the Banshee Gas Plant Acquisition Agreement, Tourmaline has committed 25 MMcf/d take-or-pay volumes at a fixed fee of $0.60/Mcf for 15 years. Topaz will receive fixed annual Processing Revenue of approximately $5.5 million per year. In addition, interruptible volume utilizing Topaz's remaining share of capacity is subject to a processing fee of $0.50/Mcf. Based on current and historical throughput volume of the Banshee Gas Plant for the past three years, Topaz estimated throughput of approximately 153MMcf/d which results in annual incremental Processing Revenue of $2.4 million. Pursuant to the Banshee CO&O Agreement, Topaz and Tourmaline are responsible for capital and operating costs in proportion to their respective ownership interests, which for Topaz is 25%. Based on actual historical operating expenses incurred by Tourmaline in 2019 for the operation of the Banshee Gas Plant, Topaz's 25% share would be approximately $1.0 million. See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Banshee Gas Plant Acquisition".
(4) The Adjusted Pro Forma revenue, EBITDA and EBITDA margin may not be indicative of the results that would have occurred if the events reflected had been in effect on the dates indicated, or of the results which may be obtained in the future, however they provide Management's best estimate of the financial results of operations, had the Initial Acquisition Agreements, Glacier Gas Plant Acquisition Agreement and Banshee Gas Plant Acquisition Agreement all been in place effective January 1 of each year. See "Notice to Investors – Non-GAAP Financial Measures".
(5) The Company pays a marketing fee to Tourmaline in an amount equal to 1% of the royalty share proceeds as the royalty production volume is marketed with Tourmaline's production volume. The Company can elect to take in-kind its share of royalty production, if desired, at which time it would not be required to pay a marketing fee.
(6) Represents estimated annual G&A of $5.0 million per year, based in part on the actual G&A expenditures incurred during the six months ended June 30, 2020, plus estimated expenses for additional regulatory and reporting costs that the Company will incur on a continuing basis related to the requirements of the Company becoming a reporting issuer after Closing.
(7) Adjusted pro forma EBITDA represents the estimated pro forma EBITDA from the GORR Interests and Infrastructure Assets, had the interests, assets and the associated contracts been in place effective January 1 of each year, and as the revenue, other income and expenses would be determined in accordance with IFRS. See "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin". "Adjusted pro forma EBITDA" is defined as adjusted pro forma operating income plus any realized hedging gains less general and administrative expenses and any realized hedging losses. See "Notice to Investors – Non-GAAP Financial Measures".
(8) Adjusted pro forma EBITDA Margin is defined as Adjusted Pro Forma EBITDA divided by Adjusted Pro Forma Revenue (expressed as a percentage of Adjusted Pro Forma Revenue). See "Notice to Investors – Non-GAAP Financial Measures".

For the year ended Dec. 31, 2018($000s)	Pro FormaTopaz(1)	Glacier Gas PlantAcquisition(2)	Banshee Gas PlantAcquisition(3)	AdjustedPro Forma(4)
Royalty production revenue	$44,290	─	─	$44,290
Processing revenue	21,793	12,045	7,884	41,722
Other income	20,310	─	─	20,310
	86,393	12,045	7,884	106,322
Expenses
Operating expense	3,280	─	1,069	4,349
Net operating income	83,113	12,045	6,815	101,973
Adjusted Pro Forma EBITDA Adjustments:
Marketing expense(5)				443
General and administrative expense(6)				5,000
Total				5,443
Adjusted Pro Forma EBITDA(7)				96,530
Adjusted Pro Forma EBITDA Margin(8)				91%

(1) See the Topaz Pro Forma Operating Statements which were derived from (i) the Initial Acquisition Operating Statements, which reflect the gross petroleum and natural gas revenue, royalty expenses, other income, operating expenses and operating income for the period ending December 31, 2018; (ii) the Topaz Financial Statements; and (iii) the Initial Acquisition Agreements.

Together, the information was then adjusted to reflect the estimated financial results had the Initial Acquisition Agreements been in place effective January 1 of each year. The pro forma Topaz amounts may not be indicative of the results that would have occurred if the events reflected had been in effect on the dates indicated, or of the results which may be obtained in the future (see the Pro Forma Operating Statements included in Appendix "A" to this prospectus).

(2) Pursuant to the Glacier Gas Plant Acquisition Agreement, Advantage will commit 50 MMcf/d take-or-pay volumes at a fixed fee of $0.66/Mcf for 15 years. Topaz will receive fixed annual Processing Revenue of approximately $12.0 million per year for the duration of the contract. Pursuant to the Glacier O&O Agreement, Advantage is responsible for all operating and maintenance capital expenditures for the duration of the Glacier Volume Commitment Agreement. See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Glacier Gas Plant Acquisition".
(3) Pursuant to the Banshee Gas Plant Acquisition Agreement, Tourmaline will commit 25 MMcf/d take-or-pay volumes at a fixed fee of $0.60/Mcf for 15 years. Topaz will receive fixed annual Processing Revenue of approximately $5.5 million per year. In addition, interruptible volume utilizing Topaz's remaining share of capacity is subject to a processing fee of $0.50/Mcf. Based on current and historical throughput volume of the Banshee Gas Plant for the past three years, Topaz estimated throughput of approximately 153 MMcf/d which results in annual incremental Processing Revenue of $2.4 million. Pursuant to the Banshee CO&O Agreement, Topaz and Tourmaline are responsible for capital and operating costs in proportion to their respective ownership interests, which for Topaz is 25%. Based on actual historical operating expenses incurred by Tourmaline in 2018 for the operation of the Banshee Gas Plant, Topaz's 25% share would be approximately $1.1 million. See "Agreements with Tourmaline and Other Counterparties – Agreements Relating to the Banshee Gas Plant Acquisition".
(4) The Adjusted Pro Forma revenue, EBITDA and EBITDA margin may not be indicative of the results that would have occurred if the events reflected had been in effect on the dates indicated, or of the results which may be obtained in the future, however they provide management's best estimate of the financial results of operations, had the Initial Acquisition Agreements, Glacier Gas Plant Acquisition Agreement and Banshee Gas Plant Acquisition Agreement all been in place effective January 1 of each year. See "Notice to Investors – Non-GAAP Financial Measures".
(5) The Company pays a marketing fee to Tourmaline in an amount equal to 1% of the royalty share proceeds as the royalty production volume is marketed with Tourmaline's production volume. The Company can elect to take in-kind its share of royalty production, if desired, at which time it would not be required to pay a marketing fee.
(6) Represents estimated annual G&A of $5.0 million per year, based in part on the actual G&A expenditures incurred during the six months ended June 30, 2020, plus estimated expenses for additional regulatory and reporting costs that the Company will incur on a continuing basis related to the requirements of the Company becoming a reporting issuer after Closing.
(7) Adjusted pro forma EBITDA represents the estimated pro forma EBITDA from the GORR Interests and Infrastructure Assets, had the interests, assets and the associated contracts been in place effective January 1 of each year, and as the revenue, other income and expenses would be determined in accordance with IFRS. See "Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin". "Adjusted pro forma EBITDA" is defined as adjusted pro forma operating income plus any realized hedging gains less general and administrative expenses and any realized hedging losses. See "Notice to Investors – Non-GAAP Financial Measures".
(8) Adjusted pro forma EBITDA Margin is defined as Adjusted Pro Forma EBITDA divided by Adjusted Pro Forma Revenue (expressed as a percentage of Adjusted Pro Forma Revenue). See "Notice to Investors – Non-GAAP Financial Measures".

CAPITALIZATION

The following table sets out the capitalization of the Company as at June 30, 2020 and the pro forma capitalization of the Company as at June 30, 2020 after giving effect to the Offering. Other than as described below, there has not been any material change in the share and loan capital of the Company, on a consolidated basis, since June 30, 2020. This table should be read in conjunction with the section entitled "Management's Discussion and Analysis" and the Company's financial statements and supplemental financial information contained elsewhere in this prospectus.

Designation	Authorized	As at June 30, 2020	As at June 30, 2020after giving effect tothe Offering	As at June 30, 2020after giving effect tothe Offering andexercise in full of theOver-AllotmentOption
Debt(1)
	See Note (1)	Nil	Nil	Nil
Share capital	Unlimited	$772,827 (2)(3)	$•(2) (4)	$•(2)(4))
		(91,690,131 Common
(thousands)		Shares)	(• Common Shares)	(• Common Shares)

Notes:

(1) The Company has entered into the Credit Facility with a Canadian chartered bank. Management does not anticipate any amounts to be drawn under the Credit Facility immediately after giving effect to the Offering. See "Credit Facility", "Notice to Investors — About this Prospectus", "Prior Sales" and "Principal Shareholders and Selling Shareholder".
(2) In addition, the Company has granted 2,050,000 Options to its executive officers and directors under the Option Plan. See "Options to Purchase Securities", "Executive Compensation" and "Executive Compensation — Incentive Award Programs — Option Plan".
(3) On July 6, 2020, the Company completed a second tranche to its June 29, 2020 private placement and issued 1,518,165 Common Shares for gross proceeds of $16,699,815. As at September 24, 2020, the Company has 93,208,296 Common Shares outstanding.
(4) The amounts included in the table include the estimated net proceeds of the Offering after deducting the estimated expenses of the Offering, and the tax effect of share issue costs, and before and after giving effect to exercise in full of the Over-Allotment Option.

OPTIONS TO PURCHASE SECURITIES

The following table sets forth certain information in respect of Options to purchase Common Shares outstanding at the date hereof. See also "Executive Compensation — Incentive Award Programs — Option Plan".

Group(Number in Group)	Common Sharesunderlying Options	Exercise Price perCommon Share	Market Value ofOptions(1)	Expiration Date
Executive officers (2)	450,000	$10.00	N/A	April 14, 2027
Directors (6)	1,200,000	$10.00	N/A	December 14, 2026
Director (1)	200,000	$11.00	N/A	June 14, 2027
Director (1)	200,000	$11.00	N/A	August 14, 2027
Total(1)	2,050,000

Note:

(1) The market value of the Common Shares underlying these Options on both the date of this prospectus and the date of grant is not reasonably ascertainable, given that the Common Shares are not, and have never been, publicly listed or traded.

CREDIT FACILITY

The Company has a covenant-based, secured, operating credit facility with a Canadian chartered bank, in the amount of $75.0 million, which was recently increased to $125.0 million (the "Credit Facility"). The maturity date is June 10, 2022. At the request of the Company and with consent of the lender, the Credit Facility can be extended on an annual basis. The Credit Facility is subject to the following covenants, on a rolling four quarter basis: (i) the ratio of adjusted EBITDA to interest expense must exceed 3:1, (ii) the ratio of consolidated senior secured debt to adjusted EBITDA must not exceed 3:1, and (iii) the ratio of total debt to adjusted EBITDA must not exceed 4:1. At September 24, 2020, the Credit Facility was not drawn and the Company was in compliance with all covenants.

See "Notice to Investors – Non-GAAP Financial Measures" and "Risk Factors – Risks Relating to the Company's Business, Industry and Operating Environment – Credit Facility Arrangements".

A copy of the credit agreement relating to the Credit Facility is available on SEDAR at www.sedar.com under the Company's profile.

An affiliate of Scotia Capital is the lender under the Credit Facility. Consequently, the Company may be considered a "connected issuer" to such Underwriter within the meaning of applicable Canadian Securities Laws. See "Relationships Among the Company, the Selling Shareholder and Certain Underwriters".

Management does not anticipate any amounts to be drawn under the Credit Facility immediately after giving effect to the Offering.

DIVIDEND POLICY

Topaz intends to use the majority of its free cash flow to pay dividends to shareholders and the Company has a long-term payout ratio target of 60-90%. The Board has established a dividend policy pursuant to which the Company intends to pay an annual dividend, currently in the amount of $0.80 per Common Share, payable on a quarterly ($0.20 per share) basis, which represented a payout ratio of approximately 84% for the six months ended June 30, 2020. Dividends are anticipated to be financed from internally-generated free cash flow. The amount of cash distributed is determined at the discretion of the Board. Following Closing, the payment of dividends will be established after considering the overall dividend policy of the Company and after consideration of numerous factors including: (i) the earnings of the Company; (ii) financial requirements for the Company's operations; (iii) the satisfaction by the Company of liquidity and solvency tests in the ABCA; and (iv) any agreements relating to the Company's indebtedness that restrict the declaration and payment of dividends. The Company currently pays dividends quarterly to shareholders of record as of the close of business on the 15th day (or next business day) of the last month of each quarter, which dividends are expected to be paid to shareholders on or about the last day of the quarter (or next business day). The Company anticipates that the dividends expected to be paid on the Common Shares will be designated as "eligible dividends" for Canadian income tax purposes, unless otherwise notified, and that the Company will include disclosure on its website to this effect.

For the three and six months ended June 30, 2020, the Company paid $16.0 million ($0.20 per Common Share) and $32.0 million ($0.40 per Common Share), respectively, in dividends to its shareholders. The Company declared a dividend of $0.20 per share, to shareholders of record on September 15, 2020, to be paid on September 30, 2020. No dividends were paid in 2019 or prior thereto.

Following Closing, the dividend will be for the quarter ending December 31, 2020 and is expected to be paid on or about December 31, 2020 to shareholders of record on December 15, 2020 in the amount of $0.20 per Common Share. See "Risk Factors – Risks Relating to the Offering and Common Shares – Cash Dividend Payments are Not Guaranteed".

MANAGEMENT'S DISCUSSION AND ANALYSIS

Basis of Presentation

This management's discussion and analysis ("MD&A") has been prepared as of the date of this prospectus for the three and six months ended June 30, 2020 and June 30, 2019 and for the year ended December 31, 2019 and discusses the Company's financial performance, business overview, strategy and outlook from Management's viewpoint.

This MD&A should be read in its entirety and is intended to complement and supplement the Topaz Financial Statements included in Appendix "A" of this prospectus. The Topaz Financial Statements have been prepared in accordance with IFRS. See "Exemptions from Certain Disclosure Requirements".

The Company's financial results for the three and six months ended June 30, 2020 and the period from November 14, 2019 to December 31, 2019 are presented as continuing operations. The Company's financial results for the three and six months ended June 30, 2019 and the period from January 1, 2019 to November 13, 2019 are presented as discontinued operations. See "– Discontinued Operations" below.

The Company presents the Topaz Financial Statements in Canadian dollars. Unless indicated otherwise, figures are presented in thousands of dollars. In this MD&A, all references to "$" or "dollars" are to Canadian dollars.

General

(i) the Royalty Assets, which generate the Company's Royalty Production Revenue; and
(ii) the Infrastructure Assets, which generate the Company's Processing Revenue and Other Income.

Topaz does not directly conduct upstream petroleum and natural gas exploration and development operations. See "The Company's Business – Overview".

Topaz's current business was established in November 2019 with the acquisition of the Initial Assets pursuant to the Initial Assets Purchase and Sale Agreement. Prior to closing, Topaz was a subsidiary controlled by Tourmaline and consequently was under common control at the time of the Initial Acquisition. Management used the book value method to determine the value of assets and liabilities acquired by the Company. As a result of the common control transaction, the Company recorded net assets acquired in the amount of $637.0 million in exchange for cash to Tourmaline of $194.5 million and Common Shares with an assigned value of $442.5 million (58.0 million Common Shares).

The COVID-19 pandemic and other macro-economic conditions around the world have contributed to a drastic decrease in global oil and liquids demand since the beginning of 2020. These events have resulted in significant price volatility of oil and liquids prices and increased economic uncertainty. See "COVID-19."

Cautionary Statement Regarding Forward-Looking Information

Certain information contained in this MD&A constitutes forward-looking information and statements (collectively, "forward-looking information") within the meaning of Canadian Securities Laws. This information relates to future events or Topaz's future performance. All information other than information of historical fact is forward-looking information. The use of any of the words "anticipate", "plan", "contemplate", "continue", "estimate", "expect", "intend", "propose", "might", "may", "will", "shall", "project", "should", "could", "would", "believe", "predict", "forecast", "pursue", "potential" and "capable" and similar expressions are intended to identify forward-looking information. This information involves 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 information. No assurance can be given that these expectations will prove to be correct and such forward-looking information should not be unduly relied upon. This information speaks only as of the date of this prospectus or, if applicable, as of the date specified in those documents specifically referenced herein. In addition, this MD&A may contain forward-looking information attributed to third-party sources. See "Notice to Investors – Forward-Looking Statements" and "Notice to Investors – Market, Independent Third-Party and Industry Data" in this prospectus.

Financial Results

($000s) except per share amounts	Three monthsendedJune 30, 2020	Six monthsendedJune 30, 2020	Period fromNov. 14, 2019 toDec. 31, 2019
Cash from (used in) operating activities from continuingoperations	24,234	38,184	(350)
Per Common Share (basic)(2)	0.30	0.48	(0.004)
Cash flow from continuing operations(1)	17,385	38,205	12,273
Per Common Share (basic)(2)	0.22	0.48	0.15
Operating income from continuing operations(1)	18,882	40,696	13,604
Per Common Share (basic)(2)	0.24	0.51	0.17
Net income (loss) from continuing operations	(1,125)	(2,359)	653
Per Common Share (basic)(2)	(0.01)	(0.03)	0.01
Working capital	148,745	148,745	20,767
Adjusted working capital(1)	149,180	149,180	20,767
Net debt (cash)(1)	(149,180)	(149,180)	(20,767)

Notes:

(1) Refer to "Non-GAAP Financial Measures" in this MD&A and "Notice to Investors – Non-GAAP Financial Measures" in this prospectus.
(2) Weighted average Common Shares outstanding. Statement of financial position information is as of end of period.
(3) Statement of financial position information is as at period end.

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020, Topaz generated $24.2 million and $38.2 million, respectively, of cash from operating activities from continuing operations. Cash flow from continuing operations(1) for the same periods was $17.4 million and $38.2 million, respectively. The Company had a net loss from continuing operations, for the three and six months ended June 30, 2020, of $1.1 million and $2.4 million, respectively, which was primarily attributable to non-cash depletion charges of $18.6 million and $41.8 million, respectively, in addition to non-cash unrealized hedging losses on financial instruments. The unrealized losses on financial instruments are due to changes in commodity prices at June 30, 2020. The Company had operating income from continuing operations(1) of $18.9 million and $40.7 million for the three and six months ended June 30, 2020, respectively.

At June 30, 2020, the Company had $148.7 million of working capital and after adjusting for the fair value of financial instruments, had adjusted working capital of $149.2 million (which is equivalent to net cash as the Company had no debt outstanding at June 30, 2020).

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, Topaz used $0.4 million cash from operating activities from continuing operations and generated $12.3 million of cash flow from continuing operations(1). The Company generated $0.7 million of net income from continuing operations while it generated operating income from continuing operations(1) of $13.6 million.

At December 31, 2019, the Company had $20.8 million of working capital (which is equivalent to adjusted working capital and net cash as the Company had no financial instruments or debt outstanding at December 31, 2019).

Note:

(1) Refer to "Non-GAAP Financial Measures" in this MD&A.

Reserves Quantities

For disclosure of the Company's reserves data prepared in accordance with NI 51-101, see "Reserves and Other Oil and Gas Information" in this prospectus.

Royalty Production Revenue, Processing Revenue and Other Income

($000s)	Three monthsendedJune 30, 2020	Six monthsendedJune 30, 2020	Nov. 14, 2019toDec. 31, 2019

Royalty Production Revenue	11,935	26,449	9,832
Processing Revenue	5,296	11,264	2,943
Other Income	2,789	5,066	1,408
	20,020	42,779	14,183
Average Royalty Production
Natural gas (Mcf/d)	55,056	56,364	58,131
Oil and condensate (Bbl/d)	715	740	766
Total (Boe/d)	9,891	10,134	10,455
Realized Royalty Production Prices
Natural gas ($/Mcf)	$2.00	$2.03	$2.56
Oil ($/Bbl)	$26.14	$35.92	$66.15
Condensate ($/Bbl)	$30.61	$44.30	$76.30
Benchmark Pricing
Natural Gas
AECO 5A (CAD$/Mcf)	$2.00	$2.02	$2.49
Oil and condensate
NYMEX WTI (USD$/Bbl)	$28.00	$36.82	$56.87
Edmonton Par (CAD$/Bbl)	$30.24	$40.89	$66.70
Edmonton Condensate (CAD$/Bbl)	$31.74	$45.55	$74.77
CAD$/USD$	$0.7220	$0.7335	$0.7577

Royalty Production Revenue

Royalty Production Revenue is determined pursuant to the terms of the Tourmaline GORR Agreement. The commodity prices for natural gas, oil and condensate are based on market index prices in the month of production. The royalty production volumes are currently marketed with the royalty payor's volume and revenue is generally received two months after the natural gas, oil and condensate are produced. The Company can elect to take its share of the royalty production volume in-kind, if desired.

Three and Six Months Ended June 30, 2020

During the three months ended June 30, 2020, Topaz generated Royalty Production Revenue of $11.9 million attributed to average production of 9,891 Boe/d and average realized royalty production prices of $2.00/Mcf for natural gas, $26.14/Bbl for oil and $30.61/Bbl for condensate. During the six months ended June 30, 2020, Topaz generated Royalty Production Revenue of $26.4 million attributed to average production of 10,134 Boe/d and average realized royalty production prices were $2.03/Mcf for natural gas, $35.92/Bbl for oil and $44.30/Bbl for condensate.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, Topaz generated Royalty Production Revenue of $9.8 million attributed to average production of 10,455 Boe/d and average realized royalty production prices were $2.56/Mcf for natural gas, $66.15/Bbl for oil and $76.30/Bbl for condensate.

Processing Revenue and Other Income

Processing Revenue is generated through the Company's non-operated ownership in processing facilities. The facilities provide natural gas processing services provided to customers on a fee-for-service basis. Certain fees include fixed take-orpay arrangements under long-term commercial arrangements.

Other Income is generated by way of a contracted interest in third-party revenue generated through fee-for-service natural gas processing contracts with no underlying facility ownership.

Three and Six Months Ended June 30, 2020

During the three months ended June 30, 2020, Topaz generated Processing Revenue and Other Income of $5.3 million and $2.8 million, respectively. During the six months ended June 30, 2020, Topaz generated Processing Revenue and Other Income of $11.3 million and $5.1 million, respectively.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, Topaz generated Processing Revenue and Other Income of $2.9 million and $1.4 million, respectively.

Liquidity and Capital Resources

Bank Debt

At June 30, 2020, Topaz had a covenant-based, secured, operating credit facility with a Canadian bank in the amount of $75.0 million (See "Credit Facility"). The maturity date is June 10, 2022. At the request of the Company and with consent of the lender, the Credit Facility can be extended on an annual basis. The Credit Facility is subject to the following covenants, on a rolling four quarter basis: (i) the ratio of adjusted EBITDA to interest expense must exceed 3:1, (ii) the ratio of consolidated senior secured debt to adjusted EBITDA must not exceed 3:1, and (iii) the ratio of total debt to adjusted EBITDA must not exceed 4:1. At June 30, 2020, the Credit Facility was not drawn and the Company was in compliance with all covenants.

The terms "adjusted EBITDA", "interest expense", "consolidated senior secured debt" and "total debt" for purposes of the financial covenants are defined as follows under the Credit Facility: "adjusted EBITDA" is net income or loss from continuing operations, excluding extraordinary items, plus interest expense, income taxes and the capital portion of any finance lease received, and adjusted for non-cash items and gains or losses on dispositions; "interest expense" is the total interest expense with respect to all outstanding indebtedness; "consolidated senior secured debt" is all total debt that is secured in priority or equivalent to any Credit Facility obligations" and "total debt" is the aggregate principal amount of all debt; all of which are determined in accordance with GAAP.

Outstanding Shares

At December 31, 2019, Topaz had 80.0 million Common Shares and 1.2 million Options outstanding.

At June 30, 2020, Topaz had 91.7 million Common Shares and 1.85 million Options outstanding.

At the date of this prospectus, Topaz had 93.2 million Common Shares and 2.05 million Options outstanding.

See "Executive Compensation — Incentive Award Programs — Option Plan".

Dividends

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020, the Company paid $16.0 million ($0.20 per Common Share) and $32.0 million ($0.40 per Common Share), respectively, in dividends to its shareholders.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, no dividends were paid.

See "Dividend Policy" in this prospectus.

Capital Management

In order to manage its capital structure, the Company's objective is to maintain financial flexibility in order to distribute cash to shareholders in the form of dividends after considering the Company's operational financial requirements and its future growth opportunities. As a royalty and energy infrastructure company, Topaz does not have any significant capital expenditure requirements, which enhances its financial flexibility.

The Company considers its capital structure to include shareholders' equity, bank debt and working capital. In order to maintain or adjust the capital structure, the Company may from time to time issue equity, utilize available credit facilities, adjust its dividend distributions and/or adjust its investment activities to manage current and forecast debt levels. The Company's operating results and capital structure are impacted by royalty production volumes, commodity prices and level of third-party revenue generated at its non-operated processing facilities or through its contracted revenue interests.

The Company's capital structure is managed through its financial and operating forecast process. The forecast of the Company's future cash flows is based on estimates of royalty interest production, natural gas, crude oil, and condensate prices, third-party facility utilization, operating and marketing expense, administrative expenses, taxes and other investing and financing activities. The forecast is regularly updated based on changes in commodity prices, royalty interest production expectations, third-party facility utilization expectations and other factors that, in the Company's view, could impact cash from operating activities. At June 30, 2020, the Company had working capital (excluding financial instruments) of $149.2 million (December 31, 2019 - $20.8 million), in addition to the undrawn $75.0 million Credit Facility.

The Company has exposure to financial risks related to its financial assets and liabilities. Financial risks include credit risk, liquidity risk, and market risk (including commodity price and interest rate risk).

Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations in accordance with agreed terms. The Company's policy to mitigate credit risk is to establish contractual agreements with creditworthy counterparties. The Company's accounts receivable at June 30, 2020 relate to royalty and contractual agreements with its controlling shareholder, Tourmaline. The Company's structure of royalty and infrastructure revenue from a counterparty, which Topaz considers to have strong creditworthiness significantly reduces Topaz's credit risk. At June 30, 2020, the Company does not have any receivable (December 31, 2019 - $nil) over 90 days. The Company is satisfied that its accounts receivable amounts are collectible.

The carrying amount of cash and cash equivalents, accounts receivable and financial instruments represents the Company's maximum credit exposure. The Company has not recorded an expected credit loss as at June 30, 2020 (December 31, 2019 – nil) nor was it required to write-off any receivables during the three or six months ended June 30, 2020 (December 31, 2019 – nil). All amounts owing to the Company at June 30, 2020 and December 31, 2019 were due from its controlling shareholder, Tourmaline.

Liquidity risk

Liquidity risk is the risk that the Company will encounter difficulties in meeting its financial obligations as they come due. The Company manages its liquidity risk by ensuring that it will have sufficient liquidity to meet its financial obligations under both normal and risked conditions. At June 30, 2020, the Company had unused capacity under the Credit Facility for up to $75.0 million. See "Credit Facility".

The timing of expected cash outflows relating to accounts payable and accrued liabilities of $4.4 million is less than one year. The Company expects to pay suppliers within 30-60 days. These terms are consistent with industry practice. As at June 30, 2020, all of the accounts payable balances were less than 90 days. Management maintains a conservative approach to debt management that aims to provide financial flexibility with respect to development of the Company's assets and the payment of dividends to shareholders. The Board reviews and determines the dividend rate annually after considering expected commodity prices, expected royalty production volumes, expected cash flow, economic conditions, income taxes, and the Company's capacity to fund its operations and investment opportunities.

The following are the contractual maturities of financial liabilities at June 30, 2020:

($000s)	Total	< 1 year	1 to 5 years
Non-derivative financial liabilities:Accounts payable and accrued liabilities	4,383	4,383	─
Derivative financial liabilities:Financial instruments	676	559	117

Market risk

Market risk isthe risk that changesin market conditions,such as commodity prices and interest rates will affect the Company's earnings or value of financial instruments. The objective of market risk management is to manage and curtail market risk exposure within acceptable limits, while maximizing the Company's returns. The Company utilizes financial derivatives contracts to manage market risks.

Interest rate risk is the risk that changes in market interest rates may affect future cash flows from the Company's financial assets or liabilities. The Company is exposed to interest rate risk to the extent that changes in market interest rates would impact any borrowings under the Credit Facility which is subject to a floating interest rate. The Company had no outstanding borrowings against the Credit Facility at June 30, 2020 (December 31, 2019 – nil).

Commodity price risk is the risk that the fair value or future cash flow will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are based upon the U.S. dollar and as a result the price received by Canadian producersis affected by the Canadian to US dollar exchange rate. The commodity prices are also impacted by world economic events that dictate the levels of supply and demand. During the three months ended June 30, 2020, the Company entered into certain financial derivative contracts in order to manage commodity risk. These instruments are not used for trading or speculative purposes. The Company has not designated itsfinancial derivative contracts as effective accounting hedges, even though the Company considers all financial derivative contractsto be effective economic hedges. As a result, all such financial commodity contracts are recorded on the statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the statement of income (loss) and comprehensive income (loss). The Company has not offset any financial assets and liabilities, in the statements of financial position.

Financial Instruments

The Company utilizes financial derivative contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table presents the financial derivative contracts outstanding as at June 30, 2020. The fair value of these contracts is a liability of $0.6 million as detailed below. All financial derivative contracts are with a Canadian chartered bank.

Natural Gas Contract Period	Type	Daily Volume	Price (CAD$/GJ)
Apr. 1, 2020 to Oct. 31, 2020	Fixed price	5,000 GJ	$1.73/GJ
Apr. 1, 2020 to Oct. 31, 2020	Fixed price	2,500 GJ	$1.75/GJ
Apr. 1, 2020 to Dec. 31, 2020	Fixed price	5,000 GJ	$1.73/GJ
Apr. 1, 2020 to Dec. 31, 2020	Fixed price	2,500 GJ	$1.72/GJ
Jun. 1, 2020 to Mar. 31, 2021	Fixed price	2,500 GJ	$2.25/GJ
Jan. 1, 2021 to Dec. 31, 2021	Fixed price	5,000 GJ	$2.09/GJ
Apr. 1, 2021 to Oct. 31, 2021	Fixed price	2,500 GJ	$2.04/GJ
Apr. 1, 2021 to Oct. 31, 2021	Fixed price	2,500 GJ	$2.035/GJ

	At June 30, 2020
($000s)	Asset	Liability
Current financial instruments	124	559
Non-current financial instruments	─	117

The following table provides the realized and unrealized losses on financial instruments for the periods presented. During the three and six months ended June 30, 2020, the Company realized a $0.2 million loss on financial instruments and during the same periods, recorded an unrealized loss on financial instruments of $0.6 million. No contracts were entered into prior to or as at December 31, 2019.

	Three monthsended	Six monthsended
($000s)	June 30, 2020	June 30, 2020
Realized loss on financial instruments	188	188
Unrealized loss on financial instruments	637	552
Total	825	740

The following table presents any financial derivative contracts entered subsequent to June 30, 2020.

Natural Gas Contract Period	Type	Daily Volume	Price (CAD$/GJ)
Apr. 1, 2021 to Oct. 31, 2021	Fixed price	2,500 GJ	$2.54/GJ

Operating results and other expenses

	Three monthsended	Six monthsended	Nov. 14, 2019to
($000s)	June 30, 2020	June 30, 2020	Dec. 31, 2019
Expenses:
Operating	1,016	1,871	481
Marketing	122	212	98
General and administrative	1,249	2,243	1,331
Share-based compensation	204	353	25
Finance expense	62	64	2
Depletion, depreciation & amortization	18,612	41,805	11,671
Total	21,265	46,548	13,608

Operating expense

Topaz incurs operating expenses attributed to the Infrastructure Assets, which were acquired pursuant to the Initial Acquisition.

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020, Topaz incurred $1.0 million and $1.9 million, respectively, of operating expenses.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, Topaz incurred $0.5 million of operating expenses.

Marketing expense

Topaz pays a marketing fee to Tourmaline as the Company's royalty share of production is marketed from the Tourmaline GORR Lands with the Tourmaline's production.

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020, Topaz incurred $0.1 million and $0.2 million, respectively, of marketing expense.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, Topaz incurred $0.1 million of marketing expense.

General and administrative expense ("G&A")

Topaz incurs G&A expenses pursuant to the Management Services Agreement, which includes a management and administrative services fee payable to Tourmaline, as Topaz agreed to share administrative services during its first year of operations. The fee is scheduled to be reduced on a quarterly basis through 2020 as the Company adds its own personnel and administrative functions, reducing the need for administrative services provided from Tourmaline. The Management Services Agreement is currently scheduled to be terminated December 31, 2020. During the three and six months ended June 30, 2020 and the period from November 14, 2019 to December 31, 2019, Topaz paid $0.5 million, $1.1 million and $0.4 million, respectively, in respect of the Management Services Agreement which were in the normal course of operations and were measured at the exchange amount. See "Agreements with Tourmaline and Other Counterparties — Management Services Agreement".

Topaz incurs professional services and other directly incurred administrative expenses.

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020, Topaz incurred total G&A expenses of $1.2 million and $2.2 million, respectively, which includes management fees of $0.5 million and $1.1 million, respectively.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, Topaz incurred total G&A expenses of $1.3 million, which includes management fees of $0.4 million.

Share-based compensation

The Company may issue Options to employees, consultants and directors of the Company pursuant to the Option Plan. At June 30, 2020, 1.85 million Options were outstanding. At December 31, 2019, 1.2 million Options were outstanding.

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020, Topaz recognized $0.2 million and $0.4 million, respectively, of sharebased compensation expense.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, Topaz recognized $0.03 million of stock-based compensation expense.

Finance expense

Topaz incurs finance expenses, which can include interest expense on its bank debt and accretion attributed to its decommissioning obligations. The Company recognized decommissioning obligations attributed to the Initial Facilities, which were acquired pursuant to the Initial Acquisition.

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020, Topaz did not have any bank debt outstanding and therefore only incurred standby interest charges of $0.06 million and $0.06 million, respectively, and recognized accretion expenses of $0.002 million and $0.004 million, respectively.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, the Company recognized accretion expenses of $0.002 million.

Depletion, depreciation & amortization ("DD&A")

Topaz records DD&A expense as follows: its royalty assets are depleted on a unit-of-production basis by reference to the ratio of: royalty production in the period to total developed reserves; and its processing facilities are depreciated on a straightline basis over the assets' useful lives.

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020, Topaz recognized DD&A expenses of $18.6 million and $41.8 million, respectively.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, Topaz recognized DD&A expenses of $11.7 million.

Income Taxes

Deferred income tax recovery

	Three months	Six months
	ended	ended	to
($000s)	June 30, 2020	June 30, 2020	Dec. 31, 2019
Deferred income tax recovery	945	2,150	78

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020, the provision for deferred income tax recovery was $0.9 million and $2.2 million, respectively. The deferred income tax recovery for the three and six months ended June 30, 2020 is primarily attributed to the Company's net loss from continuing operations before taxes of $2.1 and $4.5 million, respectively. The recovery for the three and six months ended June 30, 2020 was further increased by the recognition of previously unrecognized tax assets which are attributed to the tax pools Topaz retained from Exshaw.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, the provision for deferred income tax recovery was $0.1 million.

Capital expenditures

	Three monthsended	Six monthsended	Nov. 14, 2019to
($000s)	June 30, 2020	June 30, 2020	Dec. 31, 2019
Capital expenditures	159	271	2

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020, Topaz incurred capital expenditures of $0.2 million and $0.3 million, respectively, related to the Infrastructure Assets.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, Topaz incurred capital expenditures of $0.002 million, related to the Infrastructure Assets.

Commitments and Contractual Obligations

At June 30, 2020, Topaz does not have any material commitments or contractual obligations, with the exception of the Glacier Gas Plant Acquisition Agreement, which was completed on July 2, 2020.

Off Balance Sheet Arrangements

At June 30, 2020, Topaz does not believe it has any guarantees or off-balance sheet arrangements that have, or are reasonably likely to have, a current or future effect on the Company's financial condition, results of operations, liquidity or capital expenditures.

Subsequent Events

On July 2, 2020, Topaz completed the Glacier Gas Plant Acquisition. The purchase price was $100.0 million before customary adjustments.

On September 1, 2020, Topaz completed the Banshee Gas Plant Acquisition. The purchase price was $52.5 million before customary adjustments.

On September 18, 2020 Topaz's Credit Facility was amended to reflect an increase to the borrowing capacity from $75 million to $125 million.

The Company declared a dividend of $0.20 per share, to shareholders of record on September 15, 2020, to be paid on September 30, 2020.

Transactions Between Related Parties

In conjunction with the Initial Acquisition, Topaz entered into the Initial Acquisition Agreements, the Management Services Agreement, the Governance Agreement and the Investor Liquidity Agreement with Tourmaline. Substantially all of Topaz's Royalty Production Revenue, as well as the majority of Topaz's Processing Revenue and Other Income as described in this MD&A are derived from such agreements. See "Agreements with Tourmaline and Other Counterparties" and "Material Contracts".

Three and Six Months Ended June 30, 2020

During the three and six months ended June 30, 2020 Topaz paid $0.5 million and $1.1 million, respectively, in respect of the Management Services Agreement which were in the normal course of operations and were measured at the exchange amount.

Period from November 14, 2019 to December 31, 2019

During the period from November 14, 2019 to December 31, 2019, Topaz paid $0.4 million in respect of the Management Services Agreement, which were in the normal course of operations and were measured at the exchange amount.

Key management personnel are persons who have the authority and responsibility for planning, directing and controlling the activities of the Company, directly or indirectly. Key management includes all members of Management and the Board. See "Directors and Executive Officers". The table below summarizes all key management personnel compensation included in the financial statements for the three and six months ended June 30, 2020.

	Three monthsended	Six monthsended	Nov. 14, 2019to
($000s)	June 30, 2020	June 30, 2020	Dec. 31, 2019
Salaries and benefits	156	156	─
Share-based compensation	204	353	25
	360	509	25

Subsequent to June 30, 2020, in conjunction with the Banshee Gas Plant Acquisition, Topaz entered into the Banshee Gas Plant Acquisition Agreement with Tourmaline.

See "Agreements with Tourmaline and Other Counterparties" and "Material Contracts".

Corporate Structure

Common Control Transaction

Topaz was reorganized to acquire certain infrastructure and royalty assets. Immediately prior to closing the Initial Acquisition, Topaz was a subsidiary controlled by Tourmaline and consequently was under common control at the time of the Initial Acquisition. Management used the book value method to determine the value of assets and liabilities acquired by the Company. As a result of the common control transaction, the Company recorded net assets acquired in the amount of $637.0 million in exchange for cash to Tourmaline of $194.5 million and Common Shares with an assigned value of $442.5 million (58.0 million Common Shares).

($000s)

Book value of assets and liabilities acquired:
Petroleum and natural gas interests	637,627
Decommissioning obligations	(627)
Total	637,000
Consideration:
Cash	194,505
Common shares	442,495
Total	637,000

On November 14, 2019, Topaz completed the 2019 Equity Financing for total cash consideration of $203.5 million (net of share issue costs and taxes) which resulted in Tourmaline reducing its ownership interest from 100% to 73.9%.

On June 29, 2020 and July 6, 2020, Topaz completed the 2020 Equity Financing consisting of 13.2 million Common Shares for gross proceeds of $145.3 million which resulted in Tourmaline reducing its ownership interest from 73.9% to 63.5%.

Discontinued Operations

The Company (Exshaw for the purposes of this section) was incorporated under the ABCA in 2006 and was a controlled subsidiary of Tourmaline prior to the transactions leading up to the Initial Acquisition. Prior to the Initial Acquisition, all of Exshaw's oil and gas assets and liabilities, except for $48.1 million of deferred tax assets and $1.0 million in cash, were transferred to Tourmaline. The book value method was used to determine the value of assets and liabilities transferred. The accumulated deficit in Exshaw was then reclassified to share capital and contributed surplus balances in shareholder's equity for the continuing entity, upon receipt of shareholder approval. On November 8, 2019, articles of amendment were filed to change the Company's name to "Topaz Energy Corp." prior to the E&P Asset Disposition, the Company conducted upstream petroleum and natural gas exploration and production operations, and the results of these operations are reflected as discontinued operations.

($000s)

Book value of assets and liabilities transferred:
Intercompany receivable	(4,245)
Other current assets	(7,456)
Accounts payable	6,496
Bank debt	290,206
Petroleum and natural gas interests	(776,606)
Decommissioning obligations	38,812
Future income tax liability	104,257
Retained earnings	348,536
Total	─

The following table presents the results of discontinued operations of Exshaw.

For the period ended	June 30, 2019	Period from Jan. 1
($000s, except for share information)	Three months	Six months	to Nov.13,2019(1)
	(unaudited)	(unaudited)	(audited)
Revenue	20,734	44,868	75,454
Other income	1,275	1,782	2,872
	22,009	46,650	78,326
Expenses
Royalties	1,235	2,648	5,828
Operating	7,775	16,616	28,372
Transportation expenses	3,240	7,384	12,950
General and administrative	300	600	1,000
Finance	2,667	5,384	9,366
Depletion and depreciation	7,420	15,295	26,534
Total expenses	22,637	47,927	84,050
Net loss from discontinued operations before taxes	(628)	(1,277)	(5,724)
Deferred tax recovery	(10,116)	(10,255)	(11,184)
Net income from discontinued operations	9,488	8,978	5,460
Per share(2)	$8.63	$8.16	$4.96

Notes:

(1) Exshaw's results of operations from January 1, 2019 to November 13, 2019 are presented as discontinued operations. Topaz commenced operations on November 14, 2019 therefore its results of operations from November 14, 2019 to December 31, 2019 are presented as continuing operations.

(2) Exshaw completed a share consolidation which reduced the outstanding number of Common Shares to 1.1 million. The per share calculation for the periods above reflect the post-consolidation number of Common Shares outstanding (1.1 million).

	Three monthsended	Six monthsended	Jan. 1, 2019to
($000s)	June 30, 2019	June 30, 2019	Nov. 13, 2019
Average Production
Natural gas (Mcf/d)	18,225	19,144	19,249
Oil (Bbl/d)NGL (Bbl/d)	2,591381	2,702357	2,656447

Realized Price
Total production revenue ($/Boe)	$37.92	$39.66	$37.72

Revenue

Three and Six Months Ended June 30, 2019

During the three months ended June 30, 2019, Exshaw had total petroleum and natural gas revenue of $20.7 million with average production of 6,009 Boe/d for a total realized price of $37.92/Boe. During the six months ended June 30, 2019, Exshaw had total petroleum and natural gas revenue of $44.9 million with average production of 6,250 Boe/d for a total realized price of $39.66/Boe. The fluctuations in petroleum and natural gas revenue are due to fluctuating production volume and changes in commodity pricing.

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw had total petroleum and natural gas revenue of $75.5 million with average production of 6,311 Boe/d for a total realized price of $37.72/Boe. The fluctuations in petroleum and natural gas revenue are due to fluctuating production volume and changes in commodity pricing.

Other Income

During the three and six months ended June 30, 2019, Exshaw generated other income (processing fees) of $1.3 and $1.8 million, respectively and during the period from January 1 to November 13, 2019, Exshaw generated other income (processing fees) of $2.9 million. The fluctuations in other income are primarily due to the different number of production days within each period.

Royalties

Three and Six Months Ended June 30, 2019

During the three and six months ended June 30, 2019, Exshaw paid royalty expenses of $1.2 and $2.6 million, respectively, on its petroleum and natural gas revenue (6% for both the three and six months ended June 30, 2019).

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw paid royalty expenses of $5.8 million, or 7.7% on its petroleum and natural gas revenue. On a per Boe basis, royalty expenses were $2.26/Boe, $2.34/Boe and $2.91/Boe, respectively. The higher royalty rates paid in the period from January 1 to November 13, 2019 are attributed to a reduction in royalty credits received during the second half of 2019.

Operating expense

Three and Six Months Ended June 30, 2019

During three and six months ended June 30, 2019, Exshaw paid operating expenses of $7.8 and $16.6 million, respectively, related to its petroleum and natural gas operations ($14.22/Boe and $14.69/Boe for the three and six months ended June 30, 2019, respectively). The higher operating expenses on a per Boe basis during the six months ended June 30, 2019 are attributed to higher maintenance costs incurred during the first quarter of 2019.

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw paid operating expenses of $28.4 million, or $14.18/Boe. The lower operating expenses on a per Boe basis during the period from January 1 to November 13, 2019 are due to higher production volumes.

Transportation expense

Three and Six Months Ended June 30, 2019

During the three and six months ended June 30, 2019, Exshaw paid transportation expenses of $3.2 and $7.4 million, respectively, related to its petroleum and natural gas operations ($5.92/Boe and $6.53/Boe for the three and six months ended June 30, 2019, respectively). The higher transportation expense on a per Boe basis for the six months ended June 30, 2020 are attributed to higher oil volume produced relative to the three months ended June 30, 2020, which carry higher transportation expense relative to natural gas.

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw paid transportation expenses of $13.0 million, or $6.47/Boe.

General and administrative expense ("G&A")

Three and Six Months Ended June 30, 2019

During the three and six months ended June 30, 2019, Exshaw paid G&A expenses of $0.3 and $0.6 million, respectively ($0.55/Boe and $0.53/Boe for the three and six months ended June 30, 2019, respectively).

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw paid G&A expenses of $1.0 million, or $0.50/Boe.

Finance expense

Three and Six Months Ended June 30, 2019

During the three and six months ended June 30, 2019, Exshaw paid finance expenses of $2.7 and $5.4 million, respectively ($4.88/Boe and $4.76/Boe for the three and six months ended June 30, 2019, respectively) which relates to interest expenses on outstanding debt and accretion expenses of $0.1 and $0.3 million, respectively.

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw paid finance expense of $9.4 million, or $4.68/Boe which relates to interest expenses on outstanding debt and accretion expenses of $0.5 million.

Depletion and depreciation ("DDA")

Three and Six Months Ended June 30, 2019

During the three and six months ended June 30, 2019, Exshaw recognized DDA expenses of $7.4 and $15.3 million, respectively ($13.57/Boe and $13.52/Boe for the three and six months ended June 30, 2019, respectively).

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw recognized DDA expenses of $26.5 million, or $13.26/Boe.

Deferred tax recovery

Three and Six Months Ended June 30, 2019

During the three and six months ended June 30, 2019, Exshaw recognized deferred tax recovery of $10.1 and $10.2 million, respectively, primarily attributed to net losses from discontinued operations before taxes of $0.6 and $1.3 million, respectively. The recoveries were further increased due to a change in tax rate during the periods.

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw recognized deferred tax recovery of $11.2 million. The deferred tax recovery is primarily attributed to Exshaw's net loss from discontinued operations before tax of $5.7 million, as well as an increased recovery due to a change in tax rate during the period.

The following table presents the sources and uses of cash from the discontinued operations of Exshaw.

For the period ended		June 30, 2019
($000s)	Three months	Six months	Period from Jan.1to Nov.13, 2019(1)
Operating activities	9,562	16,955	15,089
Financing activities	(4,996)	(5,007)	(238,972)
Investing activities	(4,566)	(11,948)	224,882

Note:

Cash from operating activities from discontinued operations

Three and Six Months Ended June 30, 2019

During the three and six months ended June 30, 2019, Exshaw generated cash from operating activities from discontinued operations of $9.6 million and $17.0 million, respectively.

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw generated cash from operating activities from discontinued operations of $15.1 million. The cash was generated through Exshaw's petroleum and natural gas operations and the fluctuations are largely due to the different duration of time periods analyzed, as well as fluctuations in commodity prices.

Cash used in financing activities from discontinued operations

Three and Six Months Ended June 30, 2019

During the three and six months ended June 30, 2019, Exshaw used $5.0 million of cash in financing activities from discontinued operations, which is attributed to reducing outstanding debt.

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw used $239.0 million of cash in financing activities from discontinued operations in order to reduce outstanding debt. The cash used to reduce the debt was generated through an equity issuance as well as the proceeds from divestiture of its petroleum and natural gas assets.

Cash generated from (used in) investing activities

Three and Six Months Ended June 30, 2019

During the three and six months ended June 30, 2019, Exshaw used $4.6 million and $12.0 million, respectively, of cash in investing activities from discontinued operations, which is primarily attributed to capital expenditures related to Exshaw's exploration and development program.

Period from January 1, 2019 to November 13, 2019

During the period from January 1 to November 13, 2019, Exshaw generated $224.9 million of cash from investing activities from discontinued operations, which is primarily attributed to the proceeds received from the divestiture of its petroleum and natural gas assets.

Critical Accounting Policies and Estimates

Certain accounting policies require that Management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Management reviews its estimates on a regular basis. The emergence of new information and changed circumstances may result in actual results or changes to estimates that differ materially from current estimates. The Company's use of estimates and judgments in preparing the financial statements is discussed in Notes 2 and 3 to the Topaz Financial Statements included in Appendix "A" to this prospectus.

Changes in Accounting Policies

The following standard issued by the International Accounting Standards Board ("IASB") has been adopted by the Company effective January 1, 2019. There was no impact as the Company did not have any leases.

IFRS 16 – Leases sets out the principles for the recognition, measurement, presentation and disclosure of leases for both parties to a contract, i.e. the customer ('lessee') and the supplier ('lessor') and replaces the previous leases standard, IAS 17 – Leases. The new standard was adopted using the modified retrospective approach.

Non-GAAP Financial Measures

This MD&A makes reference to the terms "cash flow", "operating income", "adjusted working capital" and "net debt (cash)" which are not recognized measures under GAAP, and do not have a standardized meaning prescribed by GAAP. Accordingly, the Company's use of these terms may not be comparable to similarly defined measures presented by other companies. Management uses the terms "cash flow" and "operating income", for its own performance measures and to provide shareholders and potential investors with a measurement of the Company's efficiency and its ability to generate the cash necessary to fund dividends and a portion of its future growth expenditures or to repay debt. Accordingly, investors are cautioned that the non-GAAP financial measures should not be considered in isolation nor as an alternative to net income (loss) from continuing operations or other financial information determined in accordance with GAAP as an indication of the Company's performance.

For these purposes, "cash flow" is defined as cash from (used in) operations before changes in non-cash working capital. "Operating income" is revenue and other income, less operating and marketing expenses.

See also "Notice to Investors – Non-GAAP Financial Measures" in this prospectus.

Cash Flow

A summary of the reconciliation of cash from operating activities (from continuing operations in the statements of cash flow), to cash flow, is set forth below:

	Three monthsended	Six monthsended	Period fromNov. 14 to
($000s)	June 30, 2020	June 30, 2020	Dec. 31, 2019
Cash from (used in) operating activities from
continuing operations	24,234	38,184	(350)
Exclude change in non-cash working capital from
continuing operations	(6,849)	21	12,623
Cash flow	17,385	38,205	12,273

Operating Income

A summary of the calculation of operating income from continuing operations, is set forth below:

	Three monthsended	Six monthsended	Period fromNov. 14 to
($000s)	June 30, 2020	June 30, 2020	Dec. 31, 2019
Royalty Production Revenue	11,935	26,449	9,832
Processing Revenue	5,296	11,264	2,943
Other Income	2,789	5,066	1,408
Less: operating expenses	(1,016)	(1,871)	(481)
Less: marketing expenses	(122)	(212)	(98)
Operating income from continuing operations	18,882	40,696	13,604

Adjusted Working Capital

A summary of the reconciliation of working capital to adjusted working capital, is set forth below:

	At	At
($000s)	June 30, 2020	Dec. 31, 2019
Working capital	148,745	20,767
Exclude financial instruments-current (asset) liability	435	─
Adjusted working capital	149,180	20,767

Net Debt (Cash)

At June 30, 2020 and December 31, 2019, the Company had no debt outstanding therefore its net debt (cash) was equal to its adjusted working capital of $149.2 million at June 30, 2020 and $20.8 million at December 31, 2019.

Business Risks

The Company is subject to a number of business risks. See "Risk Factors".

Selected Quarterly Information from Continuing Operations(1)

	Three monthsended	Three monthsended	Period fromNov. 14, 2019 to
($000s) except per share	June 30, 2020	March 31, 2020	Dec. 31, 2019(1)

Royalty production revenue	11,935	14,514	9,832
Processing revenue	5,296	5,968	2,943
Other income	2,789	2,277	1,408
	20,020	22,759	14,183
Cash expenses:
Operating	(1,016)	(855)	(481)
MarketingGeneral and administrative	(122)(1,249)	(90)(994)	(98)(1,331)
Realized loss on financial instruments	(188)	─	─
Interest expense	(60)	─	─
Cash flow from continuing operations(2)
Per share	17,385$0.22	20,820$0.26	12,273$0.15

Cash from (used in) operating activities from continuing
operations	24,234	13,950	(350)
Per share(3)	$0.30	$0.17	$(0.004)
Net income (loss) from continuing operations	(1,125)	(1,234)	653
Per basic and diluted share(3)	$(0.01)	$(0.02)	$0.01
Dividends paid	16,000	16,000	─
Per share(3)	$0.20	$0.20	─
Capital expenditures	159	112	─
Weighted average shares outstanding (000)	80,257	80,000	80,000
($000s)	At June 30, 2020	At March 31, 2020	At Dec. 31, 2019

Total assets	793,323	679,858	697,234
Working capitalAdjusted working capital(2)	148,745149,180	25,62025,475	20,76720,767
Net debt (cash)(2)	(149,180)	(25,475)	(20,767)
Common shares outstanding	91,690	80,000	80,000

Notes:

(1) No additional comparative quarterly results have been included in the table above as the E&P Assets were transferred to Tourmaline on November 12, 2019 and the operations have been presented as discontinued operations. Refer to "Discontinued Operations" in this MD&A.

(2) Refer to "Non-GAAP Financial Measures" in this MD&A.
(3) Weighted average Common Shares outstanding.

The oil and natural gas exploration and production industry is cyclical in nature. Topaz's financial position, results of operations and cash flows are affected by commodity prices and production levels as its Royalty Production Revenue is directly impacted by commodity prices and production levels. In addition, commodity prices and production levels can indirectly affect its Processing Revenue and Other Income.

Topaz commenced its continuing operations on November 14, 2019. As discussed in "Discontinued Operations", Exshaw's E&P Assets were transferred to Tourmaline on November 12, 2019 and the operations have been presented as discontinued operations. During Topaz's first period of operation, its royalty production averaged 10,455 Boe/d which declined by 5% to average quarterly royalty production of 9,891 Boe/d during the second quarter of 2020. Similarly, Topaz's average royalty production for the six months ended June 30, 2020 of 10,134 Boe/d was 3% lower than the average production during the period ended December 31, 2019. The production declines are attributed to reduced development activity by Tourmaline due to seasonality restricting certain capital activity. Topaz's cash flow of $17.4 million during the second quarter of 2020 was 42% higher than the $12.3 million of cash flow generated during the period ended December 31, 2019. The increase is partially due to the difference in the number of days during the reporting periods due to the commencement of Topaz's continuing operations on November 14, 2019. Topaz's cash flow of $38.2 million during the six months ended June 30, 2020 was 211% higher than the cash flow generated during the period ended December 31, 2019 which is also primarily due to the difference in reporting periods. Commodity prices were significantly lower during the second quarter of 2020 and the six months ended June 30, 2020, compared to the period ended December 31, 2019. The reduction in commodity prices is partially attributed to the COVID-19 pandemic and other macro-economic conditions around the world which contributed to a drastic decrease in global oil and liquids demand since the beginning of 2020. Changes in commodity prices impact Topaz's Royalty Production Revenue and cash flow and can indirectly affect its Processing Revenue and Other Income.

Selected Annual Information from Continuing Operations(1)

	Six monthsended	Period fromNov. 14, 2019 to
($000s) except per share	June 30, 2020	Dec. 31, 2019(1)
Royalty production revenue	26,449	9,832
Processing revenue	11,264	2,943
Other income	5,066	1,408
	42,779	14,183
Cash expenses:
Operating	(1,871)	(481)
Marketing	(212)	(98)
General and administrative	(2,243)	(1,331)
Realized loss on financial instruments	(188)	─
Interest expense	(60)	─
Cash flow from continuing operations(2)	38,205	12,273
Per share	$0.48	$0.15
Cash from (used in) operating activities from continuing
operations	38,184	(350)
Per share(3)	$0.48	$(0.004)
Net income (loss) from continuing operations	(2,359)	653
Per basic and diluted share(3)	$(0.03)	$0.01
Dividends paid	32,000	─
Per share(3)	$0.40	─
Capital expenditures	271	─
Weighted average shares outstanding (000)	80,128	80,000

($000s)	At June 30, 2020	At Dec. 31, 2019
Total assets	793,323	697,234
Working capital	148,745	20,767
Adjusted working capital(2)	149,180	20,767
Net debt (cash)(2)	(149,180)	(20,767)
Common shares outstanding	91,690	80,000

Notes:

(1) No full year annual comparative results have been included in the table above as Topaz commenced its continuing operations on November 14, 2019. Furthermore, Exshaw's E&P Assets were transferred to Tourmaline on November 12, 2019 and the operations have been presented as discontinued operations. Refer to "Discontinued Operations" in this MD&A.
(2) Refer to "Non-GAAP Financial Measures" in this MD&A.

(3) Weighted average Common Shares outstanding.

DIRECTORS AND EXECUTIVE OFFICERS

The following table provides the names, residence and age of the directors of the Company and their principal occupation. The term of office of all directors of the Company will expire at the next annual meeting of shareholders of the Company and, thereafter, at each annual meeting of shareholders of the Company or at the time at which his or her successor is elected or appointed, or earlier if any director otherwise dies, resigns, is removed or is disqualified.

	Name, Residence and Age	Principal Occupation
Age: 63	Michael L. Rose (1)(3)(7)Calgary, Alberta, Canada	Chairman, President and Chief Executive Officer of Tourmaline
Age: 50	Tanya Causgrove (3)(4)(5)(8)Calgary, Alberta, Canada	Chief Financial Officer and Managing Director of ARC Financial
Age: 63	Jim Davidson (3)(6)Calgary, Alberta, Canada	Corporate Director
Age: 63	John Gordon (3)(4)(5)Calgary, Alberta, Canada	Corporate Director
Age: 54	Darlene Harris (3)(5)(6)Calgary, Alberta, Canada	Corporate Director
Age: 49	Steve Larke (2)(3)(4)Calgary, Alberta, Canada	Lead Independent Director, Corporate Director
Age: 63	Brian G. Robinson (3)(7)Calgary, Alberta, Canada	Director, Vice President, Finance and Chief Financial Officer ofTourmaline
Age: 54	Rafi Tahmazian (3)(6)Calgary, Alberta, Canada	Senior Portfolio Manager and Director of Canoe Financial
Notes:
(1)	Chair of the Board.
(2)	Lead Independent Director.
(3)		Mr. Rose was first appointed to the Board on December 13, 2006. Mr. Robinson was first appointed to the Board on November10, 2009. Messrs. Davidson, Gordon and Larke were each first appointed to the Board on November 14, 2019. Mr. Tahmazian'sappointment to the Board was authorized on November 14, 2019 and became effective on December 9, 2019. Ms. Harris wasfirst appointed to the Board on June 11, 2020. Ms. Causgrove was appointed to the Board on August 12, 2020.

(4) Member of the Governance, Compensation and Sustainability Committee. Mr. Larke is the Chair of the Governance, Compensation and Sustainability Committee.
(5) Member of the Audit Committee. Mr. Gordon is the Chair of the Audit Committee.
(6) Member of the Reserves Committee. Ms. Harris is the Chair of the Reserves Committee.
(7) Nominee of Tourmaline pursuant to the Governance Agreement. See "Agreements with Tourmaline and Other Counterparties — Governance Agreement".

(8) Nominee of ARC Energy Fund 9 pursuant to the ARC Board Nomination Rights Agreement, pursuant to which ARC Energy Fund 9 has the right to nominate one female representative to the Board. The ARC Board Nomination Rights Agreement terminates on Closing.

The following table provides the names, residences and ages of the executive officers of the Company and their offices held with the Company. Mr. Staples and Ms. Stephenson are each employed by the Company on a full-time basis and devote all of their executive time to the business and affairs of the Company.

Name and Residence	Offices Held
Marty StaplesCalgary, Alberta, CanadaAge: 45	President and Chief Executive Officer of the Company
Cheree StephensonCalgary, Alberta, CanadaAge: 40	Vice President, Finance and Chief Financial Officer of the Company
Note:

(1) Mr. Staples and Ms. Stephenson were each appointed to their roles on April 15, 2020.

The Company is currently evaluating potential candidates for roles in the areas of business development and accounting. Additional administrative and technical resources are being provided to the Company by Tourmaline pursuant to the Management Services Agreement. See "Agreements with Tourmaline and Other Counterparties — Management Services Agreement".

Directors and Executive Officers Biographical Information

The following are brief profiles of each of the executive officers and directors of the Company, which include a description of their present occupation and their principal occupations for the past five years.

Michael L. Rose

Mr. Rose's principal occupation is the Chairman, President and Chief Executive Officer of Tourmaline since he founded the Company in August 2008. Prior thereto, he was Chairman, President and Chief Executive Officer of Duvernay, a publicly traded oil and gas company (2004- 2008). Mr. Rose has held various exploration and production positions, including managing exploration and petroleum engineering research for a large exploration and production company before founding Berkley in 1993. After the sale of Berkley in 2001, Mr. Rose founded Duvernay, which was sold in August 2008. Mr. Rose was educated at Queen's University, graduating with an honours degree in Geology. Mr. Rose is a member of the Association of Professional Engineers and Geoscientists of Alberta and the Canadian Society of Petroleum Geologists. Among other awards, Mr. Rose is the recipient of the Stanley Slipper Gold Medal from the Canadian Society of Petroleum Geologists (2009). Mr. Rose has over 40 years of experience in the oil and gas industry.

Tanya Causgrove

Ms. Causgrove's principal occupation is Chief Financial Officer and Managing Director of ARC Financial. Ms. Causgrove is a member of ARC Financial's Executive Committee and is ARC Financial's Chief Compliance Officer. Ms. Causgrove leads ARC Financial's finance, accounting, tax, human resources, regulatory, technology and administrative functions and works closely with the investment team and investors. Ms. Causgrove currently represents ARC Financial on the board of Citadel Drilling Ltd. and holds a Bachelor of Commerce in Accounting from the University of Alberta, is a Chartered Professional Accountant (CPA, CA) and is a CFA Charterholder. Ms. Causgrove has more than 23 years of management experience in the energy industry.

Jim Davidson

Mr. Davidson's principal occupation is a Corporate Director. Mr. Davidson is a director of ATB Financial, the Business Council of Alberta, the Creative Destruction Lab, the Economic Futures Council of the Junior Achievement of Southern Alberta, the Fraser Institute and the Modern Miracle Network. Mr. Davidson was most recently Deputy Chairman of GMP FirstEnergy. Mr. Davidson co-founded FirstEnergy Capital Corp. in 1993. Mr. Davidson has more than 25 years of experience in the energy industry.

John Gordon

Mr. Gordon's principal occupation is a Corporate Director. Mr. Gordon is a director of TORC Oil & Gas Ltd. Mr. Gordon served as the Canadian Managing Partner, Quality and Risk Management, the Canadian Managing Partner, Audit and the Calgary Office Managing Partner for KPMG LLP prior to his retirement in 2018. Mr. Gordon has extensive experience in providing audit and other services to public oil and gas companies. Mr. Gordon is a Chartered Professional Accountant (FCPA), a Chartered Financial Analyst (CFA), and is a graduate of the University of Saskatchewan. Mr. Gordon serves on the Board of the CAMH Foundation, the Alberta Adolescent Recovery Centre, and is a lecturer for, and an active member of the Institute of Corporate Directors. Mr. Gordon has more than 30 years of experience in a variety of industries, including the energy sector.

Darlene Harris

Ms. Harris' principal occupation is a Corporate Director. Ms. Harris is a director and Chair of the Audit Finance Committee of the Spark Credit Union. Previously, Ms. Harris spent 32 years with Shell Canada, most recently as Senior Manager of M&A and Corporate Finance as well as Co-Chairman of the Shell Canada Pension Plan. Ms. Harris has a broad range of experience in strategic acquisitions and divestment, financial markets, banking, pension management and governance, talent management and directorship. Ms. Harris is a Chartered Professional Accountant (CPA, CMA).

Steve Larke

Mr. Larke's principal occupation is a Corporate Director. Mr. Larke is a director of Vermilion Energy Inc. and Headwater Exploration Inc. Mr. Larke's previous roles include Operating Partner and Advisory Board member with Azimuth Capital Management Inc., an energy-focused private equity fund based in Calgary, Alberta. Prior to joining Azimuth Capital Management Inc., Mr. Larke was Managing Director and Executive Committee member with Calgary-based Peters & Co. from 2005 to 2015, and prior thereto, was Vice-President and Director with TD Newcrest from 1997 to 2005. Both at Peters & Co. and TD Newcrest, Mr. Larke received leading rankings in the Brendan Wood International survey of institutional investors. Mr. Larke has a Bachelor of Commerce degree (with distinction) from the University of Calgary and has earned the Chartered Financial Analyst (CFA) and Institute of Corporate Directors (ICD.D) designations. In addition, Mr. Larke is a Fundamentals of Sustainability Accounting (FSA) Credential Holder. Mr. Larke has over 20 years of experience in energy capital markets, including research, sales, trading and equity finance.

Brian G. Robinson

Mr. Robinson's principal occupation is a director and Vice President, Finance and Chief Financial Officer of Tourmaline. Prior thereto, Mr. Robinson was Vice President, Finance and Chief Financial Officer of Duvernay and prior to that was Vice President, Finance and Chief Financial Officer of Berkley. Previously, Mr. Robinson held numerous positions in finance and accounting with intermediate and senior oil and gas companies, commencing his career with a large public accounting firm. Mr. Robinson is also a trustee of Boardwalk Real Estate Investment Trust, a publicly-traded real estate investment trust on the TSX. Mr. Robinson holds a Bachelor of Commerce degree from the University of Calgary and is a Chartered Accountant. Mr. Robinson has more than 39 years of experience in the oil and gas industry in the disciplines of finance, financial reporting, budgeting, accounting, management, treasury, tax, and business development.

Rafi Tahmazian

Mr. Tahmazian's principal occupation is Senior Portfolio Manager and Director with Canoe Financial. Mr. Tahmazian is also the lead portfolio manager for Canoe Energy Portfolio Class, Canoe Energy Income Portfolio Class, and Canoe Energy Alpha LP. Mr. Tahmazian is an award-winning portfolio manager. Prior to Canoe, Mr. Tahmazian spent 13 years at First Energy Capital, a leading investment dealer that focused on the energy industry. He left the firm in 2008 as Vice Chairman and Managing Director. He is currently on the board of directors for Artis Exploration Ltd, Aureus Energy Services Inc., Well Ventures Corp., Chance Oil and Gas Ltd., and Alberta Teachers Retirement Fund. Mr. Tahmazian holds a Bachelor of Economics degree from the University of Calgary. Mr. Tahmazian has more than 28 years of management experience in the energy industry.

Marty Staples

Mr. Staples is the President and Chief Executive Officer of the Company. Mr. Staples has been intimately involved in the growth and development of Tourmaline since 2010, which includes the execution of numerous asset and corporate acquisitions. Mr. Staples previously has also held positions at both private and public companies. Mr. Staples holds a Bachelor's Degree in Commerce from the Haskayne School of Business at the University of Calgary. Mr. Staples has over 18 years in the oil and gas industry in the areas of management, business development, exploration, land and evaluations.

Cheree Stephenson

Ms. Stephenson is the Vice President, Finance and Chief Financial Officer of the Company. Most recently, Ms. Stephenson was instrumental in the start-up and growth of Petrus Resources Ltd. ("Petrus") where she held the role of Vice President, Finance and Chief Financial Officer for nine years. Prior to her time at Petrus, she served as Controller at Peyto Exploration & Development Corp. after which she played an integral role in the start-up and growth of private oil and gas companies. Ms. Stephenson is a Chartered Professional Accountant (CPA, CA) and holds a Bachelor's Degree in Commerce from the Haskayne School of Business at the University of Calgary. Ms. Stephenson has over 18 years in the oil and gas industry in the areas of corporate finance and accounting.

Security Ownership by Directors and Executive Officers

As at the date hereof, the directors and executive officers of the Company beneficially own or exercise control or direction over, directly or indirectly, 1,139,665 Common Shares (approximately 1% of the issued and outstanding Common Shares), or 67,985,650 Common Shares (approximately 73% of the issued and outstanding Common Shares), if the Common Shares beneficially owned or over which control or direction is exercised, directly or indirectly, by Tourmaline, ARC Energy Fund 9 and Canoe Financial, entities associated with certain directors of the Company, are included. The directors and executive officers of the Company are anticipated to purchase approximately $• million in Common Shares pursuant to the Offering, which will result in such directors and executive officers beneficially owning or exercising control or direction over, directly or indirectly, • Common Shares (approximately •% of the issued and outstanding Common Shares). Certain of the directors of the Company are directors or executive officers of Tourmaline, which will own •% (•% if the Over-Allotment Option is exercised in full) of the issued and outstanding Common Shares following completion of the Offering. See "Principal Shareholders and Selling Shareholder" and "Directors and Executive Officers — Conflicts of Interest".

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

Cease Trade Orders

To the knowledge of the Company, no director or executive officer of the Company (nor any personal holding company of any of such persons) is, as of the date of this prospectus, or was within ten years before the date of this prospectus, a director, chief executive officer or chief financial officer of any company (including the Company), that: (i) was subject to a cease trade order (including a management cease trade order), an order similar to a cease trade order or an order that denied the relevant company access to any exemption under securities legislation, in each case that was in effect for a period of more than 30 consecutive days (collectively, an "Order"), that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; or (ii) was subject to an Order that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer or chief financial officer.

Bankruptcies

Other than as set forth below, to the knowledge of the Company, no director or executive officer of the Company (nor any personal holding company of any of such persons) or shareholder holding a sufficient number of securities of the Company to affect materially the control of the Company: (i) is, as of the date of this prospectus, or has been within the ten years before the date of this prospectus, a director or executive officer of any company (including the Company) that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets; or (ii) has, within the ten years before the date of this prospectus, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, executive officer or shareholder.

Mr. Rose, a director of the Company, and the President and Chief Executive Officer and a director of Tourmaline, served as a director of Nordegg Resources Inc. ("Nordegg") until June 10, 2016. On June 16, 2016, a secured creditor of Nordegg was granted an order under the Bankruptcy and Insolvency Act (Canada) appointing a receiver to take possession and exercise control over all of Nordegg's current and future assets.

Penalties or Sanctions

Other than as set forth below, to the knowledge of the Company, no director or executive officer of the Company (nor any personal holding company of any of such persons), or shareholder 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.

On June 30, 2005, the United States Securities and Exchange Commission ("SEC") issued a settlement order relating to certain administrative proceedings involving a number of parties including KPMG LLP and Mr. Gordon, a former partner of KPMG LLP. The SEC alleged that during the years 1999 to 2002, Mr. Gordon, while a partner at KPMG LLP, knew, in his role as concurring and reviewing audit partner, that certain accounting services were being provided by KPMG LLP to an SEC registrant, while KPMG LLP were also serving as auditors to the same registrant. KPMG LLP received $60,148 in aggregate fees from the audit and bookkeeping services it performed for this registrant during this period. Under the terms of the settlement with the SEC, Mr. Gordon agreed not to appear or practice as an accountant before the SEC, with respect to SEC registrants, for a period of nine months, after which time, he was automatically reinstated.

Conflicts of Interest

Certain of the directors and executive officers of the Company are engaged in, and may continue to be engaged in, other activities in the industries in which the Company operates from time to time. Messrs. Rose and Robinson are directors and executive officers of Tourmaline. Tourmaline is a party to certain agreements as described under "Agreements with Tourmaline and Other Counterparties" and "Material Contracts". Tourmaline is not prohibited from competing with the Company and its affiliates.

The ABCA provides that in the event that an officer or director 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 material transaction or proposed material contract or proposed material transaction, such officer or director shall disclose the nature and extent of his or her interest and shall refrain from voting to approve such contract or transaction, unless otherwise provided under the ABCA. To the extent that conflicts of interest arise, such conflicts will be resolved in accordance with the provisions of the ABCA.

Indebtedness

The Company is not aware of any individuals who are either current or former executive officers, directors or employees of the Company and who have indebtedness outstanding as at the date hereof (whether entered into in connection with the purchase of securities of the Company or otherwise) that is owing to: (i) the Company; or (ii) another entity where such indebtedness is the subject of a guarantee, support agreement, letter of credit or other similar arrangement or understanding provided by the Company.

Insurance Coverage and Indemnification

A new directors' and officers' insurance policy will become effective at Closing replacing the Company's existing directors' and officers' insurance policy. The new policy will have coverage and terms that are customary for a publicly traded company of its size in the industry in which it operates. In addition, the Company has entered into indemnification agreements with its directors and officers. The indemnification agreements generally require that the Company indemnify and hold the indemnitees harmless to the greatest extent permitted by law for liabilities arising out of the indemnitees' service to the Company as directors and officers, if the indemnitees acted honestly and in good faith with a view to the best interests of the Company and, with respect to criminal or administrative actions or proceedings that are enforced by monetary penalty, if the indemnitee had no reasonable grounds to believe that his or her conduct was unlawful. The indemnification agreements also provide for the advancement of defence expenses to the indemnitees by the Company.

CORPORATE GOVERNANCE

The Board has adopted mandates, position descriptions and corporate governance principles and practices that are intended to meet or exceed the independence and other governance standards and guidelines set out in NI 52-109, NI 52-110, NI 58- 101 and NP 58-201. The corporate governance principles address various topics, including:

responsibilities and duties of the Board;
composition of the Board, including criteria for remaining a director;
compensation of the Board;
composition and responsibilities of the Audit Committee, the Reserves Committee and the Governance, Compensation and Sustainability Committee;
relationship of the Board to Management;
approach to diversity within the Company and among the directors; and
director orientation and continuing education.

The Board

The Company has eight directors, six of whom are independent as specified in NI 58-101. A director is independent if he or she has no direct or indirect material relationship with the Company or its subsidiaries. A "material relationship" is a relationship which could, in the view of the Board, be reasonably expected to interfere with the exercise of a director's independent judgment. Certain types of relationships are, by their nature, considered to be material relationships.

All of the members of the Board are independent directors of the Company, except Mr. Rose because he is the President, Chief Executive Officer and Chairman of Tourmaline and Mr. Robinson because he is the Vice-President, Finance, Chief Financial Officer and a director of Tourmaline.

The Company takes steps to ensure that adequate structures and processes are in place to permit the Board to function independently of the Company and Tourmaline. The Company has a Lead Independent Director and the role of the Lead Independent Director will be to effectively manage and to provide leadership to the Board and to ensure that the policies and procedures adopted by the Board allow the Board to function independently of Management and Tourmaline. Where matters arise at meetings of the Board which require decision making and evaluation that is independent of Management and interested directors of the Company, directors will hold an "in-camera" session among the independent and disinterested directors, without Management and interested directors present at such meeting.

Certain directors of the Company are also directors of other reporting issuers (or the equivalent):

Director	Other Directorships	Stock Exchange Listing
Michael L. Rose	Tourmaline	TSX
John Gordon	TORC Oil & Gas Ltd.	TSX
Steve Larke	Vermilion Energy Inc.Headwater Exploration Inc.	TSXTSX
Brian G. Robinson	TourmalineBoardwalk Real Estate InvestmentTrust	TSXTSX

Board Mandate

The primary responsibility of the Board is to appoint competent Management and to oversee the management of the Company with a view to maximize shareholder value and ensure corporate conduct in an ethical and legal manner through an appropriate system of corporate governance and internal controls. The Board has absolute and exclusive power, control and authority over the property and affairs of the Company. Subject to the provisions of the ABCA, the Board may delegate certain of those powers and authority that the directors of the Company, or independent directors, as applicable, deem necessary or desirable to effect the actual administration of the duties of the Board. The directors of the Company have certain responsibilities as more particularly described in the Board of Directors' Mandate, a copy of which is attached to this prospectus as Appendix "F". See "Risk Factors — Risks Relating to the Company's Relationship with Tourmaline". See also "Directors and Executive Officers — Conflicts of Interest".

Position Descriptions

The Board has adopted written guidelines for the Chair of the Board, the Lead Independent Director, the Chair of each of the Audit Committee, the Governance, Compensation and Sustainability Committee, the Reserves Committee and the President and Chief Executive Officer ("CEO") of the Company.

The primary responsibilities of the Chair of the Board include: (i) ensuring that the Board is properly organized, functions effectively and meets its obligations and responsibilities in all aspects of its work, including those relating to corporate governance matters; and (ii) working with the CEO to co-ordinate the affairs of the Board and ensure effective relations with the directors of the Company, shareholders, other stakeholders and the public.

The primary responsibilities of the Lead Independent Director include providing independent leadership to the Board to facilitate the functioning of the Board independently of Management of the Company and other non-independent Board members.The Lead Independent Director may consult and meet with any or all of the independent Board members, at the discretion of the members and with or without the attendance of the Chair, and, as appropriate and without inhibiting direct communication, represent such Board members in discussions with the Chair on corporate governance and other matters. The Lead Independent Director may also assist in the process of conducting director evaluations. The Lead Independent Director ensures that reasonable procedures are in place for directors to consult outside advisors at the expense of the Company in appropriate circumstances, subject to its prior approval, and is to meet annually with independent directors to obtain insight as to where they believe the Board and its Committees could operate more effectively.

The responsibilities of the Chair of each committee include: (i) ensuring that their respective committee is properly organized, functions effectively and meets its obligations and responsibilities in accordance with its mandate; and (ii) to liaise and communicate with the Chair of the Board to co-ordinate input from the committee for Board meetings.

The primary responsibilities of the CEO include: (i) providing general direction and management of the business and affairs of the Company in accordance with the corporate strategy and objectives approved by the Board, within the authority limitations delegated by the Board; and (ii) establishing a process of supervision of the business and affairs of the Company that are consistent with corporate objectives, ensuring that procedures are in place for proper external and internal corporate communications to all stakeholders, and monitoring and reporting results to the Board.

Meetings of Independent Directors

The Board holds regularly-scheduled quarterly meetings as well as ad hoc meetings from time to time. The independent members of the Board also meet, as required, without the non-independent directors and members of Management before or after regularly scheduled Board meetings. A director who has a material interest in a matter before the Board or any committee on which he or she serves is required to disclose such interest as soon as the director becomes aware of it. In situations where a director has a material interest in a matter to be considered by the Board or any committee on which he or she serves, such director is required to absent himself or herself from the meeting while discussions and voting with respect to the matter are taking place, for example when discussions and/or voting are taking place with respect to proposed transactions between the Company and Tourmaline. Directors are also required to comply with the relevant provisions of the ABCA regarding conflicts of interest.

Orientation and Continuing Education

The orientation and continuing education of the directors of the Company is the responsibility of the Governance, Compensation and Sustainability Committee. The details of the orientation of new directors will be tailored to their needs and areas of expertise and will include the delivery of written materials and participation in meetings with Management and directors. The focus of the orientation program will be on providing new directors with: (i) information about the duties and obligations of directors; (ii) information about the Company's strategy and business; (iii) the expectations of directors; (iv) opportunities to meet with Management and any other senior employees or consultants designated for this purpose; and (v) access to documents from recent meetings of the Board.

The directors of the Company have all been chosen for their specific level of knowledge and expertise. In addition, directors are kept informed as to matters impacting, or which may impact, the business of the Company through reports and presentations by internal and external presenters at meetings of the Board and during periodic strategy sessions held by the Board.

Business Code of Conduct

The Board has adopted a written business code of conduct (the "Code of Conduct") that encourages and promotes a culture of ethical business conduct that is applicable to directors, Management, employees, consultants and other service providers of the Company. The Code of Conduct addresses a number of important topics, including conflicts of interest, corporate opportunities, confidentiality, protection and proper use of company assets, insider trading, fair dealing, compliance with laws, rules and regulations, compliance with environmental laws, discrimination and harassment, safety and health, accuracy of company records and reporting, use of email and internet services, political activities and contributions, illicit payments, payments to officials, the role of directors in the Code of Conduct, and compliance procedures.

The Board monitors compliance with the Code of Conduct by requiring that each director and employee acknowledge in writing his or her agreement to abide by the Code of Conduct when commencing service with the Company.

In addition to the Code of Conduct, the Board has adopted "Whistleblowing Procedures" which provides directors, employees and consultants of the Company with a mechanism by which they may raise concerns including (but not limited to) falsification of financial records, unethical conduct, harassment and theft through a confidential, anonymous process.

Upon Closing, the Company will file a copy of the Code of Conduct on SEDAR at www.sedar.com under the Company's profile.

Nomination and Election of Directors

The Governance, Compensation and Sustainability Committee, which is comprised entirely of independent directors, is responsible for recommending suitable candidates for nomination for election as directors of the Company in accordance with the terms of its mandate and subject to the applicable terms of the Governance Agreement. Pursuant to the Governance Agreement, Tourmaline is entitled to direct the Company to nominate the greater of two and 33.33% of the members of the Board (rounded up to the nearest whole number) for so long as the percentage of outstanding Common Shares (on a nondiluted basis) beneficially owned directly or indirectly by Tourmaline is not less than 10% of the issued and outstanding Common Shares. The nominees of Tourmaline to the Board may be directors, officers or employees of Tourmaline or its affiliates, or other persons, at Tourmaline's discretion. See "Agreements with Tourmaline and Other Counterparties — Governance Agreement".

The shareholders are entitled to elect directors of the Company and the provisions of the Governance Agreement do not restrict the voting rights of shareholders. The Board has adopted a Majority Voting Policy requiring that a director tender his or her resignation if the director receives more "withhold" votes than "for" votes at any meeting where shareholders vote on the uncontested election of directors. The Governance, Compensation and Sustainability Committee will consider any such resignation and make a recommendation to the Board. In the absence of special circumstances, it is expected that the Board will accept the resignation consistent with an orderly transition. The director will not participate in any Governance, Compensation and Sustainability Committee or Board deliberations on the resignation offer. It is anticipated that the Board will make its decision to accept or reject the resignation within 90 days. The Board may fill the vacancy in accordance with the Company's by-laws, applicable corporate laws and provisions of the Governance Agreement.

In addition, the Company's by-laws also include "advance notice provisions" designed to: (i) facilitate an orderly and efficient annual meeting or, where the need arises, special meeting, process; (ii) ensure that all shareholders receive adequate notice of director nominations and sufficient information with respect to all nominees; and (iii) allow shareholders to register an informed vote having been afforded reasonable time for appropriate deliberation. As a whole, these provisions are intended to provide shareholders, directors and Management of the Company with a clear framework for nominating directors. In particular, these provisions of the by-laws fix a deadline (being not less than 30 days before the date of an annual meeting of shareholders and, in the case of a special meeting, the 15th day following the day on which the first public announcement of the date of the special meeting of shareholders was made) by which holders of record of Common Shares must submit director nominations to the Company prior to any annual or special meeting of shareholders, and also set forth the information that a shareholder must include in the notice to the Company for the notice to be in proper written form in order for any director nominee to be eligible for election at any annual or special meeting of shareholders. The Company's by-laws are available on SEDAR at www.sedar.com under the Company's profile.

Compensation of Directors and Officers

The remuneration of the directors of the Company will be set and periodically reviewed by the Board on the recommendation of the Governance, Compensation and Sustainability Committee.

The compensation of Management will be periodically reviewed by the Board on the recommendation of the Governance, Compensation and Sustainability Committee. See "Executive Compensation".

Following Closing, the Company expects to adopt share ownership guidelines to encourage alignment with the interests of shareholders by requiring its directors and Management to build and hold equity in the Company in accordance with prescribed guidelines.

Board Committees

The Board has appointed three standing committees: the Audit Committee, the Governance, Compensation and Sustainability Committee and the Reserves Committee.

Audit Committee

The Audit Committee is comprised of Mr. Gordon, as Chair, and Ms. Causgrove and Ms. Harris, all of whom are independent and financially literate within the meaning of that term under NI 52-110. The specific responsibilities of the Audit Committee are set out in the Audit Committee Mandate and Terms of Reference, a copy of which is attached to this prospectus as Appendix "E". The Audit Committee's primary role is to: (i) review Management's identification of principal financial risks and monitor the process to manage such risks; (ii) oversee and monitor the Company's compliance with legal and regulatory requirements; (iii) oversee and monitor the integrity of the Company's accounting and financial reporting processes, financial statements and system of internal controls regarding accounting and financial reporting and accounting compliance; (iv) oversee audits of the Company's financial statements; (v) oversee and monitor the qualifications, independence and performance of the Company's external auditors; (vi) provide an avenue of communication among the external auditors, Management, the accountants and the Board; and (vii) report to the Board regularly.

The Company believes that each of the members of the Audit Committee possesses substantially all of the following: (i) an understanding of the accounting principles used by the Company to prepare its financial statements; (ii) the ability to assess the general application of such accounting principles in connection with the accounting for estimates, accruals and reserves; (iii) experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by the Company's financial statements, or experience actively supervising one or more individuals engaged in such activities; and (iv) an understanding of internal controls and procedures for financial reporting. For a summary of the education and experience of each member of the Audit Committee that is relevant to the performance of his or her responsibilities as a member of the Audit Committee, see "Directors and Executive Officers — Directors and Executive Officers Biographical Information".

The table below provides disclosure of the fees billed to the Company by its external auditors to date in fiscal 2020 and for the fiscal period from November 14, 2019 to December 31, 2019, dividing the services into the categories of work performed.

Type of Work	2020 Fees	2019 Fees	Nature of Services Performed
Audit Fees	$275,000	$Nil	For professional servicesrendered with respect to theaudits of the Topaz FinancialStatements and the InitialAcquisition OperatingStatements
Audit Related Fees	$345,000	$Nil	For professional servicesrendered with respect to theOffering
Tax Fees	$Nil	$Nil	N/A
All Other Fees	$Nil	$Nil	N/A
Total	$620,000	$Nil

Defined Terms:

"Audit Fees" include fees necessary to perform the annual audit and quarterly reviews of the Company's consolidated financial statements. Audit Fees include fees for review of tax provisions and for accounting consultations on matters reflected in the financial statements. Audit Fees also include audit or other attest services required by legislation or regulation, such as statutory audits.
"Audit-Related Fees" include services that are reasonably related to the performance of the audit or review of the Company's financial statements and are not reported under "Audit Fees" above. These auditrelated services include employee benefit audits, due diligence assistance, accounting consultations on proposed transactions, management information circulars and prospectus offerings, internal control reviews and audit or attest services not required by legislation or regulation.
"Tax Fees" include fees for all tax services other than those included in "Audit Fees" and "Audit-Related Fees". This category includes fees for tax compliance, tax planning and tax advice. Tax planning and tax advice includes assistance with tax audits and appeals, tax advice related to mergers and acquisitions, and requests for rulings or technical advice from tax authorities.
"All Other Fees" include all other non-audit services.

All non-audit services are disclosed and approved by the Audit Committee.

Governance, Compensation and Sustainability Committee

The Governance, Compensation and Sustainability Committee is comprised of Mr. Larke, as Chair, and Ms. Causgrove and Mr. Gordon, all of whom are independent for the purposes of NI 58-101. The specific responsibilities of the Governance, Compensation and Sustainability Committee are set out in the Governance, Compensation and Sustainability Committee Mandate, a copy of which will be available on the Company's website (www.•.com) upon completion of the Offering. The primary role of the Governance, Compensation and Sustainability Committee is to: (i) develop, implement and monitor governance standards and best practices; (ii) review the mandates of the Board and its committees; (iii) regularly assess the effectiveness of the Board as a whole, the committees of the Board and the contributions of individual directors; (iv) oversee the preparation of the annual "Statement of Corporate Governance Practices"; (v) identify and recommend individuals for nomination as members of the Board and its committees and for appointment as officers; (vi) review and recommend to the Board all matters pertaining to the compensation of directors and Management; (vii) review the Company's fundamental policies and internal controls pertaining to environment, health and safety, and sustainability and review procedures designed to minimize environmental, occupational health and safety and other risks to asset value while undertaking due consideration of opportunities and performance enhancement thereto; (viii) verify that management proactively identifies and monitors the impact of proposed legislation and other emerging issues in environment and sustainability areas; and (ix) confirm that the Company's business is conducted in a socially responsible, ethical and transparent manner and that management engages, respects and supports the communities in which the Company works.

Reserves Committee

The Reserves Committee is comprised of Ms. Harris, as Chair, and Messrs. Davidson and Tahmazian, all of whom are independent for purposes of NI 51-101. The specific responsibilities of the Reserves Committee are set out in the Reserves Committee Mandate, a copy of which will be available on the Company's website upon completion of the Offering. The primary role of the Reserves Committee is to: (i) act in an advisory capacity to the Board; (ii) review the Company's procedures relating to disclosure of information with respect to crude oil, natural gas and NGL reserves and resources data; (iii) annually review the selection of the qualified reserves evaluators or auditors chosen to report to the Board on the Company's crude oil, natural gas and NGL reserves and resources data; and (iv) review the Company's annual reserves and resources estimates prior to public disclosure.

Assessment of Directors, the Board and Board Committees

The members of the Board will collectively assess the performance of the Board as a whole, the committees of the Board and all directors. Such assessment will occur annually with an emphasis on the overall effectiveness and contributions made by the Board as a whole, the committees of the Board and all directors individually.

Diversity – Board and Executive Officers

Topaz is committed to diversity on its Board and in executive officer positions. The Board recognizes that diversity among its directors will support balanced discussion and debate which, in turn, will enhance decision making by the Board while considering the different perspectives of the members of the Board. Upon Closing, the Board will adopt a formal written diversity policy (the "Diversity Policy"). The Board will seek to achieve a target of at least 30% representation by women on the Board by no later than the end of 2023. The achievement of this objective will be monitored and reported on by the Governance, Compensation and Sustainability Committee. Currently, 50% of the executive officers of the Company and 25% of the directors are women.

The Board values diversity of experience, perspective, education, gender, background, race and national origin. The selection of candidates for appointment or nomination to the Board will be based on merit, experience and expected contribution to the Board's performance, which accordingly takes in to account diversity.

The Board and the Company are committed to ensuring a diverse and inclusive culture across the organization, including at the executive level, by promoting equality of opportunity. The Company has not imposed quotas or targets regarding the representation of women in executive officer positions, however, the Board encourages the consideration of women who have the necessary skills, knowledge, experience and character when considering new potential candidates for executive officer positions.

Director Term Limits

The Board does not believe that fixed term limits or mandatory retirement ages are in the best interest of the Company and as such, it has not specifically adopted term limits or other automatic mechanisms for board renewal.

In considering nominees for the Board, the Governance, Compensation and Sustainability Committee will develop a skills and competencies matrix for the Board as a whole and for individual directors. The Governance, Compensation and Sustainability Committee will also conduct a process for the assessment of the Board as a whole, each committee and each director regarding his, her or its effectiveness and contribution, and will report evaluation results to the Board on a regular basis. In addition, the Governance, Compensation and Sustainability Committee will also assess the knowledge, experience and character of all nominees to the Board and other factors such as independence of the directors to ensure that the Board is operating effectively and independently of Management and Tourmaline. The Board also considers whether the individual will enhance the diversity of views and experiences available to the Board in its deliberations.

The independent members of the Board were appointed between November 14, 2019 and August 12, 2020. Mr. Rose and Mr. Robinson have served on the Board since 2006 and 2009, respectively.

Environmental and Sustainability Oversight

Topaz and its Board are committed to conducting business in an environmentally responsible and sustainable manner. Recognizing the importance of environmental and sustainability factors to the Company's business, the Board has delegated oversight of such factors to the Governance, Compensation and Sustainability Committee. This Committee is responsible for, among other things, reviewing and ensuring the adequacy of the Company's fundamental policies, internal controls, risks and opportunities pertaining to environment, sustainability, climate change, health and safety. The Committee is also responsible for confirming that business is conducted in a socially responsible, ethical and transparent manner and that Management engages, respects and supports the communities in which the Company works. See "Board Committees - Governance, Compensation and Sustainability Committee" for further details.

Trading Restrictions

The Company's Disclosure, Confidentiality and Trading Policy provides that directors, officers and employees of the Company shall not knowingly sell, directly or indirectly, a security of the Company if such person selling such security does not own or has not fully paid for the security to be sold and shall not, directly or indirectly, buy or sell a call or put in respect of a security of the Company. Notwithstanding these prohibitions, directors, officers and employees of the Company may sell a security which such person does not own if such person owns another security convertible into such security or an option or right to acquire such security sold and, within 10 days after the sale, such person: (i) exercises the conversion privilege, option or right and delivers the securities so associated to the purchaser; or (ii) transfers the convertible security, option or right, if transferable to the purchaser.

Clawback Policy

The Board has adopted an executive incentive compensation recoupment policy (the "Clawback Policy") in order to enhance the Company's alignment with good compensation governance practices and to assist Topaz in managing its compensationrelated risk. The Clawback Policy applies to all persons who are, or become, executives and applies to all incentive compensation awarded, granted or paid to an executive, which includes annual cash bonuses and Options. The Clawback Policy provides that where there is a restatement of the financial results of Topaz for any reason other than a restatement caused by a change in applicable accounting rules or interpretations, and, in connection with such restatement an officer engaged in willful misconduct or fraud, the Board may determine and recover any excess compensation received by an executive in accordance with the terms of the Clawback Policy.

EXECUTIVE COMPENSATION

The following discussion describes the significant elements of the Company's executive compensation program, with particular emphasis on the process for determining compensation payable to Marty Staples, as the President and CEO and Cheree Stephenson, as the Vice President, Finance and Chief Financial Officer ("CFO") of the Company (together, the "Named Executive Officers").

The description contained herein represents the incentive program approved by the Board. Following Closing, the Governance, Compensation and Sustainability Committee will meet with Management to review the Company's executive compensation program and, if deemed appropriate, will make further recommendations to the Board regarding changes to the program in light of the then relevant factors.

Compensation Discussion and Analysis

General

Following Closing and based on recommendations made by the Governance, Compensation and Sustainability Committee, the Board will make decisions regarding salaries, short-term incentives (in the form of annual cash awards or "bonuses") and long-term incentive compensation for Management, and will approve corporate goals and objectives relevant to the compensation of the CEO and the other members of Management. The Board will solicit input from the CEO and the Governance, Compensation and Sustainability Committee regarding the performance of the Company's other members of Management. Finally, the Board will also administer the incentive compensation and benefit plans with the assistance of the Governance, Compensation and Sustainability Committee.

CEO Compensation

The compensation of the CEO will be reviewed annually and determined by the Board as a whole on the recommendation of the Governance, Compensation and Sustainability Committee. It is anticipated that the level of CEO compensation will be determined by the Board considering all factors which they deem appropriate, including CEO salaries for companies of comparable size, industry, geography and complexity. The incentive awards will be determined by the Board, upon recommendation of the Governance, Compensation and Sustainability Committee, based on consideration such as the Company's overall performance, relative shareholder returns or other relevant factors.

Compensation Objectives and Principles

The Board recognizes that the Company's success depends greatly on its ability to attract, retain and motivate employees at all levels, which can only occur if the Company has an appropriately structured and executed compensation program. The Company's compensation policies will be founded on the principle that executive and employee compensation should be consistent with shareholders' interests and the Company's incentive programs are therefore intended to encourage decisions and actions that will result in the Company's growth and create long-term shareholder value, while specifically not rewarding excessive risk-taking by Management or employees. In determining the compensation to be paid to Management, the Governance, Compensation and Sustainability Committee will consider various items including corporate achievements, comparative market data and information supplied by Management or external consultants with expertise on such matters.

The principal objectives of the Company's executive compensation program are as follows:

to attract and retain qualified Management;
to have a compensation package that is competitive within the marketplace;
to align Management's interests with those of the shareholders; and
to reward the demonstration of both leadership and performance that creates long-term shareholder value.

The Governance, Compensation and Sustainability Committee's objective will be to ensure the compensation of the Named Executive Officers provides a competitive package that reflects the above objectives, as well as provides a link between discretionary short and long-term incentives with short and long-term corporate goals. The compensation package will be designed to reward performance based on the achievement of performance goals and objectives and to be competitive with comparable companies in the market in which the Company competes for talent.

Executive Compensation

Executive compensation was determined by considering the anticipated size, scope, stage of development and risk profile of the Company relative to a group of peer companies including royalty, infrastructure and dividend-paying entities. Executive compensation is expected to be reviewed periodically and may be adjusted based on the size, scope, stage of development and risk profile of the Company.

Components of Compensation

The following components currently comprise the compensation package for the Named Executive Officers: (i) base salary; (ii) annual cash awards; and (iii) participation in the Company's long-term incentive program. Following Closing, all salary increases, cash bonuses and long-term incentive compensation for the Named Executive Officers will be reviewed by the Governance, Compensation and Sustainability Committee and amended as deemed appropriate with the approval of the Board.

Base Salary

The base salary of each Named Executive Officer will be determined by the Governance, Compensation and Sustainability Committee. The base salary of each Named Executive Officer is anticipated to be based on the median of a group of peer companies but may be adjusted upward or downward to reflect factors that include the relative complexity of the Named Executive Officer's role as compared to the peer group. Salaries will be reviewed annually and compared to the compensation market through publicly available information and the broader market through analysis of industry compensation surveys as prepared by external compensation consultants. Consideration may also be given to internal factors including the strategy and growth plans of the Company and the objective to attract and retain highly talented individuals from the industry.

Annual Cash Awards

Annual cash awards are intended to motivate and reward Named Executive Officers for achieving and surpassing annual corporate and individual goals but are fully discretionary and are not guaranteed year over year. Bonuses for the Named Executive Officers will be recommended by the Governance, Compensation and Sustainability Committee and approved by the Board. Under the discretionary bonus plan, there are no guarantees that any employee or executive officer will receive a bonus.

Long-Term Incentive Program

The long-term incentive program of the Company currently consists of Option grants (under the Option Plan). These awards are intended to encourage participants to focus on creating and improving the Company's long-term financial success and provide participants an opportunity to benefit from the share performance of the Company. The purpose of the long-term incentive program is to align the interests of shareholders and Management. See "Executive Compensation — Option Plan".

Summary Compensation Table

Based on the information available at the date hereof, the following table sets out information concerning the initial expected annualized compensation anticipated to be paid by the Company to the Named Executive Officers for the fiscal year ended December 31, 2020.

			Annual	Long-term	All other
		Option-based	incentive	incentive	compensation	Total
Name and Principal Position	Salary($)(1)	awards ($)(2)	plans ($)(3)	plans ($)(4)	($)(4)	compensation ($)
Marty Staples, President and CEO	$400,000	$212,200	N/A	N/A	Nil	$612,200
ChereeStephenson,VicePresident,	$300,000	$169,760	N/A	N/A	Nil	$469,760
Finance and CFO

(1) Base salaries presented are annualized amounts. The actual salaries paid during the year will be prorated based on the commencement date of the Named Executive Officer's employment.
(2) Represents estimation of the fair value of the options in accordance with IFRS and does not reflect what was actually paid to the option holder. The fair value of options granted are estimated at the date of grant using a Black-Scholes option pricing model with the following assumptions for the six months ended June 30, 2020: weighted average risk-free interest rate of 0.42%; dividend per share of $0.80; volatility factor of the estimated price of the common shares of 33%; and an average expected life of the Options of five years. The fair value is allocated to accounting periods in accordance with IFRS.
(3) The amount of non-equity incentive compensation to be paid to the Named Executive Officers in the form of annual cash awards for the 2020 calendar year, if any, has not yet been determined.
(4) The amount of all other compensation that might be paid to the Named Executive Officer has not yet been determined by the Governance, Compensation and Sustainability Committee and the Board, although it is not expected that the amounts will be a material component of a Named Executive Officer's total compensation.
(5) The Company does not have a pension plan or retirement savings plan in place nor are any anticipated to be put in place on Closing.

Outstanding Option-Based Awards

The following table sets forth, for each Named Executive Officer, information concerning the option-based awards that are anticipated to be outstanding on Closing. The Company has no outstanding share-based awards nor are any anticipated to be outstanding on Closing.

	Common Shares
	underlying			Value of unexercised
	unexercised	Exercise prices of	Option expiration	in-the-money
Name and Principal Position	Options(#)	Options($)	dates	Options($)(1)
Marty Staples, President and CEO	250,000	$10.00	April 15, 2027	N/A
Cheree Stephenson, Vice President, Finance and CFO	200,000	$10.00	April 15, 2027	N/A

Notes:

(1) The market value of the Common Shares underlying these Options on the date of this prospectus is not reasonably ascertainable, given that the Common Shares are not and have never been publicly listed or traded.
(2) None of the Options under the Option Plan will be vested on the date of Closing.

Option-Based Awards — Value Vested or Earned

No option-based awards presently awarded or anticipated to be awarded to the Named Executive Officers will be vested on Closing.

Termination and Change of Control Benefits

The Company has not entered into executive employment agreements with any Named Executive Officer nor has it entered into any change of control provisions that provide for payment of severance, other than the accelerated vesting of Options in connection with a Take-Over Bid (as defined in the Option Plan).

Directors' Compensation

The compensation of the Company's directors is designed to attract and retain committed and qualified directors and to align their compensation with the long-term interests of its shareholders. The Board, on the recommendation of the Governance, Compensation and Sustainability Committee, is responsible for reviewing and approving any changes to the directors' compensation arrangements.

No retainer fees are currently paid to the directors. In consideration for serving on the Board, each director was granted Options in respect of 200,000 Common Shares pursuant to the Option Plan. Directors will be reimbursed for their reasonable out-of-pocket expenses incurred while serving as directors. It is anticipated that the Governance, Compensation and Sustainability Committee will review the compensation structure for the directors following Closing.

Name	Feesearned ($)	Option-basedawards ($)(1)	Non-equityincentive plancompensation ($)	All othercompensation($)	Total ($)
Michael L. Rose	Nil	$167,744	Nil	Nil	$167,744
Tanya Causgrove(2)	Nil	$213,718	Nil	Nil	$213,718
Jim Davidson	Nil	$167,744	Nil	Nil	$167,744
John Gordon	Nil	$167,744	Nil	Nil	$167,744
Darlene Harris	Nil	$212,049	Nil	Nil	$212,049
Steve Larke	Nil	$167,744	Nil	Nil	$167,744
Brian G. Robinson	Nil	$167,744	Nil	Nil	$167,744
Rafi Tahmazian	Nil	$167,744	Nil	Nil	$167,744

Notes:

(1) Represents estimation of the fair value of the options in accordance with IFRS and does not reflect what was actually paid to the option holder. The fair value of options granted are estimated at the date of grant using a Black-Scholes option pricing model with the following assumptions for the six months ended June 30, 2020: weighted average risk-free interest rate of 0.42%; dividend per share of $0.80; volatility factor of the estimated price of the common shares of 33%; and an average expected life of the Options of five years and for the period from November 14 to December 31, 2019: weighted average risk-free interest rate of 1.64%; dividend per share of $0.80; volatility factor of the estimated price of the common shares of 30%; and an average expected life of the Options of five years. The fair value is allocated to accounting periods in accordance with IFRS.
(2) Compensation awarded to Ms. Causgrove is held for the benefit of ARC Financial or its affiliates pursuant to a written agreement between Ms. Causgrove and ARC Financial.

Directors will participate in the insurance and indemnification arrangements described under "Directors and Executive Officers — Insurance Coverage and Indemnification".

Director Outstanding Option-Based Awards

The following table sets forth, for each director, all option-based awards that are anticipated to be outstanding on Closing. No share-based awards have been granted to any directors of the Company.

			Option-based awards(3)
Name	Common SharesUnderlying unexercisedOptions (#)	Exercise pricesof Options ($)	Option expirationdates	Value of unexercisedin-the-moneyOptions ($)(1)(2)
Michael L. Rose	200,000	$10.00	December 17, 2026	N/A
Tanya Causgrove(4)	200,000	$11.00	August 15, 2027	N/A
Jim Davidson	200,000	$10.00	December 17, 2026	N/A
John Gordon	200,000	$10.00	December 17, 2026	N/A
Darlene Harris	200,000	$11.00	June 15, 2027	N/A
Steve Larke	200,000	$10.00	December 17, 2026	N/A
Brian G. Robinson	200,000	$10.00	December 17, 2026	N/A
Rafi Tahmazian	200,000	$10.00	December 17, 2026	N/A

(1) The market value of the Common Shares underlying these Options on the date of this prospectus is not reasonably ascertainable, given that the Common Shares are not and have never been publicly listed or traded.

(2) None of the Options under the Option Plan will be vested on the date of Closing.

(3) Upon Closing, the Option Plan will be amended to restrict a director from receiving more than $100,000 of option value during a calendar year pursuant to any future option grants.

(4) Option awards received by Ms. Causgrove are held for the benefit of ARC Financial or its affiliates pursuant to a written agreement between Ms. Causgrove and ARC Financial.

Option Plan

The following is a summary of the material terms of the Option Plan.

Purpose and Administration of the Option Plan

The purpose of the Option Plan is to develop the interest of existing or proposed officers, directors, employees and Service Providers (as defined below) of the Company and its subsidiaries and other persons who provide or are proposed to provide ongoing management or consulting services to the Company or its subsidiaries in the growth and development of the Company by providing them with the opportunity through Options to acquire an increased proprietary interest in the Company. For the purposes of the Option Plan, "Service Provider" means a person or company engaged, or proposed to be engaged, by the Company to provide services for an initial, renewable or extended period of 12 months or more.

The Option Plan is administered by the Board, or if appointed, by a committee of directors appointed from time to time by the Board (such committee, or if no such committee is appointed, the Board is hereinafter referred to as the "Committee") pursuant to rules of procedure fixed by the Board.

Granting of Options

The Committee has the authority to designate existing or proposed directors, officers, employees and Service Providers of the Company or its subsidiaries (collectively, the "Optionees") to whom Options to purchase Common Shares may be granted and the number of Common Shares to be optioned to each and may grant such Options, subject to the provisions of the Option Plan as summarized below.

The Option Plan provides that:

(a) the number of Common Shares reserved for issuance on exercise of all Options outstanding under the Option Plan at any time shall not exceed 8.5% of the Outstanding Common Shares (as defined in the Option Plan) at the time in question (the "Common Share Maximum") subject to adjustment as set forth in the Option Plan;

(b) the number of Common Shares reserved for issuance under the Option Plan to any one Optionee shall not exceed 5% of the Outstanding Common Shares;
(c) the number of Common Shares issuable to Insiders (as defined in the Option Plan), at any time, under all Share Compensation Arrangements (as defined in the Option Plan), shall not exceed 10% of the Outstanding Common Shares;
(d) the number of Common Shares issued to Insiders, within any one-year period, under all Share Compensation Arrangements, shall not exceed 10% of the Outstanding Common Shares; and
(e) from and after the completion of the Offering, the value of Options granted to any one director of the Company who is not an officer or employee of the Company or its subsidiaries during a calendar year, as calculated on the date of grant, shall not exceed $100,000.

Any increase in the Outstanding Common Shares (whether as a result of the exercise of Options or otherwise) will result in an increase in the number of Common Shares that may be issued on exercise of Options outstanding at any time and any decrease in the number of Options outstanding, due to the exercise of Options, will make new grants available under the Option Plan.

The Common Shares that are reserved for issuance on exercise of Options granted pursuant to the Option Plan that are cancelled, terminated or expire prior to the exercise of all or a portion thereof are available for a subsequent grant of Options pursuant to the Option Plan to the extent that any Common Shares issuable thereunder are not issued under such cancelled, terminated or expired Options.

Vesting

Vesting of Options shall be as to one third of the number of Options granted on the first anniversary of the date of grant and as to one third of the number of Options granted on the anniversary of the date of grant on each of the next two (2) succeeding years thereafter. Notwithstanding the foregoing, vesting of Options shall accelerate and Options shall be exercisable immediately prior to the time that a Change of Control (as defined in the Option Plan) takes place and as otherwise provided in the Option Plan. Further, the Committee may accelerate, or provide for the acceleration of, vesting of Options previously granted where exceptional circumstances exist as determined by the Committee and confirmed by the Board.

Exercise Price

The exercise price (the "Exercise Price") of any Option will be fixed by the Committee when such Option is granted, provided that from and after the date that the Common Shares are listed on a stock exchange (the "Exchange"), such price shall not be less than the Current Market Price. For this purpose, "Current Market Price" means the volume weighted average trading price of the Common Shares on the Exchange (or if the Common Shares are listed on more than one stock exchange, on such stock exchange as may be designated by the Committee for such purpose) for the five (5) trading days immediately preceding the date of the grant of Options and, for this purpose, the weighted average trading price shall be calculated by dividing the total value by the total volume of Common Shares traded for such period; or, if the Common Shares are not listed on any Exchange, a price determined by the Committee.

Option Terms

The period during which an Option is exercisable (the "Exercise Period") shall, subject to the provisions of the Option Plan requiring acceleration of rights of exercise, be such period as may be determined by the Committee at the time of grant provided that no Option may be exercised beyond seven years from the date of grant. Each Option shall, among other things, contain provisions to the effect that the Option shall be personal to the Optionee and shall not be assignable. In addition, each Option provides that:

(a) Termination for Cause – if the Optionee shall no longer be an officer of or be in the employ of, or consultant or other Service Provider to, either the Company or a subsidiary of the Company, as a result of termination for cause, effective at the date on which notice is given to the Optionee of such termination, all Options held by the Optionee, whether vested at such date or unvested, shall terminate and become null and void;

(b) Termination not for Cause if the Optionee shall no longer be an officer of or be in the employ of, or consultant or other Service Provider to, either the Company or a subsidiary of the Company, as a result of termination other than termination for cause, effective at the earlier of the date which is thirty (30) days following the date on which notice is given in respect of such termination and the end of the Exercise Period, all Options held by the Optionee which have not vested at such date shall terminate and become null and void, unless determined otherwise by the Committee in its sole discretion. With respect to the portion of the outstanding Options which are held by such Optionee and which have vested at the expiration of such period, unless determined otherwise by the Committee in its sole discretion, the Optionee shall have until the earlier of:
- (i) three (3) months from the date on which notice is given in respect of such termination; or
- (ii) the end of the Exercise Period; to exercise any Options which have vested as aforesaid and any vested Options which have not been so exercised shall terminate and become null and void;
(c) Voluntary Resignation – if the Optionee voluntarily ceases to be an officer of or be in the employ of, or consultant or other Service Provider to, either the Company or a subsidiary of the Company other than as a result of such Optionee's disability, retirement or death, effective at the earlier of the last day of any notice period applicable in respect of such voluntary resignation and the date on which the Optionee ceases to be a Service Provider, all Options held by the Optionee, whether vested at such date or unvested, shall terminate and become null and void;
(d) Disability if an Optionee ceases to be an officer of or be in the employ of, or a consultant or other Service Provider to either the Company or a subsidiary of the Company as a result of such Optionee's disability as defined in the Option Plan, all Options granted to such Optionee shall not change as a result of such Optionee's disability;
(e) Retirement – if an Optionee ceases to be an officer of or be in the employ of, or a consultant or other Service Provider to either the Company or a subsidiary of the Company as a result of such Optionee's Retirement (as defined in the Option Plan), if on the date of such Optionee's retirement, the Optionee has provided services to the Company or a subsidiary of the Company for a period of five (5) years or such other period as may be determined by the Committee, the Optionee shall only have until the earlier of:
- (i) thirty-six (36) months from the date of such Optionee's retirement or such other date as may be determined by the Committee; or
- (ii) the end of the Exercise Period; to exercise any Options which have vested at the date of exercise, and at the expiration of such period any Options which have not been exercised shall terminate and become null and void.

Furthermore, the Committee shall have the discretion, if it feels that it is appropriate, to alter the consequences of the retirement of an Optionee on such Optionee's outstanding Options; and

(f) Death – if the Optionee shall no longer be an officer of or be in the employ of, or consultant or other Service Provider to, either the Company or a subsidiary of the Company, as a result of the death of the Optionee, all Options which have not vested at such date shall immediately vest and the executor, administrator or personal representative of such Optionee shall have until the earlier of:
- (i) twelve (12) months from the date of death of such Optionee; or
- (ii) the end of the Exercise Period; to exercise any outstanding Options, and at the expiration of such period, any Options which have not been exercised shall terminate and become null and void.

For the purposes of the Option Plan and any Options granted pursuant to the Option Plan, the Optionee shall be deemed to have ceased to be an employee or Service Provider of the Company or any subsidiary of the Company, as applicable, and the Optionee shall be deemed to have terminated or resigned from employment or other service arrangement with the Company for the purposes hereof or for the purposes of any Option issued pursuant to the terms hereof on the first to occur of such termination or resignation or the date (as determined by the Committee) that the Optionee ceases in the active performance of all of the regular duties of the Optionee's job, which includes the carrying on of all of the usual and customary day-to-day duties of the job for the normal and scheduled number of hours in each working day, or the Optionee ceases to provide services pursuant to the services arrangement, as applicable; the foregoing to apply whether or not adequate or proper notice of termination shall have been provided by and to the Company in respect of such termination of employment or other service arrangement.

The Option Plan does not confer upon an Optionee any right with respect to continuation of employment by the Company or any subsidiary thereof, nor does it interfere in any way with the right of the Optionee, the Company or a subsidiary thereof to terminate the Optionee's employment or service provision at any time.

If the normal expiry date of any Options falls within any Blackout Period (as defined in the Option Plan) or within ten (10) business days following the end of any Blackout Period ("Blackout Options"), then the Expiry Date (as defined in the Option Plan) of such Blackout Options shall, without any further action, be extended to the date that is ten (10) business days following the end of such Blackout Period. The foregoing extension applies to all Options whatever the date of grant and shall not be considered an extension of the term of the Options.

Cashless Exercise

Subject to the provisions of the Option Plan, if permitted by the Board, an Optionee may elect to exercise an Option by surrendering such Option in exchange for the issuance of Common Shares equal to the number determined by multiplying the number of Common Shares which the Optionee is entitled to purchase pursuant to the Options being surrendered by a fraction of which the numerator is the difference between the Current Market Price (calculated as at the date of exercise) and the Exercise Price of such Option and of which the denominator is the Current Market Price (calculated as at the date of exercise). An Option may be exercised pursuant to such provisions from time to time by delivery to the Company at its head office in Calgary, Alberta or such other place as may be specified by the Company, of a written notice of exercise specifying that the Optionee has elected a cashless exercise of such Option and the number of Options to be so exercised. The Company will not be required, upon the cashless exercise of any Options pursuant to such provisions, to issue fractions of Common Shares. There will be paid to the Optionee by the Company upon the cashless exercise of such Options within ten (10) business days after the exercise date, an amount in lawful money of Canada to the then fair market value of such fractional interest (as determined by the Board), provided that the Company will not be required to make any payment, calculated as aforesaid, that is less than $10.00. Upon exercise of the foregoing, the number of Common Shares actually issued shall be deducted from the number of Common Shares reserved with the Exchange for future issuance under the Option Plan and the balance of the Common Shares that were issuable pursuant to the Options so surrendered shall be considered to have been cancelled and available for further issuance.

Mergers, Amalgamation and Sale

If the Company becomes merged (whether by plan of arrangement or otherwise) or amalgamated in or with another corporation or entity or sells the whole or substantially the whole of its assets and undertakings for shares or securities of another corporation or other entity, the Company will, subject to the Option Plan, make provision that, upon exercise of an Option during its unexpired period after the effective date of such merger, amalgamation or sale, the Optionee will receive such number of shares of the continuing successor company or other entity in such merger or amalgamation or the securities or shares of the purchasing corporation or other entity as the Optionee would have received as a result of such merger, amalgamation or sale if the Optionee had purchased the shares of the Company immediately prior thereto for the same consideration paid on the exercise of the Option and had held such shares on the effective date of such merger, amalgamation or sale and, upon such provision being made, the obligation of the Company to the Optionee in respect of the Common Shares subject to the Option will terminate and be at an end and the Optionee will cease to have any further rights in respect thereof. Alternatively, and in lieu of making such provision, in the event of such merger, amalgamation or sale, the Company may satisfy any obligations to an Optionee by paying to the Optionee, in cash, the difference between the Exercise Price of all unexercised Options held by the Optionee and the fair market value of the securities to which the Optionee would be entitled upon exercise of all unexercised Options. Adjustments under the Option Plan or any determinations as to fair market value of any securities will be made by the Committee, and any reasonable determination made by the Committee will be binding and conclusive.

Acceleration of Vesting and Termination of Option in the Event of Take-Over Bid

In the event of a Take-Over Bid (as defined in the Option Plan), Optionees have the right to exercise Options granted pursuant to the Option Plan to purchase all of the Common Shares which have not been previously purchased under such Options, but any such Common Shares not otherwise vested and exercisable may only be purchased for tender pursuant to such Take-Over Bid. If for any reason such Common Shares are not so tendered or, if tendered, are not for any reason taken up and paid for by the offeree pursuant to such Take-Over Bid, any such Common Shares so purchased by an Optionee will be and be deemed to be cancelled and returned to treasury of the Company, will be added back to the number of Common Shares, if any, remaining unexercised under the applicable Option and, upon presentation to the Company of share certificates representing such shares properly endorsed for transfer back to the Company, the Company will refund to the Optionee all consideration paid on the exercise thereof. In the event a Take-Over Bid is made and Common Shares are taken up and paid for pursuant to such Take-Over Bid, the Company will have the right to satisfy any obligations to an Optionee in respect of any Options not exercised by paying to the Optionee, in cash, the difference between the Exercise Price of unexercised Options and the fair market value of the securities to which the Optionee would have been entitled upon exercise of the unexercised Options on such date, which determination of fair market value will be conclusively made by the Committee. Upon payment as aforesaid, the Options will terminate and be at an end and the Optionee will cease to have any further rights in respect thereof.

Alterations in Shares

In the event, at any time or from time to time, that the share capital of the Company shall be consolidated or subdivided prior to the exercise by the Optionee, in full, of any Option in respect of all of the Common Shares granted or the Company shall pay a dividend (other than in the ordinary course) upon the Common Shares by way of issuance to the holders thereof of additional Common Shares, securities or other assets, or other relevant changes in the share capital of the Company shall occur, Options with respect to any Common Shares which have not been purchased at the time of any such consolidation, subdivision, stock dividend or other change shall be proportionately adjusted (including as to the number of Common Shares subject to the Option and the Exercise Price thereof, as applicable) so that the Optionee will from time to time, upon the exercise of an Option, be entitled to receive the number of shares, securities or other property of the Company he or she would have held following such consolidation, subdivision, stock dividend or other change if the Optionee had purchased the shares and had held such shares immediately prior to such consolidation, subdivision, stock dividend or other change. Upon any such adjustments being made, the Optionee will be bound by such adjustments and shall accept the terms of such Options in lieu of the Options previously outstanding.

For greater certainty, and anything above to the contrary notwithstanding, no adjustment will be made in accordance with the Option Plan with respect to the issue of Common Shares being made pursuant to or in connection with:

(a) any stock option plan or stock purchase plan, including the Option Plan, in force from time to time for existing or proposed officers, directors, employees or Service Providers of the Company; or
(b) the issuance of additional Common Shares pursuant to a public offering or private placement by the Company or a take-over bid made by the Company for the securities of another entity.

Option Agreements

A written agreement will be entered into between the Company and each Optionee to whom an Option is granted pursuant to the Option Plan, which agreement will set out the number of Common Shares subject to Option, the Exercise Price, provisions as to vesting and expiry and any other terms approved by the Committee, all in accordance with the provisions of the Option Plan. The agreement will be in such form as the Committee may from time to time approve or authorize the officers of the Company to enter into and may contain such terms as may be considered necessary in order that the Option will comply with the Option Plan, any provisions respecting Options in the income tax or other laws in force in any country or jurisdiction of which the person to whom the Option is granted may from time to time be a resident or citizen and the rules of any regulatory body having jurisdiction over the Company.

Regulatory Authorities Approvals

The Option Plan and the Company's obligation to issue and deliver Common Shares under any Option is subject to the approval, if required, of any Exchange on which the Common Shares are listed for trading. Any Options granted prior to such approval, if required, is conditional upon such approval being given and no such Options may be exercised unless such approval, if required, is given.

Amendment or Discontinuance of the Option Plan

The Committee may amend or discontinue the Option Plan and Options granted thereunder at any time without shareholder approval; provided any amendment to the Option Plan that requires approval of any Exchange on which the Common Shares are listed for trading may not be made without approval of such Exchange. Without the prior approval of the shareholders, or such approval as may be required by the Exchange, the Committee may not:

(a) make any amendment to the Option Plan to increase the Common Share Maximum;
(b) reduce the Exercise Price of any outstanding Options;
(c) cancel an Option and subsequently issue the holder of such Option a new Option or other entitlements in replacement thereof;
(d) extend the term of any outstanding Option beyond the original expiry date of such Option;
(e) make an amendment to increase the maximum limit on the number of securities that may be issued to insiders;
(f) make any amendment to the Option Plan that would permit an Optionee to transfer or assign Options to a new beneficial Optionee other than in the case of death of the Optionee; or
(g) make an amendment to amend the amendment provisions of the Option Plan.

The Committee may amend or terminate the Option Plan or any outstanding Option granted thereunder at any time without the approval of the Company, the shareholders of the Company or any Optionee whose Option is amended or terminated, in order to conform the Option Plan or such Option, as the case may be, to applicable law or regulation or the requirements of any relevant Exchange or regulatory authority, whether or not that amendment or termination would affect any accrued rights, subject to the approval of that Exchange or regulatory authority.

In addition, no amendment to the Option Plan or Options granted pursuant to the Option Plan may be made without the consent of the Optionee, if it adversely alters or impairs any Option previously granted to such Optionee under the Option Plan.

PLAN OF DISTRIBUTION

The Offering consists of • Common Shares. See "Description of Share Capital" for a description of the attributes of the Common Shares.

Under an agreement dated •, 2020 between the Company, the Selling Shareholder and the Underwriters (the "Underwriting Agreement"), the Company and the Selling Shareholder have agreed to sell and the Underwriters have severally agreed to purchase, on •, 2020 or on such other date as may be agreed upon among the parties thereto, but in any event no later than • , 2020, an aggregate of • Common Shares, each at a price of $• per Common Share, payable in cash to the Company or the Selling Shareholder, as applicable, against delivery of the Common Shares, for aggregate gross proceeds of $• million to the Company and $35 million to the Selling Shareholder. In consideration for their services in connection with the Offering, the Company and the Selling Shareholder have agreed to pay the Underwriters a fee equal to $• per Common Share sold pursuant to the Offering, including any Common Shares sold pursuant to the Over-Allotment Option. It is estimated that the total expenses of the Offering, not including the Underwriters' Commissions, will be approximately $3 million. The Underwriter's Commissions are payable on Closing. All such expenses of the Offering will be paid by the Company. The Underwriters may form a selling group including other qualified investment dealers and determine the fee payable to the members of such group, which fee will be paid by the Underwriters out of the Underwriters' Commissions.

The Offering Price was determined by negotiation between the Selling Shareholder and the Company, on the one hand, and the Underwriters, on the other hand.

The Underwriters propose to offer the Common Shares initially at the Offering Price. After the Underwriters have made a reasonable effort to sell all of the Common Shares at the Offering Price, the Offering Price may be decreased and may be further changed from time to time to an amount not greater than that set out on the cover page. In the event that the Offering Price is reduced, the compensation received by the Underwriters will be decreased by the amount that the aggregate price paid by purchasers for the Common Shares is less than the gross proceeds paid by the Underwriters to the Company and the Selling Shareholder for such Common Shares. Any such reduction in price will not affect the proceeds received by the Company and the Selling Shareholder.

The obligations of the Underwriters under the Underwriting Agreement are several and not joint, and may be terminated at their discretion on the basis of their assessment of the state of the financial markets and may also be terminated upon the occurrence of certain stated events. If an Underwriter fails to purchase the Common Shares which it has agreed to purchase, the remaining Underwriter(s) may terminate their obligation to purchase their allotment of Common Shares, or may, but are not obligated to, purchase the Common Shares not purchased by the Underwriter or Underwriters which fail to purchase. The Underwriters are, however, obligated to take up and pay for all of the Common Shares if any of the Common Shares are purchased under the Underwriting Agreement. The Underwriting Agreement also provides that the Company and the Selling Shareholder will jointly and severally indemnify the Underwriters, their respective affiliates and each of their respective directors, officers, employees, partners, agents and each other person, if any, controlling an Underwriter or any of its subsidiaries and each shareholder of the Underwriter against certain liabilities, claims, actions, complaints, losses, costs, fines, penalties, taxes, interest, damages and expenses.

The Offering is being made in each of the provinces of Canada. The Common Shares offered under this prospectus will be offered in each of the provinces of Canada through those Underwriters or their affiliates who are registered to offer such Common Shares for sale in such provinces and such other registered dealers as may be designated by the Underwriters. Subject to applicable law and the provisions of the Underwriting Agreement, the Underwriters may offer such Common Shares outside of Canada.

The Company has applied to have the Common Shares listed on the TSX under the symbol "TPZ". Listing is subject to the approval of the TSX in accordance with its original listing requirements. The TSX has not conditionally approved the Company's listing application and there is no assurance that the TSX will approve the listing application. Closing is conditional upon the Common Shares being approved for listing on the TSX.

The Common Shares offered under this prospectus have not been, and will not be, registered under the U.S. Securities Act, or any state securities laws, and may not be offered or sold within the United States absent registration or pursuant to an applicable exemption from the registration requirements of the U.S. Securities Act and applicable state securities laws. Accordingly, except to the extent permitted by the Underwriting Agreement and except for offers and sales made pursuant to an available exemption from the registration requirements of the U.S. Securities Act, the Common Shares to be sold pursuant to the Offering may not be offered or sold within the United States. Each Underwriter has agreed that it will not offer or sell Common Shares within the United States, except in transactions exempt from the registration requirements of the U.S. Securities Act and applicable state securities laws. The Underwriting Agreement provides that the Underwriters may re-offer and re-sell the Common Shares that they have acquired pursuant to the Underwriting Agreement in the United States to qualified institutional buyers ("Qualified Institutional Buyers") in accordance with Rule 144A under the U.S. Securities Act. The Underwriting Agreement also provides that the Underwriters will offer and sell the Common Shares outside the United States in accordance with Regulation S under the U.S. Securities Act. In addition, until 40 days after the Closing, an offer or sale of the Common Shares within the United States by any dealer (whether or not participating in the Offering) may violate the registration requirements of the U.S. Securities Act, unless such offer is made pursuant to an exemption from registration under the U.S. Securities Act.

Prior to the Offering, there has been no public market for the Common Shares. The sale of a substantial amount of the Common Shares in the public market after the Offering, or the perception that such sales may occur, could adversely affect the prevailing market price of the Common Shares. See "Risk Factors – Risks Relating to the Offering of Common Shares – Absence of Public Market for the Common Shares". Furthermore, because the Company has agreed that it will not offer or sell any equity securities of the Company (or other securities convertible into, or exchangeable or exercisable for, equity securities of the Company) for a period after Closing due to the restrictions on resale described under "—Standstill" below, the sale of a substantial amount of Common Shares in the public market after these restrictions lapse could adversely affect the prevailing market price of the Common Shares.

Subscriptions for Common Shares offered under this prospectus will be received subject to rejection or allotment in whole or in part and the Underwriters reserve the right to close the subscription books at any time without notice. It is expected that Closing will occur on or about •, 2020 or such later date as the Selling Shareholder, the Company and the Lead Underwriters may agree, but in any event not later than •. The Common Shares offered under this prospectus are to be taken up by the Underwriters, if at all, on or before a date not later than 42 days after the date of the receipt for the final prospectus. Common Shares sold pursuant to the Offering will be registered in the name of CDS and electronically deposited with CDS on the date of Closing. Purchasers of Common Shares will receive only a customer confirmation from the Underwriter or other registered dealer who is a CDS participant and from or through whom a beneficial interest in the Common Shares is acquired.

Pursuant to the ARC Participation Rights Agreement, if the Corporation issues Common Shares (or certain securities convertible into, or exchangeable or exercisable for, Common Shares), ARC Energy Fund 9 has the right to acquire up to that number of securities of the same type and class as the securities being offered under the financing (which includes the Common Shares issuable pursuant to the Offering) that corresponds to its percentage ownership of (or over which it exercises control or direction of) the issued and outstanding Common Shares as at such time (calculated on a non-diluted basis), at the same price and on the same terms as the securities are purchased by the other subscribers in such financing. ARC Energy Fund 9 currently holds approximately 5% of the issued and outstanding Common Shares. The ARC Participation Rights Agreement terminates on Closing.

Over-Allotment Option

The Company has granted to the Underwriters the Over-Allotment Option, exercisable at the Underwriters' sole discretion at any time, in whole or in part, from time to time, until 30 days after Closing, to purchase, at the Offering Price, up to an additional • Common Shares (representing 15% of the Common Shares offered under the Treasury Offering) to cover overallotments, if any, and for market stabilization purposes. If the Over-Allotment Option is exercised in full, the net proceeds to the Company from the Offering will be approximately $• after deducting the Underwriters' Commissions payable to the Underwriters of $• and the expenses of the Offering estimated to be approximately $3 million. As the incremental expenses of the Secondary Offering are not anticipated to be material, the Company has agreed to pay the expenses associated with the Offering and, as a result, the Selling Shareholder will not pay any expenses of the Offering other than the Underwriters' Commissions in respect of the Secondary Offering. This prospectus also qualifies the distribution of the Common Shares issuable pursuant to the exercise of the Over-Allotment Option. A purchaser who acquires Common Shares forming part of the Underwriters' over-allocation position acquires those Common Shares under this prospectus, regardless of whether the over-allocation position is ultimately filled through the exercise of the Over-Allotment Option or secondary market purchases.

Price Stabilization, Short Positions and Passive Market Making

In connection with the Offering, the Underwriters may over-allocate or effect transactions which stabilize or otherwise affect the market price of the Common Shares at levels other than those which otherwise might prevail on the open market, including: stabilizing transactions; short sales; purchases to cover positions created by short sales; imposition of penalty bids; and syndicate covering transactions.

Stabilizing transactions consist of bids or purchases made for the purpose of preventing or retarding a decline in the market price of the Common Shares while the Offering is in progress. These transactions may also include making short sales of the Common Shares, which involve the sale by the Underwriters of a greater number of Common Shares than they are required to purchase in the Offering. Short sales may be "covered short sales", which are short positions in an amount not greater than the Over-Allotment Option, or may be "naked short sales", which are short positions in excess of that amount.

The Underwriters may close out any covered short position either by exercising the Over-Allotment Option, in whole or in part, or by purchasing Common Shares in the open market or as otherwise permitted by applicable law. In making this determination, the Underwriters will consider, among other things, the price of Common Shares available for purchase in the open market compared with the price at which they may purchase Common Shares through the Over-Allotment Option. The Underwriters must close out any naked short position by purchasing Common Shares in the open market or as otherwise permitted by applicable law. A naked short position is more likely to be created if the Underwriters are concerned that there may be downward pressure on the price of the Common Shares in the open market that could adversely affect investors who purchase in the Offering.

In addition, in accordance with rules and policy statements of certain Canadian securities regulators, the Underwriters may not, at any time during the period of distribution, bid for or purchase Common Shares. The foregoing restriction is, however, subject to exceptions where the bid or purchase is not made for the purpose of creating actual or apparent active trading in, or raising the price of, the Common Shares. These exceptions include a bid or purchase permitted under the by-laws and rules of applicable regulatory authorities and the TSX, including the Universal Market Integrity Rules for Canadian Marketplaces, relating to market stabilization and passive market making activities and a bid or purchase made for and on behalf of a customer where the order was not solicited during the period of distribution.

As a result of these activities, the price of the Common Shares may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued by the Underwriters at any time. The Underwriters may carry out these transactions on any stock exchange on which the Common Shares are listed, in the over-the-counter market, or as otherwise permitted by applicable law.

Standstill

The Company has agreed that, subject to certain exceptions, it will not, directly or indirectly, without the prior written consent of the Underwriters, which consent shall not be unreasonably withheld, issue, or offer, grant any option, warrant or other right to purchase or agree to issue or sell, or otherwise lend, transfer, assign, pledge or dispose of, in a public offering or by way of private placement or otherwise, any equity securities of the Company or other securities convertible into, exchangeable for, or exercisable into Common Shares or other equity securities of the Company, or agree to do any of the foregoing or publicly announce any intention to do any of the foregoing (other than the Common Shares offered under the Offering, including upon the exercise of the Over-Allotment Option, and the Common Shares issuable pursuant to the Option Plan), for a period of 180 days from the date of Closing.

RELATIONSHIPS AMONG THE COMPANY, THE SELLING SHAREHOLDER AND CERTAIN UNDERWRITERS

Scotia Capital is, directly or indirectly, an affiliate of a bank which is a lender to the Company pursuant to the Credit Facility and each of Scotia Capital, BMO Nesbitt Burns Inc., CIBC World Markets Inc., National Bank Financial Inc., TD Securities Inc. and ATB Capital Markets Inc. is, directly or indirectly, an affiliate of a lender (collectively, the "Lenders") to the Selling Shareholder pursuant to unsecured revolving credit facilities and term loans (the "Tourmaline Credit Facilities"). In addition, Jim Davidson, a director of the Company, is a director of an affiliate of ATB Capital Markets Inc. Consequently, under applicable Canadian Securities Laws, the Company and the Selling Shareholder may be considered a "connected issuer" to such Underwriters.

As at August 31, 2020, no amounts were drawn on the Credit Facility. The Company is in compliance with all material terms of the agreements governing the Credit Facility and has not been in default or otherwise in breach of such agreements since its relevant execution date. See "Credit Facility" and "Capitalization".

As at August 31, 2020, $1.78 billion was drawn on the Tourmaline Credit Facilities. The Selling Shareholder is in compliance with all material terms of the agreements governing the Tourmaline Credit Facilities and has not been in default or otherwise in breach of such agreements since its relevant execution date. The Selling Shareholder's financial position has not changed adversely since the indebtedness under the Tourmaline Credit Facilities was incurred.

The decision to sell the Common Shares pursuant to the Offering was made by the Company and the Selling Shareholder and the determination of the terms of the Offering, including the Offering Price of such Common Shares, has been determined by negotiation between the Company and the Selling Shareholder, on the one hand, and the Underwriters, on the other hand. The Lenders did not have any involvement in such decision or determination; however, the Lenders have been advised of the Offering and the terms thereof. As a consequence of the Offering, each of the Underwriters will receive their respective share of the Underwriters' fee payable by the Company and the Selling Shareholder to the Underwriters. In addition, each of the Lenders may receive a portion of the Selling Shareholder's proceeds from the Offering as a repayment of outstanding revolving indebtedness under the Tourmaline Credit Facilities.

PRINCIPAL SHAREHOLDERS AND SELLING SHAREHOLDER

The Selling Shareholder has agreed to sell • Common Shares to the Underwriters, as described under the heading "Plan of Distribution". The Selling Shareholder has advised the Company that it may sell all or a substantial portion of its Common Shares, subject to market conditions, to meet the Selling Shareholder's requirements for capital or for other reasons. The Selling Shareholder has indicated to the Company that, other than pursuant to the Offering, it has no specific plans or timing to sell such Common Shares. See "Agreements with Tourmaline and Other Counterparties – Investor Liquidity Agreement" and "Risk Factors – Risks Relating to the Company's Relationship with Tourmaline".

The table below sets forth the number and percentage of outstanding Common Shares owned by the Selling Shareholder as of the date of this prospectus, the type of ownership of those Common Shares, the number of Common Shares anticipated to be sold by the Selling Shareholder pursuant to the Offering and the number and percentage of Common Shares anticipated to be owned by the Selling Shareholder after giving effect to the Offering (both with and without giving effect to the exercise of the Over-Allotment Option).

					Number and
					percentage of
		Number and	Common	Number and	Common Shares
		percentage of	Shares to be	percentage of	owned, controlled or
		Common Shares	sold by the	Common Shares	directed after giving
		owned, controlled	Selling	owned, controlled	effect to the Offering
		or directed prior	Shareholder	or directed after	and exercise in full of
	Type of	to giving effect to	pursuant to the	giving effect to	the Over-Allotment
Shareholder Name	Ownership(1)	the Offering(2)	Offering	the Offering(3)	Option(3)
Tourmaline	Common Shares	59,149,494	•	• (•%)	• (•%)
		(63.5%)

Notes:

(1) Such Common Shares are owned both of record and beneficially by Tourmaline.
(2) See "Prior Sales". The Selling Shareholder holds •% of the Common Shares on a fully-diluted basis.
(3) On a fully-diluted basis, •% of the Common Shares will be held by the Selling Shareholder after giving effect to the Offering and •% of the Common Shares will be held by the Selling Shareholder after giving effect to the Offering and exercise in full of the Over-Allotment Option.
(4) None of the Common Shares are held, or are to be held following Closing, subject to any voting trust or other similar agreement.

The table below sets forth the number and percentage of outstanding Common Shares owned by persons, other than the Selling Shareholder, who, as at the date of this prospectus, to the knowledge of the Company, own beneficially or control or direct, directly or indirectly, more than 10% of the outstanding Common Shares, and the number and percentage of Common Shares anticipated to be owned, control or directed, directly or indirectly, by such persons after giving effect to the Offering (both with and without giving effect to the exercise of the Over-Allotment Option).

				Number and
				percentage of
		Number and	Number and	Common Shares
		percentage of	percentage of	owned, controlled or
		Common Shares	Common Shares	directed after giving
		owned, controlled	owned, controlled	effect to the Offering
		or directed prior	or directed after	and exercise in full of
	Type of	to giving effect to	giving effect to the	the Over-Allotment
Shareholder Name	Ownership(1)	the Offering	Offering(2)	Option(2)
Cambridge Global Asset	Common Shares	11,017,206	• (•%)	• (•%)
Management, a division of		(11.82%)

CI Investments

Notes:

(1) To the knowledge of the Company, such Common Shares owned of record by various investment funds which are affiliates of Cambridge Global Asset Management, a division of CI Investments.
(2) On a fully-diluted basis, •% of the Common Shares will be held by Cambridge Global Asset Management, a division of CI Investments, after giving effect to the Offering and •% of the Common Shares will be held by Cambridge Global Asset Management, a division of CI Investments, after giving effect to the Offering and exercise in full of the Over-Allotment Option.
(3) To the knowledge of the Company, none of the Common Shares are held, or are to be held following Closing, subject to any voting trust or other similar agreement.

To the knowledge of the Company, other than as set forth above: (i) as of the date of this prospectus, there is no other person or company who beneficially owns, or controls or directs, directly or indirectly, 10% or more of the Common Shares; and (ii) following completion of the Offering, there will not be any other person or company who beneficially owns, or controls or directs, directly or indirectly, 10% or more of the Common Shares then outstanding.

PRIOR SALES

Summary of Equity Issuances to Tourmaline

During the 12-month period prior to the date of this prospectus, the Company issued the following Common Shares to Tourmaline.

On October 31, 2019, the Company issued 383,921 Common Shares (on a 74.48896:1 post-consolidation basis) to Tourmaline for $85.8 million.

On November 14, 2019, pursuant to the Initial Acquisition, the Company issued 58,049,494 Common Shares to Tourmaline at an agreed price of $10.00 per Common Share with an aggregate ascribed value for accounting purposes of $442.5 million.

Summary of Equity Financings

The following table summarizes the equity financings completed by the Company during the 12-month period prior to the date of this prospectus as well as Company insider, employee and associate participation in such equity financings.

Summary of Equity Financings

Date	Insider, Employee andAssociate Participation(3)Financings
	Shares Issued	Total GrossProceeds	GrossSubscriptions	Percentage ofGross Proceeds
November 14, 2019	20,850,506(1)	$208,505,060	$39,433,000	19%
June 29 and July 6, 2020	13,208,296(2)34,058,802	$145,291,256$353,796,316	$64,576,006$104,009,006	44%29%

(2) Private placement of 13,208,296 Common Shares at a price of $11.00 per Common Share pursuant to the 2020 Equity Financing.
(3) Represents percentage of the Company and Tourmaline's insider, employee and associate participation, including shares owned by shareholders represented by directors of the Company, for the total amount raised by the Company, which has been calculated based on the percentage of Common Shares issued to directors, officers, employees and other service providers, including shares owned by shareholders represented by directors of the Company, of the Company and Tourmaline and certain family, friends and business associates of the foregoing relative to the total number of Common Shares issued in each financing.

Summary of Option Issuances

The following table summarizes the option issuances of the Company during the 12-month period prior to the date of this prospectus.

Options Granted During 2019 and 2020
Date of Issuance	Number of Options	Exercise Price of Options
December 17, 2019	1,200,000	$10.00
April 15, 2020	450,000	$10.00
June 15, 2020	200,000	$11.00
August 15, 2020	200,000	$11.00

PROMOTER

Tourmaline may be considered a promoter of the Company within the meaning of Canadian Securities Laws. To the knowledge of the Company, as of the date of this prospectus, Tourmaline beneficially owns, controls or directs, directly or indirectly, 59,149,494 Common Shares, representing 63.5% of the issued and outstanding Common Shares. Immediately, upon completion of the Offering, Tourmaline will hold •% of the issued and outstanding Common Shares (•% if the Over-Allotment Option is exercised in full). See "Principal Shareholders and Selling Shareholder".

Tourmaline and the Company entered into certain contracts in connection with the completion of the Initial Acquisition and the Banshee Gas Plant Acquisition. See "Agreements with Tourmaline and Other Counterparties".

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

Except as otherwise described in this prospectus, there is no material interest, direct or indirect, of: (i) any director or executive officer of the Company; (ii) any person or company that beneficially owns, or controls or directs, directly or indirectly, more than 10% of the Common Shares; or (iii) any affiliate of the persons or companies referred to above in (i) or (ii), in any transaction within the three years before the date of this prospectus that has materially affected or is reasonably expected to materially affect the Company.

THE INDUSTRY

Companies operating in the oil and natural gas industry are subject to extensive regulation and control of operations (including land tenure, exploration, development, production, refining and upgrading, transportation, and marketing) as a result of legislation enacted by various levels of government and with respect to the pricing and taxation of petroleum and natural gas through legislation enacted by and agreements among the governments of Canada, Alberta and British Columbia, all of which should be carefully considered by investors in the Canadian oil and natural gas industry. All current legislation is a matter of public record and the Company is unable to predict what additional legislation or amendments may be enacted. Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and natural gas industry in Western Canada, specifically in the Provinces of Alberta and British Columbia where the Company's assets are predominately located. 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 legislation, regulations and agreements carefully.

The unique nature of the GORR Lands is expected to allow the Company to benefit from the upside potential of such properties at a reduced risk relative to traditional E&P companies. This advantage is a result of collecting royalty payments in respect of the GORR Lands rather than directly conducting operations to explore for, develop or produce petroleum or natural gas, which has a higher regulatory burden. However, legislation and regulations, including those outlined below, may impact the royalties received by the Company as an indirect participant in the development of petroleum and natural gas on its GORR Lands. In addition, if the strategy of the Company were to change in the future such that it becomes a direct participant in the development of its properties, whether as working interest owner, operator or otherwise, the aforementioned industry regulation would become the burden of the Company in respect of such development.

The Company also has non-operated interests in the Infrastructure Assets, comprised of processing facilities, and from which the Company receives fixed-fee revenues from the processing and handling services that the Infrastructure Assets provide to customers. Processing facilities purify hydrocarbons by removing contaminants from hydrocarbon streams, some of which— NGL, in particular—have independent value and are an important source of revenue for producers and marketers of petroleum products. The profitability of NGL extracted from natural gas is based on the products extracted being of greater economic value as separate commodities than as components of natural gas. NGL are heavier components of natural gas (such as ethane, propane, butanes and pentanes) that are separated from a hydrocarbon stream (typically in a vapor phase) in liquid form. This can occur in a field plant or processing facility through condensation or absorption, among other methods. Once separated, NGL can be stored and shipped in a liquid state and have many important uses, including use as an input for petrochemical plants, heating, and fuels. There are many different contractual arrangements that support the business of processing and the duration of processing contracts may vary from short-term to multiple years. In addition, the operator of a processing facility can provide processing services on cost-of-service, fee, or commodity specific bases, each of which would have a different impact on a facility's profit margins. The Infrastructure Assets, and any other similar assets in which Topaz may, in the future, obtain an interest are subject to legislation and regulation in the provinces in which they are situated, including certain of the legislation and regulations outlined below, and such legislation and regulations may impact the revenues ultimately received by the Company as a working interest owner in such facilities.

Pricing and Marketing in Canada

Crude Oil

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, but regional market and transportation issues also influence prices. The specific price that a producer receives will depend, 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.

In 2020, worldwide oversupply of crude oil, a lack of available storage capacity and decreased demand due to COVID-19 have had a significant impact on the pricing of crude oil. In an effort to stabilize global oil markets, the Organization of the Petroleum Exporting Countries ("OPEC") and a number of other oil producing countries announced an agreement to cut crude oil production by approximately 10 million Bbls/d in April 2020. See "Risks Relating to the Company's Business, Industry and Operating Environment – COVID-19" and "Risks Relating to the Company's Business, Industry and Operating Environment – Prices, Markets and Demand for Petroleum Products".

Natural Gas

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 of sale.

Natural Gas Liquids

The pricing of condensates and other NGL 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 NGL, price of competing chemical stock, distance to market, access to downstream transportation, length of contract term, supply/demand balance and other contractual terms of sale.

Exports from Canada

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 (the "CERA"), the Canadian Environmental Assessment Act, 2012 with the Impact Assessment Act (the "IAA") 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 NGL.

Exports of crude oil, natural gas and NGL 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") until such time as the Part VI Regulation is replaced. The CERA and the Part VI Regulation authorize crude oil, natural gas and NGL exports under: (i) short-term orders for up to one or two years depending on the substance, and up to 20 years for quantities of natural gas (other than NGL) not exceeding 30,000 m3 per day; or (ii) long-term export licences of up to 40 years for natural gas and up to 25 years for crude oil and other substances (e.g. NGL). With respect to applications for long-term export licenses, following a review of such applications by the CER, which may involve a public hearing, the CER can approve an application if it is satisfied, among other considerations, that the proposed export volumes are not greater than Canada's reasonably foreseeable needs. In addition to CER approval, long-term export licences also currently require various other ministerial and federal Cabinet approvals.

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.

Transportation Constraints and Market Access

One major constraint to the export of crude oil, natural gas and NGL is the deficit of transportation capacity to transport production from Western Canada to the United States and other international markets. Although certain pipeline and other transportation and export projects are underway, many proposed projects have been cancelled or delayed due to regulatory hurdles, court challenges and economic and other socio-political factors. Due in part 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.

Pipelines

Producers negotiate with pipeline operators to transport their products to market on a firm, spot or interruptible basis depending on the specific pipeline and the specific substance. 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 and the price received.

Under the Canadian Constitution, interprovincial and international pipelines fall within the federal government's jurisdiction and, under the CERA, new interprovincial and international pipelines will require a federal regulatory review and Cabinet approval before they can proceed. However, recent years have seen a perceived lack of policy and regulatory certainty such that, even when projects are approved, they often face delays due to actions taken by provincial and municipal governments and 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.

Specific Pipeline Updates

The Enbridge Line 3 Replacement from Hardisty, Alberta, to Superior, Wisconsin, previously expected to be in-service in late 2019, continues to experience permitting difficulties in the United States and completion of the United States portion of the pipeline replacement has been delayed following the announcement that the Minnesota Pollution Control Agency will require a public hearing concerning a key water permit. It is expected that most of the construction work on the United States portion of the pipeline replacement will happen in 2021; however, the Canadian portion of the replaced pipeline began commercial operation in December 2019.

The Trans Mountain Pipeline expansion received Cabinet approval in November 2016. Following a period of political opposition in British Columbia, the federal government completed a purchase of 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 approval and directed Cabinet to correct these deficiencies. Following a reconsideration by the NEB and enhanced consultation efforts led by the federal government, Cabinet reapproved the Trans Mountain Pipeline expansion. Subsequent challenges to the approval were rejected by the Federal Court of Appeal in February 2020 and the Supreme Court of Canada in July 2020.

In addition, on April 25, 2018, the Government of British Columbia submitted a reference question to the British Columbia Court of Appeal, asking 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 unanimously answered the reference question in the negative. On January 16, 2020, the Supreme Court of Canada unanimously dismissed the Attorney General of British Columbia's appeal.

Construction commenced on the Trans Mountain Pipeline expansion in late 2019 and it is expected to be in-service in late 2022.

While it was expected that construction on TC Energy Corporation's ("TC Energy") Keystone XL Pipeline would begin 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 kilometres of federal land. On March 31, 2020, TC Energy announced it would proceed with the Keystone XL Pipeline. TC Energy also announced that the Government of Alberta had made a US $1.1 billion equity investment in the project and would guarantee a US $4.2 billion project level credit facility.

While construction on the Keystone XL Pipeline started in April 2020, the Keystone XL Pipeline remains subject to legal and regulatory barriers in the United States. 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 certain permits and on April 15, 2020, a Montana judge ruled against the U.S. Army Corps of Engineers' use of a national permit for water crossings in the United States ("Nationwide Permit 12"). The United States Court of Appeals for the Ninth Circuit refused to stay the ruling. While the Supreme Court of the United States subsequently reinstated Nationwide Permit 12 in July 2020, it determined that the reinstatement would not apply to the Keystone XL Pipeline.

Marine Tankers

Bill C-48 received royal assent on June 21, 2019, enacting the Oil Tanker Moratorium Act, which imposes a ban on tanker traffic transporting crude oil or persistent crude oil products in excess of 12,500 metric tonnes along British Columbia's north coast. The ban may prevent pipelines from being built to, and export terminals from being located on, the portion of the British Columbia coast subject to the moratorium.

Crude Oil and Bitumen by Rail

On February 19, 2019, the Government of Alberta announced that it would lease 4,400 rail cars capable of transporting 120,000 Bbls/d of crude oil out of the province to help alleviate the transportation constraints impacting Canadian oil prices. In the spring of 2019, the Government of Alberta announced it would cancel the program and assign the transportation contracts to industry proponents. In February 2020, the Government of Alberta announced it had sold $10.6 billion worth of crude-by-rail contracts to the private sector.

Following two train derailments that led to fires and oil spills in Saskatchewan, the federal government announced in February 2020, that trains hauling more than 20 cars carrying dangerous goods, including crude oil and diluted bitumen, would be subject to reduced speed limits. The order was updated in early April and will remain in place until permanent rule changes are approved. As a result, trains subject to the order will be required to adhere to the reduced speed limits announced in February 2020 within metropolitan areas, with further mandatory speed reductions applying outside of metropolitan areas during winter months (November 15 to March 15).

Natural Gas and LNG

Natural gas prices in Alberta and British Columbia have 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 infrastructure 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.

Required repairs or upgrades to existing pipeline systems in Western Canada have also led to further reduced capacity and apportionment of access, which has been further exacerbated by storage limitations. However, in September 2019, the CER approved a policy change by TC Energy on its NOVA Gas Transmission Ltd. pipeline network (the "NGTL System") to prioritize deliveries into storage. The change has served to somewhat stabilize supply and pricing, particularly during periods of maintenance on the system. An expansion to the NGTL System was recommended for approval by the CER and is currently waiting to receive federal Cabinet approval and the CER has started a process to determine whether it will extend the temporary service protocol.

Specific Pipeline and Proposed LNG Export Terminal Updates

While a number of LNG export plants have been proposed in Canada, regulatory and legal 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 LNG export terminal announced a positive final investment decision. Once complete, the project will allow LNG Canada to transport natural gas from northeastern British Columbia to the LNG Canada liquefaction facility and export terminal in Kitimat, British Columbia via the Coastal GasLink pipeline (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 a 65% equity interest in the CGL Pipeline to investment companies KKR & Co Inc. and Alberta Investment Management Corporation while remaining the pipeline operator. The transaction closed in May 2020. Despite its approval, the CGL Pipeline has faced intense legal and social opposition. For example, protests involving the Hereditary Chiefs of the Wet'suwet'en First Nation and their supporters have caused delays to construction activities on the CGL Pipeline.

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 Woodside Petroleum Ltd. However, both partners are looking to sell some or all of their interest in the project. The Woodfibre LNG Project is a smallscale LNG processing and export facility near Squamish, British Columbia, and owned by Woodfibre LNG Limited a subsidiary of Singapore-based Pacific Oil and Gas Ltd. The BC Commission approved a project permit for the Woodfibre LNG Project, in July 2019. Pre-construction agreements for Woodfibre LNG are in the process of being finalized. GNL Québec Inc., the proponent of the Énergie Saguenay Project, is currently working its way through a federal impact assessment process for the construction and operation of an LNG facility and export terminal located on Saguenay Fjord, an inlet which feeds into the St. Lawrence River in Québec. The Goldboro LNG project, located in Nova Scotia, proposed by Pieridae Energy Ltd. ("Pieridae"), 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, but Pieridae has delayed its final investment decision. Finally, Cedar LNG Export Development Ltd.'s Cedar LNG Project near Kitimat, British Columbia, is currently in the environmental assessment stage, with British Columbia's Environmental Assessment Office (the "BC EAO") conducting the environmental assessment on behalf of the Impact Assessment Agency of Canada ("IA Agency").

Enbridge Open Season

In August 2019, Enbridge initiated an open season for the Enbridge mainline system, which has historically operated as a common carrier pipeline system transporting crude oil. The changes that Enbridge intends to implement include the transition of the mainline system from a common carrier to a primarily contract carrier pipeline, wherein shippers will have to commit to reserved space in the pipeline for a fixed term, with only 10% of available capacity reserved for nominations. If the service change is approved, 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 first obtaining prior regulatory approval to implement a contract carriage model. 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 approval of the proposed service and tolling framework. The regulatory hearing process is currently underway and a final decision from the CER is not expected until mid-2021.

Curtailment

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

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 and the allowable production limit is currently set at 3.81 million Bbls/d until the end of October, though it may be revised further. The Government of Alberta has also introduced certain policy changes to the curtailment program, including creating an exemption for production from new conventional oil wells and allowing crude oil production in excess of a curtailment order, provided that the extra production is shipped out of Alberta by rail.

The Curtailment Rules are set to be repealed on December 31, 2020, but they may be extended further. The Curtailment Rules currently affect 16 producers; however, the Company is not currently subject to a curtailment order.

The North American Free Trade Agreement and Other Trade Agreements

NAFTA and the USMCA

The North American Free Trade Agreement ("NAFTA") that previously existed among the governments of Canada, the United States and Mexico has been replaced by a new trade agreement, widely referred to as the United States Mexico Canada Agreement (the "USMCA") and sometimes referred to as the Canada United States Mexico Agreement, or "CUSMA". The USMCA came into force on July 1, 2020. Because the United States remains Canada's primary trading partner and the largest international market for the export of crude oil, natural gas and NGL from Canada, the implementation of the USMCA could have an impact on Western Canada's oil and natural gas industry at large, including the Company's business.

While the proportionality rules in Article 605 of NAFTA previously prevented Canada from implementing policies that limit exports to the United States and Mexico relative to the total supply produced in Canada, the USMCA does not contain the same proportionality requirements. This may allow Canadian producers to develop a more diversified export portfolio than was possible under NAFTA, subject to the construction of infrastructure allowing more Canadian production to reach eastern Canada, Asia and Europe.

Other Trade Agreements

Canada has also pursued a number of other international free trade agreements with other countries around the world and, as a result, a number of free trade or similar agreements are in force between Canada and certain other countries. 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.

Canada and 10 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 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.

Land Tenure

The respective provincial governments (i.e. the Crown) predominantly own the mineral rights to most of the crude oil and natural gas located in Western Canada. 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 Alberta and British Columbia 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.

In response to COVID-19, the governments of Alberta and British Columbia have announced measures to extend or continue Crown leases and permits that may have otherwise expired in the months following the implementation of pandemic response measures. In March 2020, the British Columbia Ministry of Energy, Mines and Petroleum Resources announced that it was suspending posting requests and dispositions of petroleum and natural gas tenure until further notice due to COVID-19.

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 to 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. Such reversionary rights may impact any GORR Interests granted out of Crown leases.

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. Rights to explore for and produce privately owned 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 companies seeking to explore for and/or develop crude oil and natural gas reserves.

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") manages subsurface and surface leases in consultation with applicable Indigenous peoples, for the 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 and further regulations are currently being developed. The Company does not have any interests in operations on Indian reserve lands.

The GORR Interests are royalty interests that are granted or carved out of leasehold interests (created through the issuance of a lease by the Crown or fee simple mineral title owner). As such, the continued existence and value of the GORR Interests is dependent upon the validity and terms of the leasehold interest out of which they were granted.

Royalties and Incentives

General

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 NGL 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 production.

Producers and working interest owners of crude oil and natural gas rights may also create 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, the terms of which are subject to negotiation.

Occasionally the governments of Western Canada's provinces create incentive programs for exploration and development. Such programs often provide for volume-based incentive programs, 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, incentive programs may be introduced to encourage producers to prioritize certain kinds of development or undertake initiatives using new technologies that may enhance or improve recovery of crude oil, natural gas and NGL.

The federal government also creates incentives and other financial aid programs intended to assist businesses operating in the oil and natural gas industry. Recently, these programs, including, but not limited to, programs that provide direct financial support to companies operating in the oil and natural gas industry and/or targeted funding for various initiatives related to industry diversification and environmental matters, have been administered through federal agencies such as the Business Development Bank of Canada, Natural Resources Canada, Export Development Canada, and Innovation, Science and Economic Development Canada.

Alberta

In Alberta, 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 until December 31, 2026. After the expiry of this 10-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. The cost component is 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 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.

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 to shorten the window during which producers can submit amendments to their royalty calculations before they become statute-barred, from four years to three.

Subject to certain available incentives, royalty rates for conventional crude oil production subject to the Old Framework range from a base rate of 0% to a cap of 40%; 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 NGL is a flat rate of 40% for pentanes and 30% for butanes and propane.

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/Bbl and increase for every dollar by which the market price of crude oil increases 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 by which the market price of crude oil increases above $55/Bbl to a maximum of 40% when crude oil is priced at $120/Bbl or higher.

In addition to royalties, producers of crude oil and natural gas from Crown lands in Alberta are also required to pay annual rental payments, at a rate of $3.50 per hectare.

Freehold mineral taxes are levied annually for production from freehold mineral lands. On average, the tax levied in Alberta is 4% of revenues reported from freehold mineral title properties. Freehold mineral taxes are in addition to any other negotiated royalty or other payment required to be paid to the owner of such freehold mineral rights.

British Columbia

The royalties payable by producers in British Columbia will vary depending on the types of wells and the characteristics of the substances being produced.

Producers of crude oil in British Columbia receive royalty invoices each month for every well or unitized tract that is producing and/or reporting sales. The royalty rate can be as high as 40%, depending on factors such as the volume of crude oil produced by the applicable well or tract and the crude oil vintage. Royalty rates are reduced on low-productivity wells and other wells with applicable royalty exemptions to reflect higher per-unit costs of exploration and extraction.

Producers of natural gas and NGL in British Columbia receive royalty invoices each month for every well or unitized tract that is producing and/or reporting sales. Different royalty rates apply for natural gas, NGL and natural gas by-products. For natural gas, the royalty rate can be up to 27% of the value of the natural gas and is based on whether the gas is classified as conservation gas or non-conservation gas, as well as reference prices and the select price. For NGL and condensates, the royalty rate is fixed at 20%. Additionally, the Government of British Columbia maintains a number of targeted royalty programs for key resource areas intended to increase the competitiveness of British Columbia's low productivity natural gas wells. These include both royalty credit and royalty reduction programs.

Producers of crude oil and natural gas from freehold lands in British Columbia are required to pay monthly freehold production taxes. For crude oil, the applicable freehold production tax is based on the volume of monthly production, which is either a flat rate, or, beyond a certain production level, is determined using a sliding scale formula based on the production level. For natural gas, the applicable freehold production tax is a flat rate, or, at certain production levels, is determined using a sliding scale formula based on a reference price, and depends on whether the natural gas is conservation gas or nonconservation gas. The production tax rate for freehold NGL is a flat rate of 12.25%. Additionally, owners of mineral rights in British Columbia must pay an annual mineral land tax that is equivalent to $4.94 per hectare of producing lands. Nonproducing lands are taxed on a sliding scale from $1.25 to $4.94 per hectare, depending on the total number of hectares owned by the entity.

Regulatory Authorities and Environmental Regulation

General

The Canadian 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 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, future changes to environmental legislation, including legislation related to air pollution and GHG emissions (typically measured in terms of their global warming potential and expressed in terms of carbon dioxide equivalent ("CO2e")), may impose further requirements on operators and other companies in the oil and natural gas industry.

Federal

Canadian environmental regulation is the responsibility of both the federal and provincial governments. While provincial governments and their delegates are responsible for most environmental regulation, the federal government can regulate environmental matters where they impact matters of federal jurisdiction or when they arise from projects that are subject to federal jurisdiction, such as interprovincial transportation undertakings, including pipelines and railways, and activities carried out on federal lands. Where there is a direct conflict between federal and provincial environmental legislation in relation to the same matter, the federal law prevails.

On August 28, 2019, the IAA replaced the Canadian Environmental Assessment Act, 2012 ("CEAA 2012") at the same time that the CERA replaced the NEB Act and the CER replaced the NEB. As part of the regulatory transition, the IA Agency replaced the Canadian Environmental Assessment Agency.

The enactment of the CERA and the IAA introduced a number of important changes to the regulation of federally regulated major projects and their associated environmental assessments. Previously, the NEB administered its statutory jurisdiction as an integrated regulatory body. However, the CERA separates the CER's administrative and adjudicative functions. A board of directors and a chief executive officer manage strategic, administrative and policy considerations while adjudicative functions fall to independent commissioners. Despite this structural change, 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 many of these projects, culminating in their eventual abandonment.

The IAA is similar to the repealed CEAA 2012 in that it relies on a designated project list as a trigger for a federal assessment. Designated projects that may have effects on matters within federal jurisdiction will generally require an impact assessment administered by the IA Agency or, in the case of certain pipelines, a joint review panel comprised of members from the CER and the IAA. The impact assessment requires consideration of the project's potential adverse effects and the overall societal impact that a project may have, both of which may include a consideration of, among other items, environmental, biophysical and socio-economic factors, climate change, and impacts to Indigenous rights. It also requires an expanded public interest assessment. The impact assessment must look at the direct result of the project's construction and operation, Designated projects specific to the oil and natural gas industry 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 GHG emissions caps and certain refining, processing and storage facilities.

The federal government has stated that an objective of the legislative changes was to improve decision certainty and turnaround times. 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. The Government of Alberta has submitted a reference question to the Alberta Court of Appeal regarding the constitutionality of the IAA but the hearing has not yet been scheduled.

Alberta

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 statutes 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 Government of Alberta relies on regional planning to accomplish its 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. 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 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.

The AER monitors seismic activity across Alberta to assess the risks associated with, and instances of, earthquakes induced by hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand or other proppants and additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate oil and natural gas production. In recent years, hydraulic fracturing has been linked to increased seismicity in the areas in which hydraulic fracturing takes place, prompting regulatory authorities to investigate the practice further.

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 are Fox Creek, Red Deer, and Brazeau (the "Seismic Protocol Regions"). Oil 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. Such 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 operations while it investigates following a seismic event until it has assessed the ongoing risk of earthquakes in a specific area and/or may require the operator to update its response plan.

The AER may extend these requirements to other areas of Alberta if necessary, subject to the results of its ongoing provincewide monitoring.

British Columbia

In British Columbia, the Oil and Gas Activities Act (the "OGAA") regulates conventional crude oil and natural gas producers, shale gas producers and other operators of crude oil and natural gas facilities in the province. Under the OGAA, the BC Commission has broad powers, particularly with respect to compliance, enforcement and the setting of technical safety and operational standards for oil and natural gas activities. The Environmental Protection and Management Regulation establishes the government's environmental objectives and requires the BC Commission to consider these environmental objectives in deciding whether or not to authorize a particular activity. In addition, the Petroleum and Natural Gas Act, in conjunction with the OGAA, requires proponents to obtain various approvals before undertaking exploration or production work. Such approvals are given subject to environmental considerations and permits, licences and project approvals can be suspended or cancelled for failure to comply with this legislation or its regulations.

The Government of British Columbia has introduced a regime to monitor and manage the risk of induced seismicity related to oil and natural gas operations, particularly in northern British Columbia, where hydraulic fracturing is used to access natural gas plays. The Drilling and Production Regulation requires a producer to suspend its operations if they trigger an earthquake with a magnitude on the Richter scale of 4.0 or greater, and to implement mitigation measures approved by the BC Commission before resuming production. In June 2016, the BC Commission amended the permitting process to require all natural gas producers to conduct ground monitoring, and to submit a ground monitoring report within 30 days of completing hydraulic fracturing operations.

In May 2018, the BC Commission issued a Special Project Order under section 75 of the OGAA, which designated the Kiskatinaw Seismic Monitoring and Mitigation Area, spanning between Fort St. John and Dawson Creek (the "Kiskatinaw Area"). Permit holders in the Kiskatinaw Area are subject to additional requirements before they can conduct hydraulic fracturing operations, including developing a seismic monitoring and mitigation plan that is approved by the BC Commission, and notifying the BC Commission and local residents about planned hydraulic fracturing requirements. During active hydraulic fracturing operations, permit holders are required to deploy an accelerometer, have access to real-time seismicity readings and report such readings to the BC Commission on demand. If a seismic event occurs, permit holders are subject to a "traffic light" reporting system that sets thresholds on the Richter scale of earthquake magnitude and triggers a sliding scale of obligations from permit holders. The obligations range from reporting the earthquake and developing an approved protocol for subsequent earthquakes, to initiating such protocols, to suspending operations until permitted to resume by the BC Commission. Future earthquakes outside of the Kiskatinaw Area may trigger the introduction of similar requirements elsewhere in the province.

On November 28, 2019, the Declaration on the Rights of Indigenous Peoples Act (the "DRIPA") became law in British Columbia. The DRIPA aims to align British Columbia's laws with the United Nations Declaration of the Rights of Indigenous Peoples; however, it is unclear what the practical consequences of this law will be.

An updated Environmental Assessment Act came into force on December 16, 2019. The new assessment regime subjects proposed projects to an enhanced environmental review process that, among other things, emphasises early engagement and aims to enhance Indigenous engagement in the project approval process with an emphasis on consensus-building. Simultaneously with the enactment of the Environmental Assessment Act, the Government of British Columbia enacted the accompanying Reviewable Projects Regulation, which sets out the projects subject to the new regime. The "project list" captures industrial, mining, energy, water management, waste disposal, transportation and other GHG intensive projects. In conducting an environmental assessment, the BC EAO will consider the environmental, health, cultural, social and economic effects of a proposed project.

Liability Management Rating Program

Alberta

The AER administers a 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 licensee, must reduce its liabilities or provide the AER with a security deposit. Failure to do so 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").

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.

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 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.

As a result of the Supreme Court of Canada's decision in Orphan Well Association v Grant Thornton (also known as the "Redwater" decision), 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 that have reached the end of their productive lives (and therefore represent a net liability) in order to deal primarily with the remaining productive and valuable assets without first satisfying any abandonment and reclamation obligations associated with the insolvent estate's assets.

In response to the increase in orphaned orphan oil and gas sites and the environmental risks associated therewith, the AER has issued several bulletins and interim rule changes to govern the AER's administration of its licensing and liability management programs. For example, 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 they can meet their abandonment and reclamation obligations.

Both the Government of Alberta and/or the AER may make further rule changes to Alberta's liability management programs at any time. For example, on July 30, 2020, the Government of Alberta announced a new Liability Management Framework ("AB LMF") that will replace the AB LMR Program and its constituent programs. Among other changes under the AB LMF, the AB LMR Program will be replaced with the Licensee Capability Assessment System, which is intended to be a more comprehensive assessment of corporate health and will consider a wider variety of factors than those considered under the AB LMR Program and will establish clear expectations for industry with regards to the management of liabilities throughout the entire lifecycle of oil and gas projects. Importantly, the AB LMF will also provide proactive support to distressed operators and will require companies operating in Alberta's oil and natural gas industry to make mandatory annual minimum payments towards outstanding reclamation obligations in accordance with five-year rolling spending targets. It is not yet clear how or when then AB LMF will be implemented.

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.

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. Parties seeking to participate in the program must commit to an inactive liability reduction target to be met through closure work of inactive assets.

British Columbia

Similar to Alberta, the BC Commission oversees a Liability Management Rating Program (the "BC LMR Program"), which is designed to manage public liability exposure related to crude oil and natural gas activities by ensuring that permit holders carry the financial risks and regulatory responsibility of their operations through to regulatory closure. Under the BC LMR Program, the BC Commission determines the required security deposits for permit holders under the OGAA. The liability management rating is the ratio of a permit holder's deemed assets to deemed liabilities. Permit holders whose deemed liabilities exceed their deemed assets (i.e., an LMR of below a ratio of 1.0) will be considered at-risk and reviewed for a security deposit. Permit holders that fail to comply with security deposit requirements are deemed non-compliant under the OGAA and enter the compliance and enforcement framework.

On April 1, 2019, a liability-based levy paid to the Orphan Site Reclamation Fund ("OSRF") replaced the orphan site reclamation fund tax paid by permit holders. Similar to Alberta's Orphan Fund, the OSRF is an industry-funded program created to address the abandonment and reclamation costs for orphan sites. Permit holders are required to pay their proportionate share of the levy. The OGAA permits the BC Commission to impose more than one levy in a given calendar year.

Effective May 31, 2019, the Dormancy and Shutdown Regulation (the "Dormancy Regulation") establishes the first set of legally imposed timelines for the restoration of oil and natural gas wells in Western Canada. The Dormancy Regulation classifies different sites based on activity levels associated with the well(s) on each site, with a goal of ensuring that 100% of currently dormant sites are reclaimed by 2036 with additional regulated timelines for sites that become dormant between 2019 and 2023 or become dormant after 2024. A permit holder will have varying reporting, decommissioning, remediation and reclamation obligations that depend on the classification of its sites. Any permit holder that has a dormant site in its portfolio must develop and submit an annual work plan to the BC Commission, outlining its decommissioning and restoration activities for each calendar year. The permit holder must also prepare and submit a retrospective annual report within 60 days of the end of the calendar year in which it conducted the work outlined in the corresponding annual work plan.

Federal and Provincial Support for Liability Management

As part of an announcement of federal relief for Canada's oil and natural gas industry in response to COVID-19, the federal government pledged $1.72 billion to clean up orphan and inactive wells in Alberta, Saskatchewan and British Columbia. However, these funds are being administered by regulatory authorities in each province. In Alberta, the Ministry of Energy is disbursing its $1 billion share of the federally provided funds through the Site Rehabilitation Program. The Government of British Columbia is disbursing its $120 million share of the federally provided funds through three programs: the Dormant Sites Reclamation Program, the Orphan Sites Supplemental Reclamation Program and the Legacy Sites Reclamation Program. In addition to the funds administered by the respective provincial governments, the federal government announced a $200 million loan to Alberta's Orphan Fund. And in early March 2020, the Government of Alberta announced an extension of an existing $235 million loan to the Orphan Fund by up to $100 million.

Climate Change Regulation

Climate change regulation at each of the international, federal and provincial levels has the potential to significantly affect the future of the oil and natural gas industry in Canada. These impacts are uncertain and it is 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. An example of a change in policy that may impact the oil and natural gas industry is the International Maritime Organization's implementation of a new regulation that limits the sulphur content of marine fuel oil, reducing the permissible amount of sulphur from 3.5% to 0.5%, effective January 1, 2020.

Federal

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. To date, 189 of the 197 parties to the UNFCCC have ratified the Paris Agreement, including Canada. 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, scheduled to take place in November 2021.

The Government of Canada has pledged to cut its emissions by 30% from 2005 levels by 2030, but indicated in the recent Speech from the Throne (also referred to as the "Throne Speech"; discussed in greater detail below) that it may implement policy changes to exceed this target. In connection with this target, the Government of Canada released the Pan-Canadian Framework on Clean Growth and Climate Change, setting out a plan to meet the federal government's emissions targets. 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 output-based pricing 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. This system applies in provinces and territories that request it and in those that do not have comparable emissions pricing systems in place that meet the federal standards. The effect of the GGPPA is that, regardless of whether a particular province has enacted legislation of its own, there is a uniform price on emissions across the country.

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 Alberta Court of Appeal determined that the GGPPA is unconstitutional. All three judgments have been appealed to the Supreme Court of Canada and the hearing took place in September 2020.

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 lowemission equipment and processes. Among other things, the Federal Methane Regulations limit how much methane upstream oil and natural gas facilities are permitted to vent. 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.

The federal government has 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, to limit the emission of air pollutants such as nitrogen oxides and sulphur dioxide.

On September 23, 2020, the Governor General of Canada delivered the Throne Speech, outlining the direction, priorities and goals of the federal government for the new session of Parliament. The federal government plans to more actively address climate change by developing a plan to exceed Canada's 2030 climate goal and legislate a goal of net-zero emissions by 2050. In addition, the federal government indicated that it intends to make a number of investments that will help it achieve these targets, including investments intended to: improve transit options; make zero-emissions vehicles more affordable; expand vehicle charging infrastructure across the country; launch a fund that will help attract investments in the development of zero-emissions technology, including a corporate tax cut of 50% for companies participating in this initiative; move forward with a Clean Power Fund that will, in part, help regions transition to cleaner sources of power generation; and support continued investment in the development and implementation of renewable and clean energy technologies. Also of relevance to the oil and natural gas industry, the federal government announced that it plans to implement a ban on singleuse plastics. Specific program details have not yet been announced and both the Throne Speech and the budget will need to pass confidence votes before the federal government can proceed to implement its plans; however, should Parliament vote to pass the Throne Speech and budget, it is expected that the federal government will begin to move forward with these plans.

Alberta

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 that was compliant with federal requirements. 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, but the regulations necessary to enforce the limit have not yet been developed.

In June 2019, the Government of Alberta repealed the CLA. As a result, the federal fuel charge took effect in Alberta on January 1, 2020, at a rate of $20/tonne. In accordance with the GGPPA, this increased to $30/tonne on April 1, 2020. However, on December 4, 2019, the federal government approved Alberta's Technology Innovation and Emissions Reduction ("TIER") regulation, which applies to large emitters. The TIER regulation came into effect on January 1, 2020 and replaces the previous Carbon Competitiveness Incentives Regulation.

The TIER regulation applies 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, 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. Similarly, for facilities that have already made substantial headway in reducing their emissions, a different "highperformance" benchmark is available to ensure that the cost of ongoing compliance takes this into account. Under the TIER regulation, facilities in high-emitting sectors can opt-in to the program in specified circumstances despite the fact that they do not meet the 100,000 tonne threshold. To encourage compliance with the emissions intensity reduction targets, TIERregulated 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 aims to 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 the updated 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. In May 2020, the Government of Canada and the Government of Alberta announced a preliminary equivalency agreement regarding the reduction of methane emissions such that the Federal Methane Regulations will not apply once the agreement is effective.

British Columbia

On August 19, 2016, the Government of British Columbia launched its Climate Leadership Plan, which aims to reduce British Columbia's net annual emissions by up to 25 million tonnes below current forecasts by 2050 and recommit the province to achieving its target of reducing emissions by 80% below 2007 levels by 2050.

British Columbia was also the first Canadian province to implement a revenue-neutral fuel charge. The fuel charge is currently set at $40/tonne of CO2e. While the scheduled increase to $45/tonne of CO2e was delayed until October 1, 2020 in response to COVID-19, the Government of British Columbia announced on September 2, 2020 that the increase would not take place until April 1, 2021.

On January 1, 2016, the Greenhouse Gas Industrial Reporting and Control Act (the "GGIRCA") came into effect, which streamlined the regulatory process for large emitting facilities. The GGIRCA sets out various performance standards for different industrial sectors and provides for emissions offsets through the purchase of credits or through emission offsetting projects.

On December 5, 2018, the Government of British Columbia announced an updated clean energy plan, "CleanBC", which seeks to ensure that British Columbia achieves 75% of its GHG emissions reduction target by 2030. The CleanBC plan includes a number of strategies targeting the industrial, transportation construction, and waste sectors of the British Columbia economy. Key initiatives include: (i) increasing the generation of electricity from clean and renewable energy sources; (ii) imposing a 15% renewable content requirement in natural gas by 2030; (iii) requiring fuel suppliers to reduce the carbon intensity of diesel and gasoline by 20% by 2030; (iv) investing in the electrification of crude oil and natural gas production; (v) reducing 45% of methane emissions associated with natural gas production; and (vi) incentivizing the adoption of zeroemissions vehicles.

On January 16, 2019, the BC Commission announced a series of amendments to the British Columbia Drilling and Production Regulation that will require facility and well permit holders to, among other things, reduce natural gas leaks and curb monthly natural gas emissions from their equipment and operations. These new rules came into effect on January 1, 2020. In February 2020, the Government of Canada and the Government of British Columbia entered an equivalency regarding the reduction of methane emissions.

Accountability and Transparency

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 CAD$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 taxes), fees, production entitlements, bonuses, dividends (other than ordinary dividends paid to shareholders), infrastructure improvement payments and other prescribed categories of payments.

RISK FACTORS

Investing in the Common Shares involves risks. A prospective investor should carefully consider the following risk factors together with all of the other information included in this prospectus in evaluating an investment in the Common Shares. Additional risks not presently known to Topaz or that Topaz currently deems immaterial could also materially affect the Company's business. The risks set out below are not an exhaustive description of all the risks associated with the Company's business and the oil and natural gas business generally. This prospectus includes forward-looking statements regarding, among other things, the Company's plans, strategies, prospects and projections, both business and financial. A prospective investor should not place undue reliance on any such statements included in this prospectus or any other offering materials. See "Notice to Investors – Forward-Looking Statements" in this prospectus.

The Common Shares offered under this prospectus should be considered speculative due to the nature of the Company's business. An investment in the Common Shares should only be made by persons who can afford a significant or total loss of their investment.

There can be no assurance that an active trading market in the Common Shares will develop or be sustained. The market price for the Common Shares could be subject to wide fluctuations. Factors such as commodity prices, government regulation, interest rates, share price movements of the Company's peer companies and competitors, as well as overall market movements, may have a significant impact on the market price of the securities of the Company. The stock market has from time to time including during 2020 experienced extreme price and volume fluctuations, particularly in the oil and natural gas sector, which have often been unrelated to the operating performance of particular companies.

If any of the following risks were to occur, the Company's business, financial condition and results of operations could be materially adversely affected. In that case, the trading price of the Common Shares could decline and a prospective investor could lose all or part of their investment.

Even though Topaz does not directly conduct upstream petroleum and natural gas exploration and development operations, its business, financial condition, results of operations and prospects will be significantly impacted by factors and risks that impact the oil and natural gas industry generally, and, in particular, affect the Company's counterparties, including Tourmaline. Oil and natural gas operations involve many risks that even a combination of experience, knowledge and careful evaluation may not be able to overcome.

Overview

In carrying out its business and operations, Topaz faces a number of risks. Generally, Topaz's risks fall into three principal categories: (i) risks relating to the Company's business, industry and operating environment including financial, legal, regulatory and strategic risks; (ii) risks relating to the Company's relationship with Tourmaline; and (iii) risks relating to the Offering and the Common Shares. These categories are outlined below along with summaries of the specific risk factors within each general category. In some instances, risks may fall into each category. In such cases, the Company has classified risks based on the primary category in terms of how they affect Topaz. To the extent Topaz's business or operations are affected by these risks, there could be an adverse effect on Topaz's financial performance and cash flow available to pay dividends.

Risks Relating to the Company's Business, Industry and Operating Environment

Limited Operating History and Track Record

Topaz's current business was established in November 2019 with the acquisition of the Initial Assets, and as a result, it has a limited operating history and track record with respect to the ownership of the Royalty Assets and the Infrastructure Assets. Accordingly, Topaz's prior operating history and historical financial statements and the historical operating statements of the Initial Assets may not be a reliable basis for evaluating the Company's business prospects or the future value of the Common Shares. In addition, the Company's business strategy may not be successful, and, if unsuccessful, Topaz may be unable to modify it in a timely and successful manner. The Company cannot give a prospective investor any assurance that it will be able to continue to implement its strategy on a timely basis, if at all. Topaz will need to continue to build its management team to implement its strategies. The Company may also be subject to both transition and growth-related risks, including capacity constraints and pressure on its internal systems and controls. Accordingly, an investment in the Common Shares is speculative and subject to a high degree of risk.

The Company's limited operating history and track record with respect to the Royalty Assets and the Infrastructure Assets also means that it continues to develop and implement various policies and procedures. For instance, in the past, the Initial Assets were operated in the context of Tourmaline's business as a whole. Accordingly, employees of Topaz had access to Tourmaline's resources, including Tourmaline's systems, business contacts, financial resources, senior management and other expertise and resources. Other than for the limited purpose and limited time specified in the Management Services Agreement, the Company does not have the same access to Tourmaline's expertise and resources. There can be no assurance that the Company will have similar expertise or resources through internal sources or by contracting services with third parties, or if such expertise or resources can be obtained on the same basis, or at the same or lesser cost, as provided historically by Tourmaline. See "Agreements with Tourmaline and Other Counterparties — Management Services Agreement".

Although the Company expects to benefit from the experience that Management and its employees have gained while working at Tourmaline and other oil and natural gas companies, the Company may be less successful in implementing its business strategy, as it is an indirect participant in the development and production of petroleum and natural gas and does not operate the Infrastructure Assets. As a result, the Company may experience significant fluctuations in its results, which may vary from those projected by Management. In addition, the forward-looking statements contained in this prospectus about expected future results or the assumptions reflected in the Topaz Pro Forma Operating Statements, the supplemental financial and production information relating to the Initial Assets and the estimated future financial and production information for the Tourmaline GORR Lands included elsewhere in this prospectus are subject to uncertainties that are due, in part, to the Company's limited operating history. No assurance can be given that the Company will be successful in implementing its business strategy or that it will achieve expected future results which could materially adversely affect the Company's business and financial condition.

COVID-19

In December 2019, COVID-19 surfaced in Wuhan, China. Since then the outbreak has spread to over 200 countries and territories and infections have been reported around the world. The World Health Organization declared a global emergency on January 30, 2020 with respect to the outbreak and subsequently characterized it as a pandemic on March 11, 2020. In response to the outbreak, governmental authorities in Canada and internationally have introduced various recommendations and measures to try to limit the pandemic, including travel restrictions, border closures, non- essential business closures, quarantines, self-isolations, shelters-in-place and social distancing. COVID-19 and the response of governmental authorities to try to limit it are having a significant impact on the private sector and individuals, including unprecedented business, employment and economic disruptions.

The Company has been closely monitoring developments related to COVID-19. COVID-19 and other macro-economic conditions around the world have contributed to a drastic decrease in global oil and liquids demand since the beginning of 2020. These events have resulted in significant price volatility of oil and liquids prices and increased economic uncertainty. Natural gas prices have also been very volatile. While there has been little to no disruption to date to the Company's business, the oil and condensate prices Topaz receives for its oil and condensate royalty revenue have been affected by the weakness in crude oil prices. During this period of uncertainty, the Company is committed to maintaining its strong balance sheet and financial liquidity. At this time, the extent to which COVID-19 may continue to affect the Company is uncertain; however, it is possible that COVID-19 may have further adverse effects on commodity prices, the Company's business and income streams, results of operations and financial condition depending on the severity and duration of the pandemic. In response to COVID-19, the Company is following all applicable rules and regulations as set out by the relevant health authorities.

Due to the uncertainty surrounding the magnitude, duration and potential outcomes of COVID-19, the Company is unable at this time to predict its long-term impact on its operations, liquidity, financial condition and results, but the impact may be material. For instance, if COVID-19 were to affect Management, the Company may be delayed in executing, or unable to execute, its business strategy. The Company will continue to closely monitor this global health crisis and will reassess its strategy and operational activities on a regular, ongoing basis as the situation evolves. Any significant decrease in the demand for oil and natural gas could in turn disrupt the Company's business and the Company's counterparties businesses, activities, and operations. Moreover, since the beginning of January 2020, the COVID-19 outbreak has caused significant disruption in the financial markets both globally and in the U.S., which could limit the Company's ability to access capital and sources of liquidity at attractive rates or at all, adversely affecting the Company's business, financial condition, liquidity and results of operations.

The extent to which COVID-19 impacts the Company's results will ultimately depend on future developments, which are highly uncertain, and will include the actions taken by governments and private businesses to attempt to contain COVID-19.

Health and Safety

The ownership and operation of Topaz's business is subject to hazards of producing, gathering and processing hydrocarbon products, including, without limitation, blowouts, fires, explosions, gaseous leaks, releases and migration of harmful substances, hydrocarbon spills, corrosion, and acts of vandalism and terrorism. Any of these hazards can interrupt operations, impact Topaz's reputation, cause loss of life or personal injury, result in loss of or damage to equipment, property, information technology systems, related data and control systems, and cause environmental damage that may include polluting water, land or air.

Further, such ownership and operations carry the potential for liability related to worker health and safety, including, without limitation, the risk of any or all of government imposed orders to remedy unsafe conditions, potential penalties for contravention of health and safety laws, licences, permits and other approvals, and potential civil liability. Compliance with health and safety laws (and any future changes thereto) and the requirements of licences, permits and other approvals are expected to remain material to Topaz's business.

However, no assurances can be given that the occurrence of any of the above listed events or the additional workers' health and safety issues relating thereto will not require unanticipated expenditures, or result in fines, penalties or other consequences (including, without limitation, changes to operations) material to Topaz's business and operations.

Operating Risk

Topaz's businesses are subject to the risks normally associated with the operation and development of natural gas, NGL, crude oil and other products and facilities, including, without limitation, mechanical failure, transportation problems, physical degradation, operator error, manufacturer defects, constraints on natural resource development, delay of or restrictions for projects due to climate change policies and initiatives, protests, activist activity, sabotage, terrorism, failure of supply, weather, wind or water resource deviation, catastrophic events and natural disasters, fires, floods, explosions, earthquakes, and other similar events. These types of events could result in injuries to personnel, damage to property and the environment, as well as unplanned outages or prolonged downtime for maintenance and repair. Among other things, these events typically increase operation and maintenance expenses and reduce revenues. The occurrence or continuation of any of these events could increase Topaz's costs and reduce the ability of Topaz and its counterparties to produce, process, store, transport, deliver, or distribute natural gas, NGL, crude oil and other products and result in significant losses for which insurance may not be sufficient or available. Environmental damage could also result in increased costs to operate and insure Topaz's assets and have a negative impact on Topaz's reputation and its ability to work collaboratively with stakeholders.

As Topaz continues to grow and diversify its royalty and energy infrastructure businesses, the risk profile of Topaz may change.

Infrastructure Service Interruptions

If the Infrastructure Assets were to become unexpectedly unavailable for delivery of current or future volumes of natural gas because of repairs, damage, spills or leaks, or any other reason, it could have a material adverse impact on financial conditions and results of operation of the business. Although the costs of infrastructure replacement programs are typically recovered in rates, on-going capital is required to fund such programs. In addition, operating issues resulting from maturing infrastructure such as leaks, equipment problems and incidents, including, without limitation, explosions and fire, could result in legal liability, repair and remediation costs, increased operating costs, increased capital expenditures, regulatory fines and penalties, and other costs and a loss of customer confidence. Any liabilities resulting from the occurrence of these events may not be fully covered by insurance or rates. Service interruption incidents that may arise through unexpected major power disruptions to Infrastructure Assets, third-party negligence or unavailability of critical replacement parts could cause its counterparties to be unable to safely and effectively operate these assets. This could adversely affect Topaz's business operations and financial results.

Reliance on Counterparty Activity and Long-Term Declines

The volumes of natural gas, NGL, crude oil and other products produced from the GORR Lands underlying the Royalty Assets and natural gas processed through the Infrastructure Assets depends on production. Without reserve additions, production will decline over time as reserves are depleted and production costs may rise.

The Company's facilities are located in or depend on the WCSB. As a mature basin, production is projected to decline over the long-term. Although new technology has allowed producers to access and produce reserves that were previously viewed as uneconomic, it is not clear the extent to which such advances in technology will offset the long-term overall production declines. As well, industry activity levels depend upon economic and regulatory conditions that permit and incent producers to explore for and develop reserves. Counterparties may not be successful in exploring for and developing additional reserves, and the Royalty Assets may not be able to maintain current production levels and the Infrastructure Assets may not be able to maintain existing volumes of throughput.

Commodity prices may not remain at a level that encourages producers to explore for and develop additional reserves or produce existing marginal reserves. Further, with current commodity pricing dynamics compounded by product egress challenges in the WCSB, some producers have slowed or modified their exploration and development plans in Western Canada. Lower production volumes will also increase the competition for natural gas supply at gas processing plants which could result in higher shrinkage gas premiums being paid to natural gas producers. The Company cannot predict the impact of future economic conditions on the energy and petrochemical industries or future demand for and prices of natural gas, NGL, crude oil and other products. These and other factors such as higher development costs or royalties, elevated global and North American commodity inventory levels and infrastructure constraints may discourage further producer exploration and development. A reduction in exploration and development activities or the curtailment of production (whether due to regulatory requirements, market constraints or voluntarily by producers) could result in declines in throughput at gas plants, pipelines, terminals and NGL processing facilities.

The rate and timing of production from proven natural gas reserves tied-in to the Infrastructure Assets are at the discretion of the producers and are subject to regulatory constraints. The producers have no obligation to produce natural gas from these lands. Producers may suspend their drilling programs or shut in production as a result of lower product prices or higher production costs. Where possible, Topaz attempts to negotiate area dedications or take-or-pay arrangements with counterparties or negotiate drilling commitments.

The Infrastructure Assets are connected to various third-party pipeline systems. Operational disruptions or apportionment on those third-party systems may prevent the full utilization of the business.

There is also risk associated with Topaz's customers being able to perform their contracted obligations. For example, counterparties may not comply with their contracted obligations (counterparty risk) or may not deliver volumes consistent with their production profile (volume risk), all of which could adversely affect Topaz's financial results, including the returns on capital investments.

Over the long-term, business will depend, in part, on the level of demand for natural gas, NGL, crude oil and other products in the geographic areas in which deliveries are made by pipelines and the ability and willingness of shippers having access or rights to utilize the pipelines to supply such demand. Topaz cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the demand for natural gas, NGL, crude oil and other products.

Highly Dependent on the Operations of Counterparties and Contractual Arrangements

The Company is dependent on its counterparties to operate the Royalty Assets and the Infrastructure Assets. In addition, the Company has limited ability to exercise influence over the operations on the Royalty Assets and the Infrastructure Assets or the associated operating or capital costs, which could adversely affect the Company's financial performance. The Company's revenues, which are derived from the Royalty Assets and the Infrastructure Assets, depend upon a number of factors, most of which are outside of the Company's control. Such factors include: the petroleum production on the Royalty Assets; the timing and amount of capital expenditures directed or committed towards the development of the Royalty Assets and the operation of the Infrastructure Assets; the counterparties' expertise, production practices and financial resources; the approval of other participants or third-party customers as the case may be; the selection of technology; risk management; and environmental compliance and remediation practices. For instance, Tourmaline manages and participates in a wide variety of projects in the conduct of its business, which may result in it diverting capital, development activity and expertise away from the Tourmaline GORR Lands. The deferral of development or capital projects conducted on the Tourmaline GORR Lands may delay or diminish expected royalty revenue. Further, the ability of Tourmaline to execute projects and market oil and natural gas from the Tourmaline GORR Lands depends upon numerous factors beyond the Company's control. Because of these factors, Tourmaline may be unable to execute projects on the Tourmaline GORR Lands on time, on budget, or at all, and may be unable to produce and market the oil and natural gas from the Tourmaline GORR Lands effectively, all of which would result in a reduction of the royalty revenue.

In addition, the Company's royalty and energy infrastructure operations rely on revenue from its counterparties under a number of contractual arrangements described elsewhere in the prospectus under the heading "Agreements with Tourmaline and Other Counterparties". There is a risk that the Company's counterparties may default under these agreements. Topaz cannot provide assurance that one or more counterparties will not default on their obligations to the Company or that such a default or defaults will not have a material adverse effect on the Company's operations, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of Topaz's counterparties, or other similar proceeding or liquidity constraint, might make it unlikely that Topaz would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such counterparties to reduce or curtail their future business operations, which could have a material adverse effect on the Company's business, financial condition and results of operations.

With respect to its Infrastructure Assets, the Company endeavors to minimize risk wherever possible by structuring its contracts in a way that minimizes volume risk (e.g. minimum guaranteed volumes and "take-or-pay" arrangements), however, it is possible that such arrangements may not be fully effective. In addition, the contract terms are finite and in some cases the agreements contain termination or suspension rights for the benefit of the counterparty.

Certain of Topaz's assets with revenues under contracts will be subject to re-contracting risk in the future. The Company cannot provide assurance that it will be able to renegotiate these contracts once their terms expire or, even if the Company is able to do so, that it will be able to obtain the same prices or terms the Company currently receives. If the Company is unable to renegotiate these contracts, or unable to receive prices at least equal to the current prices it receives, the Company's business, financial condition, results of operation and prospects could be adversely affected.

The Company is dependent on its counterparties for the cash flow it receives and this cash flow is primarily derived from the performance of the underlying businesses of the counterparties. The amount of funds received from the Company's counterparties depends upon the amount of cash they in turn generate from their operations, which will fluctuate from time to time based on, among other things: production levels; prevailing commodity prices; the levels of operating, capital and maintenance expenses and general and administrative expenses; and prevailing economic conditions.

Counterparty Credit Risk

The Company is exposed to counterparty credit risk through its ownership of the Royalty Assets and Infrastructure Assets. In the event that any counterparty fails to meet their royalty, contractual or financial obligations to the Company, such failures could materially adversely affect the Company's business and financial condition. Further, poor credit conditions may impact a counterparty's ability to fund the development and capital programs conducted with respect to the Royalty Assets or fulfill its contractual or financial obligations with respect to the Infrastructure Assets, which in turn could result in a reduction of the Company's revenues.

Prices, Markets and Demand for Petroleum Products

Numerous factors beyond the Company's control affect the marketability and price of crude oil and natural gas produced from the Royalty Assets and processed through the Infrastructure Assets.

Prices for crude oil and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for petroleum and natural gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include economic conditions in the United States, Canada, Asia and Europe, the actions of OPEC, governmental regulation, political stability in the Middle East, Northern Africa and elsewhere, the foreign supply of petroleum and natural gas, risks of supply disruption, the price of foreign imports and the availability of alternative fuel sources. Prices for crude oil and natural gas are also subject to the availability of foreign markets and the Company's (and other industry participants') ability to access such markets. For instance, during the first quarter of 2020, OPEC and Russia failed to agree on a plan to cut production of oil and related commodities. Subsequently, Saudi Arabia announced plans to increase production and reduce the prices at which they sell oil. In response to the oversupply of crude oil caused by COVID-19 and the actions of OPEC, Saudi Arabia and Russia, certain state regulators in the U.S. are considering prorating production of hydrocarbons. These events, combined with the outbreak of COVID-19 that has reduced economic activity and the related demand for oil, have contributed to a sharp drop in prices for crude oil, natural gas and NGL in the first half of 2020.

A material decline in prices or a continued low crude oil and natural gas price environment could result in a reduction of the Company's anticipated royalty revenue associated with the Royalty Assets or processing revenue associated with the Infrastructure Assets.

All of these factors could result in a material decrease in the Company's expected royalty and processing revenue and a reduction in future petroleum and natural gas development and acquisition activities. Any substantial and extended decline in or continued low crude oil and natural gas prices would have an adverse effect on the Company's carrying value of its reserves, borrowing capacity, revenues, profitability and cash flows and may have a material adverse effect on the Company's business and financial condition.

Crude oil and natural gas prices are expected to remain volatile in the near future due to market uncertainties over the supply of and the demand for these commodities due to the current state of the world economies, OPEC actions, sanctions imposed on certain oil producing nations by other countries and ongoing credit and liquidity concerns. Volatile crude oil and natural gas prices make it difficult to estimate the value of producing properties for development activities and often cause disruption in the acquisition, divestiture or leasing of petroleum and natural gas producing properties, as buyers, sellers, lessors and lessees have difficulty agreeing on the value or terms of such arrangements. Price volatility also makes it difficult to budget for and project the return on potential acquisitions, divestitures and leasing opportunities.

The future growth and development prospects of the Company's royalty and energy infrastructure business is based in large part on assumptions about the future availability and price of petroleum products and, in particular, natural gas. Natural gas prices have at various times been and may become volatile due to one or more of the following factors: insufficient supply or oversupply of natural gas; weather conditions and natural disasters; reduced demand for natural gas; decreased oil and natural gas exploration activities, which may decrease the production and increase the price of natural gas; changes in supplies of, and prices for, alternative energy sources such as coal, oil, hydrogen, nuclear, hydroelectric, biomass, wind and solar energy, which may reduce the demand for natural gas; changes in regulatory, tax or other governmental policies regarding, natural gas or alternative energy sources, which may reduce the demand for natural gas; and political conditions in natural gas producing regions.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas and technological advances in fuel economy and renewable energy generation devices could reduce the demand for oil, natural gas and liquid hydrocarbons. Recently, certain jurisdictions have implemented policies or incentives to decrease the use of fossil fuels and encourage the use of renewable fuel alternatives and other alternative technologies, which may lessen the demand for petroleum products and put downward pressure on commodity prices. In addition, advancements in energy efficient products have a similar effect on the demand for oil and natural gas products. The Company cannot predict the impact of changing demand for 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 flow by decreasing the Company's profitability, increasing its costs, limiting its access to capital and decreasing the value of its assets.

Risks Relating to Acquisitions and Competition for Acquisition Opportunities

A key part of Topaz's business strategy involves seeking acquisition opportunities. The Company's ability to grow depends in part on its ability to make acquisitions that increase its free cash flow. The acquisition component of the Company's growth strategy is based, in large part, on its expectation of ongoing acquisitions from industry participants, including Tourmaline. While Management believes Tourmaline is incentivized through its ownership of Common Shares to offer Topaz the opportunity to acquire additional royalty interests and infrastructure assets should Tourmaline choose to sell such assets, there can be no assurance that any such offer will be made, and there can be no assurance that Topaz and Tourmaline will reach agreement on the terms with respect to any acquisition opportunities that may be offered to the Company by Tourmaline or that the Company will be able to obtain financing for such acquisition opportunities. Furthermore, many factors could impair the Company's access to future acquisitions, including a change in control of Tourmaline or a reduction in its ownership interest in the Company including through sales of its Common Shares to the public or to a third-party. A material decrease in the sale of assets by Tourmaline or by third parties would limit the Company's opportunities for future acquisitions and could materially adversely affect its business, results of operations, financial condition and ability to pay dividends to shareholders. See "Risks Relating to the Company's Relationship with Tourmaline — Future Changes in Relationship with Tourmaline" and "— Competition from Tourmaline ".

Topaz has recently completed a number of acquisitions to establish its business and achieve a variety of benefits including increasing the scale, scope and diversity of the Company's operations. Achieving the benefits of such acquisitions depends in part on successfully consolidating functions and integrating operations, procedures and personnel in a timely and efficient manner, as well as Topaz's ability to realize the anticipated growth and development opportunities from the assets underlying such acquisitions. Acquisitions involve a number of other risks that may adversely affect Topaz's ability to achieve the anticipated benefits of such acquisitions, including: diversion of Management's attention; disruption to the Company's ongoing business; failure to retain key acquired personnel; difficulties in integrating acquired operations or personnel; unanticipated expenses, events or circumstances; and the assumption of disclosed and undisclosed liabilities.

While it is the Company's practice to conduct extensive due diligence investigations into businesses being acquired, it is possible that due diligence may fail to uncover all material risks in the business being acquired, or to identify a change of control trigger in a material contract or authorization, or that a contractual counterparty or government agency may take a different view on the interpretation of such a provision to that taken by the Company, thereby resulting in a dispute. The discovery of any material liabilities subsequent to an acquisition, as well as the failure of an acquisition to perform according to expectations, could have a material adverse effect on the Company's business, financial condition and results of operations. In addition, if returns are lower than anticipated from acquisitions, the Company may not be able to achieve growth in its dividends in line with the Company's stated goals and the market value of the Common Shares may decline.

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. The Company may also enter into other industry related activities or new geographical areas or acquire different energy-related assets that may result in unexpected or significantly increased risk to the Company, which could materially adversely affect the Company's business and financial condition. Additionally, Management will continually assess the value and contribution of the various assets within its portfolio. In this regard, certain assets may be periodically disposed of so the Company can focus its efforts and resources more efficiently. Depending on the state of the market for such assets, certain assets of the Company, if disposed of, may realize less than what the market may expect for such disposition or their carrying value on the financial statements of the Company.

The Company's acquisition strategy is dependent to a significant extent on the ability of the Company to identify suitable acquisition opportunities. Topaz faces competition for acquisitions primarily from other royalty and energy infrastructure companies, investment funds, operating companies acting as strategic buyers, commercial and investment banks, and commercial finance companies. Many of these competitors are substantially larger and have considerably greater financial, technical and marketing resources than are available to the Company. Some of these competitors may also have higher risk tolerances or different risk assessments, which could allow them to consider a wider variety of acquisitions and to offer terms that the Company is unable or unwilling to match. Due to the capital intensive nature of royalty and energy infrastructure acquisitions, in order to finance acquisitions the Company will need to compete for equity capital from institutional investors and other equity providers, and Topaz's ability to consummate acquisitions will be dependent on such capital continuing to be available. Increases in interest rates could also make it more difficult to consummate acquisitions because the Company's competitors may have a lower cost of capital which may enable them to bid higher prices for assets. These factors may create competitive disadvantages for the Company with respect to acquisition opportunities.

The Company cannot provide any assurance that the competitive pressures it faces will not have a material adverse effect on the Company's business, financial condition and results of operations or that Management will be able to identify and make acquisitions on its behalf that are consistent with the Company's objectives or that generate attractive returns for shareholders. The Company may lose acquisition opportunities if it does not match prices, structures and terms offered by competitors, if it is unable to access sources of equity or obtain indebtedness at attractive rates or if the Company becomes subject to antitrust or competition laws. Alternatively, Topaz may experience decreased rates of return and increased risks of loss if it match prices, structures and terms offered by competitors.

The Company's acquisitions, dispositions and other transactions are subject to a number of closing conditions, including, as applicable, security holder approval, regulatory approval (including competition authorities) and other third-party consents and approvals that are beyond its control and may not be satisfied. Consents and approvals may not be obtained, may be obtained subject to conditions which adversely affect anticipated returns, and/or may be delayed, thereby delaying or ultimately precluded the completion of acquisitions, dispositions and other transactions.

Risks Arising from Co-ownership

The gas plants comprising part of the Infrastructure Assets are jointly owned with Tourmaline and, with respect to the Glacier Gas Plant, Advantage. Approvals must be obtained from such joint owners for proposals to make capital expenditures regarding such facilities. These approvals generally require that a capital expenditure proposal be approved by at least two owners holding a specified majority percentage of the ownership interests in the relevant facility. Accordingly, as a minority owner in the gas plants it is not possible for the Company to pursue proposals for capital expenditures without the approval of the majority co-owners, which may adversely affect the Company's ability to expand or improve the gas plants. In addition, the agreements for the ownership and operation of the gas plants contain rights of first refusal which require a transferor who is proposing to transfer an ownership interest, to offer such interest on the same commercial terms to the other owners of the facility prior to completing the transfer. Such provisions may restrict the Company's ability to transfer its interests in the gas plants and may limit the Company's ability to maximize the value of a sale of its interest.

As part of the Company's effort to minimize the risks associated with co-ownership, the Company maintains communication with its co-owners through its participation in operating committees and formal decision-making processes such as mail ballots and expenditure approvals. The Company also utilizes its knowledge of industry activity and relationships with other owners to mitigate the risk of uncooperative behaviour. However, there is no guarantee that the Company will be able to execute its preferred business or operational strategy at facilities which are jointly owned.

In addition, the gas plants are operated by third parties and, therefore, to the extent a third-party operator fails to perform its functions efficiently or becomes insolvent, the Company's business and operations may be adversely affected. Efforts to mitigate this risk by contracting with competent operators and negotiating appropriate allocation of risk in its contracts may not be effective. As a minority owner in the gas plants, the Company does not have the ability to unilaterally remove the operator.

Use of Proceeds May Differ from what is Set Out in the Prospectus

Management will have discretion in the actual application of the proceeds, and may elect to allocate proceeds differently from that described under the heading "Use of Proceeds" herein if it believes that it would be in the best interests of the Company to do so if circumstances change. The results and effectiveness of the application of the proceeds of the Offering are uncertain. The failure by Management to apply these funds effectively could have a material adverse effect on the business of the Company.

Internal Controls Re: Financial Reporting and Preventing Fraud

Effective internal controls are necessary for the Company to provide reliable financial reports and to help prevent fraud. Although the Company undertakes a number of procedures in order to help ensure the reliability of its financial reports, including those imposed on it under Canadian Securities Laws, 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 consolidated financial statements and adversely affect the trading price of the Common Shares.

Uninsured or Underinsured Losses

The Company will maintain insurance at levels that it believes are reasonable and that are typical for its industry's insurance coverage. However, the Company cannot give any assurances that its insurance coverage is adequate for any given risk or liability, that such insurance will continue to be available on commercially reasonable terms, that all events that could give rise to a loss or liability are insured or reasonably insurable or that its insurers would be capable of honouring their commitments if an unusually high number of claims were made against their policies. Certain losses, including certain environmental liabilities and business interruption losses, are not covered by insurance.

Management of Growth

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 properly manage growth may have a material adverse effect on the Company's business, financial condition, results of operations and prospects.

Natural Gas and NGL Composition

The gas plants comprising part of the Infrastructure Assets are designed to process raw natural gas feedstock within a certain range of composition specifications. The gas plants comprising the Infrastructure Assets may require modification to operate efficiently if the composition of the raw gas being processed changes significantly. The configuration of each of the Company's gas plants may not be optimal for efficient operation in the future if a change in inlet gas composition is outside a plant's acceptable range of composition specifications.

As a minority owner in the gas plants, the Company is largely reliant on its majority co-owner operators to monitor plant throughput, gas composition, third-party system performance and industry development activity in the capture areas surrounding the facilities. This information is used to assist with ongoing operational decisions, bringing on new production and new customers, evaluating expansion opportunities and assessing opportunities to modify or add new services to accept the inlet gas in the capture areas surrounding its facilities.

Decommissioning, Abandonment, and Reclamation Costs

Topaz is responsible for its proportionate share of the costs associated with decommissioning, abandonment and reclamation of the Infrastructure Assets (other than the facilities which generate the Other Income) at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they are a function of regulatory requirements at the time of decommissioning, abandonment and reclamation and the actual costs may exceed current estimates that are the basis of the asset retirement obligation shown in Topaz's financial statements.

General Economic, Market Risks and Political Conditions

Topaz's operations are affected by the condition and overall strength of the global economy and, in particular, the economies of Canada and the U.S. During economic downturns, the demand for the products and services that Topaz provides and the supply of or demand for natural gas, and NGL may be adversely affected. The occurrence of periods of poor economic conditions or low or negative economic growth could have an adverse impact on Topaz's results and restrict Topaz's ability to make dividends to its shareholders. The Company's royalty and energy infrastructure business is, in part, dependent upon, and also correlated to, market risks and political conditions; in particular, adverse events in financial markets, which may have a profound effect on global or local economies. Some key impacts of general financial market turmoil include contraction in credit markets resulting in a widening of credit spreads, devaluations and enhanced volatility in global equity, commodity and foreign exchange markets and a general lack of market liquidity. A slowdown in the financial markets or other key measures of the global economy or the local economies of the regions in which the Company operates (including, but not limited to, employment rates, business conditions, inflation, fuel and energy costs, commodity prices, lack of available credit, the state of the financial markets, interest rates and tax rates) may adversely affect the Company's growth and profitability. For instance, a credit/liquidity crisis, such as the global crisis experienced in 2008/2009, could materially impact the cost and availability of financing and overall liquidity; the volatility of commodity output prices and currency exchange markets could materially impact revenues, profits and cash flow; volatile energy, commodity input and consumables prices and currency exchange rates could materially impact production costs; and the devaluation and volatility of global stock markets could materially impact the valuation of the Common Shares.

In addition, political changes in North America, including resulting from the upcoming Presidential election in the United States scheduled to be held in November, 2020 and a potential upcoming federal election in Canada, and political instability in the Middle East and elsewhere may cause disruptions in the supply of oil and natural gas that affects the marketability and price of oil and natural gas. Conflicts, or, conversely, peaceful developments, arising outside of Canada, including changes in political regimes or parties in power, may have a significant impact on the price of oil and natural gas. It is unclear exactly what other actions the current U.S. administration or any new 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 or any new 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. 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 the balance between economic development and environmental policy.

The oil and natural gas industry has become an increasingly politically polarizing topic in Canada, which has resulted in a rise in civil disobedience surrounding oil and natural gas development—particularly with respect to infrastructure projects. Protests, blockades and demonstrations have the potential to delay and disrupt the Company's activities, as well as activities that it is indirectly involved in. See "Industry Conditions – Transportation Constraints and Market Access – Natural Gas".

Non-Governmental Organizations and Eco-Terrorism Risks

The oil and natural gas production and processing 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 project costs, delays or even project

cancellations due to increased pressure on governments and regulators by special interest groups including Indigenous and climate change 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, and delays in, challenges to, or the revocation of regulatory approvals, permits and/or licenses. 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 and its counterparties' oil and natural gas properties, wells and facilities could be the subject of a terrorist attack. If any of the Company's or its counterparties' 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.

Reputational Risks

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 licences 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. In particular, the Company's reputation could be impacted by negative publicity related to environmental damage, loss of life, injury or damage to property caused by the Company's operations or due to opposition from special interest groups opposed to oil and natural gas development. 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.

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 of the Company's securities.

Changing Investor Sentiment

A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, the impact of oil and natural gas operations on the environment, environmental damage relating to spills of petroleum products during transportation and Indigenous rights, have affected certain investors' sentiments towards investing in the oil and natural gas industry. As a result of these concerns, some institutional, retail and public investors have announced that they no longer are willing to fund or invest in oil and 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 environmental, social and governance policies and practices. Developing and implementing such policies and practices can involve significant costs and require a significant time commitment from the Board, Management and employees of the Company. Failing to implement such 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 of the Company's securities even if the Company's operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause a decrease in the value of the Company's assets, which may result in an impairment change.

Occupational Health and Safety and Accident Risks

The Royalty Assets and the Infrastructure Assets are highly exposed to the risk of accidents that may give rise to personal injury, loss of life, disruption to service and economic loss. Some of the tasks undertaken by employees and contractors are inherently dangerous and have the potential to result in serious injury or death.

The Company is subject to laws and regulations governing health and safety matters, protecting both members of the public and their employees and contractors. Occupational health and safety legislation and regulations differ in each jurisdiction. Any breach of these obligations, or serious accidents involving the Company's employees, contractors or members of the public could expose the Company to adverse regulatory consequences, including the forfeit or suspension of operating licences, potential litigation, claims for material financial compensation, reputational damage, fines or other legislative sanction, all of which have the potential to impact the Company's financial results and its ability to pay dividends. Furthermore, as the Company is not the operator of the Royalty Assets and Infrastructure Assets, Topaz has a limited ability to influence health and safety practices and outcomes which may involve drilling hazards, environmental damage and various field operating conditions, including, delays in obtaining governmental approvals or consents, 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 a counterparty's production from the GORR Lands, which may reduce the Company's revenue.

Reserves Estimates

There are numerous uncertainties inherent in estimating quantities of oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserves and associated cash flow information set forth in this prospectus are estimates only. Generally, estimates of economically recoverable crude oil, natural gas and NGL 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 reserve recovery; timing and amount of capital expenditures by the working interest owners thereon; marketability of oil and natural gas; royalty rates (which, in the case of the Company, generally consist of the royalties to be paid to the Company); and the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially from actual results.

For those reasons, estimates of the economically recoverable crude oil, natural gas and NGL 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 engineers, or by the same engineers at different times, may vary. The Company's actual net production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

The estimation of proved reserves that may be developed and produced in the future is 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 formations. 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 Canadian Securities Laws, GLJ, the Company's independent qualified reserves evaluator, has used forecast prices and costs in estimating the reserves and future net cash flows as summarized in this prospectus. 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 crude oil, natural gas and NGL reserves contained in the Tourmaline GORR Lands will vary from the estimates contained in the Topaz Reserve Report, and such variations could be material. The reserves evaluation is based in part on the assumed success of activities undertaken on the Tourmaline GORR Lands in future years. The reserves and estimated cash flows to be derived therefrom and contained in the Topaz Reserve Report will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluation. The Topaz Reserve Report is effective as of December 31, 2019 with a preparation date of March 2, 2020 and, except as may be specifically stated or required by Canadian Securities Laws, has not been updated and thus does not reflect changes in the reserves acquired pursuant to the Initial Acquisition since that date.

Gathering and Processing Facilities and Pipeline Systems

The products produced from the GORR Lands must be delivered through gathering, processing and pipeline systems such as the Company's Infrastructure Assets. The amount of petroleum and natural gas produced and sold from the GORR Lands is subject to the accessibility, availability, proximity and capacity of these gathering, processing and pipeline systems. The lack of availability of capacity in any of the gathering, processing and pipeline systems, and in particular the processing facilities, including any restrictions placed on such systems or facilities, could result in an inability to realize the full economic potential of the GORR Lands. Although pipeline expansions are ongoing, the lack of firm pipeline capacity continues to affect the oil and natural gas industry and limit the ability to produce and to market petroleum and natural gas production. In addition, the pro-rationing of capacity on interprovincial pipeline systems also continues to affect the ability to export petroleum and natural gas. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, including remedial work on certain pipeline sections, as well as any delays in constructing new infrastructure systems and facilities, could harm the ability to develop and produce from the GORR Lands and, in turn, the Company's business and financial condition.

The production from the GORR Lands will be processed through facilities over which the Company will have no control. From time to time, these facilities may discontinue or decrease operations either as a result of normal servicing requirements or as a result of unexpected events. A discontinuation or decrease of operations could materially adversely affect the ability of third parties to process production from the GORR Lands and to deliver the same for sale, which, in turn, would indirectly reduce the Company's revenues.

For any royalty payments taken-in-kind by the Company, the ability of the Company or a third-party marketer (including Tourmaline) to successfully market in-kind petroleum and natural gas products may depend, in part, on the Company's or the third-party marketer's ability to acquire space on pipelines that deliver petroleum and natural gas to commercial markets. Deliverability uncertainties related to the distance the Company's reserves are to pipelines, processing and storage facilities, operational problems affecting pipelines and facilities, as well as government regulation relating to prices, taxes, royalties, land tenure, allowable production, the export of petroleum and natural gas and other aspects of the oil and natural gas industry may also affect the Company.

Force Majeure Events

The Company's operations and information systems may be vulnerable to substantial loss or damage as a result of certain disruptions, including natural disasters, national emergencies, acts of war, acts of terrorism, technological attacks, domestic and global trade disruptions, infrastructure disruptions, civil disobedience or unrest, and the outbreak of disease (such as COVID-19) or similar events, any of which may have a material adverse effect on Topaz's reputation, business, financial conditions or operating results.

Reliance on Key Personnel

The Company's success depends in large measure on certain key personnel. The loss of the services of such key personnel may have a material adverse effect on the Company's business and financial condition. The Company does not intend to have any key person insurance in effect for the Company on Closing. In addition, the competition for qualified personnel in Alberta, and, in particular, 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. Investors must rely upon the ability, expertise, judgment, discretion, integrity and good faith of Management.

Title to Assets

Title reviews conducted on petroleum and natural gas producing properties, if any, do not guarantee or certify that an unforeseen defect in the chain of title will not arise to defeat the Company's claim. The actual interest of the Company in the Royalty Assets may vary from the records previously maintained by a counterparty. 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 could materially adversely affect the Company's business and financial condition. There may be valid challenges to title, or proposed legislative changes which affect title, to the Royalty Assets that, if successful or made into law, could result in a reduction of the revenue received by the Company.

Capital and Additional Funding Requirements

The Company's cash flow from the Royalty Assets and the Infrastructure Assets may not be sufficient to fund its ongoing activities at all times, and from time to time the Company may require additional financing, which may include making capital expenditures for the acquisition of additional royalty and energy infrastructure assets. Future capital and other expenditures will be financed out of cash flow, borrowings and possible future equity issuances, and the Company's ability to do so will be dependent on, among other factors: the overall state of the capital markets; the Company's credit rating (if applicable); interest rates; tax burden due to current and future tax laws; and investor appetite for investments in the royalty and energy infrastructure industry and the Company's securities in particular. The Company's ability to finance through future equity issuances may also be affected by any future sales of Common Shares by Tourmaline.

There can be no assurance that debt or equity financing, or cash flow generated by operations, will be available or sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable to the Company. There is risk that if the economy and banking industry experienced unexpected and/or prolonged deterioration, the Company's access to additional financing may be affected. The inability of the Company to access sufficient capital for its operations could materially adversely affect the Company's financial condition.

In addition, the future development of the Royalty Assets and the operation of the Infrastructure Assets may require additional financing from the Company's counterparties and there are no assurances that such financing will be available, or, if available, will be available upon acceptable terms to the counterparties. For instance, failure to obtain any financing necessary for such counterparties' capital expenditure plans may result in a delay in development of the Royalty Assets.

Equity Dilution

The Company may make future acquisitions or enter into financings or other transactions involving the issuance of securities of the Company, which may be dilutive to existing shareholders. There are no restrictions in the Company's articles or bylaws with respect to the number of shares of any class that may be issued by the Company.

Issuance of Debt

From time to time, the Company may finance its activities (including potential future petroleum and natural gas asset acquisitions) in whole or in part with debt, which may increase the Company's debt levels above industry standards for peers of similar size. Additional debt financing 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.

Credit Facility Arrangements

The Company is required to comply with customary positive and negative covenants under the Credit Facility and, in the event that the Company does not comply with these covenants, the Company's access to capital could be restricted or repayment could be required. Events beyond the Company's control may contribute to the failure of the Company to comply with such covenants. A failure to comply with any of the covenants could result in an event of default which, if not cured or waived, would permit acceleration of the indebtedness pursuant to the Credit Facility and would prevent dividends from being paid to shareholders. The acceleration of the Company's indebtedness under the Credit Facility may permit acceleration of indebtedness under other agreements that contain cross default or cross-acceleration provisions. In addition, the Credit Facility imposes certain operating and financial restrictions on the Company that include restrictions on the payment of dividends, limitations on liens, entering into disposition of assets or amalgamations and restrictions on speculative hedging, among others. Even if the Company is able to obtain new financing, it may not be on commercially reasonable terms or terms that are acceptable to the Company.

Variations in Foreign Exchange Rates and Interest Rates

The Canadian/United States dollar exchange rate, which fluctuates over time, could affect the price received by Canadian producers of oil and natural gas. Material increases in the value of the Canadian dollar may indirectly affect the Company's revenues, as revenues received by Canadian producers and, similarly, royalties payable to the Company could decrease. Future variations in Canadian/United States exchange rates may accordingly affect the future value of the Company's reserves as determined by independent evaluators.

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 activities and the cash available to pay dividends, and could negatively impact the market price of the Common Shares.

Hedging

From time to time, the Company may enter into hedging arrangements to fix interest rates applicable to the Company's debt. However, if interest rates decrease as compared to the interest rate fixed by the Company, the Company will not benefit from the lower interest rate. Similarly, from time to time the Company may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar. However, if the Canadian dollar declines in value compared to the United States dollar, the Company will not benefit from the lower exchange rate.

In addition, the Company may enter into agreements to fix the commodity prices for any of its take-in-kind royalty volumes in order to offset the risk of revenue losses if the prices for crude oil or natural gas decline compared to the current levels. However, if commodity prices increase compared to the prices fixed by the Company, the Company will not benefit from such higher prices.

Litigation and Indigenous Claims

In the normal course of the Company's activities, 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 property damage, property tax, land rights, the environment and lease and contract disputes. The outcome of outstanding, pending or future proceedings cannot be predicted with certainty, such proceedings may be determined adversely to the Company and any indemnity from Tourmaline or other third parties in respect of any loss suffered by the Company as a result of such proceedings may not be sufficient, and, as a result, could materially adversely affect the Company's business and financial condition.

Indigenous peoples have claimed aboriginal title and rights to portions of Western Canada, including in the provinces of Alberta and British Columbia. If such claims arise in relation to the GORR Lands, and if such claims are successful, it could materially adversely affect the Company's business and financial condition.

Income Taxes

Income tax laws relating to the oil and natural gas industry 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.

The Company will file all required income tax returns in order to be 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, such reassessment may have an impact on current and deferred taxes payable.

Conflicts of Interest

Certain members of the Board and Management are also, or may in the future be, directors or officers of other oil and natural gas companies, including Tourmaline, that may compete or be counterparties to agreements with the Company, 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 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 disclose his or her interest in 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 "Directors and Executive Officers — Conflicts of Interest" and "Risk Factors — Risks Relating to the Company's Relationship with Tourmaline".

Regulatory

Various levels of governments impose extensive controls and regulations on oil and natural gas operations, including on exploration, production, pricing, marketing and transportation. Governments may regulate or intervene with respect to exploration and production activities, prices, taxes, royalties and the exportation of petroleum and natural gas. Amendments to these controls and regulations, including potential expropriation of fee simple mineral title lands and changes to royalty regimes may occur from time to time in response to economic or political conditions. See "The Industry". The implementation of new regulations or the modification of existing regulations affecting the oil and natural gas industry could reduce demand for oil and natural gas or make certain projects on the Company's properties uneconomic, which could materially adversely affect the Company's business and financial condition.

Availability of Drilling Equipment and Access

Oil and natural gas exploration and development activities are dependent on the availability of drilling and related equipment (typically leased from third parties) in the particular areas where such activities will be conducted. Demand for such limited equipment or access restrictions may affect the availability of such equipment for the counterparties operating on the GORR Lands and may delay such exploration and development activities, which, in turn, could materially adversely affect the Company's business and financial condition.

Breach of Confidentiality

While discussing potential business relationships or other transactions with third parties, the Company may disclose confidential information relating to the business, operations or affairs of the Company. Although confidentiality agreements are signed by third parties prior to the disclosure of any confidential information, a breach could put the Company at competitive risk and may cause significant damage to its business. The harm to the Company's business from a breach of confidentiality cannot presently be quantified, but may be material and may not be compensable in damages. There is no assurance that, in the event of a breach of confidentiality, the Company will be able to obtain equitable remedies, such as injunctive relief, from a court of competent jurisdiction in a timely manner, if at all, in order to prevent or mitigate any damage to its business that such a breach of confidentiality may cause.

Environmental

All phases of the oil and natural gas and related infrastructure business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, provincial and local laws and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.

As a royalty interest holder, the Company believes it will have no direct exposure to environmental claims and regulation and the associated costs in connection with the GORR Lands. However, such matters will directly impact the working interest owners and/or operators of the GORR Lands. As a working interest owner in the gas plants comprising a portion of the Infrastructure Assets, the Company is exposed to environmental claims and regulation and the associated costs in connection with such assets. Compliance with environmental legislation can require significant expenditures and a breach of applicable environmental legislation may result in the imposition of fines and penalties on the working interest owners or operators of the GORR Lands or on the Company and its co-owners in respect of the Infrastructure Assets, 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 Company will rely on the working interest owners or operators of the GORR Lands and the operators of the gas plants comprising part of the Infrastructure Assets to be in material compliance with current applicable environmental regulations; however, no assurance can be given that environmental laws will not result in a curtailment of production or processing or a material increase in the costs of production, development or exploration activities associated with the GORR Lands or in the cost of operation of the gas plants comprising a portion of the Infrastructure Assets or otherwise have a material adverse effect on the Company's business and financial condition.

Global Climate Change

Over the past several years, changing weather patterns and climatic conditions, such as global warming, have added to the unpredictability and frequency of natural disasters in certain parts of the world, including the markets in which the Company operates and intends to operate, and have created additional uncertainty as to future trends. There is a growing consensus today that climate change increases the frequency and severity of extreme weather events and, in recent years, the frequency of major weather events appears to have increased. The Company cannot predict whether or to what extent damage that may be caused by natural events, such as severe storms, hurricanes and tornados, will affect the Company's operations or the economies in the Company's current or future market areas, but the increased frequency and severity of such weather events could increase the negative impacts to economic conditions in these regions and result in a decline in the value or the destruction of the Company's Infrastructure Assets. In particular, if one of the regions in which the Company's Infrastructure Assets are operating is impacted by such a natural catastrophe in the future, it could have a material adverse effect on the Company's business. Further, the economies of such impacted areas may require significant time to recover and there is no assurance that a full recovery will occur. Even the threat of a severe weather event could impact the Company's business, financial condition or the price of the Common Shares.

In addition, the Company expects continued and increasing legislative attention to climate change issues and the emission of GHG, including methane (a primary component of natural gas) and carbon dioxide (a by-product of oil and natural gas combustion). Climate change policy is evolving at national and international levels, and political and economic events may significantly affect the scope and timing of climate change measures that are ultimately put in place by governments around the world, including the jurisdictions in which the Company is active. Any such regulations could increase the cost of carrying out operations and the cost of consumption, thereby impacting Topaz's business financial condition or the price of the Common Shares.

Finally, political and legal opposition to the fossil fuel industry has historically focused on public opinion and the regulatory process. More recently, however, there has been a movement to more directly hold governments and oil and natural gas companies responsible for climate change through climate litigation. Litigants have received mixed success, but it is not possible for the Company to predict whether any climate change litigation will have an effect on its business and operations or those of its counterparties.

Hydraulic Fracturing

Hydraulic fracturing involves the injection of water, sand and certain amounts of additives under pressure into rock formations to stimulate petroleum and natural gas production. Specifically, hydraulic fracturing is used to produce commercial quantities of petroleum and natural gas from reservoirs that were previously unproductive or to make existing reservoirs more productive. 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 delay or eliminate the development of certain oil and natural gas resources which are not commercial without the use of hydraulic fracturing on the GORR Lands. Restrictions on hydraulic fracturing could also reduce the amount of petroleum and natural gas that is ultimately produced from the reserves associated with the GORR Lands and, therefore, could materially adversely affect the Company's business and financial condition.

Concentration of Assets in Alberta and British Columbia

All of Topaz's assets are currently concentrated in Alberta and British Columbia in the WCSB, which leaves the Company exposed to the economic conditions of such provinces.

Seasonality

The level of activity in the Canadian oil and natural gas industry is influenced by seasonal weather patterns. Wet weather and spring thaw may make the ground unstable. Consequently, municipalities and provincial transportation departments enforce road bans that restrict the movement of rigs and other heavy equipment, thereby potentially reducing activity levels on the GORR Lands. Additionally, certain oil and natural gas producing areas are located in areas that are inaccessible other than during the winter months because the ground surrounding the sites in these areas consists of swampy terrain. Seasonal factors and unexpected weather patterns may lead to declines in exploration and production activity and to volatility in commodity prices as the demand for natural gas rises during cold winter months and hot summer months.

Information Technology, Cyber-Attacks, Privacy and Data Protection

The Company relies on information technology systems and networks in its operations and the administration of its business. A failure of these information systems could lead to the impairment of business processes, and there is a risk of cascading failure of information systems leading to the impairment of multiple business processes. In addition, Topaz collects and stores sensitive information in the ordinary course of business, including personal information in respect of its employees and proprietary information in respect of its stakeholders, including customers, suppliers, and investors.

Security breaches of Topaz's information technology infrastructure, including, without limitation, cyber-attacks and cyberterrorism, or other failures of Topaz's information technology infrastructure could result in disruptions to operations and other operational outages, ability to operate safely, delays, damage to assets, the environment or to Topaz's reputation, diminished counterparty confidence, lost profits, lost data including, without limitation, the unauthorized release of customer, employee or company data that is crucial to Topaz's operational security or could adversely affect the ability to deliver and collect on customer bills, increased regulation and other adverse outcomes, including, without limitation, material legal claims and liability or fines or penalties under applicable laws and could adversely affect its business operations and financial results.

Topaz's cybersecurity strategy focuses on information technology security risk management which includes, without limitation, continuous monitoring, ongoing cybersecurity communications and training for staff, conducting third-party vulnerability and security tests, threat detection, and an incident response protocol. However, there is no assurance that Topaz will not suffer a cyber-attack or an information technology failure notwithstanding the implementation of this strategy and the measures taken pursuant to that strategy, including, without limitation, as set forth above and the occurrence of any of these cyber events could adversely affect Topaz's financial condition and results of operations.

The Company's business operations could be targeted by individuals or groups seeking to sabotage or disrupt its information technology systems and networks, or to steal data. A successful cyber-attack could materially disrupt the Company's operations, including the safety of its operations and the availability of its facilities, or lead to unauthorized release of information or alteration of information in the Company's systems. Any such attack or other breach of the Company's information technology systems could have a material adverse effect on the Company's business and results of operations. The Company is subject to laws, directives and regulations relating to the collection, use, retention, disclosure, security and transfer of personal data. These laws, directives, and regulations, and their interpretation and enforcement continue to evolve and may be inconsistent from jurisdiction to jurisdiction. Complying with emerging and changing privacy and data protection requirements may cause Topaz to incur substantial costs or require the Company to change its business practices. Noncompliance with the Company's legal obligations relating to privacy and data protection could result in penalties, fines, legal proceedings by governmental entities or others, loss of reputation, legal claims by individuals and customers and significant legal and financial exposure and could affect the Company's ability to retain and attract counterparties.

Changes in the nature of cyber-threats and/or changes to industry standards and regulations might require Topaz to adopt additional procedures for monitoring cybersecurity, which could require additional expenses and/or capital expenditures. However, the impact of such regulations is hard to predict at this time.

Technical Systems and Processes Incidents

Failure of key technical systems and processes to effectively support information requirements and business processes may lead to Topaz's inability to effectively and efficiently measure, record, access, analyze, and accurately report key data. This could result in increased costs and missed business opportunities.

Risks Relating to the Company's Relationship with Tourmaline

Tourmaline's Shareholdings and Provision of Management Services

Following Closing, Tourmaline will remain the majority shareholder of the Company and, as such, will be able to exert significant influence on the Company through its voting rights, including the right to vote for the election of directors to the Board. In addition, pursuant to the Governance Agreement, Tourmaline will have the right, in certain circumstances, to nominate directors for election to the Board and will have certain consent rights. As a result, Tourmaline will be able to exercise influence over the management, administration, strategy and growth of the Company.

Until December 31, 2020, unless terminated by either party on not less than three months notice, the Company will depend on Tourmaline to provide certain management and administrative services to the Company pursuant to the Management Services Agreement. Tourmaline personnel and support staff that provide services to the Company under the Management Services Agreement are not required to have as their primary responsibility the administration of the Company or to act exclusively for the Company and the Management Services Agreement does not require any specific individuals to be provided by Tourmaline. If the Company is not satisfied with the manner in which Tourmaline performs its services under the Management Services Agreement, it is only entitled to terminate such services upon three months written notice to Tourmaline. The failure of Tourmaline to exercise its influence or provide its services in a manner consistent with the views of the directors or Management could materially adversely affect the Company's business and financial condition.

Furthermore, Tourmaline has experienced departures of key employees in the past and this could also happen in the future, and the Company cannot predict the impact that any such departures will have on the Company's ability to achieve its objectives, particularly during the term of the Management Services Agreement. See "Risk Factors — Risks Relating to the Company's Business, Industry and Operating Environment — Reliance on Key Personnel".

Competition from Tourmaline

Tourmaline is not prohibited from engaging in other businesses or activities, including those that might be in direct competition with those of the Company. In addition, Tourmaline may compete with the Company for investment opportunities and may own an interest in entities that compete with Topaz. This may create actual and potential conflicts of interest between the Company and Tourmaline and result in less than favorable treatment of the Company and its shareholders. See "Conflicts of Interest with Tourmaline" below.

Conflicts of Interest with Tourmaline

The Management Services Agreement, the Governance Agreement and the Company's other arrangements with Tourmaline do not impose any duty on Tourmaline to act in the best interest of the Company, and, as mentioned above, Tourmaline is not prohibited from engaging in other business activities that may compete with those of the Company. The Company's ownership and management structure involves a number of relationships that may give rise to conflicts of interest between the Company and the shareholders, on the one hand, and Tourmaline, on the other hand. In certain instances, the interests of Tourmaline may differ from the interests of the Company and its shareholders, including with respect to the timing and amount of dividends paid by the Company, the reinvestment of returns generated by the Company's activities, future acquisitions or strategic decisions, Tourmaline's operations, if any, on the GORR Lands and the appointment of outside advisors and service providers. It is possible that conflicts of interest may arise between the Company and Tourmaline and that such conflicts may not be resolved in a manner that is in the best interests of the Company or its shareholders. See "Agreements with Tourmaline and Other Counterparties".

Under the Management Services Agreement, Tourmaline has not assumed any responsibility other than to perform its obligations and discharge its duties in the provision of the services under the Management Services Agreement as a reasonable and prudent manager (as defined in the Management Services Agreement). In addition, under the Management Services Agreement, the liability of Tourmaline is limited to liability arising directly from the gross negligence or wilful misconduct of Tourmaline or its affiliates and representatives, subject to certain exceptions. In addition, the Company has agreed to indemnify Tourmaline and its affiliates and representatives from and against any claims, liabilities, losses, damages, costs or expenses incurred arising out of, or attributable to, any act or omission of Tourmaline or the Company in connection with the provisions of the services described in the Management Services Agreement by Tourmaline, except to the extent that the claims, liabilities, losses, damages, costs or expenses are determined to have resulted from gross negligence or wilful misconduct of Tourmaline or its affiliates or representatives. The indemnification arrangements with the Company to which Tourmaline will be a party may also give rise to legal claims for indemnification that would be adverse to the Company and its shareholders.

In addition, pursuant to the Governance Agreement, Tourmaline has the right to nominate the greater of two and 33.33% of the members of the Board (rounded up to the next whole number, if applicable) for so long as the percentage of outstanding Common Shares (on a non-diluted basis) beneficially owned directly or indirectly by Tourmaline is not less than 10% of the issued and outstanding Common Shares. Following Closing, Tourmaline will hold •% of the issued and outstanding Common Shares (•% if the Over-Allotment Option is exercised in full), which will entitle Tourmaline to continue to nominate the greater of two and 33.33% of the members of the Board (rounded up to the next whole number, if applicable). The directors of the Company are required to act honestly and in good faith with a view to the best interests of the Company. However, directors nominated and subsequently appointed by a particular shareholder are entitled, under the ABCA, to give special, if not exclusive, consideration to the interests of the shareholder that appointed them. The interests of Tourmaline may conflict with those of other shareholders.

Departure of Tourmaline's Professionals

The Company relies on the diligence, skill and business contacts of Tourmaline's professionals and the information and opportunities they generate during the normal course of their activities. Topaz's future success will depend on the continued service of these individuals, who are not obligated to remain employed with Tourmaline. The departure of a significant number of Tourmaline's professionals for any reason, or the failure to appoint qualified or effective successors in the event of such departures, could have a material adverse effect on the Company's ability to achieve its objectives. The Management Services Agreement does not require Tourmaline to maintain the employment of any of its professionals or to cause any particular professionals to provide services to the Company or on its behalf.

Ability to Recover Indemnification from Tourmaline

As described under "Agreements with Tourmaline and Other Counterparties — Agreements Relating to the Initial Acquisition", Tourmaline has provided certain representations, warranties and indemnities regarding the Initial Assets. If the Company suffers any loss as a result of a breach of the representations, warranties or any other term of the Initial Acquisition Agreements by Tourmaline, or as a result of the occurrence of an event for which Tourmaline agreed to indemnify the Company under the terms of the Initial Acquisition Agreements, the Company may not be able to recover the amount of its loss from Tourmaline. Purchasers of Common Shares offered under this prospectus will not have a direct right of action against Tourmaline for a breach of the Initial Acquisition Agreements. The sole remedy of the shareholders against Tourmaline will be through the Company exercising its rights under the Initial Acquisition Agreements to claim for indemnification in respect of a breach by Tourmaline of the representations and warranties or agreements contained therein, subject to the limitations specified therein and as described under "Agreements with Tourmaline and Other Counterparties — Agreements Relating to the Initial Acquisition".

Future Changes in Relationship with Tourmaline

The arrangements between the Company and Tourmaline do not require Tourmaline to maintain any ownership level in the Company. Accordingly, Tourmaline may transfer all or a substantial portion of its interest in the Company to the public through secondary offerings (including pursuant to its rights under the Investor Liquidity Agreement; see "Agreements with Tourmaline and Other Counterparties — Investor Liquidity Agreement"), or to a third-party, including in a merger or consolidation or sale of Common Shares (without the consent of the Company or its shareholders) subject to market conditions, Tourmaline's requirements for capital or other circumstances that may arise in the future. Certain of the rights and obligations under the Governance Agreement, as described under "Agreements with Tourmaline and Other Counterparties – Governance Agreement", may also be assignable to a transferee of the Common Shares (other than in respect of transfers made pursuant to a public offering), upon notice to the Company. Accordingly, there can be no assurance as to who may hold and exercise such rights in the future. The interests of a transferee of the Common Shares may be different from Tourmaline's and may not align with those of other shareholders. The Company cannot predict with any certainty the effect that any such transfer would have on the trading price of the Common Shares or the Company's ability to raise capital in the future. As a result, the future of the Company would be uncertain and the Company's business and financial condition may suffer.

For the year ended December 31, 2019, all of the Company's total revenue was derived from the Initial Assets. See also the supplemental production, oil and gas reserves and operational information in respect of the Tourmaline GORR Lands in Appendix "B".

Risks Relating to the Offering and Common Shares

Absence of Public Market for the Common Shares

Prior to the Offering, no public market existed for the Common Shares. An active and liquid market for the Common Shares may not develop following Closing or, if developed, may not be maintained. If an active public market does not develop or is not maintained, investors may have difficulty selling their Common Shares.

The Offering Price was determined by negotiation between Tourmaline and the Company, on the one hand, and the Underwriters, on the other hand, and may not be indicative of the price at which the Common Shares will trade following Closing. The market price of the Common Shares may materially decline below the Offering Price.

Volatility in Market Price of Common Shares

The market price for the Common Shares may be volatile and subject to wide fluctuations in response to numerous factors, many of which are beyond the Company's control, including, without limitation: (i) actual or anticipated fluctuations in the Company's financial results; (ii) recommendations by securities research analysts; (iii) changes in the economic performance or market valuations of other companies that investors deem comparable to the Company; (iv) the loss or resignation of members of Management or the Board and other key personnel of the Company; (v) sales or perceived sales of additional Common Shares; (vi) significant acquisitions or business combinations, strategic partnerships, joint ventures or capital commitments by or involving the Company, Tourmaline or its competitors where the Company does not realize its anticipated benefits from such transaction; (vii) trends, concerns, technological or competitive developments, regulatory changes and other related issues in the oil and natural gas industry; and (viii) actual or anticipated fluctuations in interest rates.

Financial markets have experienced significant price and volume fluctuations in recent years that have particularly affected the market prices of equity securities of companies and that have, in many cases, been unrelated to the operating performance, underlying asset values or prospects of such companies. Accordingly, the market price of the Common Shares may decline even if the Company's operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause decreases in asset values which may result in impairment losses. Certain institutional investors may base their investment decisions on consideration of the Company's ESG practices and performance against such institutions' respective investment guidelines and criteria, and failure to meet such criteria may result in a limited or no investment in the Common Shares by those institutions, which could adversely affect the trading price of the Common Shares.

Cash Dividend Payments are Not Guaranteed

The payment of dividends under the Company's dividend policy is not guaranteed and could fluctuate with the performance of the Company. The Board has the discretion to determine the amount of dividends, if any, to be declared and paid to shareholders. The Company may alter its dividend policy at any time and the payment of dividends will depend on, among other things, changes in commodity prices; financial condition; current and expected future levels of earnings; liquidity requirements; market opportunities; income taxes; debt repayments; legal, regulatory and contractual constraints; tax laws; and other relevant factors. The Credit Facility, or certain other financial instruments which the Company may enter into from time to time, may prohibit the Company from paying dividends at any time at which a default or event of default has occurred and is continuing, or if a default or event of default would exist as a result of paying the dividend.

Over time, the Company's capital and other cash needs may change significantly from its current needs, which could affect whether the Company pays dividends and the amount of dividends, if any, it may pay in the future. If the Company pays dividends at the level currently anticipated under the dividend policy, it may not retain a sufficient amount of cash to finance external growth opportunities, meet any large unanticipated liquidity requirements or fund its activities in the event of a significant business downturn. The Board may amend, revoke or suspend the Company's dividend policy at any time. A decline in the market price or liquidity, or both, of the Common Shares could result if the Company reduces or eliminates the payment of dividends, which could result in losses to shareholders.

Negative Impact of Additional Sales or Issuances of Common Shares

Tourmaline may sell additional Common Shares from time to time, including pursuant to the Investor Liquidity Agreement, and is not required to consider the potential negative impact of such sales on the trading price of the Common Shares or the Company in general. Immediately upon completion of the Offering, Tourmaline will hold •% of the issued and outstanding Common Shares (•% if the Over-Allotment Option is exercised in full). The Investor Liquidity Agreement provides for Demand Registration rights in favour of Tourmaline that enable Tourmaline to require the Company to qualify by prospectus or register, as applicable, all or a portion of the Common Shares held, directly and indirectly, by Tourmaline for a distribution to the public in Canada. The Investor Liquidity Agreement also provides Tourmaline with the Piggy-Back Registration rights. Where the Company proposes to make a distribution, for its own account or for the account of any other holder of securities of the Company, Tourmaline will have the right to include a specified number of its Common Shares in the distribution, subject to certain limitations. Sales of Common Shares owned, directly and indirectly, by Tourmaline through the Investor Liquidity Agreement or otherwise could exert downwards pressure on the trading price of the Common Shares and could impair the future ability of the Company to raise capital through the sale of its equity securities.

Additionally, the Board may issue an unlimited number of Common Shares without any vote or action by the shareholders, subject to the rules of any stock exchange on which the Company's securities may be listed from time to time. The Company may make future acquisitions or enter into financings or other transactions involving the issuance of securities. If the Company issues any additional equity, the percentage ownership of existing shareholders will be reduced and diluted and the price of the Common Shares could decline.

A Purchaser of the Common Shares under the Offering will do so at a Substantial Premium to Book Value per Common Share

The Offering Price of $• per Common Share will be substantially higher than the book value per share of the Common Shares issued prior to Closing. As a result, purchasers of Common Shares pursuant to the Offering will experience immediate dilution. In addition, future equity issuances may result in further dilution to investors.

Increased Costs of Being a Publicly Traded Company

As the Company will have publicly-traded securities, there will be significant legal, accounting, annual sustaining and filing fees to be incurred that are not presently being incurred. Canadian Securities Laws and the rules and policies of the Exchange require publicly listed companies to, among other things, adopt corporate governance policies and related practices and to continuously prepare and disclose material information, all of which will significantly increase legal, financial and securities regulatory compliance costs.

Foreign Exchange Risk on Dividends

The Company's cash dividends will be declared in Canadian dollars and may be converted in certain instances to foreign denominated currencies at the spot exchange rate at the time of payment. As a consequence, non-resident shareholders, and shareholders who calculate their return in currencies other than the Canadian dollar, will be subject to foreign exchange risk. To the extent that the Canadian dollar strengthens with respect to their currency, the amount of the dividend will be reduced when converted to their home currency.

EXEMPTIONS FROM CERTAIN DISCLOSURE REQUIREMENTS

Pursuant to an application (the "Application") made to the Alberta Securities Commission (the "ASC"), as principal regulator on behalf of the securities regulatory authorities in the other provinces of Canada (other than Ontario), and to the Ontario Securities Commission, the Company has applied for exemptive relief (the "Exemptive Relief") as contemplated by Item 19 of NI 41-101 and Item 31 of Form 41-101F1 from the requirements in Item 32 of Form 41-101F1 to include the following historical financial statements in this prospectus:

(a) audited annual financial statements of the Company (Exshaw Oil Corp. prior to November 8, 2019) consisting of the statements of financial position as at December 31, 2019 and 2018, and the statements of comprehensive income, changes in equity and cash flows for the three years ended December 31, 2019, 2018 and 2017, and notes thereto in accordance with Subsection 32.2(1) of Form 41-101F1 (the "E&P Historical Financial Statements"); and
(b) because the Initial Assets would reasonably be regarded as the "primary business" of Topaz pursuant to Subsection 32.1(1)(b) of Form 41-101F1, audited annual financial statements of the Initial Assets consisting of the statements of financial position as at December 31, 2019 and 2018, and the statements of comprehensive income, changes in equity and cash flows for the three years ended December 31, 2019, 2018 and 2017 and the notes thereto in accordance with Subsection 32.2(6) of Form 41-101F1 (the "Initial Acquisition Historical Financial Statements").

The Company confirmed in the Application that in lieu of including the E&P Historical Financial Statements and the Initial Acquisition Historical Financial Statements, this prospectus would include the following:

(a) the Topaz Financial Statements comprised of the audited financial statements consisting of the statements of financial position as at June 30, 2020 and December 31, 2019, the statements of income (loss) and comprehensive income (loss), and the statements of cash flows for the three and six month periods ended June 30, 2020 and for the period ended December 31, 2019, and the statements of changes in shareholder's equity for the six month period ended June 30, 2020 and for the year ended December 31, 2019 and the notes thereto (the June 30, 2019 three and six month comparative periods are unaudited);
(b) the Alternative Financial Statements comprised of the audited operating statement of Tourmaline containing the operating statements for the Initial Assets for the years ended December 31, 2017 and 2018 and the period from January 1, 2019 to November 13, 2019 with respect to Tourmaline's gross historical interest in the assets comprising the Initial Assets, without adjustment to reflect the newly-created interests acquired by Topaz in such assets on November 14, 2019 pursuant to the Initial Acquisition (the "Initial Acquisition Operating Statements") and the unaudited pro forma operating statements of Topaz that gives effect to the acquisition of the Initial Assets as if the Initial Assets were acquired on January 1 of each of 2019, 2018 and 2017 (the "Topaz Pro Forma Operating Statements"); and
(c) the additional supplemental information required in accordance with Subsection 32.9(1) of Form 41-101F1 which will include, for greater certainty, disclosure of the results of a December 31, 2019 independent reserve evaluation for the developed reserves associated with the Tourmaline GORR Lands in accordance with NI 51-101.

The Company submitted, among other things, in the Application that:

(a) it did investigate the possibility of including in this prospectus Topaz historical financial statements reflecting the common control Initial Acquisition with retrospective restatement of prior periods as well as carve-out historical financial statements for the Initial Assets. However, neither of these alternative financial statements would be in compliance with IFRS as the Initial Assets were newly-created;
(b) it believes that the exclusion of the E&P Historical Financial Statements and the Initial Acquisition Historical Financial Statements in this prospectus would not be prejudicial to the public interest, nor would the inclusion of such financial statements be necessary for this prospectus to contain full, true and plain disclosure of all material facts relating to Topaz;
(c) it believes that the Alternative Financial Statements will provide the most full, true and plain disclosure of the historical results of operations of the Initial Assets; and

(d) it believes that the inclusion of the E&P Historical Financial Statements for Topaz when it was an upstream E&P company will not provide the reader of this prospectus with any additional meaningful information pertaining to Topaz or its financial results or position and the inclusion of such financial statements would likely be misleading to, or cause confusion for, the reader of this prospectus.

In connection with the Application, the Company also provided additional submissions relating to the requirement to include in a prospectus certain historical financial statements for a business, which may be considered the "primary business" of an issuer for the purposes of Item 32 of 41-101F1. In particular, the treatment of the Glacier Gas Plant Acquisition and the Banshee Gas Plant Acquisition as the primary business of Topaz would require Topaz to include in this prospectus audited annual financial statements for such assets for up to three years prior to the date of this prospectus. The purpose of the additional submissions were to confirm that no financial statements are, or would be, required to be included in this prospectus in respect of: (i) the Glacier Gas Plant Acquisition; and (ii) the Banshee Gas Plant Acquisition.

The Company has been advised by the ASC that the issuance of a receipt for this prospectus will evidence the granting of the foregoing Exemptive Relief.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings that the Company is or was a party to, or that any of the Company's property is or was the subject of, since January 1, 2019, that were or are material to the Company, and there are no such material legal proceedings that the Company knows to be contemplated. For the purposes of the foregoing, a legal proceeding is not considered to be "material" by the Company if it involves a claim for damages and the amount involved, exclusive of interest and costs, does not exceed 10% of the Company's current assets, provided that if any proceeding presents in large degree the same legal and factual issues as other proceedings pending or known to be contemplated, the Company has included the amount involved in the other proceedings in computing the percentage. See "Risk Factors".

There were no: (i) penalties or sanctions imposed against the Company by a court relating to Canadian Securities Laws or by a securities regulatory authority within the three years immediately preceding the date of this prospectus; (ii) other penalties and sanctions imposed by court or regulatory body against the Company that the Company believes must be disclosed for this prospectus to contain full, true and plain disclosure of all material facts relating to the Common Shares; or (iii) settlement agreements the Company entered into before a court relating to Canadian Securities Laws or with a securities regulatory authority within the three years immediately preceding the date of this prospectus.

AUDITORS, TRANSFER AGENT AND REGISTRAR

The auditors of the Company are KPMG LLP, Chartered Professional Accountants, Suite 3100, 205 5th Avenue SW, Calgary, Alberta T2P 4B9.

The transfer agent and registrar for the Common Shares is AST Trust Company (Canada), at its principal offices in Calgary, Alberta and Toronto, Ontario where transfers of securities may be recorded.

EXPERTS

Certain legal matters relating to the Offering under Canadian law will be passed upon by Burnet, Duckworth & Palmer LLP on behalf of the Company and the Selling Shareholder and by Torys LLP on behalf of the Underwriters. Certain legal matters relating to the Offering under U.S. law will be passed upon by Dorsey & Whitney LLP on behalf of the Company and by Torys LLP on behalf of the Underwriters. As at the date hereof, the partners and associates of each of Burnet, Duckworth & Palmer LLP, Torys LLP and Dorsey & Whitney LLP, as respective groups, beneficially own, directly or indirectly, less than 1% of the outstanding securities of any associate or affiliate of the Company.

No person or company whose profession or business gives authority to a report, valuation, statement or opinion made by such person or company and who is named in this prospectus as having prepared or certified a part of this prospectus, or a report, valuation, statement or opinion described in this prospectus, has received or shall receive a direct or indirect interest in any securities or other property of the Company or any associate or affiliate of the Company.

As at the date hereof, the principals of each of GLJ and Deloitte, independent qualified reserves evaluators to each of the Company and Tourmaline, do not beneficially own, directly or indirectly, any of the outstanding Common Shares.

KPMG LLP has advised they are independent with respect to each of the Company and Tourmaline within the meaning of the Rules of Professional Conduct of the Institute of Chartered Professional Accountants of Alberta.

MATERIAL CONTRACTS

The following are the only material contracts, other than those contracts entered into in the ordinary course of business, which the Company entered into since the beginning of the last fiscal year before the date of this prospectus, entered into prior to such date but which contract is still in effect, or to which the Company will become a party to prior to Closing:

1. the Underwriting Agreement. See "Plan of Distribution";
1. the Initial Acquisition Agreements. See "Agreements with Tourmaline and Other Counterparties — Agreements Relating to the Initial Acquisition — Initial Acquisition Agreements";
1. the Management Services Agreement. See "Agreements with Tourmaline and Other Counterparties — Management Services Agreement";
1. the Governance Agreement. See "Agreements with Tourmaline and Other Counterparties — Governance Agreement";
1. the Investor Liquidity Agreement. See "Agreements with Tourmaline and Other Counterparties — Investor Liquidity Agreement"; and
1. the credit agreement relating to the Credit Facility. See "Credit Facility".

Copies of these documents are or will be once executed, as applicable, available on SEDAR at www.sedar.com under the Company's profile.

RIGHTS OF WITHDRAWAL AND RESCISSION

Securities legislation in certain of the provinces of Canada provides purchasers with the right to withdraw from an agreement to purchase securities. This right may be exercised within two business days after receipt or deemed receipt of a prospectus and any amendment. In several of the provinces, the securities legislation further provides a purchaser with remedies for rescission, or, in some jurisdictions, revisions of the price or damages, if the prospectus and any amendment contains a misrepresentation or is not delivered to the purchaser, provided that the remedies for rescission, revisions of the price or damages are exercised by the purchaser within the time limit prescribed by the securities legislation of the purchaser's province or territory. The purchaser should refer to any applicable provisions of the securities legislation of the purchaser's province or territory for the particulars of these rights or consult with a legal advisor.

APPENDIX "A"

FINANCIAL STATEMENTS

Topaz Financial Statements

Independent Auditor's Report......................................................................................................................A-2

Audited financial statements consisting of the statements of financial position as at June 30, 2020 and December 31, 2019, the statements of income (loss) and comprehensive income (loss), and the statements of cash flows for the three and six month periods ended June 30, 2020 and for the year ended December 31, 2019 and the statements of changes in shareholders' equity for the six month period ended June 30, 2020 and year ended December 31, 2019 and the notes thereto (the June 30, 2019 three and six month comparative periods are unaudited).

.....................................................................................................................................................................A-5

Alternative Financial Statements (comprised of the Initial Acquisition Operating Statements and Topaz Pro Forma Operating Statements)

Independent Auditor's Report....................................................................................................................A-28

Audited operating statements of Tourmaline for the Initial Assets for the period from January 1 to November 13, 2019 and for the years ended December 31, 2018 and 2017 with respect to Tourmaline's historical interest in the assets comprising the Initial Assets, without adjustment to reflect the newly-created interests acquired by Topaz in such assets on November 14, 2019 pursuant to the Initial Acquisition (the "Initial Acquisition Operating Statements")...........................................................................................................................A-30 Unaudited pro forma operating statements of Topaz that give effect to the acquisition of the Initial Assets as if the Initial Assets were acquired on January 1 of each of 2019, 2018 and 2017 (the "Topaz Pro Forma Operating Statements")...........................................................................................................................A-31

INDEPENDENT AUDITORS' REPORT

To the Shareholders of Topaz Energy Corp.

Opinion

We have audited the financial statements of Topaz Energy Corp. (the "Company"), which comprise:

the statements of financial position as at June 30, 2020 and December 31, 2019
the statements of income (loss) and comprehensive income (loss) for the three and six month periods ended June 30, 2020, and the year ended December 31, 2019
the statements of changes in shareholders' equity for the six month period ended June 30, 2020 and the year ended December 31, 2019
the statements of cash flows for the three and six month periods ended June 30, 2020, and the year ended December 31, 2019
and notes to the financial statements, including a summary of significant accounting policies (Hereinafter referred to as the "financial statements").

In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company as at June 30, 2020 and December 31, 2019, and its financial performance and its cash flows for the three and six month periods ended June 30, 2020, and the year ended December 31, 2019 in accordance with International Financial Reporting Standards ("IFRS").

Basis for Opinion

We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the "Auditors' Responsibilities for the Audit of the Financial Statements" section of our auditors' report.

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

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

Other Information

Management is responsible for the other information. Other information comprises:

• the information included in Management's Discussion and Analysis.

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

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

We obtained the information included in Management's Discussion and Analysis as at the date of this auditors' report. If, based on the work we have performed on this other information, we conclude that there is a material misstatement of this other information, we are required to report that fact in the auditors' report.

We have nothing to report in this regard.

Responsibilities of Management and Those Charged with Governance for the Financial Statements

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

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

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

Auditors' Responsibilities for the Audit of the Financial Statements

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditors' report that includes our opinion.

Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian generally accepted auditing standards will always detect a material misstatement when it exists.

Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of the financial statements.

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

We also:

• Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion.

The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.

Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control.
Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.
Conclude on the appropriateness of management's use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditors' report to the related disclosures in the financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based

on the audit evidence obtained up to the date of our auditors' report. However, future events or conditions may cause the Company to cease to continue as a going concern.

Evaluate the overall presentation, structure and content of the financial statements, including the disclosures, and whether the financial statements represent the underlying transactions and events in a manner that achieves fair presentation.
Communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

• Chartered Professional Accountants

Calgary, Canada

•, 2020

Financial Statements

TOPAZ ENERGY CORP. STATEMENTS OF FINANCIAL POSITION

As at
($000s)	June 30, 2020	Dec. 31, 2019
Assets
Current Assets
Cash	$140,037	$ 8,144
Accounts receivable (note 7)	13,432	13,490
Deposits	94	─
Fair value of financial instruments (note 7)	124	─
Total Current Assets	153,687	21,634
Deposit on acquisition	2,500	─
Petroleum and natural gas interests (notes 8 and 9)	584,499	625,958
Deferred income tax asset (note 16)	52,637	49,642
Total Assets	$793,323	$697,234
Liabilities and Shareholders' EquityCurrent Liabilities
Accounts payable and accrued liabilities	$4,383	$867
Fair value of financial instruments (note 7)	559	─
Total Current Liabilities	4,942	867
Decommissioning obligation (note 11)	708	629
Fair value of financial instruments (note 7)	117	─
Total Liabilities	5,767	1,496
Shareholders' Equity
Share capital (note 12)	772,827	647,003
Contributed surplus	48,435	48,082
Retained earnings (deficit)	(33,706)	653
Total Shareholders' Equity	787,556	695,738
Total Liabilities and Shareholders' Equity	$793,323	$697,234

(1) Refer to accompanying notes to the financial statements

(2) Subsequent events (notes 12 and 20)

Approved on behalf of the Board of Directors of Topaz Energy Corp.:

TOPAZ ENERGY CORP. STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

For the period ended	Three months		Six months		Year ended
($000s, except for share information)	June 30, 2020	June 30, 2019(2)	June 30, 2020	June 30, 2019(2)	Dec. 31, 2019(2)
		(unaudited)		(unaudited)
Revenue
Royalty production revenue (note 14)	$11,935	─	$26,449	─	$9,832
Processing revenue (note 14)	5,296	─	11,264	─	2,943
Other income	2,789	─	5,066	─	1,408
Realized loss on financial instruments (note 7)	(188)	─	(188)	─	─
Unrealized loss on financial instruments (note 7)	(637)	─	(552)	─	─
	19,195	─	42,039	─	14,183
Expenses
Operating	1,016	─	1,871	─	481
Marketing	122	─	212	─	98
General and administrative	1,249	─	2,243	─	1,331
Share-based compensation (note 12)	204	─	353	─	25
Finance (note 15)	62	─	64	─	2
Depletion and depreciation (note 9)	18,612	─	41,805	─	11,671
	21,265	─	46,548	─	13,608
Net income (loss) from continuing operations
before taxes	(2,070)	─	(4,509)	─	575
Deferred tax recovery (note 16)	(945)	─	(2,150)	─	(78)
Net income (loss) from continuing operations	(1,125)	─	(2,359)	─	653
Net income from discontinued operations (note 5)	─	9,488	─	8,978	5,460
Net income (loss) and comprehensive income (loss)	$(1,125)	$9,488	$(2,359)	$8,978	$6,113
Net income (loss) from continuing operations per
common share
Basic and diluted (note 13)	$(0.01)	─	$(0.03)	─	$0.01
(1)Refer to accompanying notes to the financial statements

(2) Topaz commenced operations November 14, 2019 (notes 1 and 5)

TOPAZ ENERGY CORP. STATEMENT OF CHANGES IN SHAREHOLDERS' EQUITY

($000s)	ShareCapital(2)	ContributedSurplus(2)	RetainedEarnings(deficit)(2)	TotalEquity(2)
Balance, December 31, 2018	$144,000	$─	$162,339	$306,339
Net income from discontinued operations	─	─	8,978	8,978
Balance, June 30, 2019	$144,000	─	$171,317	$315,317
Net loss from discontinued operations	─	─	(3,518)	(3,518)
Distributions to Tourmaline (note 5)	─	─	(348,536)	(348,536)
Issue of shares to Tourmaline (note 12)	85,794	─	─	85,794
Equity reclassification (note 12)	(228,794)	48,057	180,737	─
Issue of common shares (note 12)	208,505	─	─	208,505
Issue of common shares to Tourmaline (note 12)	442,495	─	─	442,495
Share issue costs, net of tax (note 12)	(4,997)	─	─	(4,997)
Share-based compensation	─	25	─	25
Net income from continuing operations	─	─	653	653
Balance, December 31, 2019	$647,003	$48,082	$653	$695,738
Issue of common shares (note 12)	128,592	─	─	128,592
Share issue costs, net of tax (note 12)	(2,768)	─	─	(2,768)
Share-based compensation	─	353	─	353
Net loss from continuing operations	─	─	(2,359)	(2,359)
Dividends to common shareholders (note 12)	─	─	(32,000)	(32,000)
Balance, June 30, 2020	$772,827	$48,435	$(33,706)	$787,556

(1) Refer to accompanying notes to the financial statements

(2) Topaz commenced operations November 14, 2019 (notes 1 and 5)

TOPAZ ENERGY CORP. STATEMENTS OF CASH FLOWS

For the period ended	Three months			Six months	Year ended
($000s)	June 30, 2020	June 30, 2019(2)	June 30, 2020	June 30, 2019(2)	Dec. 31, 2019(2)
		(unaudited)		(unaudited)
Operating Activities
Net income (loss) from continuing
operations	(1,125)	─	(2,359)	─	653
Unrealized loss on financial instruments (note		─
7)	637		552	─	─
Finance expenses	2	─	4	─	2
Share-based compensation (note 12)	204	─	353	─	25
Depletion and depreciation (note 9)	18,612	─	41,805	─	11,671
Deferred income tax recovery (note 16)	(945)	─	(2,150)	─	(78)
Net change in non-cash working capital	6,849	─	(21)	─	(12,623)
Cash from (used in) operating activities from
continuing operations	24,234	─	38,184	─	(350)
Discontinued operations (note 5)	─	9,562	─	16,955	15,089
Cash from operating activities	24,234	9,562	38,184	16,955	14,739

Financing Activities
Issue of common shares (note 12)	128,592	─	128,592	─	208,505
Share issue costs (note 12)	(3,613)	─	(3,613)	─	(6,503)
Dividends paid (note 12)	(16,000)	─	(32,000)	─	─
Debt transaction costs	(112)	─	(112)	─	─
Net change in non-cash working capital	3,613	─	3,613	─	─
Cash from financing activities from continuing
operations	112,480	─	96,480	─	202,002
Discontinued operations (note 5)	─	(4,996)	─	(5,007)	(238,972)
Cash from (used in) financing activities	112,480	(4,996)	96,480	(5,007)	(36,970)

Investing Activities
Petroleum and natural gas interests (note 9)	(159)	─	(271)	─	(194,507)
Deposit on acquisition	(2,500)	─	(2,500)	─	─
Cash used in investing activities from continuing
operations	(2,659)	─	(2,771)	─	(194,507)
Discontinued operations (note 5)	─	(4,566)	─	(11,948)	224,882
Cash from (used in) investing activities	(2,659)	(4,566)	(2,771)	(11,948)	30,375

Increase in cash	134,055	─	131,893	─	8,144
Cash and cash equivalents, beginning	5,982	─	8,144	─	─
Cash and cash equivalents, end	140,037	─	140,037	─	8,144

(1) Refer to accompanying notes to the financial statements

(2) Topaz commenced operations November 14, 2019 (notes 1 and 5)

Notes to the Financial Statements

As at June 30, 2020 and December 31, 2019, and for the three and six months ended June 30, 2020 and 2019, and for the year ended December 31, 2019 June 30, 2019 three and six month-periods are unaudited

(amounts in thousands of Canadian dollars unless otherwise noted)

1. NATURE OF THE ORGANIZATION

Topaz Energy Corp. ("Topaz" or the "Company") is a royalty and energy infrastructure company focused on generating low-risk income and paying dividends to its shareholders, while strategically investing in additional revenue generating assets to provide growth.

Topaz was reorganized in November 2019 to acquire certain royalty and infrastructure ownership and revenue interests. Pursuant to an asset purchase and sale agreement dated November 14, 2019, Topaz acquired its formative assets from Tourmaline Oil Corp. ("Tourmaline") for total cash and share consideration with an assigned value of $637.0 million (the "Initial Acquisition"). The assets acquired pursuant to the Initial Acquisition included: (i) a newly created gross overriding royalty interest on natural gas, crude oil, and condensate production on 100% of Tourmaline's existing developed and undeveloped lands; (ii) a non-operated 45% jointly owned interest in two of Tourmaline's existing 19 natural gas processing facilities supported by newly created long-term take-or-pay commitments from Tourmaline in relation to the two facilities; and (iii) a newly created contracted interest in a portion of certain third-party revenues generated by natural gas processing and handling agreements to which Tourmaline is a party.

Prior to the completion of the Initial Acquisition, Topaz (named "Exshaw Oil Corp." prior to November 8, 2019 ("Exshaw")) had been engaged in upstream oil and gas exploration and production. On November 12, 2019, Topaz sold all of its E&P assets (representing substantially all of its assets) to Tourmaline (the "E&P Asset Disposition").

Topaz does not conduct upstream petroleum and natural gas exploration and production and, as a result, the Company has presented the results of Exshaw's operations as discontinued operations (note 5).

These financial statements reflect only the Company's proportionate interest in its business activities. The Company's registered office is located at Suite 2400, 525 – 8th Avenue S.W., Calgary, Alberta, Canada T2P 1G1.

2. BASIS OF PREPARATION

(a) Statement of compliance

These financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). The Company's business operations commenced on November 14, 2019 and financial results prior to the Initial Acquisition are considered discontinued operations as discussed in note 5.

The financial statements have been prepared on a going-concern basis, amounts are in thousands of Canadian dollars unless otherwise stated and were authorized for issuance by the Company's Board of Directors on •, 2020.

(b) Functional and presentation currency

These financial statements are presented in Canadian dollars, which is the functional currency of Topaz.

(c) Basis of measurement

The financial statements have been prepared on the historical-cost basis except for derivative financial instruments which are measured at fair value. The methods used to measure fair values are discussed in note 6.

(d) Use of judgments and estimates

The timely preparation of the financial statements requires management to use judgments, estimates and assumptions. These judgments, estimates and assumptions are subject to change and could differ from actual results. The key sources of estimation uncertainty that have a significant risk of causing a material adjustment to the reported amounts of assets, liabilities, revenues, expenses and the disclosure of contingencies are discussed below.

Critical judgments in applying accounting policies:

The following are the critical judgments, apart from those involving estimations (see below), that management has made in the process of applying the Company's accounting policies and that have the most significant effect on the amounts recognized in these financial statements:

Identification of cash-generating units

The Company's assets are aggregated into cash-generating units ("CGUs") for the purpose of impairment. A CGU is comprised of a group of assets that that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets. By their nature, these estimates and assumptions are subject to measurement uncertainty and may impact the carrying value of the Company's assets in future periods.

Impairment of asset carrying values

Judgments are required to assess when impairment indicators, or reversal indicators, exist and impairment testing is required with respect to the carrying values of petroleum and natural gas interests. Refer to note 3e. For the purposes of determining whether impairment of the Company's petroleum and natural gas interests has occurred, the key assumptions the Company uses in estimating future cash flows are forecasted petroleum and natural gas prices, expected royalty production volumes and anticipated recoverable quantities and value of developed reserves. Changes in economic conditions can also affect the rate used to discount future cash flow estimates. Changes in the aforementioned assumptions could affect the carrying amounts of assets. These assumptions are subject to change as new information becomes available. Impairment charges and reversals are recognized in profit or loss.

Deferred taxes

Deferred tax assets are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment of when those deferred tax assets are likely to reverse and a judgment as to whether or not there will be sufficient taxable profits available to offset the tax assets when they do reverse. Thisrequires assumptionsregarding future profitability and is therefore inherently uncertain. To the extent assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets as well as the amounts recognized in profit or loss in the period in which the change occurs.

Key sources of estimation uncertainty:

The following are the key assumptions concerning the sources of estimation uncertainty at the end of the reporting period, that have a significant risk of causing adjustments to the carrying amounts of assets and liabilities.

Business Environment

COVID-19 and other macro-economic conditions around the world have had a significantly negative impact and have increased economic uncertainty. These conditions have contributed to a drastic decrease in global oil and liquids demand since the beginning of 2020 and have resulted in significantly lower oil and liquids prices. There is ongoing uncertainty surrounding COVID-19 and the extent and duration of the impacts that it may have on demand for commodities, on our employees and on global financial markets. There is an increased potential for asset impairments or reversals of impairment over the duration of the pandemic due to increased volatility in commodity prices and decreased global economic activity.

At this time, the extent to which COVID-19 may affect the Company is uncertain; however, it is possible that COVID-19 may have further adverse effects on commodity prices, the Company's business, results of operations and financial condition depending on the severity and duration of the pandemic.

Reserves

Reserves estimates are not recorded in the Company's financial statements but they do affect net earnings and assets and liabilities through their impact on depreciation, depletion and amortization ("DD&A"), inputs in the impairment calculations, inputs in calculating the recoverability of deferred income tax assets and inputs in determining fair values of assets acquired through business combinations. By their nature, reserve estimates, including the estimates of future prices, costs, discount rates and the related future cash flows, are subject to measurement uncertainty. Accordingly, the impact to amounts reported in the financial statements for future periods could be material. The Company's petroleum and gas reserves are independently evaluated by reserve engineers at least annually and are determined pursuant to National Instrument 51-101 Standard of Disclosures for Oil and Gas Activities.

Oil and natural gas revenue accruals

The Company follows the accrual method of accounting, making estimates in its financial and operating results. This may include estimates of royalty revenue and related expenses, including estimates of production and/or commodity pricing, for the period reported, for which actual results have not yet been received. The Company has no operational control over its royalty assets and as a result, the Company uses historical production information to estimate revenue accruals. These accrual estimates are revised based on the receipt of actual production results and realized prices.

Share-based payments

All equity-settled, share-based awards issued by the Company are recorded at fair value using the Black-Scholes optionpricing model. In assessing the fair value of equity-based compensation, estimates have to be made regarding the expected volatility in share price, option life, dividend yield, risk-free rate, share price and estimated forfeitures at the initial grant date.

Deferred taxes

Tax provisions are based on enacted orsubstantively enacted laws. Changesin those laws could affect amountsrecognized in profit or loss both in the period of change, which would include any impact on cumulative provisions, and in future periods.

3. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently to all periods presented in these financialstatements and have been applied consistently by the Company.

(a) BusinessCombinations

The purchase method of accounting is used to account for acquisitions of businesses and assetsthat meet the definition of a business under IFRS. The cost of an acquisition is measured as the fair value of the assets given up, equity instruments issued, and liabilities incurred or assumed at the date of exchange. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. If the consideration of acquisition given up is less than the fair value of the net assets received, the difference is recognized immediately in profit or loss. If the consideration of acquisition is greater than the fair value of the net assets received, the difference is recognized as goodwill on the statement of financial position. Acquisition costs incurred are expensed.

Amendments made to IFRS 3 – Business Combinations were adopted by the Company on July 1, 2019. The amendments include a change in the definition of a business and the addition of an optional concentration test to determine if the acquisition is a business.

The definition of a business under IFRS 3 is that a business consists of inputs and processes applied to those inputs that have the ability to contribute to the creation of outputs. The three elements of a business are defined as follows:

Input: any economic resource that creates outputs, or has the ability to contribute to the creation of outputs, when one or more processes are applied to it.
Process: Any system, standard, protocol, convention or rule that, when applied to an input or inputs, creates outputs or has the ability to contribute to the creation of outputs.
Output: The result of inputs and processes applied to those inputs that provide goods or services to customers, generate investment income or generate other income from ordinary activities.

The optional concentration test permits a simplified assessment of whether an acquired set of activities and assets is in fact a business. An entity may elect to apply, or not apply, the test. An entity may make such an election separately for each transaction or other event. If the concentration test is met, the set of activities and assets is determined not to be a business and no further assessment is needed.

(b) Jointly-owned assets:

A portion of the Company's petroleum and natural gas interests involve jointly-owned assets. The financial statements include the Company's share of these jointly-owned assets and a proportionate share of the relevant revenue and related costs.

(c) Financial instruments

Non-derivative financial instruments

Non-derivative financial instruments comprise cash and cash equivalents, accounts receivable and accounts payable and accrued liabilities. Non-derivative financial instruments are recognized initially at fair value plus, for instruments not at fair value through profit or loss, any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured as follows:

Cash and cash equivalents comprise cash on hand, term deposits held with banks, other short-term highly-liquid investments with original maturities of three months or less, and are measured at amortized cost. Other non-derivative financial instruments,such as accountsreceivable, and accounts payable and accrued liabilities, are measured at amortized cost using the effective interest method, less any impairment losses.

Derivative financial instruments

The Company has entered into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, and thus not applied hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, all financial derivative contracts are classified as fair value through profit or loss and are recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred.

Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at fair value through earnings. Changes in the fair value of separable embedded derivatives are recognized immediately in earnings.

Share capital

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and stock options are recognized as a deduction from equity, net of any tax effects.

(d) Petroleum and natural gas interests

Petroleum and natural gas interests are grouped into CGUs and measured at cost less accumulated depletion and accumulated impairment losses.

Costs accumulated within each area are depleted by reference to the ratio of: royalty production in the period to developed reserves, without taking into account estimated future development costs. Developed reserves are estimated annually by independent qualified reserve evaluators and represent the estimated quantities of crude oil, condensate, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. Internal estimates of changes in developed reserves are determined on a quarterly basis.

For divestitures of properties, a gain or loss is recognized in net income (loss). Exchanges of properties are measured at fair value, unless the transaction lacks commercial substance or fair value cannot be reliably measured. Where the exchange is measured at fair value, a gain or loss is recognized in net income (loss).

The net carrying value of property, plant & equipment assets, including capital improvements thereof, are depreciated on a straight-line basis over the estimated useful life of each asset. Office equipment is depreciated using the 25% declining balance method. Depreciation methods, useful lives and residual values are reviewed at each reporting date.

(e) Impairment

Financial assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset.

An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.

Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in profit or loss.

An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in profit or loss.

Non-financial assets

The carrying amounts of the Company's non-financial assets, other than deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset's recoverable amount is estimated. For goodwill and other intangible assets that have indefinite lives, or that are not yet available for use, an impairment test is completed each year.

For the purpose of impairment testing, assets are grouped into CGUs. The recoverable amount of an asset or a CGU is the greater of its value in use or its fair value less costs to sell.

In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of developed reserves. Fair value less costs to sell is determined as the amount that would be obtained from the sale of an asset in an arm's length transaction between knowledgeable and willing parties.

The goodwill acquired in an acquisition, for the purpose of impairment testing, is allocated to the CGUs that are expected to benefit from the synergies of the combination.

An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the assets in the unit (group of units) on a pro-rata basis. Impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset's carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized.

(f) Provisions

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

Decommissioning obligations

The Company recognizes the decommissioning obligations for the future costs associated with removal, site restoration and decommissioning costs. The Company's decommissioning obligation isrecorded in the period in which it is incurred, discounted to its present value using the risk-free interest rate and the corresponding amount recognized by increasing the carrying amount of petroleum and natural gas assets.

The asset recorded is depreciated on a straight-line basis over the life of the property, plant & equipment. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost could also result in an increase or decrease to the obligation. Actual costs incurred upon settlement of the decommissioning obligation are charged against the obligation to the extent of the liability recorded.

Onerous contracts

Aprovision for onerous contracts is recognized when the expected benefits to be derived by the Company from a contract are lower than the unavoidable cost of meeting its obligations under the contract. The provision is measured at the present value of the lower of the expected cost of terminating the contract and the expected net cost of continuing with the contract. Before a provision is established, the Company recognizes any impairment loss on associated assets.

(g) Revenue recognition

Royalty production revenue

The Company receives royalties on production from third-party production and development of petroleum and natural gas pursuant to lease agreements on its royalty interests.

The continuation of a lease istypically dependent on the holderthereof continuing to produce hydrocarbons and maintaining the lease in good standing. Accordingly, the Company's performance obligations with respect to production royalties are satisfied over time, as petroleum and natural gas are produced.

Royalty revenue from the sale of natural gas, crude oil, and condensate is recognized as it accrues in accordance with the terms of the royalty agreement, which is generally in the month when the product is produced with production volumes primarily marketed with royalty payors' production. The commodity prices for natural gas, crude oil and condensate are based on market index prices in the month of production. Revenue for royalty production that is taken-in-kind is recognized when the performance obligations are met, which is when control of the product and title are transferred to the purchaser. Royalty revenue is measured at fair value of the consideration received or receivable when management can reliably estimate the amount, pursuant to the terms of the royalty agreements. An accrual is included in revenue and accountsreceivable for amounts not received at the reporting date based on historical trends, new wells on stream and current market prices. Differences between the estimates and actual amounts received are adjusted and recorded in the period when the actual amounts are received.

Processing revenue

The Company's non-operated ownership in processing facilities generates processing fee revenue. The facilities provide natural gas processing services to customers on a fee-for-service basis. Certain fees include fixed take-or-pay arrangements under longterm commercial arrangements. Revenue is recognized when service is provided, and under the long-term commercial arrangements, if monthly volume requirements are not met, revenue is recognized under the contractual terms of the arrangements.

Other income

The Company also generates income by way of a contracted interest in third-party revenue through fee-for-service natural gas processing contracts with no underlying facility ownership.

Processing revenue and other income are recognized as they accrue in accordance with the terms of the service agreements and are generally received 30 days after the services are provided.

(h) Finance income and expenses

Interest income and expense is recognized as it accrues in net earnings, using the effective-interest method.

(i) Deferred taxes

Income tax expense comprises current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

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

Deferred tax is recognized on the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred-tax assets and liabilities are offset if there is a legally enforceable right to offset, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously.

A deferred-tax asset is recognized to the extent that it is probable that future taxable profits will be available against which the temporary difference can be utilized. Deferred-tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

(j) Share-basedpayments

The Company applies the fair-value method for valuing stock option grants. Under this method, compensation cost attributable to all stock options granted are measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest. Upon the exercise of the stock options, consideration received, together with the amount previously recognized in contributed surplus, is recorded as an increase to share capital.

(k) Per-share information

Basic per-share information is computed by dividing net income or loss attributable to shareholders by the weighted average number of common shares outstanding for the period. The treasury-stock method is used to determine the diluted per share amounts, whereby any proceeds from the stock options are assumed to be used to purchase common shares at the average market price during the period. The weighted average number of shares outstanding is then adjusted by the net change.

(l) Leased assets

At inception of a contract, the Company assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. This policy is applied to new and existing contracts as at or after January 1, 2019.

The Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset isinitially measured at cost, which comprises the initial amount of the lease liability adjusted for any lease payments made at or before the commencement date, plus any initial direct costs incurred and an estimate of costs to dismantle and remove the underlying asset or to restore the underlying asset or the site on which it is located, less any lease incentives received.

The right-of-use asset is subsequently depreciated using the straight-line method from the commencement date to the earlier of the end of the useful life of the right-of-use asset or the end of the lease term. The estimated useful lives of right-of-use assets are determined on the same basis as those of property, plant, & equipment. In addition, the right-of-use asset is periodically reduced by impairment losses, if any, and adjusted for certain re-measurements of the lease liability.

The lease liability is initially measured at the present value of the minimum lease payments that are not yet paid at the commencement date, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined, the Company's incremental borrowing rate for that asset. Generally, the Company uses its incremental borrowing rate as the discount rate. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is re-measured when there is a change in future lease payments arising from a change in an index or rate, a change in estimate of the amount expected to be payable under a residual value guarantee, changes in the assessment of whether a purchase or extension option is reasonably certain to be exercised or a termination option is reasonably certain not to be exercised.

The Company has elected not to recognize right-of-use assets and lease liabilities for short-term leased assets that have a lease term of 12 months or less and leases of low-value assets defined as less than $5,000 or less. The Company recognizes lease payments associated with these leases as an expense on a straight- line basis over the lease term.

(m) Lessor accounting

The Company recognizes and presents assets held under a finance lease as a finance lease receivable equal to the net investment in the lease. The finance lease is initially measured at the present value of the minimum lease payments, discounted using the interest rate implicit in the lease or, if that rate cannot be readily determined the Company's incremental borrowing rate for that asset. Any deferred profit is recognized in addition to the interest income on the lease receivable and accretion on the unguaranteed residual asset.

Interest on the finance lease receivable is calculated by multiplying the rate implicit in the lease by the outstanding receivable balance each period. The finance lease receivable is increased for accrued interest and reduced by cash payments received from the lessee.

The residual asset is recorded at its present value and accreted to its final expected value at the expiration of the lease term.

(n) Common control transactions

Business combinations involving entities under common control are outside the scope of IFRS 3 – Business Combinations. A business combination involving entities under common control is a business combination in which all of the combining entities are ultimately controlled by the same party, both before and after the business combination, and control is not transitory. Since IFRS provides no guidance on the accounting for these types of transactions, the Company is required to develop an accounting policy. The most common methods utilized are the fair value method, or the book value method. Management determined the book value method to be the most appropriate method.

4. ACCOUNTING CHANGES

The following standard issued by the International Accounting Standards Board ("IASB") has been adopted by the Company effective January 1, 2019. There was no impact to the Company as the Company did not have any leases outstanding.

5. DISCONTINUED OPERATIONS

Exshaw was incorporated under the Business Corporations Act (Alberta) in 2006 and was a controlled subsidiary of Tourmaline prior to the transactions leading up to the Initial Acquisition. Prior to the Initial Acquisition, all of Exshaw's oil and gas assets and liabilities, except for $48.1 million of deferred tax assets and $1.0 million in cash, were transferred to Tourmaline. The book value method was used to determine the value of assets and liabilities transferred. The accumulated deficit in Exshaw was then reclassified to share capital and contributed surplus balances in shareholder's equity for the continuing entity, upon receipt of shareholder approval. On November 8, 2019, articles of amendment were filed to change the Company's name to "Topaz Energy Corp." Prior to the E&P Asset Disposition, the Company conducted upstream petroleum and natural gas exploration and production operations and the results of these operations are reflected as discontinued operations.

($000s) Book value of assets and liabilities transferred: Intercompany receivable (4,245) Other current assets (7,456) Accounts payable 6,496 Bank debt 290,206 Petroleum and natural gas interests (776,606) Decommissioning obligations 38,812 Deferred income tax liability 104,257 Retained earnings 348,536 Total ─

The following table presents the results of discontinued operations of Exshaw.

For the period ended	June 30, 2019	Period from Jan.1
($000s, except for share information)	Three months	Six months	to Nov.13, 2019(1)
	(unaudited)	(unaudited)
Revenue
Revenue	20,734	44,868	75,454
Other income	1,275	1,782	2,872
Total	22,009	46,650	78,326
Expenses
Royalties	1,235	2,648	5,828
Operating	7,775	16,616	28,372
Transportation expenses	3,240	7,384	12,950
General and administrative	300	600	1,000
Finance	2,667	5,384	9,366
Depletion and depreciation	7,420	15,295	26,534
Total expenses	22,637	47,927	84,050
Net loss from discontinued operations before taxes	(628)	(1,277)	(5,724)
Deferred tax recovery	(10,116)	(10,255)	(11,184)
Net income from discontinued operations	9,488	8,978	5,460

Per share(2)		$8.63	$8.16	$4.96
(1)	Exshaw's results of operations from January 1, 2019 to November 13, 2019 are presented as discontinued operations. Topaz commenced

operations on November 14, 2019 therefore its results of operations from November 14, 2019 to December 31, 2019 are presented as continuing operations (notes 1 and 5).

(2) As described in note 12, on October 31, 2019, Tourmaline purchased the remaining 9.4% minority interest in Exshaw. In conjunction with the transaction, Exshaw completed a share consolidation which reduced the outstanding number of shares to 1.1 million. The per share calculation for the periods above reflect the post-consolidation number of shares outstanding (1.1 million).

The following table presents the sources and uses of cash from the discontinued operations of Exshaw.

For the period ended		June 30, 2019Period from Jan.1
($000s)	Three months	Six months	to Nov.13, 2019(1)
Operating activities	9,562	16,955	15,089
Financing activities	(4,996)	(5,007)	(238,972)
Investing activities	(4,566)	(11,948)	224,882

6. DETERMINATION OF FAIR VALUE

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

a. Petroleum and natural gas interests

The fair value of petroleum and natural gas interests recognized in a business combination and for impairment testing, is based on market values. The market value of these assets is the estimated amount which could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm's length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently and without compulsion. The market value of petroleum and natural gas interests is estimated with reference to the discounted cash flow expected to be derived from developed reservesbased on externally prepared reserve reports. The risk-adjusted discount rate is specific to the asset with reference to general market conditions. The fair value less costs of disposal value used to determine the recoverable amount of any impaired petroleum and natural gas interests are classified as Level 3 fair value measurements. Refer to "Financial Instruments" section below for fair value hierarchy classifications.

b. Cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities

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

c. Derivatives

The fair value of financial commodity price risk management contractsis determined by discounting the difference between the contracted prices and published forward price curves as at the statement of financial position date, using the remaining contracted oil and natural gas volumes and a risk-free interest rate (based on published government rates). The fair value of options and costless collars is based on option models that use published information with respect to volatility, prices and interest rates.

d. Stock options

The fair value of employee stock options is measured using a Black-Scholes option-pricing model. Measurement inputs include share price on measurement date, exercise price of the instrument, expected volatility (based on weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instruments (based on historical experience and general option holder behavior), expected dividends, and the risk-free interest rate (based on government bonds).

e. Measurement

The Company's fair value measurements require disclosure about how the fair value was determined based on significant levels of inputs described in the following hierarchy:

Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 Pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.
Level 3 Valuations in this level are those with inputs for the asset or liability that are not based on observable market data.

Assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy level. The Company's risk management contracts are considered Level 2.

7. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Credit risk

Credit risk is the risk of financial loss to the Company if a customer or counterparty to a financial instrument fails to meet its contractual obligations in accordance with agreed terms. The Company's policy to mitigate credit risk is to establish contractual agreements with creditworthy counterparties. The Company's accounts receivable at June 30, 2020 relate to royalty and contractual agreements with its controlling shareholder. The Company's structure of royalty and infrastructure revenue from a counterparty, which Topaz considers to have strong creditworthiness, significantly reduces Topaz's credit risk. At June 30, 2020, the Company does not have any receivable (December 31, 2019 - $nil) over 90 days. The Company is satisfied its accounts receivable amounts are collectible.

Liquidity risk

Liquidity risk is the risk that the Company will encounter difficulties in meeting its financial obligations as they come due. The Company manages its liquidity risk by ensuring that it will have sufficient liquidity to meet its financial obligations under both normal and risked conditions. The Company has unused capacity under its available credit facilities, described in note 10, for up to $75.0 million.

The timing of expected cash outflows relating to accounts payable and accrued liabilities of $4.4 million is less than one year. The Company expects to pay suppliers within 30-60 days. These terms are consistent with industry practice. As at June 30, 2020, all of the accounts payable balances were less than 90 days. Management maintains a conservative approach to debt management that aims to provide financial flexibility with respect to development of the Company's assets and the payment of dividends to shareholders. The Board of Directors reviews and determines the dividend rate annually after considering expected commodity prices, expected royalty production volumes, expected cash flow, economic conditions, income taxes, and the Company's capacity to fund its operations and investment opportunities.

The following are the contractual maturities of financial liabilities at June 30, 2020:

($000s)	Total	< 1 year	1 to 5 years
Non-derivative financial liabilities:
Accounts payable and accrued liabilities	4,383	4,383	─
Derivative financial liabilities:
Financial instruments	676	559	117

Market risk

Market risk is the risk that changes in market conditions, such as commodity prices and interest rates will affect the Company's earnings or value of financial instruments. The objective of market risk management is to manage and curtail market risk exposure within acceptable limits, while maximizing the Company'sreturns. The Company utilizes financial derivative contracts to manage market risks.

Interest rate risk is the risk that changes in market interest rates may affect future cash flows from the Company's financial assets or liabilities. The Company is exposed to interest rate risk to the extent that changes in market interest rates would impact any borrowings under the Company's credit facility which is subject to a floating interest rate. The Company has no outstanding borrowings against its credit facility at June 30, 2020 (December 31, 2019 – nil) (note 10).

Commodity price risk is the risk that the fair value or future cash flow will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are based upon the US dollar and as a result the price received by Canadian producers is affected by the Canadian to US dollar exchange rate. The commodity prices are also impacted by world economic events that dictate the levels of supply and demand. As at June 30, 2020, the Company has entered into certain financial derivative contracts in order to manage commodity price risk. These instruments are not used for trading or speculative purposes. The Company has not designated its financial derivative contracts as effective accounting hedges, even though the Company considers all financial derivative contracts to be effective economic hedges. As a result, all such financial instruments are recorded on the statement of financial position at fair value, with changes in the fair value being recognized as an unrealized gain or loss on the statement of loss and comprehensive loss. The Company has not offset any financial assets and liabilities, in the statements of financial position.

Financial Instruments

The Company utilizes financial derivative contracts as a risk management technique to mitigate exposure to commodity price volatility. The following table presents the financial derivative contracts outstanding as at June 30, 2020. The fair value of these contracts is a liability of $0.6 million as detailed below. No contracts were entered subsequent to June 30, 2020.

Natural Gas Contract Period	Type	Daily Volume	Price (CAD$/GJ)
Apr. 1, 2020 to Oct. 31, 2020	Fixed price	5,000 GJ	$1.73/GJ
Apr. 1, 2020 to Oct. 31, 2020	Fixed price	2,500 GJ	$1.75/GJ
Apr. 1, 2020 to Dec. 31, 2020	Fixed price	5,000 GJ	$1.73/GJ
Apr. 1, 2020 to Dec. 31, 2020	Fixed price	2,500 GJ	$1.72/GJ
Jun. 1, 2020 to Mar. 31, 2021	Fixed price	2,500 GJ	$2.25/GJ
Jan. 1, 2021 to Dec. 31, 2021	Fixed price	5,000 GJ	$2.09/GJ
Apr. 1, 2021 to Oct. 31, 2021	Fixed price	2,500 GJ	$2.04/GJ
Apr. 1, 2021 to Oct. 31, 2021	Fixed price	2,500 GJ	$2.035/GJ

		At June 30, 2020
($000s)	Asset	Liability
Current financial instruments	124	559
Non-current financial instruments	─	117

The Company did not have any financial derivative contracts outstanding at December 31, 2019.

The following table provides the realized and unrealized losses on financial instruments for the periods presented.

For the period ended	Three months		Six months		Year ended
($000s)	June 30, 2020	June 30, 2019(1)	June 30, 2020	June 30, 2019(1)	Dec. 31, 2019(1)
Realized loss on financial instruments	188	─	188	─	─
Unrealized loss on financial instruments	637	─	552	─	─
Total	825	─	740	─	─

(1) Refer to note 5 "Discontinued Operations".

The Company's financial derivative contracts are sensitive to fluctuations in commodity prices. For the contracts in place at June 30, 2020, if the future strip prices for natural gas were $0.10 per Mcf higher, with all other variables held constant, the unrealized loss would increase by $0.7 million, directly impacting earnings (December 31, 2019 - $nil as there were no financial derivative contracts outstanding). An equal and opposite impact would have occurred if natural gas prices were $0.10 per Mcf lower.

Capital management

The Company considers its capital structure to include shareholders' equity, bank debt and working capital. In order to maintain or adjust the capital structure, the Company may from time to time issue equity, utilize available credit facilities, adjust its dividend distributions and/or adjust its investment activities to manage current and forecast debt levels. The Company's operating results and capital structure are impacted by royalty production volumes, commodity prices and third-party revenue generated at its nonoperated processing facilities or through its contracted revenue interests.

8. ACQUISITIONS AND DISPOSITIONS

Topaz was established to acquire certain infrastructure and royalty assets. Prior to closing, Topaz was a subsidiary controlled by Tourmaline and consequently was under common control at the time of the Initial Acquisition. Management used the book value method to determine the value of assets and liabilities acquired by the Company. As a result of the common control transaction, the Company recorded net assets acquired in the amount of $637.0 million in exchange for cash to Tourmaline of $194.5 million and Topaz common shares with an assigned value of $442.5 million (58.0 million common shares).

($000s)
Book value of assets and liabilities acquired:
Petroleum and natural gas interests	637,627
Decommissioning obligations	(627)
Total	637,000
Consideration:
Cash	194,505
Common shares	442,495
Total	637,000

9. PETROLEUM AND NATURAL GAS INTERESTS

Cost
($000s)	Cost
Balance, December 31, 2018	1,064,384
Capital expenditures on discontinued operations	53,861
Change in decommissioning liabilities on discontinued operations	10,012
Common control disposition	(1,128,257)
Common control acquisition	637,627
Capital expenditures on continued operations	2
Balance, December 31, 2019	637,629
Additions	271
Change in decommissioning liabilities	75
Balance, June 30, 2020	637,975

Accumulated Depletion, Depreciation & Amortization (DD&A)

($000s) Accumulated DD&A

Balance, December 31, 2018	(325,117)
Depletion, depreciation and amortization on discontinued operations	(26,534)
Common control disposition	351,651
Depletion, depreciation and amortization on continued operations	(11,671)
Balance, December 31, 2019	(11,671)
Depletion and depreciation	(41,805)
Balance, June 30, 2020	(53,476)

Net Book Value

($000s)	Net book value
Balance, December 31, 2019	625,958
Balance, June 30, 2020	584,499

Impairment Assessment

In accordance with IFRS, an impairment test is performed on a CGU if the Company identifies an indicator of impairment. The Company determined that there were no indicators of impairment on the Company's CGU and there was no impairment test completed as at June 30, 2020 and December 31, 2019.

At March 31, 2020, the Company identified indicators of impairment on its CGU due to the decline in current and forward commodity prices and performed an impairment test accordingly.

An impairment is recognized if the carrying value of a CGU exceeds the recoverable amount for that CGU. The Company determines the recoverable amount by using the greater of fair value less cost to sell and the value-in-use. Value-in-use is generally the future cash flows expected to be derived from production of total developed reserves estimated by the Company's third-party reserve evaluators and internally updated to March 31, 2020 along with the internally estimated future cash flows of facility infrastructure, when required. At March 31, 2020, the Company used value-in-use, discounted at pre-tax rates ranging between 9- 12%.

The following forward third-party commodity price estimates were used in determining whether an impairment to the carrying value of the CGU existed at March 31, 2020:

	WTI Oil	Foreign	Edmonton Light Crude Oil	AECO Gas
Year	(USD$/Bbl)1	Exchange Rate1	(Cdn$/Bbl)1	(Cdn$/mmbtu)1
2020	43.07	0.7089	31.04	1.75
2021	50.52	0.7283	46.85	2.20
2022	63.05	0.7450	59.27	2.38
2023	69.10	0.7467	65.02	2.45
2024	72.14	0.7483	68.43	2.53
2025	75.18	0.7500	69.81	2.60
2026	76.82	0.7500	71.24	2.66
2027	78.36	0.7500	72.70	2.72
2028	79.92	0.7500	74.19	2.79
2029	83.15	0.7500	75.71	2.85
Thereafter	+2.0%/yr	0.7500	+2.0%/yr	+2.0%/yr

(1) Source: 3 consultants' average, GLJ Petroleum Consultants, McDaniel & Associates Consultants, and Sproule Associates price forecasts, effective April 1, 2020.

The Company determined that there was no impairment at March 31, 2020.

10. DEBT

At June 30, 2020, Topaz had a covenant-based, secured, operating credit facility with a Canadian bank in the amount of $75.0 million ("Credit Facility"). The maturity date is June 10, 2022. At the request of the Company and with consent of the lender, the Credit Facility can be extended on an annual basis.

The Credit Facility is subject to the following covenants, on a rolling four quarter basis: (i) the ratio of adjusted EBITDA to interest expense must exceed 3:1, (ii) the ratio of consolidated senior secured debt to adjusted EBITDA must not exceed 3:1, and (iii) the ratio of total debt to adjusted EBITDA must not exceed 4:1. At June 30, 2020 and December 31, 2019, the Credit Facility was not drawn and the Company was in compliance with all covenants.

11. DECOMMISSIONING OBLIGATIONS

The decommissioning liability was estimated based on the Company's net ownership interest in all facilities, the estimated costs to abandon and reclaim the facilities and the estimated timing of the costs to be incurred in future periods. The estimated future cash flows have been discounted using an average risk-free rate of 0.99% and an inflation rate of 0.99% (December 31, 2019; 1.76% and 1.35%, respectively). Changes in estimates in 2020 are due to the decrease in both the risk-free rate as well as the inflation rate since December 31, 2019. The Company has estimated the net present value of the decommissioning obligations to be $0.7 million as at June 30, 2020 ($0.6 million at December 31, 2019). The undiscounted, uninflated total future liability at June 30, 2020 is $0.7 million ($0.7 million at December 31, 2019). The payments are expected to be incurred over the operating lives of the assets. The following table reconciles the decommissioning liability:

($000s)
Balance, December 31, 2018	28,300
Obligation incurred on discontinued operations	579
Obligation incurred on discontinued operations property acquisitions	9,433
Accretion expense on discontinued operations	500
Obligation disposed on common control transaction	(38,812)
Obligation incurred on common control transaction	627
Accretion expense on continued operations	2
Balance, December 31, 2019	629
Change in estimates	75
Accretion expense	4
Balance, June 30, 2020	708

12. SHARE CAPITAL

Authorized

The authorized share capital consists of an unlimited number of common voting shares without par value. The common shares entitle holders to one vote per share at meetings of shareholders. The Company is also authorized to issue First Preferred Shares, issuable in series, and Second Preferred Shares, issuable in series.

Issued and Outstanding

($000s except share amounts)
-------------------------------

($000s except share amounts)	Number of Shares	Amount
Balance, December 31, 2018	53,340,001	144,000
Issue of shares to Tourmaline (1)	28,597,855	85,794
Share consolidation (1)	(80,837,856)	─
Equity reclassification (2)	─	(228,794)
Issue of common shares (3)	20,850,506	208,505
Issue of common shares to Tourmaline (3)	58,049,494	442,495
Share issue costs, net of tax (3)	─	(4,997)
Balance, December 31, 2019	80,000,000	647,003
Issue of common shares (4)	11,690,131	128,592
Share issue costs, net of tax (4)	─	(2,768)
Balance, June 30, 2020	91,690,131	772,827

1. On October 31, 2019, Tourmaline purchased the 9.4% minority interest in Exshaw, resulting in Exshaw becoming a wholly-owned subsidiary of Tourmaline. Subsequently, Tourmaline invested $85.8 million in exchange for 28.6 million common shares of Exshaw in order to repay the remaining bank indebtedness. In conjunction with the transaction, Exshaw completed a share consolidation which reduced the outstanding number of shares to 1.1 million.
1. As described in note 5, all of Exshaw's oil and gas assets and liabilities, except for $48.1 million of deferred tax assets and $1.0 million in cash, were transferred to Tourmaline in November 2019 and the book value method was used to determine the value of assets and liabilities transferred. The accumulated deficit in Exshaw of $228.8 million was then reclassified to share capital and contributed surplus balances in shareholder's equity for the continuing entity, upon receipt of shareholder approval.
1. On November 14, 2019, Topaz issued 20.85 million common shares for gross proceeds of $208.5 million. The Company incurred share issue costs of $5.0 million, net of tax. The net proceeds were used as consideration for the Acquisition described in note 8. Using the book value method to determine the value of assets and liabilities acquired from Tourmaline, management recorded net assets acquired in the amount of $637.0 million in exchange for the 58.0 million Topaz common shares with an assigned value of $442.5 million as well as cash to Tourmaline of $194.5 million.
1. On June 29, 2020, Topaz completed a private placement of 11.7 million common shares of the Company for gross proceeds of $128.6 million. The Company incurred share issue costs of $2.8 million, net of tax.

On July 6, 2020, Topaz completed a second tranche to its June 29, 2020 private placement and issued 1.5 million common shares for gross proceeds of $16.7 million. Following the second closing, Topaz was 63.5% owned by Tourmaline and 36.5% owned by other investors.

Dividends

For the three and six months ended June 30, 2020, the Company has paid $16.0 million ($0.20 per common share) and $32.0 million ($0.40 per common share), respectively, in dividends to its shareholders. No dividends were paid in 2019.

SHARE‐BASED COMPENSATION

Stock Options

The Company has a stock option plan in place whereby it may issue stock options to employees, consultants and directors of the Company. The aggregate number of shares that may be acquired upon exercise of all options granted pursuant to the plan shall, at any date or time of determination, be not greater than 8.5% of the number of the Company's basic common shares then issued and outstanding. Options are granted throughout the year and vest 1/3 on each of the first, second and third anniversaries from the date of grant and expire seven years from the date of issuance. At June 30, 2020, 1,850,000 stock options were outstanding.

	Number of StockOptions	W.A.(1)exercise price
Stock options outstanding, December 31, 2018	─	─
Granted	1,200,000	$10.00
Stock options outstanding, December 31, 2019	1,200,000	$10.00
Granted	650,000	$10.31
Stock options outstanding, June 30, 2020	1,850,000	$10.11

(1) Weighted average

The following table summarizes stock options outstanding and exercisable at June 30, 2020.

Exercise price	Numberoutstanding atperiod end	W.A. (1)remaining life	W.A. (1)exercise price	Numberexercisable atperiod end	W.A.(1)exercise price
$10.00 - $11.00	1,850,000	6.60	$10.11	─	─

(1) Weighted average

The fair value of stock options granted during the three and six months ended June 30, 2020 was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values:

	Three and six months endedJune 30, 2020
Fair value of options granted (weighted average)	$0.92
Risk-free interest rate	0.42%
Estimated hold period prior to exercise	5.0 years
Expected volatility	33%
Forfeiture rate	2%
Dividend per share	$0.80

The fair value of stock options granted during the period ended December 31, 2019 was estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions and resulting values:

	Year endedDec. 31, 2019(1)
Fair value of options granted (weighted average)	$0.84
Risk-free interest rate	1.64%
Estimated hold period prior to exercise	5.0 years
Expected volatility	30%
Forfeiture rate	2%
Dividend per share	$0.80

(1) Refer to note 5 "Discontinued Operations".

13. NET INCOME (LOSS) FROM CONTINUING OPERATIONS PER SHARE

Net income (loss) per share amounts are calculated by dividing the net income (loss) for the period attributable to the common shareholders of the Company by the weighted average number of common shares outstanding during the period.

For the period ended	Three months		Six months	Year ended
($000s, except for share information)	June 30, 2020	June 30, 2019(2)	June 30, 2020	June 30, 2019(2)	Dec. 31, 2019(2)
Net income (loss) from continuingoperations	(1,125)	─	(2,359)	─	653
W.A.(1) common shares - basic	80,256,926	─	80,128,463	─	80,000,000
W.A.(1) common shares - diluted	80,256,926	─	80,128,463	─	80,000,000
Net income (loss) per common share basicand diluted(3)	$(0.01)	─	$(0.03)	─	$0.01

(1) Weighted average

(2) Refer to note 5 "Discontinued Operations".

(3) For the three and six months ended June 30, 2020, 1,850,000 stock options, respectively, were excluded from the weighted average share calculation as they were anti-dilutive (three and six months ended June 30, 2019 – nil); year ended December 31, 2019 – 1,200,000). Refer to note 5 "Discontinued Operations" for 2019.

14. REVENUE

For the three and six months ended June 30, 2020, the Company had one operating segment: natural gas infrastructure and royalty production, as the chief operating decision maker reviews operating results at this level to assess financial performance and make resource allocation decisions. The operating segment includes the following revenue categories: royalty production revenue and processing revenue. The Company also generates other income by way of a contracted interest in third-party revenue through feefor-service natural gas processing contracts with no underlying facility ownership. Amounts disclosed below do not include realized or unrealized gains and losses on financial derivative contracts resulting from the Company's commodity price risk management activities.

Royalty production revenue

The Company's royalty production revenue is determined pursuant to the terms of its royalty agreements. The commodity prices for natural gas, crude oil and condensate are based on market index prices in the month of production. Royalty production revenue is generally received two months after the natural gas, crude oil, and condensate are produced.

The Company's processing revenue is generated through its non-operated ownership in processing facilities. The facilities provide natural gas processing services to customers on a fee-for-service basis. Certain fees include fixed take-or-pay arrangements under long-term commercial arrangements.

For the period ended		Three months	Six months		Year ended
($000s)	June 30, 2020	June 30, 2019(1)	June 30, 2020	June 30, 2019(1)	Dec. 31, 2019(1)
Royalty production revenue	11,935	─	26,449	─	9,832
Processing revenue	5,296	─	11,264	─	2,943
Total	17,231	─	37,713	─	12,775

(1) Refer to note 5 "Discontinued Operations".

15. FINANCE EXPENSES

For the period ended		Three months	Six months		Year ended
($000s)	June 30, 2020	June 30, 2019(1)	June 30, 2020	June 30, 2019(1)	Dec. 31, 2019(1)
Accretion of decommissioning obligations	2	─	4	─	2
Interest expense	60	─	60	─	─
Total finance expense	62	─	64	─	2

(1) Refer to note 5 "Discontinued Operations".

16. DEFERRED INCOME TAXES

For the period ended		Three months	Six months		Year ended
($000s, except for share information)	June 30, 2020	June 30, 2019(2)	June 30, 2020	June 30, 2019(2)	Dec. 31, 2019(2)
Income (loss) from continuing operations	(2,070)	─	(4,509)	─	575
Combined federal and provincial tax rate(1)	25.09%	─	25.09%	─	26.50%
Computed "expected" tax recovery	(519)	─	(1,131)	─	152
Increase/(decrease) in tax resulting from:Share-based paymentsRecognition of tax assetCurrent vs. future tax rate difference	52(513)35	───	89(1,192)84	───	7(218)(19)
Deferred tax recovery	(945)	─	(2,150)	─	(78)
Effective tax rate	46%	─	48%	─	14%

(1) The Alberta corporate income tax rate decreased to 11% (from 12%) effective July 1, 2019 and to 10% effective January 1, 2020. The

corporate tax rate will further decrease to 9% on January 1, 2021 and 8% on January 1, 2022.

(2) Refer to note 5 "Discontinued Operations".

The components of the Company's deferred tax position were as follows:

($000s)	June 30, 2020	December 31, 2019
Net book value of assets in excess of tax pools	(28,352)	(33,893)
Unrealized loss on financial instruments	128	─
Decommissioning obligations	164	146
Share issuance costs	1,814	1,203
Non-capital losses	78,883	82,186
Deferred tax asset	52,637	49,642

The movement in deferred tax balances during the periods ended June 30, 2020 and December 31, 2019 are as follows:

	Balance	Recognized in net	Recognized	Balance
($000s)	January 1, 2020	earnings	in equity	June 30, 2020
Deferred tax liabilities:
Petroleum and natural gas interests	(33,893)	5,541	─	(28,352)

Deferred tax assets:
Unrealized gain on financial instruments	─	128	─	128
Decommissioning obligation	146	18	─	164
Non-capital losses	82,186	(3,303)	─	78,883
Share issue costs	1,203	(234)	845	1,814
Deferred tax asset	49,642	2,150	845	52,637

	Balance	Recognized in net	Recognized	Balance

($000s)	January 1, 2019	earnings	in equity	Dec. 31, 2019
Deferred tax liabilities:
Petroleum and natural gas interests	11,692	(45,585)	─	(33,893)
Deferred tax assets:
Decommissioning obligation		146		146
Non-capital losses	─36,366	45,820	──	82,186
Share issue costs	─	(303)	1,506	1,203

Under the terms of the Initial Acquisition (note 8), the Company retained tax pools in the amount of approximately $775.0 million. The Company has not recognized deductible temporary differences of $70.7 million at June 30, 2020 ($74.4 million at December 31, 2019) related to the excess of tax pools acquired over the carrying value of the net assets transferred because the common control transaction is not a business combination and is therefore subject to the initial recognition exemption under IAS 12 "Income Taxes". Deferred income tax assets and liabilities are not recognized for temporary differences arising on the initial recognition of an asset or liability in a transaction that is not a business combination and at the time of the transaction, effects neither the accounting profit nor taxable benefit. The unrecognized deferred income tax asset is being amortized based on the net tax pool claims calculated for the period. The reversal of unrecognized deferred tax asset for the six months ended June 30, 2020 was $1.2 million (six months ended June 30, 2019 - nil and year ended December 31, 2019 - $0.2 million).

Management has assessed the recoverability of the deferred tax asset of $52.6 million at June 30, 2020. Based on future cash flow projections it has been determined that it is probable that future taxable profits will be available against which the deferred tax asset can be used.

17. SUPPLEMENTAL CASH FLOW INFORMATION

For the period endedThree months			Six months	Year ended
($000s)	June 30, 2019(1)June 30, 2020		June 30, 2019(1)June 30, 2020		Dec. 31, 2019(1)
Source (use) in non-cash working capital
Accounts receivable & deposits	6,557	─	76	─	(13,490)
Accounts payable and accrued liabilities	3,905	─	3,516	─	867
	10,462	─	3,592	─	(12,623)
Operating activities	6,849	─	(21)	─	(12,623)
Financing activities	3,613	─	3,613	─	─

(1) Refer to note 5 "Discontinued Operations".

18. RELATED PARTY TRANSACTIONS

In conjunction with the Initial Acquisition, Topaz entered into a number of agreements with Tourmaline including a royalty, facilities and revenue interest sale agreement, gross overriding royalty agreement, Topaz TPF revenue interest agreement, agreement for the construction, ownership and operation of the Brazeau Gas Plant Complex and agreement for the construction, ownership and operation of the Musreau Gas Plant Complex. Substantially all of Topaz's royalty production revenue, processing revenue and other income as described in these financial statements are derived from such agreements. Topaz also entered into an agreement with Tourmaline in connection with the E&P Asset Disposition.

In conjunction with the Initial Acquisition, Topaz entered into a management services agreement with Tourmaline pursuant to which Tourmaline provides certain management and administrative services required by the Company until such time that Topaz completes a Liquidity Event (as such term is defined in the agreement). During the three and six months ended June 30, 2020, Topaz paid $0.5 million and $1.1 million, respectively, in respect of this agreement which were in the normal course of operations. The management and administrative services agreement is scheduled to be reduced on a quarterly basis through 2020 as the Company adds its own personnel and administrative functions.

Key management personnel are persons who have the authority and responsibility for planning, directing and controlling the activities of the Company, directly or indirectly. Key management includes all directors and executives of the Company. The table below summarizes all key management personnel compensation included in the financial statements for the three and six months ended June 30, 2020 and 2019.

For the period ended	Three months		Six months	Year ended
($000s)	June 30, 2020	June 30, 2019(1)	June 30, 2020	June 30, 2019(1)	Dec. 31, 2019(1)
Salaries and benefits	156	─	156	─	─
Share-based compensation	204	─	353	─	25
Total	360	─	509	─	25

(1) Refer to note 5 "Discontinued Operations".

19. COMMITMENTS

At June 30, 2020, Topaz does not have any material commitments or contractual obligations, with the exception of the infrastructure acquisition agreement which was completed on July 2, 2020 (note 20).

20. SUBSEQUENT EVENTS

On July 2, 2020, Topaz completed the Glacier Gas Plant Acquisition. The purchase price was $100.0 million before customary adjustments.

On September 1, 2020, Topaz completed the Banshee Gas Plant Acquisition. The purchase price was $52.5 million before customary adjustments.

On September 18, 2020 Topaz's Credit Facility was amended to reflect an increase to the borrowing capacity from $75 million to $125 million.

The Company declared a dividend of $0.20 per share, to shareholders of record on September 15, 2020, to be paid on September 30, 2020.

INDEPENDENT AUDITORS' REPORT

To the Board of Directors of Tourmaline Oil Corp.

Opinion

We have audited the operating statement of Tourmaline Oil Corp. ("the Assets") for the period from January 1 to November 13, 2019 and for the years ended December 31, 2018 and 2017 containing the gross:

petroleum and natural gas revenue
royalty expenses
other income
operating expenses
operating income
and notes to the operating statement, including a summary of significant accounting policies.

(Hereinafter referred to as the "operating statement").

In our opinion, the accompanying operating statement for the period from January 1 to November 13, 2019 and for the years ended December 31, 2018 and 2017 of the Assets is prepared, in all material respects, in accordance with the financial reporting framework specified in section 3.17 of National Instrument 52-107, Acceptable Accounting Principles and Auditing Standards for Predecessor Statements or Primary Business Statements that are an Operating Statement.

Basis for Opinion

We conducted our audits in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the "Auditors' Responsibilities for the Audit of the Operating Statement" section of our auditors' report.

We are independent of Tourmaline Oil Corp. (the "Entity) in accordance with the ethical requirements that are relevant to our audit of the operating statement in Canada and we have fulfilled our other ethical responsibilities in accordance with these requirements.

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

Responsibilities of Management and Those Charged with Governance for the Operating Statement

Management of the Entity is responsible for the preparation of the operating statement in accordance with the financial reporting framework specified in section 3.17 of National Instrument 52-107, Acceptable Accounting Principles and Auditing Standards for Predecessor Statements or Primary Business Statements that are an Operating Statement, and for such internal control as management determines is necessary to enable the preparation of an operating statement that is free from material misstatement, whether due to fraud or error.

Those charged with governance of the Entity are responsible for overseeing the Entity's financial reporting process of the operating statement of the Assets.

Auditors' Responsibilities for the Audit of the Operating Statement

Our objectives are to obtain reasonable assurance about whether the operating statement as a whole is free from material misstatement, whether due to fraud or error, and to issue an auditors' report that includes our opinion.

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

We also:

• Identify and assess the risks of material misstatement of the operating statement, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion.

Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Entity's internal control.
Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.
Communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

Chartered Professional Accountants

Calgary, Canada •, 2020

•

Operating Statements of

TOURMALINE OIL CORP.

For the period from January 1 to November 13, 2019 and for the years ended December 31, 2018 and 2017

TOURMALINE OIL CORP.

Operating Statements

For the period from January 1 to November 13, 2019 and for the years ended December 31, 2018 and 2017

($000s)	Period fromJan.1-Nov.13, 2019	Year endedDecember 31, 2018	Year endedDecember 31, 2017

Revenue
Petroleum and natural gas (note 3)	1,539,320	1,706,557	1,647,352
Royalties	(71,260)	(77,369)	(80,638)
Other income	31,761	34,176	35,342
	1,499,821	1,663,364	1,602,056
Expenses
Operating (note 4)	(303,912)	(322,387)	(282,494)
Operating income	1,195,909	1,340,977	1,319,562

See accompanying notes to the operating statements

TOURMALINE OIL CORP.

Notes to the Operating Statements

For the period from January 1 to November 13, 2019 and for the years ended December 31, 2018 and 2017

1. BASIS OF PRESENTATION

These operating statements reflect the gross petroleum and natural gas revenue, royalty expenses, other income, operating expenses and operating income of certain petroleum and natural gas assets of Tourmaline Oil Corp. ("Tourmaline").

In November 2019, Topaz Energy Corp. ("Topaz") acquired from Tourmaline (i) a newly created gross overriding royalty interest on natural gas, crude oil, and condensate production on 100% of Tourmaline's existing developed and undeveloped lands; (ii) a non-operated 45% jointly owned interest in two of Tourmaline's existing natural gas processing facilities supported by newly created long-term take-or-pay commitments from Tourmaline in relation to the two facilities; and (iii) a newly created contracted interest in a portion of certain thirdparty revenue generated by natural gas processing and handling agreements to which Tourmaline is a party (collectively, the "Acquired Assets"). These operating statements reflect the gross revenue, royalties, operating expenses and operating income of the petroleum and natural gas assets from which the Acquired Assets will be derived.

The operating statements have been prepared by management of Tourmaline. These operating statements do not reflect the operations of the Acquired Assets but rather the gross petroleum and natural gas revenue, royalty expenses, other income, operating expenses and operating income of certain petroleum and natural gas assets of Tourmaline for the period from January 1 to November 13, 2019 and for the years ended December 31, 2018 and 2017.

The operating statements do not include any adjustments to reflect the newly created gross overriding royalty interest, the 45% interest acquired in the two gas processing facilities, the third-party revenue generated by natural gas processing and handling agreements, depletion and depreciation, accretion of decommissioning obligation, future capital costs, general and administrative expenses or income taxes.

These operating statements were prepared in accordance with the financial reporting framework specified in section 3.17 of National Instrument 52-107, Acceptable Accounting Principles and Auditing Standards for Predecessor Statements or Primary Business Statements that are an Operating Statement.

2. SIGNIFICANT ACCOUNTING POLICIES

(a) Revenue recognition

Revenue from the sale of crude oil, condensate, natural gas and natural gas liquids is recorded when control of the product is transferred to the buyer based on the consideration specified in the contracts with customers. This usually occurs when the product is physically transferred at the delivery point agreed upon in the contract and legal title to the product passes to the customer. The Company evaluates its arrangements with third parties and partners to determine if the Company acts as the principal or as an agent. In making this evaluation, the Company considers if it obtains control of the product delivered or services provided, which is indicated by the Company having the primary responsibility for the delivery of the product or rendering of the service, having the ability to establish prices or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in a transaction, then the revenue is recognized on a net-basis, only reflecting the fee, if any, realized by the Company from the transaction.

Tariffs and tolls charged to other entities for use of facilities owned by the Company are recognized as revenue as they accrue in accordance with the terms of the service or tariff and tolling agreements.

Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements.

Revenues do not include any amounts from financial derivative contracts.

(b) Operating expenses

Operating expenses include all the costs related to the operation of the petroleum and natural gas assets.

(c) Joint operations

The operating statements reflect only the proportionate interests of Tourmaline.

A-33

3. REVENUE

Tourmaline sells its production pursuant to fixed and variable priced contracts. The transaction price for variable priced contracts is based on the commodity price, adjusted for quality, location or other factors, whereby each component of the pricing formula can be either fixed or variable, depending on the contract terms. Under the contracts, Tourmaline is required to deliver a fixed volume of crude oil, condensate, NGL or natural gas to the contract counterparty. Revenue is recognized when a unit of production is delivered to the contract counterparty. The amount of revenue recognized is based on the agreed transaction price, whereby any variability in revenue related specifically to Tourmaline's efforts to deliver production, and therefore the resulting revenue is allocated to the production delivered in the period during which the variability occurs. As a result, none of the variable revenue is considered constrained.

The following table presents the commodity sales disaggregated by revenue source:

($000s)	Period fromJan.1-Nov.13, 2019	Year endedDecember 31, 2018	Year endedDecember 31, 2017
Sales from production
Natural gas	881,462	894,944	1,053,409
Oil	151,268	167,910	125,563
Condensate	360,477	413,770	303,469
NGL	146,113	229,933	164,911
Total petroleum and natural gas sales	1,539,320	1,706,557	1,647,352

4. OPERATING EXPENSES

Operating expenses include all periodic lease and field-level expenses and excludes income recoveries from processing third-party volumes. The following table presents the operating expenses incurred in respect of the Acquired Assets for the period from January 1 to November 13, 2019 and for the years ended December 31, 2019, 2018 and 2017, disaggregated from Tourmaline's consolidated operating expenses.

($000s)	Period fromJan.1-Nov.13, 2019	Year endedDecember 31, 2018	Year endedDecember 31, 2017
Operating expenses (Acquired Assets)	7,695	6,626	5,925
Other operating expenses	296,217	315,761	276,569
Total operating expenses	303,912	322,387	282,494

Pro Forma Operating Statements of

TOPAZ ENERGY CORP.

For the years ended December 31, 2019, 2018 and 2017

A-35

TOPAZ ENERGY CORP.

Pro Forma Operating Statement

Year ended December 31, 2019

(unaudited)

($000s)
	Nov.14 – Dec. 31,	Jan.1- Nov.13, 2019
	2019	Gross Tourmaline	Pro forma		Pro forma Topaz
	Topaz Energy Corp.	audited balance	adjustments	Notes	Energy Corp.
Revenue
Royalty production revenue	9,832	─	43,125	2(a)	52,957
Petroleum and natural gas	─	1,539,320	(1,539,320)	2(d)	─
Processing revenue	2,943	─	18,644	2(b)	21,587
Other income	1,408	31,761	(19,950)	2(c)	13,219
Royalties	─	(71,260)	71,260	2(d)	─
	14,183	1,499,821	(1,426,241)		87,763
Expenses
Operating	(481)	(303,912)	300,584	2(d)	(3,809)
Net operating income	13,702	1,195,909	(1,125,657)		83,954

See accompanying notes to the pro forma operating statements

TOPAZ ENERGY CORP.

Pro Forma Operating Statement

Year ended December 31, 2018

(unaudited)

($000s)		Gross Tourmaline	Pro forma		Pro forma Topaz
	Topaz Energy Corp.	audited balance	adjustments	Notes	Energy Corp.
Revenue
Royalty production revenue	─	─	44,290	2(a)	44,290
Petroleum and natural gas	─	1,706,557	(1,706,557)	2(d)	─
Processing revenue	─	─	21,793	2(b)	21,793
Other income	─	34,176	(13,866)	2(c)	20,310
Royalties	─	(77,369)	77,369	2(d)	─
	─	1,663,364	(1,576,971)		86,393
Expenses
Operating	─	(322,387)	319,107	2(d)	(3,280)
Net operating income	─	1,340,977	(1,257,864)		83,113

See accompanying notes to the pro forma operating statements

TOPAZ ENERGY CORP.

Pro Forma Operating Statement

Year ended December 31, 2017

(unaudited)

($000s)	Topaz Energy Corp.	Gross Tourmalineaudited balance	Pro formaadjustments	Notes	Pro forma TopazEnergy Corp.
Revenue
Royalty production revenue	─	─	49,375	2(a)	49,375
Petroleum and natural gas	─	1,647,352	(1,647,352)	2(d)	─
Processing revenue	─	─	21,654	2(b)	21,654
Other income	─	35,342	(13,941)	2(c)	21,401
Royalties	─	(80,638)	80,638	2(d)	─
	─	1,602,056	(1,509,626)		92,430
Expenses
Operating	─	(282,494)	279,561	2(d)	(2,933)
Net operating income	─	1,319,562	(1,230,065)		89,497

See accompanying notes to the pro forma operating statements

1. Basis of presentation

The accompanying unaudited pro forma operating statements of Topaz Energy Corp. (the "Company" or "Topaz"), for the years ended December 31, 2019, 2018 and 2017 (the "pro forma operating statements") have been prepared to reflect the acquisition by Topaz of certain interests in petroleum and natural gas properties from Tourmaline Oil Corp. ("Tourmaline") on November 14, 2019. The assets acquired pursuant to the Initial Acquisition included: (i) a newly created gross overriding royalty interest on natural gas, crude oil, and condensate production on 100% of Tourmaline's existing developed and undeveloped lands; (ii) a non-operated 45% jointly owned interest in two of Tourmaline's existing 19 natural gas processing facilities supported by newly created long-term take-or-pay commitments from Tourmaline in relation to the two facilities; and (iii) a newly created contracted interest in a portion of certain thirdparty revenues generated by natural gas processing and handling agreements to which Tourmaline is a party (collectively, the "Acquired Assets").

Prior to the completion of the Acquired Assets, Topaz (named "Exshaw Oil Corp." prior to November 8, 2019 ("Exshaw")) had been engaged in upstream oil and gas exploration and production. On November 12, 2019 Topaz sold all of its E&P assets (representing substantially all of its assets) to Tourmaline (the "E&P Asset Disposition").

Topaz does not conduct upstream petroleum and natural gas exploration and production and as a result the Company has presented the results of Exshaw's operations as discontinued operations. As a result, the pro forma operating statements reflect the actual results of operations for the period from November 14, 2019 to December 31, 2019. The pro forma operating statements for the period January 1, 2019 to November 13, 2019, and the years ended December 31, 2018 and 2017 reflect the pro forma results from continuing operations had the agreements been in place effective January 1 of each year.

The unaudited pro forma operating statements have been prepared by management in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board ("IASB"). Accounting policies used in the preparation of the unaudited pro forma operating statements are in accordance with those disclosed in the Company's audited financial statements as at June 30, 2020 and December 31, 2019, and for the three and six months ended June 30, 2020 and for the year ended December 31, 2019.

The unaudited pro forma operating statements may not be indicative of the results, that actually would have occurred if the events reflected therein had been in effect on the dates indicated, or of the results which may be obtained in the future.

The unaudited pro forma operating statements have been prepared from information derived from the following:

The Company's audited financial statements as at June 30, 2020 and December 31, 2019, and for the three and six months ended June 30, 2020 and for the year ended December 31, 2019.
The audited Operating Statements of Tourmaline reflecting the gross petroleum and natural gas revenue, royalty expenses, other income, operating expenses and operating income of certain assets of Tourmaline for the period from January 1 to November 13, 2019 and for years ended December 31, 2018 and 2017.

The unaudited pro forma operating statements do not include any provision for depletion and depreciation, asset retirement obligations, future capital costs, impairment of unevaluated properties, general and administrative expenses or income taxes, as these amounts are based on the operations of Topaz.

2. Adjustments

The unaudited pro forma operating statements for the years ended December 31, 2019, 2018 and 2017 were derived from the results from continuing operations of Topaz and from the audited Operating Statements of Tourmaline reflecting the gross revenue, royalties, operating expenses and operating income of certain assets for the periods ended December 31, 2019, 2018 and 2017 and adjusted as follows:

a. The Acquired Assets included a newly created gross overriding royalty interest on natural gas, crude oil, and condensate production on 100% of Tourmaline's existing developed and undeveloped lands as follows:
- i) a 4% gross overriding royalty on natural gas production until December 31, 2021; and a 3% gross overriding royalty thereafter. The gross overriding royalty for gas is based off the AECO 5A monthly index prices.
- ii) a 2.5% gross overriding royalty on oil and condensate production. The gross overriding royalty for oil is based off the Peace Sour (C$/Bbl) benchmark price and condensate is based off the Namao Peace Condensate (C$/Bbl) benchmark price.

The adjustments to royalty production revenue reflect the 4% gross overriding royalty for gas and the 2.5% gross overriding royalty for oil and condensate derived from the audited Operating Statements of Tourmaline for the period from January 1, 2019 to November 13, 2019 and for the years ended December 31, 2018 and 2017. In addition, the adjustment reflects a single benchmark pricing for natural gas being AECO 5A monthly index in calculating the natural gas gross overriding royalty production revenue. The adjustments described above resulted in the following adjustments to the unaudited pro forma operating statements: 2019 - $43,125; 2018 - $44,290; and 2017 - $49,357.

b. The Acquired Assets include a non-operated 45% jointly owned interest in two natural gas processing facilities supported by newly created long-term take-or-pay contracts with Tourmaline in relation to the two facilities. As a result, adjustments to processing revenue were made to reflect the take-or-pay contracts (2019 - $18,644, 2018 - $21,793, and 2017 - $21,654). In addition, an adjustment to operating costs was made to reflect Topaz's 45% working interest share of operating expenses related to the Acquired Assets (2019 - $3,328, 2018 - $3,280, and 2017 - $2,933).
c. The Acquired Assets also included a newly created contracted interest in a portion of certain third-party revenue generated by natural gas processing and handling agreements to which Tourmaline is a party. Topaz earns 100% of Tourmaline's third-party revenue up to a maximum of $16 million per year, and any amount over $16 million per year is split between Topaz (70%) and Tourmaline (30%). As a result, an adjustment to other income was made to reflect the newly created third-party income (2019 - $19,950, 2018 - $13,866, and 2017 - $13,941).

Due to the Operating Statements of Tourmaline including all of the gross revenue, royalties, operating expenses and operating income of certain assets of Tourmaline, the unaudited pro forma Operating Statements were adjusted to remove the gross petroleum and natural gas production revenue, gross royalties, and gross operating costs that Topaz is not contractually entitled to or obligated to incur (2019 - $303,912; 2018 - $322,387; and 2017 - $282,494). The pro forma adjustments for operating expenses are presented net of the pro forma adjustments noted in 2(b) (2019 - $300,584; 2018 - $319,107; and 2017 - $279,561).

APPENDIX "B"

SUPPLEMENTAL INFORMATION REGARDING THE TOURMALINE GORR LANDS

Notice to Reader

Unless the context indicates otherwise, capitalized terms which are used in this Appendix "B" and not otherwise defined in this Appendix "B" have the meanings given to such terms under the heading "Glossary" in the prospectus.

Supplemental Disclosure of Tourmaline Reserves Data

The reserves data set forth below is based upon the Tourmaline Consolidated Reserve Report. The Tourmaline Consolidated Reserve Report evaluates, as at December 31, 2019, the crude oil, NGL and natural gas reserves of Tourmaline and, notwithstanding that Tourmaline owned 74% of Topaz as at December 31, 2019, includes the full impact of the Initial Assets.

GLJ evaluated in the Tourmaline GLJ Reserve Report approximately 82.7% of the assigned total proved plus probable reserves and 80.0% of the total proved plus probable future net revenue discounted at 10% recognized in the Tourmaline Consolidated Reserve Report. Deloitte evaluated in the Tourmaline Deloitte Reserve Report approximately 17.3% of the assigned total proved plus probable reserves and 20.0% of the total proved plus probable future net revenue discounted at 10% recognized in the Tourmaline Consolidated Reserve Report. Deloitte evaluated in the Tourmaline Deloitte Reserve Report Tourmaline's greater Hinton, Kakwa and Alberta Foothills properties located in the Alberta Deep Basin and Tourmaline's Mulligan and Spirit River properties located in the Alberta portion of the Peace River High. Deloitte incorporated the forecast price and cost assumptions as described below under the heading "Tourmaline Consolidated Reserve Report Pricing Assumptions" in their evaluation. GLJ evaluated in the Tourmaline GLJ Reserve Report the balance of Tourmaline's properties.

GLJ prepared the Tourmaline Consolidated Reserve Report by consolidating the Tourmaline GLJ Reserve Report with the Tourmaline Deloitte Reserve Report adjusted to apply certain of GLJ's assumptions and methodologies used in the preparation of the Tourmaline GLJ Reserve Report to the Tourmaline Deloitte Reserve Report. Accordingly, the consolidated reserves information below varies from the reserve information that would be derived from a simple arithmetic summation of the Tourmaline GLJ Reserve Report and the Tourmaline Deloitte Reserve Report. Also due to rounding, certain columns may not add. The price forecast used in the reserve evaluations is an equal weighted average of the January 1, 2020 price forecasts for GLJ, Sproule and McDaniel.

The Tourmaline Consolidated Reserve Report has been prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101 and the COGE Handbook. Additional information not required by NI 51-101 has been presented to provide continuity. GLJ and Deloitte were engaged to provide evaluations of proved and proved plus probable reserves and no attempt was made to evaluate possible reserves.

Shale natural gas is required to be presented separately from conventional natural gas as its own product type pursuant to NI 51-101. While the Tourmaline Montney reserves do not strictly fit the definition of "shale gas" as defined in NI 51-101 because the natural gas is not "primarily adsorbed" as stated within the definition, the Montney reserves have been included as shale gas for purposes of this disclosure.

All of Tourmaline's consolidated reserves are in Canada and, more specifically, substantially all are in the provinces of Alberta and British Columbia.

The applicable Reports on Reserves Data by Independent Qualified Reserves Evaluators in Form 51-101F2 and the Report of Management and Directors on Oil and Gas Disclosure in Form 51-101F3 are attached as Appendix "C" through "D" to this prospectus.

There are numerous uncertainties inherent in estimating quantities of crude oil, natural gas and NGL reserves and the future cash flows attributed to such reserves. The reserve and associated cash flow information set forth in this prospectus are estimates only. In general, estimates of economically recoverable 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 reserve recovery, timing and amount of capital expenditures, marketability of 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, estimates of the economically recoverable crude oil, NGL 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 engineers, or by the same engineers at different times, may vary. Tourmaline's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material.

The information relating to Tourmaline's crude oil, NGL and natural gas reserves contains forward-looking statements relating to future net revenues, forecast capital expenditures, future development plans and costs related thereto, forecast operating costs, anticipated production and abandonment and reclamation costs. See "Notice to Investors – Forward-Looking Statements", "Notice to Investors – Certain Reserves Data and Other Oil and Gas Information", "The Industry" and "Risk Factors" in this prospectus.

Reserves and Future Net Revenue Data (Forecast Prices and Costs)

The following tables summarize Tourmaline's gross reserves defined as the working interest share of reserves prior to the deduction of interest owned by others (burdens). Royalty interest reserves are not included in company gross reserves. Company net reserves are defined as the working net carried, and royalty interest reserves after deduction of all applicable burdens.

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2019 Forecast Prices and Costs(1)

	Light & Medium CrudeOil		Conventional NaturalGas		Shale Natural Gas		Natural Gas Liquids		Total Oil Equivalent
Reserves Category	CompanyGross(Mbbls)	CompanyNet(Mbbls)	CompanyGross(MMcf)	CompanyNet(MMcf)	CompanyGross(MMcf)	CompanyNet(MMcf)	CompanyGross(Mbbls)	CompanyNet(Mbbls)	CompanyGross(Mboe)	CompanyNet(Mboe)
Proved Producing	13,948	11,422	1,676,894	1,505,877	910,873	844,148	82,118	68,535	527,361	471,628
Proved Developed Non-Producing	1,935	1,504	95,010	85,260	208,272	196,007	12,432	10,958	64,914	59,340
Proved Undeveloped	32,189	26,203	1,929,133	1,751,774	1,408,310	1,308,908	113,735	102,419	702,164	638,736
TotalProved	48,072	39,130	3,701,036	3,342,911	2,527,455	2,349,063	208,285	181,912	1,294,439	1,169,704
Total Probable	48,912	39,478	2,412,245	2,173,075	3,653,824	3,279,086	247,566	210,547	1,307,490	1,158,719
Total Proved Plus Probable	96,984	78,608	6,113,281	5,515,987	6,181,279	5,628,148	455,851	392,458	2,601,928	2,328,422

Net Present Values of Future Net Revenue ($000s)

			Before Income Taxes Discounted at (2)(%/year)			After Income Taxes Discounted at (2) (3)(%/year)						Unit Value BeforeIncome TaxDiscountedat 10%/year
Reserves Category	0	5	10	15	20	0	5	10	15	20	($/Boe)	($/Mcfe)
Proved Producing	6,776,073	5,475,633	4,579,234	3,953,261	3,496,236	6,513,916	5,329,729	4,494,030	3,901,446	3,463,622	9.71	1.62
Proved Developed Non-Producing	951,690	723,446	581,989	487,603	420,666	703,333	555,992	464,566	402,764	357,903	9.81	1.63
Proved Undeveloped	8,114,346	5,258,108	3,623,511	2,611,296	1,943,173	5,988,919	3,824,651	2,584,398	1,819,464	1,317,883	5.67	0.95
Total Proved	15,842,109	11,457,187	8,784,733	7,052,160	5,860,075	13,206,167	9,710,371	7,542,994	6,123,674	5,139,408	7.51	1.25
Total Probable	20,521,808	10,555,460	6,308,597	4,165,195	2,945,016	15,169,537	7,746,820	4,579,558	2,987,161	2,086,554	5.44	0.91
Total Proved Plus Probable
	36,363,916	22,012,647	15,093,330	11,217,355	8,805,091	28,375,704	17,457,191	12,122,552	9,110,834	7,225,961	6.48	1.08

(1) Numbers may not add due to rounding.
(2) Values are presented on the basis that all Revenue Streams sold to Topaz are excluded from these tables notwithstanding the fact Tourmaline owned 74% of Topaz as at December 31, 2019.
(3) The after-tax net present value of Tourmaline's oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider Tourmaline's tax situation, or tax planning. It does not provide an estimate of the value at the company level for Tourmaline which may be significantly different.

Total Future Net Revenue ($000s) (Undiscounted) as of December 31, 2019 Forecast Prices and Costs(1)

Reserves Category	Revenue	Royalties(2)	OperatingCosts	CapitalDevelopmentCosts	AbandonmentandReclamationCosts	Future NetRevenueBeforeIncome Tax	IncomeTax	Future NetRevenueAfterIncomeTax(3)
Proved Producing	12,077,042	1,248,887	3,611,456	50	440,576	6,776,073	262,157	6,513,916
Proved Developed Non-Producing	1,573,143	164,268	368,213	66,242	22,730	951,690	248,357	703,333
Proved Undeveloped……………	17,308,773	1,640,354	3,550,448	3,805,349	198,275	8,114,346	2,125,427	5,988,919
Total Proved……………………	30,958,957	3,053,509	7,530,117	3,871,642	661,581	15,842,109	2,635,941	13,206,167
Total Probable……………………	37,823,111	4,827,222	8,615,423	3,532,409	326,248	20,521,808	5,352,271	15,169,537
Total Proved Plus Probable………	68,782,068	7,880,731	16,145,540	7,404,051	987,829	36,363,916	7,988,212	28,375,704

Notes:

(1) Numbers may not add due to rounding.

(2) Values are presented on the basis that all Revenue Streams sold to Topaz are excluded from these tables notwithstanding the fact Tourmaline owned 74% of Topaz as at December 31, 2019.
(3) The after-tax net present value of Tourmaline's oil and gas properties reflects the tax burden on the properties on a stand-alone basis. It does not consider Tourmaline's tax situation, or tax planning. It does not provide an estimate of the value at the company level for Tourmaline, which may be significantly different.

Future Net Revenue by Production Type as of December 31, 2019 Forecast Prices and Costs

		Future NetRevenue BeforeIncome Taxes	Unit Value(discounted at10%/year)(2)
Reserves Category	Production Type(1)	(discounted at10%/year)($000s)(2)	($/Boe)	($/Mcfe)
Proved Reserves	Light and Medium Crude Oil	1,214,986	11.62	1.94
	Conventional Natural Gas	3,247,914	5.84	0.97
	Shale Natural Gas	4,321,833	8.49	1.41
	Total	8,784,733	7.51	1.25
Proved Plus Probable	Light and Medium Crude Oil	1,965,330	9.38	1.56
	Conventional Natural Gas	4,919,036	5.50	0.92
	Shale Natural Gas	8,208,964	6.71	1.12
	Total	15,093,330	6.48	1.08

Notes:

(1) By-products, including solution gas, NGL and other associated by-products are included in their main product group (natural gas or oil).
(2) Values are presented on the basis that all Revenue Streams sold to Topaz are excluded from these tables notwithstanding the fact Tourmaline owned 74% of Topaz as at December 31, 2019.

Reconciliation of Changes in Reserves

Reconciliation of Company Gross Reserves by Principal Product Type Forecast Prices and Costs

		Light and Medium Crude Oil		Conventional Natural Gas
Factors	GrossProved(Mbbl)	GrossProbable(Mbbl)	GrossProved PlusProbable(Mbbl)	GrossProved(MMcf)	GrossProbable(MMcf)	GrossProved PlusProbable(MMcf)
December 31, 2018	39,626	42,421	82,047	3,669,359	2,402,017	6,071,376
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	5,081	4,972	10,053	320,573	80,700	401,273
Technical Revisions	(6,573)	(12,060)	(18,633)	60,802	(164,321)	(103,519)
Acquisitions	12,969	13,750	26,719	88,590	97,415	186,005
Dispositions	-	-	-	-	-	-
Economic Factors	(98)	(171)	(269)	(87,154)	(3,566)	(90,720)
Production	(2,932)	-	(2,932)	(351,135)	-	(351,135)
December 31, 2019	48,072	48,912	96,984	3,701,036	2,412,245	6,113,281

				Total
		Shale Natural Gas	Natural Gas Liquids
Factors	GrossProved(MMcf)	GrossProbable(MMcf)	GrossProved PlusProbable(MMcf)	GrossProved(Mbbl)	GrossProbable(Mbbl)	GrossProved PlusProbable(Mbbl)
December 31, 2018	2,218,064	3,423,238	5,641,302	185,518	237,680	423,198
Discoveries	-	-	-	-	-	-
Extensions and Improved Recovery	374,021	110,239	484,260	32,220	6,845	39,065
Technical Revisions	92,533	103,835	196,368	7,425	(980)	6,445
Acquisitions	16,178	20,589	36,767	3,207	3,673	6,880
Dispositions	-	-	-	-	-	-
Economic Factors	(7,788)	(4,077)	(11,865)	(2,827)	348	(2,479)
Production	(165,553)	-	(165,553)	(17,258)	-	(17,258)
December 31, 2019	2,527,455	3,653,824	6,181,279	208,285	247,566	455,851

		Total Boe
Factors	GrossProved(Mboe)	GrossProbable(Mboe)	GrossProved PlusProbable(Mboe)
December 31, 2018	1,206,381	1,250,976	2,457,357
Discoveries	-	-	-
Extensions and Improved Recovery	153,066	43,641	196,707
Technical Revisions	26,408	(23,121)	3,286
Acquisitions	33,637	37,090	70,727
Dispositions	-	-	-
Economic Factors	(18,748)	(1,097)	(19,845)
Production	(106,305)	-	(106,305)
December 31, 2019	1,294,439	1,307,489	2,601,928

Notes to Reserves Data Tables:

(1) Numbers may not add due to rounding.

(2) Tourmaline has no bitumen, coalbed methane, gas hydrates, heavy crude oil, synthetic crude oil or synthetic gas reserves.

(3) Company gross reserves do not include royalty interests received by Tourmaline.

(4) The crude oil, NGL, conventional natural gas and shale natural gas reserve estimates presented in the Tourmaline Consolidated Reserve Report are based on the definitions and guidelines contained in the COGE Handbook. A summary of those definitions are set forth below.

Reserve Categories

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:

Analysis of drilling, geological, geophysical and engineering data;
The use of established technology; and
Specified economic conditions, which are generally accepted as being reasonable, and shall be disclosed.

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

(a) Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
(b) Probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

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

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

(a) Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.
- (i) Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
- (ii) Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.
(b) Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed nonproducing. 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.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(a) at least a 90 percent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and
(b) at least a 50 percent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A quantitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of 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 the COGE Handbook.

(5) Well abandonment, disconnect and surface reclamation costs were estimated and included in the Tourmaline Consolidated Reserve Report for both wells that were assigned reserves and inactive wells that were not assigned reserves. Complete abandonment, disconnect and surface reclamation costs have also been estimated for gathering systems, batteries, plants and processing facilities.

Tourmaline Consolidated Reserve Report Pricing Assumptions

Summary of Pricing and Inflation Rate Assumptions Forecast Prices and Costs (1)

Crude Oil and Natural Gas Liquids Pricing

	NYMEX WTI NearMonth Futures ContractCrude Oil at Cushing,Oklahoma			BrentBlend	MSW,LightCrudeOil (40API,	BowRiverCrudeOilStream	WCSCrudeOilStream	HeavyCrudeOilProxy	LightSourCrudeOil (35API,	MediumCrudeOil (29API,			Alberta Natural Gas Liquids(Then Current Dollars)
Year	Inflation(2)%	CAD/USDExchangeRate$US/$Cdn(3)	Constant2020$$US/Bbl	ThenCurrent$US/Bbl	CrudeOil FOBNorthSeaThenCurrent$US/Bbl	0.3%S)atEdmonton ThenCurrent$Cdn/Bbl	QualityatHardistyThenCurrent$Cdn/Bbl	QualityatHardistyThenCurrent$Cdn/Bbl	(12 API)atHardistyThenCurrent$Cdn/Bbl	1.2%S)atCromerThenCurrent$Cdn/Bbl	2.0%S)atCromerThenCurrent$Cdn/Bbl	SpecEthane$Cdn/Bbl	EdmontonPropane$Cdn/Bbl	EdmontonButane$Cdn/Bbl	EdmontonC5+ Stream Quality$Cdn/Bbl
2020	0.0	0.7600	61.00	61.00	66.33	72.64	58.43	57.57	51.23	72.16	70.22	6.42	26.36	42.09	76.83
2021	1.7	0.7700	62.70	63.75	67.94	76.06	63.00	62.35	56.11	75.23	73.15	7.41	29.80	47.03	79.82
2022	2.0	0.7850	63.82	66.18	70.06	78.35	64.99	64.33	57.72	77.50	74.95	8.33	32.94	50.66	82.30
2023	2.0	0.7850	64.20	67.91	71.66	80.71	66.91	66.23	59.45	79.83	77.19	8.65	34.00	52.21	84.72
2024	2.0	0.7850	64.40	69.48	73.27	82.64	68.65	67.96	61.09	81.76	79.05	8.98	34.89	53.48	86.71
2025	2.0	0.7850	64.58	71.07	74.57	84.60	70.41	69.72	62.75	83.69	80.92	9.24	35.78	54.77	88.73
2026	2.0	0.7850	64.75	72.68	76.22	86.57	72.20	71.49	64.43	85.66	82.82	9.46	36.69	56.07	90.77
2027	2.0	0.7850	64.84	74.24	77.83	88.49	73.91	73.19	66.04	87.57	84.66	9.67	37.57	57.32	92.76
2028	2.0	0.7850	64.84	75.73	79.36	90.31	75.53	74.80	67.55	89.37	86.40	9.89	38.41	58.50	94.65
2029	2.0	0.7850	64.85	77.24	80.92	92.17	77.17	76.43	69.08	91.21	88.17	10.12	39.26	59.71	96.57
2030	2.0	0.7850	64.85	78.79	82.54	94.01	78.72	77.96	70.47	93.04	89.94	10.35	40.11	60.90	98.53
2031	2.0	0.7850	64.85	80.36	84.19	95.89	80.29	79.52	71.87	94.90	91.74	10.56	40.91	62.12	100.50
2032	2.0	0.7850	64.84	81.97	85.87	97.81	81.90	81.11	73.31	96.80	93.57	10.77	41.73	63.36	102.51
2033	2.0	0.7850	64.84	83.61	87.59	99.76	83.54	82.73	74.78	98.73	95.44	10.98	42.56	64.63	104.56
20342035	2.02.0	0.7850	64.85	85.28	89.35+2.0%/y	101.76	85.21	84.39	76.27	100.71	97.35	11.20	43.42	65.92	106.65
		0.7850	64.85	+2.0%/yr	r	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr

							Alberta Plant Gate		Saskatchewan Plant Gate				British Columbia
		NYMEX Henry HubNear Month Contract				Spot
Year	Constant2020 $$US/MMbtu	Then Current$US/MMbtu	Midwest Price@ ChicagoThen Current$US/MMbtu	AECO/NITSpotThen Current$Cdn/MMbtu	Dawn Price@ Ontario ThenCurrent$US/MMbtu	Constant 2020$$Cdn/MMbtu	Then Current$Cdn/MMbtu	ARP $Cdn/MMbtu	SaskEnergy$Cdn/MMbtu	Spot$Cdn/MMbtu	Sumas Spot$US/MMbtu	WestcoastStation 2$Cdn/MMbtu	Spot Plant Gate$Cdn/MMbtu
2020	2.62	2.62	2.53	2.04	2.58	1.82	1.82	1.83	1.93	2.49	2.16	1.66	1.41
2021					2.82
2022	2.82	2.87	2.78	2.32	3.01	2.07	2.10	2.11	2.21	2.72	2.44	1.99	1.74
2023	2.95	3.06	2.96	2.62	3.12	2.30	2.39	2.40	2.50	2.89	2.72	2.31	2.07
	2.99	3.17	3.07	2.71		2.35	2.48	2.50	2.60	2.88	2.83	2.46	2.21
2024	3.01	3.24	3.15	2.81	3.20	2.39	2.58	2.59	2.70	2.98	2.90	2.56	2.31
2025	3.02	3.32	3.23	2.89	3.27	2.41	2.66	2.67	2.77	3.06	2.98	2.66	2.42
2026	3.02	3.39	3.30	2.96	3.34	2.42	2.72	2.74	2.84	3.13	3.05	2.73	2.48
2027					3.41
2028	3.02	3.46	3.36	3.03	3.48	2.43	2.78	2.80	2.91	3.20	3.12	2.80	2.54
	3.02	3.52	3.43	3.10		2.44	2.85	2.87	2.98	3.27	3.18	2.87	2.61
2029	3.02	3.60	3.50	3.17	3.55	2.45	2.92	2.94	3.05	3.34	3.26	2.93	2.68
2030	3.02	3.67	3.58	3.24	3.62	2.46	2.99	3.00	3.12	3.41	3.33	3.00	2.74
2031	3.02				3.69		3.05	3.07			3.39	3.06	2.80
2032	3.02	3.74	3.65	3.30	3.77	2.46	3.11	3.13	3.18	3.48	3.46	3.12	2.85
2033	3.02	3.81	3.72	3.37	3.84	2.46	3.17	3.19	3.24	3.55	3.54	3.19	2.91
		3.89	3.80	3.43		2.46			3.30	3.62
2034	3.02	3.97	3.87	3.50	3.92	2.46	3.23	3.25	3.37	3.70	3.61	3.25	2.97
2035	3.02	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	2.46	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr	+2.0%/yr

Natural Gas and Sulphur Pricing

Notes:

(1) Crude oil and natural gas benchmark reference pricing, inflation and exchange rates utilized by GLJ in the Tourmaline GLJ Reserve Report and Deloitte in the Tourmaline Deloitte Reserve Report, were an average of forecast prices and costs published by Sproule as at December 31, 2019 and GLJ and McDaniel as at January 1, 2020 (each of which is available on their respective websites at www.sproule.com, www.gljpc.com, and www.mcdan.com). GLJ assigns a value to Tourmaline's existing physical diversification contracts for natural gas for consuming markets at Dawn, Chicago, Ventura, Malin and PG&E based on forecasted differentials to NYMEX Henry Hub as per the aforementioned consultant average price forecast, contracted volumes and transportation costs. No incremental value is assigned to potential future contracts which were not in place as of December 31, 2019.
(2) Inflation rates used for forecasting prices and costs.
(3) Exchange rates used to generate the benchmark reference prices in this table.

During the year ended December 31, 2019, Tourmaline received the following weighted average prices, including realized gains and losses on financial instruments, in respect of its production: natural gas – $2.59/Mcf; NGL – $15.33/Bbl; and oil and condensate – $68.50/Bbl. The overall weighted average price received by Tourmaline on an oil equivalent basis was $20.04/Boe.

Additional Information Relating to Reserves Data

The additional information contained in this section pertains to Tourmaline and Exshaw on a consolidated basis and references to Tourmaline include Exshaw (without reduction to reflect the 9.4% third-party minority interest in Exshaw for years 2017 and 2018 as well as from January 1, 2019 to October 31, 2019). On October 31, 2019, Exshaw became a wholly-owned subsidiary of Tourmaline.

Undeveloped Reserves

The following tables set forth the proved undeveloped reserves and the probable undeveloped reserves, each by product type, attributed to Tourmaline's properties as at the end of the financial years ended December 31, 2019, 2018 and 2017.

Proved Undeveloped Reserves

Year	Light Crude Oil andMedium Crude Oil(Mbbl)			Conventional Natural Gas(MMcf)		Shale Natural Gas(2)(MMcf)		Natural Gas Liquids(Mbbl)		MBoe OilEquivalent
	FirstAttributed(1)	Cumulativeat Year-end	FirstAttributed	Cumulativeat Year-end	FirstAttributed	Cumulativeat Year-end	FirstAttributed	Cumulativeat Year-end	FirstAttributed	Cumulativeat Year-end
2017	4,447	20,692	366,973	1,790,816	185,067	1,028,389	13,069	83,560	109,613	574,119
2018	4,056	25,008	266,730	1,927,661	178,286	1,310,007	16,658	106,988	94,884	671,607
2019	2,370	32,189	128,803	1,929,133	130,035	1,408,310	11,108	113,735	56,618	702,164

Notes:

(1) "First Attributed" refers to reserves first attributed on the effective date of the corresponding fiscal year.

(2) Because of product type guidelines and definitions, contained in NI 51-101, Tourmaline's Montney proved reserves are classified as shale natural gas.

It is anticipated that most of the proved undeveloped locations will be drilled by December 31, 2023.

Probable Undeveloped Reserves

Year		Light Crude Oil andMedium Crude Oil(Mbbl)		Conventional Natural Gas(MMcf)		Shale Natural Gas(2)(MMcf)		Natural Gas Liquids(Mbbl)		MBoe OilEquivalent
	FirstAttributed(1)	Cumulativeat Year-end	FirstAttributed	Cumulativeat Year-end	FirstAttributed	Cumulativeat Year-end	FirstAttributed	Cumulativeat Year-end	FirstAttributed	Cumulativeat Year-end
2017	7,230	28,508	293,590	1,698,090	158,300	2,956,703	11,651	193,252	94,197	997,559
2018	4,699	35,637	268,608	1,793,200	84,574	3,085,264	14,790	209,952	78,353	1,058,666
2019	4,961	42,224	140,471	1,821,303	224,623	3,249,233	16,397	215,010	82,206	1,102,323

Notes:

(1) "First Attributed" refers to reserves first attributed on the effective date of the corresponding fiscal year.

(2) Because of product type guidelines and definitions, contained in NI 51-101, Tourmaline's Montney probable reserves are classified as shale natural gas.

It is anticipated that most of the future development capital associated with the probable undeveloped reserves will be incurred by December 31, 2025.

In general, once proved and/or probable undeveloped reserves are identified, they are scheduled into Tourmaline's development plans. Normally, Tourmaline plans to develop its proved and probable undeveloped reserves within three to seven years. A number of factors that could result in delayed or cancelled development are as follows: changing economic conditions (due to pricing, operating and capital expenditure fluctuations); changing technical conditions (production anomalies such as water breakthrough or accelerated depletion); multi-zone developments (delay of a prospective formation completion until the initial completion is no longer economic); a larger development program may need to be spread out over several years to optimize capital allocation and facility utilization; and surface access issues (landowners, weather conditions and/or regulatory approvals). See "Risk Factors" and "The Industry" in this prospectus.

Significant Factors or Uncertainties Affecting Reserves Data

The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. These estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. The reserves estimates contained in this prospectus are based on current production forecasts, prices and economic conditions available as at the date of the Tourmaline Consolidated Reserve Report.

Although every reasonable effort is made to ensure that reserve estimates are accurate, reserve estimation is an inferential science. As a result, the subjective decisions, new geological or production information and a changing environment may impact these estimates. Revisions to reserve estimates can arise from changes in year-end oil and natural gas prices and reservoir performance. Such revisions can be either positive or negative.

Other than as discussed above and the various risks and uncertainties that participants in the oil and natural gas industry are exposed to generally, Tourmaline is unable to identify any important economic factors or significant uncertainties that will affect any particular components of the reserves data disclosed in this prospectus. See "Risk Factors" and "The Industry" in this prospectus.

GLJ's forecast of well abandonment and reclamation costs for all wells with reserves assigned are included in their report and therefore in their estimate of future net revenue. Abandonment and reclamation costs for wells for which no reserves are assigned and for facilities owned by Tourmaline are also included for the purposes of calculating GLJ's estimate of future net revenue.

The following table sets forth abandonment and reclamation costs deducted in the estimation of future net revenue in the Tourmaline Consolidated Reserve Report:

	Forecast Prices and Costs (Total Proved plus Probable) ($000s)
Year	Abandonment andReclamation Costs(Undiscounted)	Abandonment andReclamation Costs(Discounted at 10%)
2020	-	-
2021	-	-
2022	-	-
Thereafter	987,829	69,566
Total	987,829	69,566

Future Development Costs

The following table sets forth development costs deducted in the estimation of Tourmaline's future net revenue attributable to the reserve categories noted below ($000s):

	Undiscounted Forecast Prices and Costs
Year	Proved Reserves	Proved PlusProbable Reserves
2020	748,390	897,346
2021	935,193	1,227,853
2022	1,018,961	1,286,136
2023	754,098	1,092,795
2024	315,297	1,098,248
Thereafter	99,703	1,801,673
Total	3,871,642	7,404,051

Tourmaline expects that the capital listed in the preceding table will be funded through its existing cash balance, unutilized credit facilities, expected cash flow from operations and completed financings.

Other Oil and Natural Gas Information

The additional information contained in this section pertains to Tourmaline and Exshaw on a consolidated basis and references to Tourmaline include Exshaw (without reduction to reflect the 9.4% third-party minority interest in Exshaw from January 1, 2019 to October 31, 2019). On October 31, 2019, Exshaw became a whollyowned subsidiary of Tourmaline.

Crude Oil and Natural Gas Wells

The following table sets forth the number and status of wells in which Tourmaline had a working interest as at December 31, 2019 and that Tourmaline considers capable of production.

	Crude Oil Wells(1)				Natural Gas Wells(1)
		Producing		Non-Producing(2)		Producing	Non-Producing(2)
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta(1)	331	308.9	119	82.5	1,765	1,469.8	356	239.2
British Columbia(1)	1	0.2	-	-	443	411.8	167	152.5
Saskatchewan(1)	1	0.1	-	-	-	-	-	-
Total	333	309.2	119	82.5	2,208	1,881.6	523	391.7

Notes:

(1) All of Tourmaline's wells are located onshore.

(2) The non-producing oil wells and natural gas wells capable of production but which are not currently producing will be re-evaluated with respect to future product prices, proximity to facility infrastructure, design of future exploration and development programs and access to capital.

Landholdings

The following table sets out Tourmaline's developed and undeveloped properties as at December 31, 2019, in which Tourmaline has an interest. When determining gross and net acreage for two or more leases covering the same lands but different rights, the acreage is reported for each lease. When there are multiple discontinuous rights in a single lease, the acreage is reported only once.

B-12

	Developed Acres		Undeveloped Acres		Total Acres
	Gross	Net	Gross	Net	Gross	Net
Alberta	862,588	692,982	1,316,098	1,180,152	2,178,686	1,873,134
British Columbia	89,985	78,859	163,584	146,723	253,570	225,582
Saskatchewan	324	37	69,722	65,930	70,046	65,967
Total	952,897	771,878	1,549,404	1,392,805	2,502,302	2,164,683

Note:

(1) Numbers may not add due to rounding.

Properties with no Attributable Reserves

The following table sets forth the gross and net acres of unproved properties held by Tourmaline as at December 31, 2019.

	Gross Acres	Net Acres
Alberta	1,151,937	1,052,118
British Columbia	49,662	44,696
Saskatchewan	69,272	65,930
Total	1,270,871	1,162,744

Unproved Properties as at December 31, 2019

The maximum net area for which Tourmaline expects the rights to explore, develop and exploit to expire during 2020 is 283,938 acres in Alberta, 19,233 acres in British Columbia and 61 acres in Saskatchewan. The expiring acreage is continuously being evaluated and attempts will be made to maintain our rights on the acreage and mitigate expiries through land swaps, asset dispositions or drilling to maintain the lease. There are no material work commitments necessary to maintain these properties.

Significant Factors or Uncertainties Relevant to Properties With No Attributed Reserves

For information with respect to Tourmaline's reclamation and abandonment obligations for the properties to which reserves have been attributed, see "Additional Information Relating to Reserves Data – Significant Factors or Uncertainties Affecting Reserves Data" in this Appendix "B".

Tax Horizon

Tourmaline has no current tax expense and, based on current reserve forecasts, will be able to realize the benefit of its non-capital losses and expects to remain non-taxable through at least 2024. Tourmaline has approximately $7.0 billion of tax pools available as at December 31, 2019, which can be used to offset taxable income in future years.

Capital Expenditures

The following table summarizes capital expenditures (including property acquisitions, net of dispositions, as well as capitalized general administrative expenses) related to Tourmaline's activities for the year ended December 31, 2019:

	$000s
Exploration, drilling and completions	743,397
Development, equipping and tie-in	171,875
Property acquisitions(1)	226,657
Property dispositions	(8,105)
Facilities	117,792
Geological and geophysical	-
Other (including capitalized G&A)	35,643
Total(2)	1,287,259

Notes:

(1) Property acquisitions are a result of approximately $168.5 million of acquired proved properties and approximately $58.2 million of acquired unproved properties.
(2) Includes capital expenditures related to Exshaw from January 1, 2019 to October 31, 2019 and also includes capital expenditures related to Topaz from November 1, 2019 to December 31, 2019 (without reduction to reflect the 26% thirdparty minority interest in Topaz).

Exploration and Development Activities

The following table sets forth the gross and net exploratory and development wells in which Tourmaline participated in the year ended December 31, 2019:

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
Natural Gas	-	-	195	191.2
Oil	3	2.3	21	17.4
Service	-	-	-	-
Dry	-	-	-	-
Total(1)	3	2.3	216	208.6

Note:

(1) Includes wells in which Exshaw participated from January 1, 2019 to October 31, 2019 (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

B-14

Production Estimates

The following table sets out the volume of Tourmaline's production estimated for the year ended December 31, 2020 as evaluated by GLJ and Deloitte, which is reflected in the estimate of future net revenue disclosed in the tables contained under "Disclosure of Reserves Data" above in this Appendix "B".

	Light and MediumCrude Oil	ConventionalNatural Gas	Shale Natural Gas	Natural GasLiquids	Oil EquivalentTotal
	Company Gross(Bbls/d)	Company Gross(Mcf/d)	Company Gross(Mcf/d)	Company Gross(Bbls/d)	Company Gross(Boe/d)
Proved Producing	8,139	776,203	425,900	40,374	248,863
Proved Developed Non
Producing	492	40,870	88,661	5,722	27,802
Proved Undeveloped	3,942	197,814	122,175	11,146	68,420
Total Proved	12,573	1,014,887	636,736	57,242	345,085
Total Probable	94	96,321	85,285	7,816	38,177
Total Proved PlusProbable	12,666	1,111,208	722,021	65,058	383,262

Notes:

(1) No one field accounted for 20% or more of Tourmaline's estimated 2020 total proved production in the Tourmaline Consolidated Reserve Report.
(2) Numbers may not add due to rounding.

Production History

Tourmaline Production History (gross production)

		Quarter Ended
		2019(1)(2)(3)
	March 31	June 30	September 30	December 31
Average Daily Production(4)
Light and Medium Crude Oil (Bbl/d)	24,438	23,395	24,056	27,832
Conventional Natural Gas (Mcf/d)	1,015,357	957,066	917,294	925,580
Shale Natural Gas (Mcf/d)	423,855	414,259	485,174	514,166
NGL (Bbl/d)(3)	29,127	28,598	31,777	32,054
Combined (Boe/d)	293,434	280,547	289,578	299,844
Average Price Received
Light and Medium Crude Oil ($/Bbl)	62.29	75.49	71.92	65.08
Conventional Natural Gas ($/Mcf)	3.82	2.24	2.04	3.05
Shale Natural Gas ($/Mcf)	3.02	1.67	1.60	2.26
NGL ($/Bbl)(3)	23.93	9.29	12.74	15.58
Combined ($/Boe)	25.15	17.37	16.52	21.01
Royalties Paid
Light and Medium Crude Oil ($/Bbl)	5.79	7.19	6.93	6.65
Conventional Natural Gas ($/Mcf)(5)	0.02	(0.05)	(0.08)	(0.03)
Shale Natural Gas ($/Mcf)	0.31	0.08	0.01	0.07
NGL ($/Bbl)(3)	1.93	0.89	1.25	1.62
Combined ($/Boe)	1.20	0.63	0.47	0.82
Production Costs (includes transportation)
Light and Medium Crude Oil ($/Bbl)	14.74	12.96	13.97	14.19
Conventional Natural Gas ($/Mcf)	1.21	1.19	1.23	1.32
Shale Natural Gas ($/Mcf)	1.30	1.35	1.13	1.04
NGL ($/Bbl)(6)(3)	-	-	-	-
Combined ($/Boe)	7.30	7.14	6.95	7.19
Netback Received ($/Boe)(7)	16.65	9.60	9.10	13.00

(1) Represents gross production and includes Exshaw from January 1, 2019 to October 31, 2019 (without reduction to reflect the 9.4% third-party minority interest in Exshaw) and also includes Topaz from November 1, 2019 to December 31, 2019 (without reduction to reflect the 26% third-party minority interest in Topaz).
(2) Numbers may not add due to rounding.
(3) For the purposes of this disclosure, condensate has been combined with Light and Medium Crude Oil as the associated revenues and certain costs of condensate are similar to Light and Medium Crude Oil. Accordingly, NGL in this disclosure exclude condensate. The Tourmaline GORR Interest includes natural gas, crude oil and condensate and does not include other NGL production. Accordingly, no NGL are applicable to Topaz.
(4) Before deduction of royalties.
(5) Includes royalty reductions for the quarters ended March 31, June 30, September 30 and December 31 of $0.11/Mcf, $0.13/Mcf, $0.14/Mcf and $0.14/Mcf, respectively, relating to the entire Alberta Gas Cost Allowance credits received by Tourmaline.
(6) NGL volumes are derived from natural gas production, as such all the related operating costs are attributed to the production of natural gas.
(7) Netbacks are calculated by subtracting royalties and production costs from revenues.

The following table sets forth the average daily production volumes for the year ended December 31, 2019 for each of the important fields, aggregated by area, comprising the Tourmaline GORR Lands.

Area	Light Crude Oiland MediumCrude Oil(Bbl/d)	NGL(Bbl/d)	ConventionalNatural Gas(Mcf/d)	Shale NaturalGas(Mcf/d)	Total(boe/d)
Alberta Deep Basin	6,594	19,220	893,004	-	174,648
Other Alberta properties	7,933	1,249	60,474	-	19,261
British Columbia properties	10,410	9,932	-	459,682	96,956
Total(1)(2)	24,937	30,401	953,478	459,682	290,865

Notes:

(1) Includes Exshaw from January 1, 2019 to November 10, 2019 (without reduction to reflect the 9.4% third-party minority interest in Exshaw).

For the purposes of this disclosure, condensate has been combined with Light and Medium Crude Oil as the associated revenues and certain costs of condensate are similar to Light and Medium Crude Oil. Accordingly, NGL in this disclosure exclude condensate

Forward Contracts and Marketing

Tourmaline's commodity hedging policy has been established with the Board authorizing management to hedge up to 50% of current production. Other than as disclosed in the Financial Statements, Tourmaline is not bound by any agreement (including any transportation agreement), directly or through an aggregator, under which it is precluded from fully realizing, or may be protected from the full effect of, future market prices for crude oil or natural gas. Refer to note 5(c) "Financial Risk Management – Market Risk" in the recently filed Consolidated Financial Statements of Tourmaline as at and for the years ended December 31, 2019 and 2018 for further discussion on the Tourmaline's commodity hedging activities.

Tourmaline's transportation obligations or commitments for future physical deliveries of crude oil and natural gas are not expected to vary significantly from Tourmaline's future forecasted production.

APPENDIX "C"

FORM 51-101F2 REPORTS ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR

Topaz Reserves

To the board of directors of Topaz Energy Corp. (the "Company"):

1. We have evaluated the Company's reserves data as at December 31, 2019. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2019, estimated using forecast prices and costs.
1. The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
1. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
1. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook.
1. The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2019, and identifies the respective portions thereof that we have evaluated and reported on to the Company's board of directors:

Independent Qualified	Effective Date of	Location ofReserves (Countryor Foreign	Net Present Value of Future Net Revenue(before income taxes, 10% discount rate - $MM)
Reserves Evaluator or Auditor	Evaluation Report	Geographic Area)	Audited	Evaluated	Reviewed	Total
Deloitte	December 31, 2019	Canada	-	$170.8	-	$170.8
GLJ Petroleum Consultants	December 31, 2019	Canada	-	$316.9	-	$316.9
Total			-	$487.8	-	$487.8

1. In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
1. We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports.
1. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

EXECUTED as to our report referred to above.

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 25, 2020. ORIGINALLY SIGNED BY

"Originally signed by"

Chad P. Lemke, P. Eng. Vice President & COO

Deloitte LLP, Calgary, Alberta, Canada, February 25, 2020. ORIGINALLY SIGNED BY

"Originally signed by" Andrew Botterill Partner, Resource Evaluation and Advisory

Tourmaline Reserves

To the board of directors of Tourmaline Oil Corp. (the "Company"):

1. We have evaluated the Company's reserves data as at December 31, 2019. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2019, estimated using forecast prices and costs.
1. The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
1. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
1. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions in the COGE Handbook.
1. The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2019, and identifies the respective portions thereof that we have evaluated and reported on to the Company's board of directors:

Independent Qualified	Effective Date of	Location ofReserves (Countryor Foreign	Net Present Value of Future Net Revenue(before income taxes, 10% discount rate - $MM)
Reserves Evaluator or Auditor	Evaluation Report	Geographic Area)	Audited	Evaluated	Reviewed	Total
Deloitte	December 31, 2019	Canada	-	$2,973	-	$2,973
GLJ Petroleum Consultants	December 31, 2019	Canada	-	$11,894	-	$11,894
*GLJ Petroleum Consultants	December 31, 2019	Canada	-	$217	-	$217
Total			-	$15,093	-	$15,093

*Gas Marketing Premium for all gas sales outside of Western Canadian markets

1. In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
1. We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports.
1. Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material.

EXECUTED as to our report referred to above.

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 25, 2020. ORIGINALLY SIGNED BY

"Originally signed by"

Chad P. Lemke, P. Eng. Vice President

Deloitte LLP, Calgary, Alberta, Canada, February 25, 2020. ORIGINALLY SIGNED BY

"Originally signed by"

Andrew Botterill Partner, Resource Evaluation and Advisory

APPENDIX "D"

FORM 51-101F3 REPORTS OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE

Topaz Reserves

Management of Topaz Energy Corp. (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.

GLJ Petroleum Consultants Ltd. and Deloitte LLP, each an independent qualified reserves evaluator, has evaluated the Company's reserves data. The reports of the independent qualified reserves evaluator are presented below.

The Reserves Committee of the board of directors of the Company has

(a) reviewed the Company's procedures for providing information to the independent qualified reserves evaluators;
(b) met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and
(c) reviewed the reserves data with management and the independent qualified reserves evaluators.

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 approved

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;
(b) the filing of Form 51-102F2 which is the reports of the independent qualified reserves evaluators on the reserves data, contingent resources data, or prospective resources data; and
(c) the content and filing of this report.

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

DATED as of this 24th day of September, 2020.

(signed)	"Marty Staples"Marty StaplesPresident and Chief Executive Officer	(signed)	"Cheree Stephenson"Cheree StephensonVice President, Finance and Chief FinancialOfficer
(signed)	"Darlene Harris"Darlene HarrisDirector	(signed)	"Jim Davidson"Jim DavidsonDirector

Tourmaline Reserves

Management of Tourmaline Oil Corp. (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.

The Reserves Committee of the board of directors of the Company has

(a) reviewed the Company's procedures for providing information to the independent qualified reserves evaluators;
(b) met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and
(c) reviewed the reserves data with management and the independent qualified reserves evaluators.

(a) the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;
(b) the filing of Form 51-102F2 which is the reports of the independent qualified reserves evaluators on the reserves data, contingent resources data, or prospective resources data; and
(c) the content and filing of this report.

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

DATED as of this 3rd day of March, 2020.

(signed)	"Michael L. Rose"	(signed)	"Brian G. Robinson"
	Michael L. Rose		Brian G. Robinson
	Chairman, President and Chief Executive		Vice President, Finance and Chief Financial
	Officer		Officer

(signed)	"Andrew B. MacDonald"	(signed)	"Lee A. Baker"
	Andrew B MacDonald		Lee A. Baker
	Director		Director

APPENDIX "E"

AUDIT COMMITTEE MANDATE AND TERMS OF REFERENCE

Role and Objective

The Audit Committee (the "Committee") is a committee of the board of directors (the "Board") of Topaz Energy Corp. ("Topaz" or the "Corporation") to which the Board has delegated its responsibility for the oversight of the following:

1. nature and scope of the annual audit;
1. the oversight of management's reporting on internal accounting standards and practices;
1. the review of financial information, accounting systems and procedures;
1. financial reporting and financial statements,

and has charged the Committee with the responsibility of recommending, for approval of the Board, the audited financial statements, interim financial statements and other mandatory disclosure releases containing financial information.

The primary objectives of the Committee are as follows:

1. To assist directors of Topaz ("Directors") in meeting their responsibilities (especially for accountability) in respect of the preparation and disclosure of the financial statements of the Corporation and related matters, including compliance with legal and regulatory requirements;
1. To provide better communication between Directors and external auditors;
1. To enhance the external auditor's independence;
1. To increase the credibility and objectivity of financial reports, the financial reporting process and internal controls over financial reporting;
1. To strengthen the role of the independent Directors by facilitating in depth discussions between Directors on the Committee, management of Topaz ("Management") and external auditors;
1. To maintain oversight of risk identification, assessment and management programs; and
1. To establish procedures for the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal controls or auditing matters.

Membership of Committee

1. The Board, on recommendation of the Governance, Compensation and Sustainability Committee, will appoint members to the Committee. The Committee will be comprised of at least three (3) Directors or such greater number as the Board may determine from time to time and all members of the Committee shall be "independent" (as such term is used in National Instrument 52-110 – Audit Committees ("NI 52-110") unless the Board determines that the exemption contained in NI 52-110 is available and determines to rely thereon.
1. The Board, on recommendation of the Governance, Compensation and Sustainability Committee, may from time to time designate one of the members of the Committee to be the Chair of the Committee.

All of the members of the Committee must be "financially literate" (as defined in NI 52-110) unless the Board determines that an exemption under NI 52-110 from such requirement in respect of any particular member is available and determines to rely thereon in accordance with the provisions of NI 52-110.

Mandate and Responsibilities of Committee

It is the responsibility of the Committee to:

1. Oversee the work of the external auditors, including the resolution of any disagreements between Management and the external auditors regarding financial reporting.
1. Satisfy itself on behalf of the Board with respect to Topaz's internal control systems, including financial and non-financial elements; identify, monitor and mitigate business risks; and ensuring compliance with legal, ethical and regulatory requirements.
1. Review the annual and interim financial statements of the Corporation and related management's discussion and analysis ("MD&A") prior to their submission to the Board for approval. The process should include but not be limited to:
- reviewing changes in accounting principles and policies, or in their application, which may have a material impact on the current or future years' financial statements;
- reviewing significant accruals, reserves or other estimates such as the ceiling test calculation;
- reviewing accounting treatment of unusual or non-recurring transactions;
- ascertaining compliance with covenants under loan agreements;
- reviewing disclosure requirements for commitments and contingencies;
- reviewing adjustments raised by the external auditors, whether or not included in the financial statements;
- reviewing unresolved differences between Management and the external auditors;
- obtaining explanations of significant variances with comparative reporting periods; and
- determining through inquiry if there are any related party transactions and ensuring that the nature and extent of such transactions are properly disclosed.
1. In addition to the review of financial statements and MD&A described above, review public disclosure containing audited or unaudited financial information (including, without limitation, annual and interim press releases and any other press releases disclosing earnings or financial results, prospectuses, and if applicable, the annual information form) before release and prior to Board approval. The Committee must be satisfied that adequate procedures are in place for the review of Topaz's disclosure of all other financial information and will periodically assess the accuracy of those procedures.
1. With respect to the appointment of external auditors by the Board:
- recommend to the Board the external auditors to be nominated;
- recommend to the Board the terms of engagement of the external auditor, including the compensation of the auditors and a confirmation that the external auditors will report directly to the Committee;
on an annual basis, review and discuss with the external auditors all significant relationships such auditors have with the Corporation to determine the auditors' independence;
monitor the relationship between management and the external auditor including reviewing any management letters or other reports of the external auditor and discussing any material differences of opinions between management and the external auditor;
when there is to be a change in auditors, review the issues related to the change and the information to be included in the required notice to securities regulators of such change; and
review and pre-approve any non-audit services to be provided to Topaz or its subsidiaries by the external auditors and consider the impact on the independence of such auditors. The Committee may delegate to one or more independent members the authority to pre–approve non–audit services, provided that the member(s) report to the Committee at the next scheduled meeting such pre– approval and the member(s) comply with such other procedures as may be established by the Committee from time to time.
1. Review with external auditors (and internal auditor if one is appointed by Topaz) their assessment of the internal controls of Topaz, their written reports containing recommendations for improvement, and Management's response and follow-up to any identified weaknesses. The Committee will also review annually with the external auditors their plan for their audit and, upon completion of the audit, their reports upon the financial statements of Topaz and its subsidiaries.
1. Review risk management policies and procedures of the Corporation (i.e., hedging, litigation, third-party credit risk, insurance and cybersecurity). In this regard, the Committee shall:
- Regularly identify and review the principal business risks, including potential emerging risks, of the Corporation and the actions taken by the Corporation to mitigate the risks;
- Regularly identify and review the principal financial risks and exposures of the Corporation, together with mitigating strategies, including physical and financial positions in commodities markets, derivatives strategies, capital commitments, foreign exchange exposures, and exposure to interest rate fluctuations, as well as non-financial risks and exposures including, but not limited to, risks relating to climate change, environmental and social elements;
- Regularly review the policies and activities of the Corporation's treasury and marketing groups and the financial risks arising from those activities, including any proposed authorities of Management from the Board for the hedging of the exposures;
- Review, and if desirable, recommend changes to the insurance program including coverage for property damage, business interruption and liabilities; and
- Regularly review and identify information technology, information systems and cybersecurity risks of the Corporation.
1. Establish a procedure for:
- the receipt, retention and treatment of complaints received by Topaz regarding accounting, internal accounting controls or auditing matters; and
- the confidential, anonymous submission by employees of Topaz of concerns regarding questionable accounting or auditing matters.
1. Review and approve Topaz's hiring policies regarding partners and employees and former partners and employees of the present and former external auditors of the Corporation.

The Committee has authority to communicate directly with the internal auditors (if any) and the external auditors of the Corporation. The Committee will also have the authority to investigate any financial activity of Topaz. All employees of Topaz are to cooperate as requested by the Committee.

The Committee may also retain persons having special expertise and/or obtain independent professional advice to assist in filling their responsibilities at such compensation as established by the Committee and at the expense of Topaz without any further approval of the Board.

Meetings and Administrative Matters

1. At all meetings of the Committee every resolution shall be decided by a majority of the votes cast. In case of an equality of votes, the Chair of the meeting shall not be entitled to a second or casting vote and in such cases, the undecided matter should be referred to the Board as a whole**.**
1. The Chair will preside at all meetings of the Committee, unless the Chair is not present, in which case the members of the Committee that are present will designate from among such members the Chair for purposes of the meeting.
1. A quorum for meetings of the Committee will be a majority of its members, and the rules for calling, holding, conducting and adjourning meetings of the Committee will be the same as those governing the Board unless otherwise determined by the Committee or the Board.
1. Meetings of the Committee should be scheduled to take place at least four times per year. Minutes of all meetings of the Committee will be taken. The Chief Financial Officer of Topaz will attend meetings of the Committee, unless otherwise excused from all or part of any such meeting by the Chair.
1. The Committee will meet with the external auditor at least once per year (in connection with the preparation of the year-end financial statements) and at such other times as the external auditor and the Committee consider appropriate.
1. Agendas, approved by the Chair, will be circulated to Committee members along with background information on a timely basis prior to the Committee meetings.
1. The Committee may invite such officers, directors and employees of the Corporation and its subsidiaries and related corporate entities as it sees fit from time to time to attend at meetings of the Committee and assist in the discussion and consideration of the matters being considered by the Committee. At each meeting, the Committee will meet, including with the external auditors, in camera without management present.
1. Minutes of the Committee will be recorded and maintained and circulated to Directors who are not members of the Committee or otherwise made available at a subsequent meeting of the Board.
1. The Committee may retain persons having special expertise and may obtain independent professional advice to assist in fulfilling its responsibilities at the expense of the Corporation as determined by the Committee.
1. Any members of the Committee may be removed or replaced at any time by the Board and will cease to be a member of the Committee as soon as such member ceases to be a Director. The Board may fill vacancies on the Committee by appointment from among its members. If and whenever a vacancy exists on the Committee, the remaining members may exercise all its powers so long as a quorum remains. Subject to the foregoing, following appointment as a member of the Committee each member will hold such office until the Committee is reconstituted.
1. Any issues arising from these meetings that bear on the relationship between the Board and Management should be communicated to the Chair of the Board by the Committee Chair.

In discharging its duties under this Mandate, the Committee may investigate any matter brought to its attention and will have access to all books, records, facilities and personnel, may conduct meetings or interview any officer or employee, the Corporation's legal counsel, external auditors and consultants and may invite any such persons to attend any part of any meeting of the Committee.

APPENDIX "F"

BOARD OF DIRECTORS' MANDATE

GENERAL

The Board of Directors (the "Board") of Topaz Energy Corp. (the "Corporation" or "Topaz") is responsible for the stewardship of the Corporation. In discharging its responsibility, the Board will exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances and will act honestly and in good faith with a view to the best interests of Topaz. In general terms, the Board will:

in consultation with the chief executive officer of the Corporation (the "CEO"), define the principal objectives of Topaz;
supervise the management of the business and affairs of Topaz with the goal of achieving Topaz's principal objectives as developed in association with the CEO;
discharge the duties imposed on the Board by applicable laws; and
for the purpose of carrying out the foregoing responsibilities, take all such actions as the Board deems necessary or appropriate.

SPECIFIC

Executive Team Responsibility

Appoint the CEO and senior officers, approve their compensation, and monitor the CEO's performance against a set of mutually agreed corporate objectives directed at maximizing shareholder value.
In conjunction with the CEO, develop a clear mandate for the CEO, which includes a delineation of management's responsibilities.
Establish processes as required that adequately provides for succession planning, including the appointment, training and monitoring of senior management.
Establish limits of authority delegated to management.

Operational Effectiveness and Financial Reporting

Annual review and adoption of a strategic planning process and approval of Topaz's strategic plan, which takes into account, among other things, the opportunities and risks of the business.
Establish or cause to be established systems to identify the principal risks to Topaz and ensure that the best practical procedures are in place to monitor and mitigate the risks.
Establish or cause to be established processes to address applicable regulatory, corporate, securities and other compliance matters.
Establish or cause to be established an adequate system of internal control.
Establish or cause to be established due diligence processes and appropriate controls with respect to applicable certification requirements regarding Topaz's financial and other disclosure.
Review and approve Topaz's financial statements and oversee Topaz's compliance with applicable audit, accounting and reporting requirements.
Approve annual operating and capital budgets.
Review and consider for approval all amendments or departures proposed by management from established strategy, capital and operating budgets.
Review operating and financial performance results relative to established strategy, budgets and objectives.

Integrity/Corporate Conduct

Establish a communications policy or policies to ensure that a system for corporate communications to all stakeholders exists, including processes for consistent, transparent, regular and timely public disclosure, and to facilitate feedback from stakeholders.
Approve a Code of Business Conduct and Ethics (the "Code") for directors, officers, employees and contractors and monitor compliance with the Code and approve any waivers of the Code for officers and directors.
To the extent feasible, satisfy itself as to the integrity of the CEO and other executive officers of the Corporation and that the CEO and other executive officers create a culture of integrity throughout Topaz and demonstrate a commitment to conducting business ethically and legally and in a manner that is fiscally, environmentally and socially responsible.

Board Process/Effectiveness

Attempt to ensure that Board materials are distributed to directors in advance of regularly scheduled meetings to allow for sufficient review of the materials prior to such meetings. Directors are expected to attend all meetings.
Engage in the process of determining Board member qualifications with the Governance, Compensation and Sustainability Committee including ensuring that a majority of directors qualify as independent directors pursuant to National Instrument 58 101 Disclosure of Corporate Governance Practices (as implemented by the Canadian Securities Administrators and as amended from time to time) and that the appropriate number of independent directors are on each committee of the Board as required under applicable securities rules and requirements.
Approve the nomination of directors.
Provide a comprehensive orientation to each new director.
Establish an appropriate system of corporate governance including practices to ensure the Board functions independently of management.
Establish appropriate practices for the regular evaluation of the effectiveness of the Board, its committees and its members.
Establish committees and approve their respective mandates and the limits of authority delegated to each committee.
Review and re assess the adequacy of the mandate of the committees of the Board on a regular basis.
Appoint members to committees and appoint the chairperson of each committee, having received the recommendation of the Governance, Compensation and Sustainability Committee. In this regard, consideration should be given to rotating committee members from time to time and to the special skills of particular directors.
Review the adequacy and form of the directors' compensation to ensure it realistically reflects the responsibilities and risks involved in being a director.

Each member of the Board is expected to understand the nature and operations of Topaz's business, and have an awareness of the political, economic and social trends prevailing in all countries or regions in which Topaz operates, or is contemplating potential operations.

Independent directors shall meet regularly, and in no case less frequently than quarterly, without non independent directors and management participation.

The Board may retain persons having special expertise and may obtain independent professional advice to assist it in fulfilling its responsibilities at the expense of the Corporation, as determined by the Board.

In addition to the above, adherence to all other Board responsibilities as set forth in the Corporation's By Laws, applicable policies and practices and other statutory and regulatory obligations, such as issuance of securities, etc., is expected.

DELEGATION

The Board may delegate its duties to, and receive reports and recommendations from, any committee of the Board.
Subject to terms of the Disclosure, Confidentiality and Trading Policy and other policies and procedures of Topaz, the Chair of the Board will act as a liaison between stakeholders of Topaz and the Board (including independent members of the Board).

CERTIFICATE OF THE ISSUER

Dated: September 24, 2020

This prospectus, together with the documents and information incorporated by reference, will, as of the date of the supplemented prospectus providing the information permitted to be omitted from this prospectus, constitute, full, true and plain disclosure of all material facts relating to the securities offered by this prospectus as required under the securities legislation of each of the provinces of Canada.

(Signed) "Marty Staples" President and Chief Executive Officer

(Signed) "Cheree Stephenson" Vice President, Finance and Chief Financial Officer

On behalf of the Board of Directors of Topaz Energy Corp.

(Signed) "Steve Larke" Director

(Signed) "John Gordon" Director

CERTIFICATE OF THE PROMOTER

Dated: September 24, 2020

TOURMALINE OIL CORP.

(Signed) "Michael L. Rose"

Chairman, President and Chief Executive Officer

CP-3

CERTIFICATE OF THE UNDERWRITERS

Dated: September 24, 2020

To the best of our knowledge, information and belief, this prospectus, together with the documents and information incorporated by reference, will, as of the date of the supplemented prospectus providing the information permitted to be omitted from this prospectus, constitute full, true and plain disclosure of all material facts relating to the securities offered by this prospectus as required under the securities legislation of each of the provinces of Canada.

PETERS & CO. LIMITED

(Signed) "Christopher S. Potter"

SCOTIA CAPITAL INC.

(Signed) "Roy Arthur"

BMO NESBITT BURNS INC.

(Signed) "Greg Stadnyk"

NATIONAL BANK FINANCIAL INC.

(Signed) "Arun Chandrasekaran"

RBC DOMINION SECURITIES INC.

(Signed) "Darrell Law"

CIBC WORLD MARKETS INC.

(Signed) "Chris Folan"

(Signed) "Kiel R. Depoe"

TD SECURITIES INC.

DESJARDINS SECURITIES INC.

(Signed) "Kristopher Zack"

STIFEL NICOLAUS CANADA INC.

(Signed) "Nicholas J. Johnson"

ATB CAPITAL MARKETS INC.

CANACCORD GENUITY CORP.

INDUSTRIAL ALLIANCE SECURITIES INC.

RAYMOND JAMES LTD.

TUDOR, PICKERING, HOLT & CO. SECURITIES

(Signed) "Brian Heald"

(Signed) "Andrew Birkby"

(Signed) "Trevor Conway"

(Signed) "Dion Degrand"

– CANADA, ULC

(Signed) "Derek Wheatley"

AI assistant

Topaz Energy Corp. — Capital/Financing Update 2020

47862_rns_2020-09-24_ac9d2ee0-77ae-446c-b0b8-16eddbc7e8e2.pdf

PRELIMINARY BASE PREP PROSPECTUS

APPENDICES

IMPORTANT ADVISORY

A prospective investor should read this entire prospectus and consult the prospective investor's own professional advisors to assess the income tax, legal, risk factors and other aspects of their investment in the Common Shares.

PRESENTATION OF INFORMATION

ELIGIBILITY FOR INVESTMENT

GLOSSARY

ABBREVIATIONS

Natural Gas

Other

NOTICE TO INVESTORS

About this Prospectus

General

Prospective investors are urged to carefully read the information under this heading and under the headings "Important Advisory", "Presentation of Information" and "Risk Factors" in this prospectus.

Use of Industry Specific Terminology

Certain Reserves Data and Other Oil and Gas Information

Forward-Looking Statements

COVID-19

Marketing Materials

Financial Statements

Exemptive Relief

Non-GAAP Financial Measures

Market, Independent Third-Party and Industry Data

Information Regarding Public Issuer Counterparties

Credit Ratings

Processing Capacity Volume Figures

PROSPECTUS SUMMARY

Summary of the Offering

The Company's Business

Strategic Relationships with High-Quality Counterparties

Tourmaline

Advantage

Investment Highlights

Unique large-scale exposure to high-quality royalty and infrastructure assets

Strategic relationship with investment grade rated sponsor underpins strong growth prospects

Ability to strategically execute M&A in an opportunity rich environment

Predictable, high free cash flow margin supports attractive, sustainable dividend

Environmental, social and governance (ESG) focus and leadership

Experienced, aligned management and board of directors

Proactively Monitoring and Managing its royalty and energy infrastructure assets

See "Investment Highlights".

Growth Strategy

Organic Growth of Royalty Production Revenue from the Royalty Assets

Pursue Accretive Strategic Acquisitions

The Company's Assets

Strategic Location of the Assets

Description of the Royalty Assets

Description of the Infrastructure Assets

The Company

Summary of Reserves Associated with the Tourmaline GORR Lands

Summary of Oil and Gas Reserves and Net Present Values of Future Net Revenue as of December 31, 2019 Forecast Prices and Costs(1)

Net Present Values of Future Net Revenue ($000s)

Notes:

Selected Historical and Pro Forma Financial and Production Information

See "Exemptions from Certain Disclosure Requirements".

Selected Pro Forma Financial Information for the Initial Assets

Selected Pro Forma Production Information for the Initial Assets

Analysis of Adjusted Pro Forma Revenue, EBITDA and EBITDA Margin

Relationship with Tourmaline

THE COMPANY'S BUSINESS

Overview

Strategic Relationships with High-Quality Counterparties

Tourmaline

Advantage

INVESTMENT HIGHLIGHTS

Investment Highlights

Unique large-scale exposure to high-quality royalty and infrastructure assets

Strategic relationship with investment grade rated sponsor underpins strong growth prospects

Ability to strategically execute M&A in an opportunity rich environment

Predictable, high free cash flow margin supports attractive, sustainable dividend

Environmental, social and governance (ESG) focus and leadership

Experienced, aligned management and board of directors

Note:

Proactively Monitoring and Managing its royalty and energy infrastructure assets

GROWTH STRATEGY

Growth Strategy

Organic Growth of Royalty Production Revenue from the Royalty Assets

Topaz Energy Corp. Capital/Financing Update 2020