Headwater Exploration Inc. — M&A Activity 2021

Feb 10, 2021

HEADWATER EXPLORATION INC.

FORM 51-102F4

BUSINESS ACQUISITION REPORT

ITEM 1. – IDENTITY OF COMPANY

1.1 Name and Address of Company

Headwater Exploration Inc. (" Headwater " or the " Company ") 1200, 500 – 4[th] Avenue S.W. Calgary, Alberta T2P 2V6

1.2 Executive Officer

The executive officer of the Company who is knowledgeable about the Acquisition (as defined herein) and this business acquisition report (the " Report ") is Ali Horvath, Chief Financial Officer and Vice President, Finance of the Company, whose business telephone number is (587) 3913682.

ITEM 2. – DETAILS OF ACQUISITION

2.1 Nature of Business Acquired

On November 8, 2020, the Company entered into a purchase and sale agreement (the " Acquisition Agreement ") with Cenovus Energy Inc. (" Cenovus ") and an affiliate of Cenovus, Cenovus Marten Hills Partnership (the " Vendor "), to acquire (the " Acquisition ") Cenovus' assets located in the Marten Hills area of Alberta (the " Acquired Assets ") from the Vendor for a purchase price of approximately $100.0 million, subject to customary closing adjustments (the " Purchase Price "). Pursuant to the terms of the Acquisition Agreement, the Purchase Price was payable through: (i) the issuance to the Vendor of 50.0 million common shares (the " Common Shares ") of the Company and 15.0 million common share purchase warrants (" Warrants " together with the Common Shares, the " Equity Consideration ") of the Company; and (ii) a cash payment to the Vendor of $35.0 million (the " Cash Consideration "). The Company paid a $10.0 million deposit to the Vendor on execution of the Acquisition Agreement (the " Deposit "), which Deposit and accrued interest thereon was deducted from the Cash Consideration due on the Closing Date (as defined below). A copy of the Acquisition Agreement is available at www.sedar.com under the Company's SEDAR profile.

The Acquisition was completed on December 2, 2020 (the " Closing Date ") and effective October 1, 2020. The Company issued 50.0 million Common Shares and 15.0 million Warrants and paid approximately $32.8 million (inclusive of interim closing adjustments and the Deposit) as satisfaction of the Cash Consideration. A final statement of closing adjustments will be prepared by the Vendor within 180 days following the Closing Date.

The Acquired Assets are comprised of approximately 189,000 acres (including approximately 172,800 acres or 270 net sections of Clearwater rights) located in the Marten Hills area of Alberta with net proved plus probable reserves of 8.3 MMBbls as estimated by GLJ Ltd. (" GLJ ") in their independent report dated effective December 31, 2020 with a preparation date of November 5, 2020, evaluating the oil reserves attributable to the Acquired Assets which is based on the average forecast prices of three independent reserves evaluators (GLJ, McDaniel & Associates Consultants Ltd. and Sproule Associates Ltd.) as of October 1, 2020 (the " Acquisition Reserves Report ").

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Reserves data and other oil and gas information in respect of the Acquired Assets is set forth in Schedule "C" to this Report.

In connection with the completion of the Acquisition, Headwater entered into a development agreement with the Vendor (the " Development Agreement ") on the Closing Date, under which the Company committed to spend $100.0 million in capital expenditures (" Expenditures ") on the Acquired Assets by December 31, 2022 unless otherwise extended by the Vendor (the " Development Term "). The Company agreed that if it fails to satisfy the Expenditures within the Development Term, the Company will pay to the Vendor the balance of any remaining Expenditures and Headwater will have no further capital expenditure obligations under the Development Agreement.

In addition, the Vendor and Headwater entered into a royalty agreement (the " Royalty Agreement ") on the Closing Date, pursuant to which, Cenovus (through its beneficial ownership of the Vendor) will retain a gross overriding royalty on the lands comprising the Acquired Assets.

2.2 Date of Acquisition

The closing date of the Acquisition was December 2, 2020.

2.3 Consideration

In consideration of the Vendor transferring the Acquired Assets to the Company, the Company issued 50.0 million Common Shares and 15.0 million Warrants and paid approximately $32.8 million (inclusive of interim closing adjustments and the Deposit) pursuant to the terms of the Acquisition Agreement.

Under IFRS 3 Business Combinations , the value of the Common Shares and Warrants issued as consideration paid by the Company to the Vendor must be recognized at the Closing Date fair value. Based on the closing price of the Common Shares on December 2, 2020 of $1.93 per Common Share, the value of the Equity Consideration was approximately $103 million, an increase of approximately $38 million from the value of the Equity Consideration on announcement of the Acquisition of approximately $65 million.

Each Warrant issued to the Vendor entitles the Vendor to purchase one (1) Common Share (each an " Underlying Share ") at an exercise price of $2.00 per Underlying Share at any time within three (3) years following the Closing Date.

2.4

Effect on Financial Position

Except as otherwise publicly disclosed and in the ordinary course of business and other than in respect of changes that occurred as a result of the Acquisition, the Company does not presently have any plans or proposals for material changes in the business affairs of the Company or with respect to the Acquired Assets that may have a significant effect on the financial performance and financial position of the Company, including any proposal to liquidate the business or to sell, lease or exchange all or a substantial portion of the Acquired Assets.

2.5

Prior Valuations

No valuation opinion was obtained by the Company or the Vendor or in respect of the Acquired Assets within the last 12 months required by securities legislation or a Canadian exchange or market to support the consideration paid by the Company for the Acquired Assets.

2.6

Parties to Transaction

The Acquisition did not involve an "informed person", "associate" or "affiliate" (as each term is defined in securities legislation) of Headwater.

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2.7 Date of Report

February 10, 2021.

ITEM 3. – FINANCIAL STATEMENTS AND OTHER INFORMATION

The following financial statements and other information required by Part 8 of National Instrument 51-102 are attached hereto and form part of this Report:

Schedule "A" Operating statements of the Acquired Assets, comprised of: (i) an audited operating statement of the Acquired Assets for the year ended December 31, 2019; (ii) an unaudited operating statement of the Acquired Assets for the year ended December 31, 2018; and (iii) an unaudited operating statement of the Acquired Assets for the nine (9) months ended September 30, 2020 and September 30, 2019.

Schedule "B" Pro forma operating statements, comprised of: (i) a pro forma operating statement of Headwater for the year ended December 31, 2019 after giving effect to the Acquisition; and (ii) a pro forma operating statement of Headwater for the nine (9) months ended September 30, 2020 after giving effect to the Acquisition.

Schedule "C" Reserves data and other oil and gas information in respect of the Acquired Assets.

The operating statements and reserves information comprising each of Schedules "A", "B" and "C" above, as applicable, have been derived from information provided by Cenovus and the Vendor prior to completion of the Acquisition.

FORWARD-LOOKING STATEMENT ADVISORY

Certain statements contained in this Report constitute forward-looking statements and forward-looking information (collectively, " forward-looking statements "). 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 Report should not be unduly relied upon. These statements speak only as of the date of this Report. In addition, this Report 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 Report.

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

• the timing of the Expenditures and the amounts of Expenditures to be made by the Company under the Development Agreement;

• future production on the Acquired Assets;

• • timing of receipt by the Company the final statement of adjustments;

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• anticipated future crude oil, natural gas and natural gas liquids (" NGL ") prices and currency, exchange and interest rates; and

• supply and demand for petroleum and natural gas.

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

• the ability of the Company to obtain financing on acceptable terms or generate sufficient cash flow to fund the Expenditures;

• field production rates, decline rates and the well performance and characteristics of the Acquired Assets;

• 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 Report, 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:

• the Acquired Assets will not be developed in the manner anticipated by the Company;

• volatility in the demand, supply and market prices for crude oil, natural gas and NGL;

• liabilities inherent in petroleum and natural gas operations;

• uncertainties associated with estimating crude oil reserves and future production levels;

• competition for, among other things, third party capital and acquisitions of reserves, additional petroleum and natural gas assets and undeveloped lands;

• risks related to the environment and changing environmental laws in relation to the operations conducted on the Acquired Assets;

• geological, technical, drilling, processing and handling issues associated with petroleum and natural gas development;

• ability to obtain regulatory approvals;

• impacts of the current coronavirus (COVID-19) pandemic;

• general economic, market and business conditions; and

• changes in tax or environmental laws or royalty or incentive programs relating to the oil and natural gas industry.

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 Report and the Company does not 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 applicable securities laws. New factors emerge from time to time, and it is not possible for the Company 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 Report are expressly qualified by the foregoing cautionary statements.

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PRESENTATION OF FINANCIAL AND OIL AND GAS INFORMATION

Unless indicated otherwise, the financial information contained in this Report has been prepared in accordance with generally accepted accounting principles (which, since January 1, 2011, have been consistent with International Financial Reporting Standards as issued by the International Accounting Standards Board).

All dollar amounts set forth in this Report are in Canadian dollars, except where otherwise indicated.

All crude oil reserves and other information with respect to the Acquired Assets contained in this Report have been prepared and are presented in accordance with National Instrument 51-101 – Standards for Disclosure for Oil and Gas Activities (" NI 51-101 ") .

OIL AND GAS DEFINITIONS

Certain terms used in this Report in describing reserves and other oil and natural gas information are defined below. Certain other terms and abbreviations used in this Report, but not defined or described, are defined in NI 51-101 or the Canadian Oil and Gas Evaluation Handbook (the " COGE Handbook ") and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101 or the COGE Handbook.

" 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;

" development costs " means costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing the crude oil and natural gas from the reserves. More specifically, development costs, including applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to: (a) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines and power lines, to the extent necessary in developing the reserves; (b) drill and equip development wells, development type stratigraphic test wells and service wells, including the costs of platforms and well equipment such as casing, tubing, pumping equipment and wellhead assembly; (c) acquire, construct and install production facilities such as flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and (d) provide improved recovery systems;

" development well " means a well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive;

" forecast prices and costs " means future prices and costs that are:

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

• (b) if, and only to the extent that, there are fixed or presently determinable future prices or costs to which Headwater is legally bound by a contractual or other obligation to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs rather than the prices and costs referred to in subparagraph (a);

" gross " means: (a) in relation to an issuer's interest in production or reserves, its "company gross reserves", which are its working interest (operating or non-operating) share before deduction of royalties and without including any royalty interests of the issuer; (b) in relation to wells, the total number of wells in which an issuer has an interest; and (c) in relation to properties, the total area of properties in which an issuer has an interest;

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" net " means: (a) in relation to an issuer's interest in production or reserves its working interest (operating or non-operating) share after deduction of royalty obligations, plus its royalty interests in production or reserves; (b) in relation to an issuer's interest in wells, the number of wells obtained by aggregating the issuer's working interest in each of its gross wells; and (c) in relation to an issuer's interest in a property, the total area in which the issuer has an interest multiplied by the working interest owned by the issuer;

" Proved plus Probable Reserves " means Proved Reserves plus Probable 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;

" 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;

" Reserves " are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates;

" 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 classification (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 subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status; and

" working interest " means the percentage of undivided interest held by an issuer in the oil and/or natural gas or mineral lease granted by the mineral owner, Crown or freehold, which interest gives the issuer the right to "work" the property (lease) to explore for, develop, produce and market the leased substances.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserve entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserve estimates are prepared). 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 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.

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OIL AND GAS EQUIVALENCY

The term "Boe" means a barrel of oil equivalent on the basis of 6 Mcf of natural gas to 1 Bbl of oil. The term "Mcfe" means a thousand cubic feet of gas equivalent on the basis of 1 Bbl of oil to 6 Mcf of natural gas. Boes and Mcfes may be misleading, particularly if used in isolation. A Boe conversion ratio of 6 Mcf: 1 Bbl or a Mcfe conversion ratio of 1 Bbl: 6 Mcf 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 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 Mcf: 1 Bbl, utilizing a conversion ratio at 6 Mcf: 1 Bbl may be misleading as an indication of value.

ABBREVIATIONS

In this Report, the following abbreviations have the meanings set forth below consistent with Appendix B of the COGE Handbook (as defined herein), where applicable.

API	American Petroleum Institute
Bbl	barrel
Bbl/d	barrels per day
Boe	barrel of oil equivalent
Boe/d	barrels of oil equivalent per day
MBbl	thousands of barrels
MMBbl	millions of barrels
MBbl/d	thousands of barrels per day
MMBbl/d	millions of barrels per day
MBoe	thousands of barrels of oil equivalent
MMBoe	million barrels of oil equivalent
MBoe/d	thousands of barrels of oil equivalent per day
Mcf	thousand cubic feet
Mcfe	thousand cubic feet equivalent
MMcfpd	million cubic feet per day
MMcf	million cubic feet

CONVERSION

The following table sets forth certain standard conversions between Standard Imperial Units and the International System of Units (or metric units) consistent with Appendix C of the COGE Handbook.

To Convert From Mcf cubic metres Bbl cubic metres feet metres miles kilometres acres hectares	To cubic metres cubic feet cubic metres Bbl metres feet kilometres miles hectares acres	Multiply By
		28.174 35.494 0.159 6.292 0.305 3.281 1.609 0.621 0.405 2.471

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SCHEDULE "A"

OPERATING STATEMENTS

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To the Directors of Cenovus Energy Inc.

Our opinion

In our opinion, the accompanying financial information relating to the Marten Hills Assets of Cenovus Energy Inc. (the Property) for the year ended December 31, 2019 is prepared, in all material respects, in accordance with the financial reporting framework specified in subsection 3.11(5) of National Instrument 52-107, Acceptable Accounting Principles and Auditing Standards, for operating statements of an oil and gas property that is to be acquired.

What we have audited

The Property financial information comprises the operating statement containing gross sales, royalties, production costs and operating income for the year ended December 31, 2019 and the notes to the financial information, which include a summary of significant accounting policies.

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 of the financial information section of our report.

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

Independence

We are independent of Cenovus Energy Inc. in accordance with the ethical requirements that are relevant to our audit of the financial information in Canada. We have fulfilled our other ethical responsibilities in accordance with these requirements.

Other matter

The financial information of the Property for the year ended December 31, 2018 and the nine-month periods ended September 30, 2020 and September 30, 2019 are unaudited.

Responsibilities of management and those charged with governance for the financial information

Management of Cenovus Energy Inc. is responsible for the preparation of the financial information of the Property in accordance with the financial reporting framework specified in subsection 3.11(5) of National Instrument 52-107, Acceptable Accounting Principles and Auditing Standards, for operating statements of

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

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an oil and gas property that is to be acquired, and for such internal control as management determines is necessary to enable the preparation of financial information that is free from material misstatement, whether due to fraud or error.

Those charged with governance are responsible for overseeing the management al reporting process.

financial information

Our objectives are to obtain reasonable assurance about whether the financial information as a whole is 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 this financial information.

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 information, 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 management .

• Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by management.

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

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Chartered Professional Accountants

Calgary, Alberta November 12, 2020

Cenovus Energy Inc. Marten Hills Assets

Operating Statements Containing Gross Sales, Royalties, Production Costs and Operating Income

Income
($ Canadian) Revenues Gross Sales Less: Royalties Revenues Expenses Transportation Operating Operating Income	2019 2018 (audited) (unaudited) 9,432,414 $ 9,893,995 $ 1,333,580 884,464 8,098,834 9,009,531 483,464 535,702 3,736,487 2,656,689 3,878,883 $ 5,817,140 $ For the Years Ended December 31,
		(unaudited) 9,893,995 $ 884,464
		9,009,531
		535,702 2,656,689
		5,817,140 $

See accompanying Notes to Operating Statements

Cenovus Energy Inc. Marten Hills Assets Notes to Operating Statements Containing Gross Sales, Royalties, Production Costs and Operating Income

For the Year Ended December 31, 2019

1. Basis of Presentation

The Operating Statements containing Gross Sales, Royalties, Production Costs and Operating Income (the "Operating Statements") includes the net working interest of the operating results of Cenovus Energy Inc. ("Cenovus" or the "Company") relating to the Marten Hills Assets (the "Property").

The line items in the Operating Statements have been prepared in all material respects using accounting policies that are permitted by International Financial Reporting Standards applicable to publicly accountable enterprises, with such accounting policies applying to those line items as if such line items were presented as part of a complete set of financial statements. The Operating Statements are prepared in accordance with the financial reporting framework specified in subsection 3.11(5) of National Instrument 52-107 Acceptable Accounting Principles and Auditing Standards for an operating statement.

The Operating Statements for the Property do not include any provision for depletion, depreciation and amortization, decommissioning liabilities, capital costs, impairment of properties, general and administrative costs or income taxes as these amounts are based on the consolidated operations of Cenovus of which the Marten Hills Assets form only a part.

2. Significant Accounting Policies

(A) Functional and Presentation Currency

The functional and presentation currency of the Operating Statements is Canadian dollars.

(B) Revenue Recognition

Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from Cenovus to its customer.

Cenovus satisfies its performance obligations in contracts with customers upon the delivery of crude oil, which is generally at a point in time. Cenovus sells its production of crude oil pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on the agreed transaction price with any variability in transaction price recognized in the same period.

The Company’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. Cenovus's risk management gains and losses are excluded from these Operating Statements.

(C) Royalties

Royalties are calculated in accordance with applicable regulations and/or the terms of individual royalty agreements.

(D) Transportation Expenses

The costs associated with the transportation of crude oil are recognized when the product is sold.

(E) Operating Expenses

Operating expenses include amounts incurred on extraction of product to the surface, gathering, field processing, treating and field storage. More specifically they include workforce, electricity, energy, processing fees, repairs and maintenance, waste fluid handling and trucking, workovers, property tax and lease costs, overhead and other direct expenses. Costs or credits that are corporate based are excluded from these Operating Statements.

(F) Use of Estimates

Management estimates and assumptions in regards to certain revenues and expenses have been used. Such estimates relate to unsettled transactions and events. Estimates by their nature are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

3. Commitments and Contingencies

Cenovus has entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements.

As at December 31, 2019 future payments for transportation commitments associated with the Property are below.

($ Canadian millions) Mitsue Terminal Total		2020 13.7	2021 -	2022 -	2023 -	2024 -	Thereafter
							-
		13.7	-	-	-	-	-

Cenovus Energy Inc. Marten Hills Assets

Operating Statements Containing Gross Sales, Royalties, Production Costs and Operating Income

($ Canadian) Revenues Gross Sales Less: Royalties Revenues Expenses Transportation Operating Operating Income	2020 2019 (unaudited) (unaudited) 24,179,402 $ 6,059,055 $ 1,256,855 968,262 22,922,547 5,090,793 1,601,063 266,236 5,965,417 2,669,189 15,356,067 $ 2,155,368 $ For the Nine Months Ended September 30,	2020 2019 (unaudited) (unaudited) 24,179,402 $ 6,059,055 $ 1,256,855 968,262 22,922,547 5,090,793 1,601,063 266,236 5,965,417 2,669,189 15,356,067 $ 2,155,368 $ For the Nine Months Ended September 30,
		(unaudited) 6,059,055 $ 968,262
		5,090,793
		266,236 2,669,189
		2,155,368 $

See accompanying Notes to Operating Statements

Cenovus Energy Inc. Marten Hills Assets Notes to Operating Statements Containing Gross Sales, Royalties, Production Costs and Operating Income

For the Nine Months Ended September 30, 2020

1. Basis of Presentation

The Operating Statements containing Gross Sales, Royalties, Production Costs and Operating Income (the "Operating Statements") includes the net working interest of the operating results of Cenovus Energy Inc. ("Cenovus" or the "Company") relating to the Marten Hills Assets (the "Property").

The line items in the Operating Statements have been prepared in all material respects using accounting policies that are permitted by International Financial Reporting Standards applicable to publicly accountable enterprises, with such accounting policies applying to those line items as if such line items were presented as part of a complete set of financial statements. The Operating Statements are prepared in accordance with the financial reporting framework specified in subsection 3.11(5) of National Instrument 52-107 Acceptable Accounting Principles and Auditing Standards for an operating statement.

The Operating Statements for the Property do not include any provision for depletion, depreciation and amortization, decommissioning liabilities, capital costs, impairment of properties, general and administrative costs or income taxes as these amounts are based on the consolidated operations of Cenovus of which the Marten Hills Assets form only a part.

2. Significant Accounting Policies

(A) Functional and Presentation Currency

The functional and presentation currency of the Operating Statements is Canadian dollars.

(B) Revenue Recognition

Revenue is measured based on the consideration specified in a contract with a customer and excludes amounts collected on behalf of third parties. Cenovus recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from Cenovus to its customer.

Cenovus satisfies its performance obligations in contracts with customers upon the delivery of crude oil, which is generally at a point in time. Cenovus sells its production of crude oil pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors. The amount of revenue recognized is based on the agreed transaction price with any variability in transaction price recognized in the same period.

The Company’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. Cenovus's risk management gains and losses are excluded from these Operating Statements.

(C) Royalties

Royalties are calculated in accordance with applicable regulations and/or the terms of individual royalty agreements.

(D) Transportation Expenses

The costs associated with the transportation of crude oil are recognized when the product is sold.

(E) Operating Expenses

Operating expenses include amounts incurred on extraction of product to the surface, gathering, field processing, treating and field storage. More specifically they include workforce, electricity, energy, processing fees, repairs and maintenance, waste fluid handling and trucking, workovers, property tax and lease costs, overhead and other direct expenses. Costs or credits that are corporate based are excluded from these Operating Statements.

(F) Use of Estimates

Management estimates and assumptions in regards to certain revenues and expenses have been used. Such estimates relate to unsettled transactions and events. Estimates by their nature are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

3. Commitments and Contingencies

Cenovus has entered into various commitments in the normal course of operations primarily related to demand charges on firm transportation agreements.

As at September 30, 2020, future payments for transportation commitments associated with the Property are below.

($ Canadian millions) Rainbow Pipeline Mitsue Terminal Total		2020 0.2 13.0	2021 - -	2022 - -	2023 - -	2024 - -	Thereafter
							- -
		13.2	-	-	-	-	-

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SCHEDULE "B"

PRO FORMA OPERATING STATEMENTS

Headwater Exploration Inc. Unaudited Pro Forma Operating Statements Containing Gross Sales, Royalties, Production Costs and Operating Income

($ Canadian)

For the Year Ended December 31, 2019

Revenues Gross Sales Less: Royalties Revenues Expenses Transportation Operating Operating Income	Headwater Marten Hills Assets Adjustments (note 5) Pro Forma
	$ 9,333,075 $ 9,432,414 $ - $ 18,765,489 230,464 1,333,580 605,437 2,169,481
	9,102,611 8,098,834 (605,437) 16,596,008
	- 483,464 1,487,517 1,970,981 2,610,765 3,736,487 (1,487,517) 4,859,735
	$6,491,846 $3,878,883 $ (605,437) $ 9,765,292

See accompanying Notes to the Unaudited Pro Forma Operating Statements

Headwater Exploration Inc. Unaudited Pro Forma Operating Statements Containing Gross Sales, Royalties, Production Costs and Operating Income

($ Canadian)

For the Nine Months Ended September 30, 2020

Revenues Gross Sales Less: Royalties Revenues Expenses Transportation Operating Operating Income	Headwater Marten Hills Assets Adjustments (note 5) Pro Forma
	$ 2,873,068 $ 24,179,402 $ - $ 27,052,470 71,512 1,256,855 1,569,743 2,898,110
	2,801,556 22,922,547 (1,569,743) 24,154,360
	- 1,601,063 3,597,048 5,198,111 1,700,358 5,965,417 (3,597,048) 4,068,727
	$ 1,101,198 $ 15,356,067 $ (1,569,743) $ 14,887,522

See accompanying Notes to the Unaudited Pro Forma Operating Statements

Headwater Exploration Inc. Notes to Unaudited Pro Forma Operating Statements Containing Gross Sales, Royalties, Production Costs and Operating Income

For the Year Ended December 31, 2019 and Nine Months Ended September 30, 2020

1. General Information

Headwater Exploration Inc. (formerly Corridor Resources Inc.) (“Headwater” or the “Company”) is a Canadian junior resource company engaged in the exploration for and development and production of petroleum and natural gas in Canada. Headwater is a public company existing under the Alberta Business Corporations Act with common shares listed on the Toronto Stock Exchange (“TSX”) under the symbol “HWX”.

The Company was recapitalized on March 4, 2020, pursuant to which the Company raised aggregate gross proceeds of $50 million, a new management team was appointed and the board of directors was reconstituted.

On November 8, 2020, the Company entered into a purchase and sale agreement (the "Acquisition Agreement") with Cenovus Energy Inc. ("Cenovus") and an affiliate of Cenovus, Cenovus Marten Hills Partnership (the "Vendor"), to acquire (the "Acquisition") Cenovus' assets located in the Marten Hills area of Alberta (the "Marten Hills Assets").

Headwater’s principal place of business is located at 1200, 500-4th Avenue S.W., Calgary, Alberta, T2P 2V6 and its registered office is located at 2400, 525-8th Avenue S.W., Calgary, Alberta, T2P 1G1.

2. Basis of Presentation

These unaudited pro forma operating statements for the year ended December 31, 2019 and the nine months ended September 30, 2020 (collectively the “Unaudited Pro Forma Operating Statements”) have been prepared by management of Headwater to give effect to the Acquisition as if it occurred on January 1, 2019. The Pro Forma Operating Statements containing schedules of gross revenues, royalties and production costs, give effect to significant acquisitions that occurred during the reporting periods presented.

The Unaudited Pro Forma Operating Statements have been prepared from information derived from and should be read in conjunction with the following:

• the audited annual financial statements of Headwater for the year ended December 31, 2019;

• the audited operating statement of the Marten Hills Assets for the year ended December 31, 2019 and the unaudited operating statement of the Marten Hills assets for the year ended December 31, 2018;

• the unaudited condensed interim financial statements of Headwater for the nine months ended September 30, 2020; and

• the unaudited operating statements of the Marten Hills Assets for the nine months ended September 30, 2020.

The line items in the Unaudited Pro Forma Operating Statements have been prepared in all material respects using accounting policies that are permitted by International Financial Reporting Standards applicable to publicly accountable enterprises, with such accounting policies applying to those line items as if such line items were presented as part of a complete set of financial statements. The operating statements of Headwater and the Marten Hills Assets, which are included in the Unaudited Pro Forma Operating Statements are prepared in accordance with the financial reporting framework specified in subsection 3.11(5) of National Instrument 52-107 Acceptable Accounting Principles and Auditing Standards for an operating statement.

These Unaudited Pro Forma Operating Statements do not include any provision for depletion, depreciation and amortization, decommissioning liabilities, capital costs, impairment of properties, general and administrative costs or income taxes.

These Unaudited Pro Forma Operating Statements give effect to the Acquisition and assumptions described herein, as if they had occurred on January 1, 2019. They may not be indicative of the results of operations that would have occurred had the Acquisition been effected on the date indicated, or the results that may be obtained in the future. In the opinion of management, the Unaudited Pro Forma Operating Statements include all necessary adjustments for the fair presentation of the ongoing entity.

3. Significant Accounting Policies

(A) Functional and Presentation Currency

The functional and presentation currency of the Unaudited Pro Forma Operating Statements is Canadian dollars.

(B) Joint Operations

A portion of the Company’s exploration and development activities are conducted jointly with others. The joint interests in the Unaudited Pro Forma Operating Statements reflect only the Company’s proportionate share of the revenues, expenses and cash flows from these activities.

(C) Revenue Recognition

Revenue is measured based on the consideration specified in a contract with a customer. The Company recognizes revenue when it transfers control of the product or service to a customer, which is generally when title passes from Headwater to its customer.

The Company satisfies its performance obligations in contracts with customers upon the delivery of the product, which is generally at a point in time. Headwater primarily sells its production pursuant to variable price contracts. The transaction price for variable price contracts is based on the commodity price, adjusted for quality, location and other factors.

The amount of revenue recognized is based on the agreed transaction price with any variability in transaction price recognized in the same period.

Processing fees charged under contracts with customers are recognized in revenue when the related services are provided.

The Company’s revenue transactions do not contain significant financing components and payments are typically due within 30 days of revenue recognition. The Company's financial derivative gains and losses are excluded from these Unaudited Pro Forma Operating Statements.

(D) Royalties

Royalties are calculated in accordance with applicable regulations and/or the terms of individual royalty agreements.

(E) Transportation Expenses

The costs associated with the transportation of each product are recognized when the product is sold.

(F) Operating Expenses

Operating expenses include amounts incurred on extraction of product to the surface, gathering, field processing, treating and field storage. More specifically they include workforce, electricity, energy, processing fees, repairs and maintenance, waste fluid handling and trucking, workovers, property tax and lease costs, overhead and other direct expenses.

(G) Use of Estimates

Management estimates and assumptions in regards to certain revenues and expenses have been used. Such estimates relate to unsettled transactions and events. Estimates by their nature are subject to measurement uncertainty. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

4. Gross Sales

For the Year Ended December 31, 2019

Crude oil Natural gas Natural gas liquids Processing revenue Gross Sales	Headwater Marten Hills Assets Pro Forma
	$ - $ 9,432,414 $ 9,432,414 8,767,177 - 8,767,177 107,206 - 107,206 458,692 - 458,692
	$ 9,333,075 $ 9,432,414 $ 18,765,489

For the Nine Months Ended September 30, 2020

Crude oil Natural gas Natural gas liquids Processing revenue Gross Sales	Headwater Marten Hills Assets Pro Forma
	$ - $ 24,179,402 $ 24,179,402 2,500,400 - 2,500,400 36,707 - 36,707 335,961 - 335,961
	$ 2,873,068 $ 24,179,402 $ 27,052,470

5. Pro Forma Adjustments

For the Year Ended December 31, 2019

The royalty adjustment gives effect to the gross overriding royalty (“GORR”) retained by Cenovus Energy Inc. as if it had been in place on January 1, 2019.

Certain transportation expenses were reclassed from operating expenses to align with Headwater’s accounting policies.

For the Nine Months Ended September 30, 2020

The royalty adjustment gives effect to the GORR retained by Cenovus Energy Inc. as if it had been in place on January 1, 2020.

Certain transportation expenses were reclassed from operating expenses to align with Headwater’s accounting policies.

• 10 -

SCHEDULE "C"

RESERVES DATA AND OTHER OIL AND GAS INFORMATION IN RESPECT OF THE ACQUIRED ASSETS

The reserves data for the Acquired Assets set forth below is based upon the Acquisition Reserves Report. The reserves data summarizes the heavy crude oil reserves and the net present value of future net revenue for those reserves using forecast prices and costs, not including the impact of any price risk management activities. The Acquisition Reserves Report was prepared in accordance with the standards contained in the COGE Handbook and the reserve definitions contained in NI 51-101.

The Acquisition Reserves Report is based on certain factual data supplied to Headwater by Cenovus and the Vendor and the opinion of GLJ of reasonable practice in the industry. The extent and character of ownership and all factual data pertaining to the Acquired Assets (except for certain information residing in the public domain) were supplied by Cenovus and the Vendor to GLJ. GLJ accepted this data as presented and did not conduct title searches or field inspections. The Acquisition Reserves Report was prepared by GLJ for the Company. As a result, the Company participated in the preparation of the Acquisition Reserves Report and reviewed the reserves data with GLJ in conjunction with the preparation thereof.

The tables below provide a summary of the crude oil reserves attributable to the Acquired Assets and the net present value of future net revenue attributable to such reserves as evaluated in the Acquisition Reserves Report, based on forecast price and cost assumptions. The tables summarize the data contained in the Acquisition Reserves Report and, as a result, may contain slightly different numbers than such report due to rounding. Due to rounding, certain columns may not add exactly.

The net present value of future net revenue attributable to reserves is stated without provision for interest costs and general and administrative costs, but after providing for estimated royalties, operating costs, development costs and well abandonment and reclamation costs. It should not be assumed that the undiscounted or discounted net present value of future net revenue attributable to reserves estimated by GLJ represent the fair market value of those reserves. Other assumptions and qualifications relating to costs, prices for future production and other matters are summarized herein. The recovery and reserve estimates of crude oil reserves provided herein are estimates only. Actual reserves may be greater than or less than the estimates provided herein .

All of the reserves associated with the Acquired Assets are located in the Province of Alberta. The only "product type" (as such term is defined in CSA Staff Notice 51-324 – Glossary to NI 51-101 ) attributed to the Acquired Assets is heavy crude oil.

• 11 -

Reserves Data for the Acquired Assets (Forecast Prices and Costs)

SUMMARY OF OIL AND GAS RESERVES as of December 31, 2020 FORECAST PRICES AND COSTS

Reserve Category PROVED Developed Producing Developed Non-Producing Undeveloped TOTAL PROVED TOTAL PROBABLE TOTAL PROVED PLUS PROBABLE	Heavy Crude Oil	Heavy Crude Oil
	Gross (MBbl) 2,176 - 3,622 5,798 2,464 8,262	Net (MBbl)
		1,788 - 3,040
		4,829 1,984
		6,812

SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE as at December 31, 2020 FORECAST PRICES AND COSTS

SUMMARY OF	NET PRESENT VALUES OF FUTURE NET REVENUE as at December 31, 2020 FORECAST PRICES AND COSTS	NET PRESENT VALUES OF FUTURE NET REVENUE as at December 31, 2020 FORECAST PRICES AND COSTS	NET PRESENT VALUES OF FUTURE NET REVENUE as at December 31, 2020 FORECAST PRICES AND COSTS	NET PRESENT VALUES OF FUTURE NET REVENUE as at December 31, 2020 FORECAST PRICES AND COSTS
RESERVES CATEGORY PROVED Developed Producing Developed Non-Producing Undeveloped TOTAL PROVED TOTAL PROBABLE TOTAL PROVED PLUS PROBABLE	Before Income Tax Discounted at(%/year) 0 ($000's) 5 ($000's) 10 ($000's) 15 ($000's) 20 ($000's) 43,203 40,635 38,274 36,144 34,239 - - - - - 52,992 43,290 35,332 28,843 23,541 96,195 83,924 73,606 64,988 57,781 62,919 50,576 41,505 34,814 29,801 159,115 134,501 115,111 99,802 87,582				Before Tax Net Value
	0 ($000's) 43,203 - 52,992 96,195 62,919 159,115	5 ($000's) 40,635 - 43,290 83,924 50,576 134,501	10 ($000's) 38,274 - 35,332 73,606 41,505 115,111	15 ($000's) 36,144 - 28,843 64,988 34,814 99,802	10%/yr ($/Boe)(1)
					21.40 - 11.62
					15.24 20.92
					16.90

Note:

(1) The unit values are based on net reserve volumes.

TOTAL FUTURE NET REVENUE (UNDISCOUNTED) as at December 31, 2020 FORECAST PRICES AND COSTS

RESERVES CATEGORY Proved Reserves Proved Plus Probable Reserves	REVENUE ($000's) 258,745 381,919	ROYALTIES ($000's) 43,691 67,593	OPERATING COSTS ($000's) 71,112 106,791	DEVELOPMENT COSTS ($000's) 39,083 39,083	ABANDONMENT AND RECLAMATION COSTS(2) ($000's) 8,665 9,337	FUTURE NET REVENUE BEFORE INCOME TAXES ($000's) (1)
						96,195 159,115

Notes:

(1) The estimated values of future net revenues disclosed do not represent fair market value.

(2) Reflects estimated abandonment and reclamation for all wells (both existing and undrilled wells) that have been attributed reserves, non-attributed reserves and facilities.

• 12 -

FUTURE NET REVENUE BY PRODUCTION TYPE as of December 31, 2020 FORECAST PRICES AND COSTS

	FUTURE NET REVENUE BY PRODUCTION TYPE as of December 31, 2020 FORECAST PRICES AND COSTS
RESERVES CATEGORY Proved Reserves Proved Plus Probable Reserves	PRODUCTION TYPE Heavy Crude Oil Total Heavy Crude Oil Total	FUTURE NET REVENUE BEFORE INCOME TAXES (discounted at 10%/year) ($000's) 73,606 73,606 115,111 115,111	UNIT VALUE(1) ($)
			15.24/Boe 15.24/Boe 16.90/Boe 16.90/Boe

Note:

(1) Unit values are based on net reserve volumes.

Pricing Assumptions – Forecast Prices and Costs

The following tables set forth the benchmark reference prices, as at October 1, 2020 reflected in the Reserves Data. The forecast of prices, inflation and exchange rates provided in the table below were computed using the average of the forecasts by GLJ, McDaniel & Associates Ltd. and Sproule Associates Limited, effective as at October 1, 2020.

PRICING AND INFLATION RATE ASSUMPTIONS SUMMARY OF PRICING AND INFLATION RATE ASSUMPTIONS[(1)] as of October 1, 2020 FORECAST PRICES AND COSTS

Year Forecast(3) 2020 Q4 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031	WTI Cushing Oklahoma ($US/Bbl) 41.33 45.33 50.50 53.84 55.73 57.46 58.61 59.78 60.97 62.19 63.44 64.71	Light Sweet Crude Oil at Edmonton 40o API ($Cdn/Bbl) Bow River Crude Oil at Hardisty ($Cdn/Bbl) 49.12 40.20 53.73 42.85 60.39 49.07 64.66 53.18 67.53 55.33 69.73 57.24 71.16 58.39 72.62 59.55 74.11 60.74 75.63 61.96 77.14 63.19 78.69 64.46 Thereafter	WCS Crude Oil at Hardisty ($Cdn/Bbl) Natural Gas AECO-C Spot ($Cdn/ MMBtu) Operating Cost Inflation Rates %/Year 39.02 2.82 0.0 42.21 2.75 0.3 48.22 2.61 1.7 52.33 2.59 2.0 54.47 2.63 2.0 56.37 2.68 2.0 57.50 2.73 2.0 58.65 2.79 2.0 59.82 2.84 2.0 61.02 2.90 2.0 62.24 2.96 2.0 63.49 3.02 2.0 Escalation rate of 2.0%	Capital Cost Inflation Rates %/Year 0.0 0.3 1.7 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0	Exchange Rate (2) ($US/$Cdn)
					0.7567 0.7600 0.7667 0.7667 0.7667 0.7667 0.7667 0.7667 0.7667 0.7667 0.7667 0.7667

Notes:

(1) This summary table identifies benchmark reference pricing schedules that might apply to a reporting issuer . (2) The exchange rate used to generate the benchmark reference prices in this table. (3) As at October 1, 2020.

During the nine (9) months ended September 30, 2020, the historical weighted average prices realized in respect of the production associated with the Acquired Assets were $31.49/bbl for heavy crude oil.

• 13 -

Production Estimates

The following table sets out the volumes of working interest production, using forecast prices and costs, estimated for the year ended December 31, 2021 in the Acquisition Reserves Report, which is reflected in the estimate of future net revenue disclosed in the tables above.

Proved Producing Developed Non-Producing Undeveloped Total Proved Total Probable Total Proved Plus Probable	Heavy Crude Oil (Bbls/d) Gross Net 2,363 1,981 - - 1,109 976 3,471 2,957 465 403 3,936 3,360	Heavy Crude Oil (Bbls/d) Gross Net 2,363 1,981 - - 1,109 976 3,471 2,957 465 403 3,936 3,360	Total	Total
			(Boe/d)
	Gross		Gross 2,363 - 1,109 3,471 465 3,936	Net
	2,363 - 1,109 3,471 465 3,936			1,981 - 976
				2,957 403
				3,360