UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 001-39191

Ovintiv Inc.

(Exact name of registrant as specified in its charter)

Delaware	84-4427672
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

Suite 1700, 370 17^th Street, Denver, Colorado, 80202, U.S.A.

(Address of principal executive offices)

Registrant’s telephone number, including area code (303) 623-2300

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of each exchange on which registered
Common Shares	OVV	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes ☒ No ☐

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act):

Yes ☐ No ☒ 

Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 28, 2019	$	6,907,265,769
Number of registrant’s shares of common stock outstanding as of February 19, 2020, at $0.01 par value		259,821,141

Documents Incorporated by Reference

Portions of registrant’s definitive proxy statement (“Proxy Statement”) for the registrant’s 2020 annual meeting of stockholders to be held April 29, 2020 (to be filed with the Securities and Exchange Commission prior to April 29, 2020) are incorporated by reference in Part III of this Annual Report on Form 10-K.

OVINTIV INC.

FORM 10-K

TABLE OF CONTENTS

PART I
Items 1 and 2. Business and Properties	8
Item 1A. Risk Factors	30
Item 1B. Unresolved Staff Comments	41
Item 3.    Legal Proceedings	41
Item 4.    Mine Safety Disclosures	42
PART II
Item 5.    Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities	43
Item 6.    Selected Financial Data	45
Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations	46
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	73
Item 8.    Financial Statements and Supplementary Data	75
Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	142
Item 9A. Controls and Procedures	142
Item 9B. Other Information	142
PART III
Item 10.  Directors, Executive Officers and Corporate Governance	143
Item 11.  Executive Compensation	143
Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters	143
Item 13.  Certain Relationships and Related Transactions, and Director Independence	143
Item 14.  Principal Accounting Fees and Services	143
PART IV
Item 15.  Exhibits and Financial Statement Schedules	144
Signatures	151

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DEFINITIONS

Unless the context otherwise requires or otherwise expressly stated, all references in this Annual Report on Form 10-K to “Ovintiv,” the “Company,” “us,” “we,” “our” and “ours,” (i) for periods until the Reorganization (as hereinafter defined), refer to Encana Corporation and its consolidated subsidiaries and (ii) for periods after the Reorganization, refer to Ovintiv Inc. and its consolidated subsidiaries. In addition, the following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:

“AECO” means Alberta Energy Company and is the Canadian benchmark price for natural gas.

“ASC” means Accounting Standards Codification.

“ASU” means Accounting Standards Update.

“bbl” or “bbls” means barrel or barrels.

“bbls/d” means barrels per day.

“Bcf” means billion cubic feet.

“Bcf/d” means billion cubic feet per day.

“BOE” means barrels of oil equivalent.

“BOE/d” means barrels of oil equivalent per day.

“Btu” means British thermal units, a measure of heating value.

“DD&A” means depreciation, depletion and amortization expenses.

“FASB” means Financial Accounting Standards Board.

“LIBOR” means London Interbank Offered Rate.

“Mbbls” means thousand barrels.

“Mbbls/d” means thousand barrels per day.

“MBOE” means thousand barrels of oil equivalent.

“MBOE/d” means thousand barrels of oil equivalent per day.

“Mcf” means thousand cubic feet.

“Mcf/d” means thousand cubic feet per day.

“MD&A” means Management’s Discussion and Analysis of Financial Condition and Results of Operations.

“MMbbls” means million barrels.

“MMbbls/d” means million barrels per day.

“MMBOE” means million barrels of oil equivalent.

“MMBOE/d” means million barrels of oil equivalent per day.

“MMBtu” means million Btu.

“MMcf” means million cubic feet.

“MMcf/d” means million cubic feet per day.

“NCIB” means normal course issuer bid.

“NGL” or “NGLs” means natural gas liquids.

“NYMEX” means New York Mercantile Exchange.

“NYSE” means New York Stock Exchange.

“OPEC” means Organization of the Petroleum Exporting Countries.

“SCOOP” means South Central Oklahoma Oil Province.

“SEC” means United States Securities and Exchange Commission.

“STACK” means Sooner Trend, Anadarko basin, Canadian and Kingfisher counties

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“Standardized measure” means the present value of after-tax future net revenues discounted at 10% per annum.

“S&P 500” means Standard and Poor’s 500 index.

“S&P/TSX Composite Index” means Standard and Poor’s index for Canadian equity markets.

“TSX” means Toronto Stock Exchange.

“U.S.” or “United States” or “USA” means United States of America.

“U.S. GAAP” means U.S. Generally Accepted Accounting Principles.

“WTI” means West Texas Intermediate.

CONVERSIONS

In this Annual Report on Form 10-K, a conversion of natural gas volumes to BOE is on the basis of six Mcf to one bbl.  BOE is based on a generic energy equivalency conversion method primarily applicable at the burner tip and does not represent economic value equivalency at the wellhead. Given that the value ratio based on the current price of 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, particularly if used in isolation.

CONVENTIONS

Unless otherwise specified, all dollar amounts are expressed in U.S. dollars, all references to “dollars”, “$” or “US$” are to U.S. dollars and all references to “C$” are to Canadian dollars. All amounts are provided on a before tax basis, unless otherwise stated. In addition, all information provided herein is presented on an after royalties basis.

The term “liquids” is used to represent oil, NGLs and condensate. The term “liquids rich” is used to represent natural gas streams with associated liquids volumes. The term “play” is used to describe an area in which hydrocarbon accumulations or prospects of a given type occur. The Company’s focus of development is on hydrocarbon accumulations known to exist over a large areal expanse and/or thick vertical section and are developed using hydraulic fracturing. This type of development typically has a lower geological and/or commercial development risk and lower average decline rate, when compared to conventional development.

The term “core asset” refers to plays that are the focus of the Company’s current capital investment and development plan. The Company continually reviews funding for development of its plays based on strategic fit, profitability and portfolio diversity and, as such, the composition of plays identified as a core asset may change over time.

References to information contained on the Company’s website at www.ovintiv.com are not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

FORWARD-LOOKING STATEMENTS AND RISK

This Annual Report on Form 10-K and documents incorporated herein by reference contain certain forward-looking statements or information (collectively, “forward-looking statements”) within the meaning of applicable securities legislation, including the United States Private Securities Litigation Reform Act of 1995. Forward-looking statements include: composition of the Company’s core assets, including the allocation of capital and focus of development plans; growth in long-term shareholder value; vision of being a leading North American resource play company; statements with respect to the Company’s strategic objectives including capital allocation strategy, focus of investment, focus of returning capital to shareholders through sustainable dividends, growth of high margin liquids volumes, operating and capital efficiencies and ability to preserve balance sheet strength; statements regarding the benefits of the Company’s multi-basin portfolio of assets; ability to leverage technology to reduce development risks, enhance capital and operating efficiencies and sustainably enhance margins while minimizing the Company’s environmental footprint; ability to lower costs and improve efficiencies to achieve competitive advantage, including benefits of integrated supply chain model and self-sourcing; ability to repeat and deploy successful practices across the Company’s multi-basin portfolio; balancing commodity portfolio; anticipated commodity prices; success of and benefits from technology and innovation, including cube development approach,

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precision well targeting and advanced completion designs; reduced dependence on fresh water requirements and anticipated water infrastructure; ability to accelerate activity levels; ability to optimize well and completion designs, including changes to lateral lengths drilled, stage, well spacing and stacking optimization; future well inventory; anticipated drilling, number of drilling rigs and the success thereof; anticipated drilling costs and cycle times; anticipated proceeds and future benefits from various joint venture, partnership and other agreements; expected timing for construction of facilities and costs thereof; expansion of future midstream services; estimates of reserves and resources; expected production and product types; ability to replicate successful test wells to future production; statements regarding anticipated cash flow, non-GAAP cash flow margin and leverage ratios; anticipated cash and cash equivalents; anticipated hedging and outcomes of risk management program, including ability to leverage marketing fundamentals expertise, exposure to certain commodity prices and foreign exchange, amount of hedged production, market access and physical sales locations; impact of changes in laws and regulations, including recent U.S. tax reform and potential changes to free trade agreements; compliance with environmental legislation and claims related to the purported causes and impact of climate change, and the costs therefrom; adequacy of provisions for abandonment and site reclamation costs; financial flexibility and discipline; access to cash and cash equivalents and other methods of funding; ability to meet financial obligations, manage debt and financial ratios, finance growth and compliance with financial covenants; impact to the Company as a result of changes to its credit rating; access to the Company's credit facilities; planned annualized dividend and the declaration and payment of future dividends, if any; statements regarding the Company’s financial flexibility and access to liquidity through commodity cycles; managing capital structure including adjustments to capital spending or dividends, issuing debt or equity, or repaying existing debt; adequacy of the Company's provision for taxes and legal claims; projections and expectation of meeting the targets contained in the Company's corporate guidance; ability to manage cost inflation and expected cost structures, including expected operating, transportation and processing and administrative expenses; competitiveness and pace of growth of the Company’s assets within North America and against its peers; outlook of oil and gas industry generally and impact of geopolitical environment; returns from the Company’s core assets; anticipated capital spending plans and source of funding thereof; anticipated staffing levels; expected future interest expense; the Company’s commitments and obligations and ability to satisfy the same; statements with respect to future ceiling test impairments; and the possible impact and timing of accounting pronouncements, rule changes and standards.

Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous assumptions, risks and uncertainties that may cause such statements not to occur, or results to differ materially from those expressed or implied. These assumptions include: future commodity prices and differentials; foreign exchange rates; ability to access credit facilities and shelf prospectuses; assumptions contained in the Company’s corporate guidance and as specified herein; data contained in key modeling statistics; availability of attractive hedges and enforceability of risk management program; effectiveness of the Company's drive to productivity and efficiencies; results from innovations; expectation that counterparties will fulfill their obligations under the gathering, midstream and marketing agreements; access to transportation and processing facilities where the Company operates; assumed tax, royalty and regulatory regimes; and expectations and projections made in light of, and generally consistent with, the Company's historical experience and its perception of historical trends, including with respect to the pace of technological development, benefits achieved and general industry expectations.

Risks and uncertainties that may affect these outcomes include: ability to generate sufficient cash flow to meet obligations; commodity price volatility; ability to secure adequate transportation and potential pipeline curtailments; variability and discretion of the Company's board of directors (the “Board of Directors”) to declare and pay dividends, if any; timing and costs of well, facilities and pipeline construction; business interruption, property and casualty losses or unexpected technical difficulties, including impact of weather; counterparty and credit risk; ability to realize the anticipated benefits of acquisitions; ability to achieve the benefits of the Reorganization; actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls; sustained declines in commodity prices resulting in impairment of assets; impact of a downgrade in credit rating and its impact on access to sources of liquidity; fluctuations in currency and interest rates; risks associated with inflation rates; risks inherent in the Company's corporate guidance; failure to achieve cost and efficiency initiatives; risks inherent in marketing operations; risks associated with technology, including electronic, cyber and physical security breaches; changes in or interpretation of royalty, tax, environmental, greenhouse gas, carbon, accounting and other laws or regulations, including potential environmental liabilities that are not covered by an effective indemnity or insurance; risks associated with existing and potential lawsuits and regulatory actions made against the Company; impact of disputes arising with its partners, including suspension of certain obligations and inability to dispose of

6

assets or interests in certain arrangements; the Company's ability to acquire or find additional reserves; imprecision of reserves estimates and estimates of recoverable quantities, including future net revenue estimates; land, legal, regulatory and ownership complexities inherent in Canada, the U.S. and other applicable jurisdictions; risks associated with past and future acquisitions or divestitures of certain assets or other transactions or receipt of amounts contemplated under the transaction agreements (such transactions may include third-party capital investments, farm-outs or partnerships, which the Company may refer to from time to time as “partnerships” or “joint ventures” and the funds received in respect thereof which the Company may refer to from time to time as “proceeds”, “deferred purchase price” and/or “carry capital”, regardless of the legal form) as a result of various conditions not being met; and other risks described in Item 1A. Risk Factors of this Annual Report on Form 10-K and risks and uncertainties impacting the Company's business as described from time to time in the Company's other periodic filings with the SEC incorporated by reference in this Annual Report on Form 10-K.

Although the Company believes the expectations represented by such forward-looking statements are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned that the assumptions, risks and uncertainties referenced above and in the documents incorporated by reference herein are not exhaustive. Forward-looking statements are made as of the date of this document (or, in the case of a document incorporated by reference, the date of such document incorporated by reference) and, except as required by law, the Company undertakes no obligation to update publicly or revise any forward-looking statements. The forward-looking statements contained or incorporated by reference in this Annual Report on Form 10-K are expressly qualified by these cautionary statements.

The reader should read carefully the risk factors described in Item 1A. Risk Factors of this Annual Report on Form 10-K and the documents incorporated by reference in this Annual Report on Form 10-K for a description of certain risks that could, among other things, cause actual results to differ from these forward-looking statements.

EXPLANATORY NOTE

Pursuant to Rule 12g-3(a) under the Exchange Act, Ovintiv is the successor issuer to Encana, Ovintiv’s common stock is deemed to be registered under Section 12(b) of the Exchange Act, and Ovintiv is subject to the periodic and current reporting requirements of the Exchange Act and the rules and regulations promulgated thereunder. Therefore, financial information and results of operations presented in this Annual Report on Form 10-K relate to Ovintiv Inc. Refer to Items 1 and 2. Business and Properties under Part 1 for further information on this Form 10-K.

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PART I

Items 1 and 2. Business and Properties

GENERAL

On January 24, 2020, Encana Corporation (“Encana”) completed a corporate reorganization (the “Reorganization”), which included (i) a plan of arrangement under the Canada Business Corporations Act (the “CBCA”), pursuant to which, among other things, Encana completed a share consolidation on the basis of one post-consolidation share for each five pre-consolidation shares (the “Share Consolidation”) and Ovintiv ultimately acquired all of the issued and outstanding common shares of Encana in exchange for shares of Ovintiv on a one-for-one basis and became the parent company of Encana and its subsidiaries (collectively, the “Arrangement”) and (ii) following completion of the Arrangement, Ovintiv migrated out of Canada and became a Delaware corporation (the “U.S. Domestication”). Ovintiv and its subsidiaries continue to carry on the business previously conducted by Encana and its subsidiaries prior to the completion of the Reorganization.

Prior to the completion of the Reorganization, Encana was incorporated under the CBCA, having been formed in 2002 through the business combination of two predecessor companies.

Ovintiv is a leading North American resource play company that is focused on developing its multi-basin portfolio of top tier oil and natural gas assets located in the United States and Canada. Ovintiv's operations also include the marketing of oil, NGLs and natural gas. As at December 31, 2019, all of the Company’s reserves and production were located in North America.

Ovintiv’s principal office is located at 370 – 17^th Street, Suite 1700, Denver, Colorado 80202, U.S.A. Ovintiv’s shares of common stock are listed and posted for trading on the NYSE and the TSX under the symbol “OVV”.

Available Information

Ovintiv is subject to the informational requirements of the United States Securities Exchange Act of 1934, as amended (the “Exchange Act”) and, in accordance with the Exchange Act, it also files reports with and furnishes other information to the SEC. The public may obtain any document Ovintiv files with or furnishes to the SEC from the SEC's Electronic Document Gathering, Analysis, and Retrieval system (“EDGAR”), which can be accessed at www.sec.gov, or via the System for Electronic Document Analysis and Retrieval (“SEDAR”), which can be accessed at www.sedar.com, as well as from commercial document retrieval services.

Copies of this Annual Report on Form 10-K and the documents incorporated herein by reference may be obtained on request without charge from Ovintiv’s Corporate Secretary, 370 – 17^th Street, Suite 1700, Denver, Colorado 80202, U.S.A., telephone: (303) 623-2300. Ovintiv also provides access without charge to all of the Company’s SEC filings, including copies of this Annual Report on Form 10-K and the documents incorporated herein by reference, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after filing or furnishing, on Ovintiv’s website located at www.ovintiv.com.

STRATEGY

Ovintiv’s vision is to be a leading North American resource play company that is committed to growing long-term stockholder value through a disciplined focus on generating profitable liquids growth as well as generating cash flows in excess of capital expenditures. Objectives that support the execution of the Company’s strategy include:

• Balance sheet strength

• Focused investment in high margin liquids plays to drive cash flow, free cash flow and returns from a multi-basin portfolio

• Disciplined capital allocation

• Maximizing profitability through operational and capital efficiencies

• Focused on returning capital to stockholders through sustainable dividends

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The following strengths enable Ovintiv to achieve the Company’s strategy of creating stockholder value and generating free cash flow:

• Liquids rich resource base in North America’s leading resource plays – The Company holds a multi-basin portfolio of prolific oil and liquids rich plays in North America, including: the Permian in Texas, the Anadarko in Oklahoma and the Montney in British Columbia and Alberta. Ovintiv’s multi-basin portfolio provides both optionality and risk management attributes due to the diversity of the Company’s resource plays and their geographic locations. Production for the year ended December 31, 2019 was approximately 53 percent oil and NGLs and 47 percent natural gas. As of December 31, 2019, the Company’s estimated net proved reserves comprised approximately 33 percent oil, 27 percent natural gas liquids and 40 percent natural gas.

• A deep inventory of short-cycle opportunities and disciplined capital allocation strategy – The Company has a deep inventory of high-quality, liquids-rich opportunities which underpin the Company’s sustainable business model. Each of the Company’s assets has a defined role, ranging from near-term liquids growth, optimized cash flow generation from base assets, or future growth potential. Ovintiv’s quick-cycle resource plays allow for capital programs to be right-sized to the macro commodity-price and service cost environment. Ovintiv’s capital investment strategy focuses on quality growth from a limited number of core, high-margin liquids and scalable projects.

• Enhancing returns through leveraging technology and efficiency – The Company is a leader in innovative horizontal drilling and completions methods that leverage advanced technology. Successful operating practices are quickly deployed across the Company’s multi-basin portfolio, as appropriate, to achieve competitive advantage. Technology and innovation enable Ovintiv to reduce development risks, enhance capital and operating efficiencies, and sustainably enhance margins and returns while minimizing its environmental footprint.

• Access to ample liquidity – The Company has access to ample liquidity to allow the business to be managed through the inevitable commodity cycles. We have financial flexibility and the Company’s annual capital programs can be quickly adapted to reflect changes in commodity markets and cash flows. Ovintiv also leverages its market fundamentals expertise by actively monitoring and managing market volatility and diversifying price and market access risks to enhance the Company’s margins.

• Retention of experienced and proven management team and key personnel – The Company has cultivated a culture of innovation and entrepreneurial spirit that allows for continual improvement of the Company’s practices across its multi-basin portfolio. Management and key personnel have extensive experience in the core plays as well as executing on multi-rig horizontal development drilling programs. Ovintiv also ensures management and personnel interests are aligned with those of the Company’s shareholders.

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REPORTING SEGMENTS

Ovintiv’s operations are focused on the finding and development of oil, NGLs and natural gas reserves. The Company is also focused on creating and capturing additional value through its market optimization segment. The Company conducts a substantial portion of its business through subsidiaries. Ovintiv’s operating and reportable segments are: (i) USA Operations; (ii) Canadian Operations; (iii) China Operations; and (iv) Market Optimization.

• USA Operations includes the exploration for, development of, and production of oil, NGLs, natural gas and other related activities within the U.S. Core assets that are part of Ovintiv’s strategic development focus include: Permian in west Texas and Anadarko in west-central Oklahoma. Other Upstream Operations comprise assets that are not part of Ovintiv’s current strategic focus and primarily include: Eagle Ford in south Texas, Bakken in North Dakota and Uinta in central Utah.

• Canadian Operations includes the exploration for, development of, and production of oil, NGLs, natural gas and other related activities within Canada. Core assets that are part of Ovintiv’s strategic development focus include Montney in northeast British Columbia and northwest Alberta. Other Upstream Operations comprise assets that are not part of Ovintiv’s current strategic focus and primarily include: Duvernay in west central Alberta, Wheatland in southern Alberta, Horn River in northeast British Columbia and Deep Panuke located offshore Nova Scotia.

• China Operations includes the exploration for, development of, and production of oil and other related activities within China. The Company terminated its production sharing contract with the China National Offshore Oil Corporation (“CNOOC”) and exited its China Operations effective July 31, 2019. The Company no longer has operations in China. Results from China operations during February 14, 2019 to July 31, 2019 were not material to the Company.

• Market Optimization activities are managed by the Midstream, Marketing & Fundamentals team, which is primarily responsible for the sale of the Company’s proprietary production to third party customers and enhancing the associated netback price. Market Optimization activities also include third party purchases and sales of product to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification.

For additional information regarding the reporting segments, see Note 2 of the audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

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OIL AND GAS PROPERTIES AND ACTIVITIES

The following map reflects the location of Ovintiv’s North American landholdings and assets.

The term “core asset” refers to plays that are the primary focus of Ovintiv’s capital investment and development, providing a competitive return profile and free cash flows. Other Upstream Operations comprise base assets that are not part of Ovintiv’s current strategic focus and therefore receive limited capital that is directed to high margin locations that generate cash flows and returns.

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USA Operations

Overview: In 2019, the USA Operations had total capital investment of approximately $2,134 million and drilled approximately 236 net wells predominately in Permian, Anadarko, Eagle Ford and Bakken. Production averaged approximately 162.3 Mbbls/d of oil, approximately 78.4 Mbbls/d of NGLs and approximately 547 MMcf/d of natural gas. At December 31, 2019, the USA Operations had an established land position of approximately 1.1 million net acres including approximately 207,000 net undeveloped acres. In addition, the USA Operations accounted for 71 percent of production revenues, excluding the impacts of hedging, during 2019 and 70 percent of total proved reserves as at December 31, 2019.

With the acquisition of Newfield Exploration Company (“Newfield”) on February 13, 2019 (the “Newfield acquisition”), the Company acquired new properties in the following plays: Anadarko and Arkoma in Oklahoma, Bakken in North Dakota and Uinta in Utah, as well as offshore oil assets located in China.

Upon completion of the Newfield acquisition, certain plays were re-organized to align to the Company’s current strategic development focus. As a result, Eagle Ford is presented in Other Upstream Operations. Accordingly, comparative information has been reorganized.

During 2019, the Company divested of approximately 140,000 net acres in Arkoma for proceeds of $155 million, after closing adjustments.

The following tables summarize the USA Operations landholdings, producing wells and daily production as at and for the periods indicated.

Landholdings (1)	Developed Acreage		Undeveloped Acreage		Total Acreage		Average Working Interest
(thousands of acres at December 31, 2019)	Gross	Net	Gross	Net	Gross	Net
Permian	100	92	30	18	130	110	85%
Anadarko	595	372	33	14	628	386	61%
Other Upstream Operations
Eagle Ford	44	42	-	-	44	42	95%
Bakken	99	66	6	6	105	72	69%
Uinta	240	185	59	37	299	222	74%
Other (2)	221	113	318	132	539	245	45%
Total USA Operations	1,299	870	446	207	1,745	1,077	62%

(1) Excludes interests in royalty acreage.

(2) Other comprises assets that are not part of the Company’s strategic focus.

Producing Wells	Oil		Natural Gas		Total
(number of wells at December 31, 2019) (1)	Gross	Net	Gross	Net	Gross	Net
Permian	1,689	1,587	2	2	1,691	1,589
Anadarko	1,490	643	576	161	2,066	804
Other Upstream Operations
Eagle Ford	489	460	62	57	551	517
Bakken	616	244	-	-	616	244
Uinta	1,493	1,177	17	8	1,510	1,185
Other (2)	30	-	123	111	153	111
Total USA Operations	5,807	4,111	780	339	6,587	4,450

(1) Figures exclude wells capable of producing, but not producing.

(2) Other comprises assets that are not part of the Company’s strategic focus.

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			NGLs
Production	Oil (Mbbls/d)		Plant Condensate (Mbbls/d)		Other (Mbbls/d)		Total (Mbbls/d)		Natural Gas (MMcf/d)
(average daily)	2019	2018	2019	2018	2019	2018	2019	2018	2019	2018
Permian	64.7	58.8	2.3	2.1	20.0	17.2	22.3	19.3	106	86
Anadarko	44.4	-	6.0	-	38.3	-	44.3	-	316	-
Other Upstream Operations (1)
Eagle Ford	25.3	28.4	1.3	1.6	5.9	6.8	7.2	8.4	43	52
Bakken	14.0	-	0.6	-	3.1	-	3.7	-	23	-
Uinta	13.9	-	0.2	-	0.5	-	0.7	-	13	-
Other (2)	-	2.3	0.1	0.1	0.1	1.2	0.2	1.3	46	13
Total USA Operations	162.3	89.5	10.5	3.8	67.9	25.2	78.4	29.0	547	151

(1) Other Upstream Operations includes production from Arkoma which was divested in 2019 and from San Juan which was divested in 2018.

(2) Other comprises assets that are not part of the Company’s strategic focus.  

Permian

Permian is an oil play located in west Texas in Midland, Martin, Howard, Glasscock and Upton counties. The primary focus is on the development of the Spraberry and Wolfcamp formations in the Midland basin, where Ovintiv holds a large position. At December 31, 2019, the Company controlled approximately 110,000 net acres in the play. The properties are characterized by exposure of up to 11 potential producing horizons spanning approximately 4,000 feet of stratigraphy or stacked pay, an extensive production history and developed infrastructure. In 2019, production averaged approximately 64.7 Mbbls/d of oil, approximately 22.3 Mbbls/d of NGLs and approximately 106 MMcf/d of natural gas.

During 2019, the Company continued to focus on efficiency improvements and maximizing resource recovery by accessing layers of the stacked pay simultaneously using the cube development model. This approach utilizes multi-well pads, multi-rig spreads and frac spreads running in parallel to optimize cycle times, and increase capital efficiency, while minimizing the surface footprint. The Company focused on capturing operational efficiencies through optimizing wellbore designs and maximizing usage of recycled water from its centralized water infrastructure to reduce costs. During 2019, the Company drilled 114 horizontal net wells with lateral lengths ranging from approximately 6,200 to 12,500 feet at a measured average total depth of approximately 17,800 feet with well spacing ranging from approximately 500 to 1,000 feet. As Ovintiv continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change.

Oil and natural gas facilities include field gathering systems, storage batteries, saltwater disposal systems, separation equipment and pumping units. The majority of Ovintiv’s acreage and associated oil production is dedicated to a pipeline gathering agreement, which has a total remaining term of 14 years including optional renewal terms. In the event of pipeline capacity constraints, Ovintiv’s oil production is trucked by a third party. Natural gas is delivered by the Company to the purchaser’s meter and pipeline interconnection point in the field.

Anadarko

Anadarko is a liquids rich play located in west-central Oklahoma in Blaine, Canadian, Custer, Dewey, Grady, Kingfisher, Major and McClain counties. The majority of the Anadarko properties are located in the black oil window of the STACK which comprises the Woodford, Meramec and Osage formations spanning up to 800 feet of stratigraphy and in the SCOOP which comprises the Woodford, Sycamore, Caney and Springer formations spanning up to 1,150 feet of stratigraphy. At December 31, 2019, the Company controlled approximately 386,000 net acres in the play. The play is characterized by exposure to up to eight geologic horizons which include silt, shale and carbonate formations providing multiple potential horizontal oil and gas targets making the play ideal for long laterals and cube development. From February 14, 2019 to December 31, 2019, production averaged approximately 44.4 Mbbls/d of oil, approximately 44.3 Mbbls/d of NGLs and approximately 316 MMcf/d of natural gas.

The focus of development is on the liquids weighted portions of the basin, including the Woodford, Springer and Mississippian targets. Since acquiring the asset in February 2019, the Company has utilized its cube development model to optimize completion and well spacing, which has resulted in reducing the cycle times and drilling and

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completion costs by approximately 20 percent. In addition, the Company implemented self-sourced consumables, including sand and chemicals to improve supply reliability, reduce costs and minimize its environmental footprint.

During 2019, the Company drilled 74 horizontal net wells with lateral lengths ranging from approximately 5,000 to 10,000 feet at a measured average total depth of approximately 18,800 feet with well spacing ranging from approximately 660 to 1,300 feet. As the Company continues to optimize well and completion designs, lateral lengths drilled, stage and well spacing may change.  

The play has significant existing infrastructure and is located within close proximity to markets including Cushing, Oklahoma, the Gulf Coast and Mont Belvieu. Oil and natural gas production are gathered at various production facilities, with the majority of the oil subsequently transported to sales points by pipeline. The majority of Ovintiv’s acreage and associated production is dedicated to various long-term gathering and processing agreements with various third parties, which have remaining terms ranging from five to 12 years.

Other Upstream Operations

Eagle Ford

Eagle Ford is an oil play located in south Texas in Karnes and Atascosa counties. The focus is on the development of the thickest portion of the Eagle Ford shale in the Karnes Trough, where Ovintiv holds a largely contiguous position. At December 31, 2019, the Company controlled approximately 42,000 net acres in the play. Ovintiv is focused on developing the lower Eagle Ford, as well as optimizing targets in the upper Eagle Ford, expanding development activity in the Austin Chalk and delineation of Graben, exclusively using horizontal drilling. During 2019, the Company drilled approximately 33 net wells in the area with lateral lengths ranging from approximately 2,500 to 7,200 feet with an average measured total depth of approximately 16,600 feet. As Ovintiv continues to optimize development and apply advanced completions designs, lateral lengths drilled, cluster spacing and well spacing may change. Production averaged approximately 25.3 Mbbls/d of oil, approximately 7.2 Mbbls/d of NGLs and approximately 43 MMcf/d of natural gas during the year.

During 2019, the Company continued to focus on precision well targeting, spacing and stacking optimization and improving completions designs. Performance improvements were achieved from optimizing wellbore designs, pumping high volumes of thin fluid and proppant with tight cluster spacing of less than 20 feet, resulting in increased well productivity and optimized capital efficiency. The Company also focused on maintaining cost controls through well control automation, optimizing artificial lift systems and streamlining well interventions.

The play is located within close proximity to markets and has a well-developed infrastructure. Oil and natural gas production is gathered at various production facilities, with the majority of the oil subsequently transported to sales points by pipeline. Ovintiv has access to firm natural gas gathering capacity of up to approximately 50 MMcf/d and firm processing capacity of up to approximately 80 MMcf/d with third parties with remaining terms of less than six years, and owns oil processing capacity of 50.0 Mbbls/d. Ovintiv also utilizes interruptible capacity arrangements for excess production.

Bakken

Bakken is an oil play located in North Dakota primarily in McKenzie and Dunn counties, and in Montana in Richland county. The focus of development includes targets in the Bakken and Three Forks formations. At December 31, 2019, the Company controlled approximately 72,000 net acres in the play. During 2019, the Company drilled approximately 12 net wells in the area with lateral lengths ranging from approximately 9,500 to 10,200 feet with an average measured total depth of approximately 21,500 feet. From February 14, 2019 to December 31, 2019, production averaged approximately 14.0 Mbbls/d of oil, approximately 3.7 Mbbls/d of NGLs and approximately 23 MMcf/d of natural gas.

The majority of Ovintiv’s acreage and associated production is dedicated to various long-term gathering and processing agreements with various third parties, which have remaining terms of less than two years. Ovintiv uses a combination of pipeline and truck to transport oil to sales points. Ovintiv also utilizes interruptible capacity arrangements for excess production.

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Uinta

Uinta is an oil play located in central Utah primarily in Duchesne and Uintah counties. Uinta provides a deep inventory of stacked oil horizons including the Wasatch and Lower Green River formations which includes the Uteland Butte and Castle Peak, with approximately 4,000 feet of oil saturated reservoir rock across Ovintiv’s acreage. At December 31, 2019, the Company controlled approximately 222,000 net acres in the play. During 2019, the Company drilled approximately two net wells in the area with lateral lengths that averaged approximately 9,700 feet with an average measured total depth of approximately 19,300 feet. From February 14, 2019 to December 31, 2019, production averaged approximately 13.9 Mbbls/d of oil, approximately 0.7 Mbbls/d of NGLs and approximately 13 MMcf/d of natural gas.

All of Ovintiv’s oil production is transported by truck to sales points under crude oil minimum volume delivery commitments with two refineries in the Salt Lake City area with remaining terms expiring in 2020 and 2025.

Canadian Operations

Overview: In 2019, the Canadian Operations had total capital investment of approximately $480 million and drilled approximately 92 net wells predominately in Montney and Duvernay. Production averaged approximately 59.7 Mbbls/d of oil and NGLs and approximately 1,030 MMcf/d of natural gas. At December 31, 2019, the Canadian Operations had an established land position in Canada of approximately 1.7 million net acres including approximately 1.1 million net undeveloped acres. In addition, the Canadian Operations accounted for 28 percent of production revenues, excluding the impacts of hedging, during 2019 and 30 percent of total proved reserves as at December 31, 2019.

During 2019, Duvernay was reorganized to be included in Other Upstream Operations to align with the Company’s current strategic development focus. Accordingly, comparative information has been reorganized.

The following tables summarize the Canadian Operations landholdings, producing wells and daily production as at and for the periods indicated.

Landholdings (1)	Developed Acreage		Undeveloped Acreage		Total Acreage		Average Working Interest
(thousands of acres at December 31, 2019)	Gross	Net	Gross	Net	Gross	Net
Montney	572	369	671	420	1,243	789	63%
Other Upstream Operations
Duvernay	119	51	369	194	488	245	50%
Other (2)	210	148	707	498	917	646	70%
Total Canadian Operations	901	568	1,747	1,112	2,648	1,680	63%

(1) Includes interests in royalty acreage.

(2) Other primarily includes Wheatland, Horn River and Deep Panuke, as well as assets where the Company may pursue growth opportunities.

Producing Wells	Oil		Natural Gas		Total
(number of wells at December 31, 2019) (1)	Gross	Net	Gross	Net	Gross	Net
Montney	7	6	1,583	1,298	1,590	1,304
Other Upstream Operations
Duvernay	15	6	186	93	201	99
Other (2)	8	5	570	473	578	478
Total Canadian Operations	30	17	2,339	1,864	2,369	1,881

(1) Figures exclude wells capable of producing, but not producing.

(2) Other primarily includes Wheatland and Horn River.

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			NGLs
Production	Oil (Mbbls/d)		Plant Condensate (Mbbls/d)		Other (Mbbls/d)		Total (Mbbls/d)		Natural Gas (MMcf/d)
(average daily)	2019	2018	2019	2018	2019	2018	2019	2018	2019	2018
Montney	0.2	0.3	36.4	28.6	15.5	12.8	51.9	41.4	931	894
Other Upstream Operations
Duvernay	0.4	0.1	6.0	6.6	1.2	1.2	7.2	7.8	57	59
Other (1)	-	-	-	-	-	-	-	-	42	54
Total Canadian Operations	0.6	0.4	42.4	35.2	16.7	14.0	59.1	49.2	1,030	1,007

(1) Other primarily includes Wheatland, Horn River and Deep Panuke.

Montney

Montney is primarily a condensate rich natural gas play located in northeast British Columbia and northwest Alberta. While Ovintiv is currently targeting the development of condensate rich locations in the Montney formation, the acreage comprising the Montney play also includes landholdings with incremental producing formations such as Cadomin and Doig. In 2019, total production from the play averaged approximately 52.1 Mbbls/d of oil and NGLs and approximately 931 MMcf/d of natural gas. As at December 31, 2019, the Company controlled approximately 789,000 net acres in the play.

During 2019, the Company continued to focus development in the Montney formation, which is characterized by up to six stacked horizons spanning over 1,000 feet of stratigraphy and is being developed exclusively with horizontal well technology. At December 31, 2019, the Company held a large position in the Montney formation of approximately 483,000 net acres, including 256,000 net undeveloped acres and during the year production averaged approximately 51.9 Mbbls/d of oil and NGLs and approximately 892 MMcf/d of natural gas.

Ovintiv utilizes the cube development approach which has provided sustained efficiencies resulting in reduced cycle times and well costs. This development approach utilizes multi-well pads, multiple drilling rigs and completions spreads simultaneously, and advances technology to optimize well spacing and completions intensity. During 2019, the Company increased frac size while maintaining drilling and completions costs per well through efficiencies, lower cycle times, maximizing use of recycled water and leveraging its integrated supply chain. In 2019, the Company drilled approximately 84 net horizontal wells with lateral lengths ranging from approximately 5,000 to 13,000 feet and inter-well spacing ranging from approximately 650 to 990 feet. As Ovintiv continues to optimize well and completion designs, lateral lengths drilled and well spacing may change.

Ovintiv has access to natural gas processing capacity of approximately 1,400 MMcf/d, of which approximately 1,200 MMcf/d is under contract with third parties under varying terms and duration and approximately 215 MMcf/d is owned by the Company. Ovintiv also has access to gathering and compression capacity of approximately 1,600 MMcf/d, of which approximately 1,500 MMcf/d is under contract with third parties under varying terms and duration and approximately 100 MMcf/d is owned by the Company. In addition, Ovintiv has access to liquids handling capacity of approximately 100 Mbbls/d of which approximately 70 Mbbls/d is contracted with third parties under varying terms and duration, and approximately 30 Mbbls/d is owned by the Company.

The Company has a partnership agreement with a subsidiary of Mitsubishi Corporation (“Mitsubishi”) to jointly develop certain lands that are predominately in the Montney formation. Under the agreement, Mitsubishi agreed to invest C$2.9 billion for a 40 percent partnership interest. During 2019, the Company received the final investment from Mitsubishi, satisfying the commitment under the agreement. 

Other Upstream Operations:

Duvernay

Duvernay is a liquids rich shale play located in west central Alberta and includes properties that are primarily located in the Duvernay formation, which extends across the Simonette, Pinto, Edson and Willesden Green properties, but also holds potential in other overlapping formations such as the Montney. As at December 31, 2019, the Company controlled approximately 245,000 net acres, including 194,000 net undeveloped acres in the play.

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Ovintiv is currently targeting the development of liquids rich locations in the Simonette area using multi-well pad horizontal drilling technology. During 2019, the Company continued to focus on efficient development to fill existing processing capacity, reducing drilling days and increasing lateral lengths drilled to maximize capital efficiency. The Company drilled approximately seven net wells during the year and production averaged approximately 7.6 Mbbls/d of oil and NGLs and approximately 57 MMcf/d of natural gas.

Ovintiv holds an approximate 50.1 percent ownership in three Simonette natural gas processing plants and the associated gathering and compression, of which Ovintiv’s share of natural gas processing capacity is approximately 103 MMcf/d with liquids production capacity of approximately 18.0 Mbbls/d.

Wheatland

Wheatland is located in southern Alberta and includes producing horizons primarily in the coals and sands of the Cretaceous Edmonton and Belly River Groups. As at December 31, 2019, the Company had approximately 430 net producing wells and controlled approximately 153,000 net acres in the play. In 2019, natural gas production averaged approximately 5 MMcf/d.

Horn River

Horn River is located in northeast British Columbia, where development was historically in the Horn River Basin shales (Muskwa, Otter Park and Evie), which are upwards of 500 feet thick. In 2019, the Company’s natural gas production averaged approximately 37 MMcf/d. As at December 31, 2019, the Company had approximately 48 net producing horizontal wells and controlled approximately 156,000 net acres in the Horn River Basin shales. Ovintiv owns an interest in natural gas compression capacity in Horn River of approximately 285 MMcf/d at various facilities in the area. Ovintiv has a take or pay commitment under the Cabin plant natural gas processing arrangement with a third party, which has a remaining term of 14 years.

Deep Panuke

Ovintiv owns and operates the Deep Panuke natural gas field located offshore Nova Scotia, which is approximately 250 kilometres southeast of Halifax on the Scotian shelf. The offshore Production Field Centre (“PFC”) utilized for operations is under a lease arrangement which has an initial term that expires in 2021.

In May 2018, the Company permanently ceased production at Deep Panuke and commenced decommissioning activities during 2019. The Company anticipates decommissioning activities for the PFC and wells to be completed in 2020.

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PROVED RESERVES AND OTHER OIL AND GAS INFORMATION

The process of estimating oil, NGLs and natural gas reserves is complex and requires significant judgment. The Company’s estimates of proved reserves and associated future net cash flows were evaluated and prepared by the Company’s internal qualified reserves evaluators (“QREs”) and are the responsibility of management. As a result, Ovintiv has developed internal policies that prescribe procedures and standards to be followed for preparing, estimating and recording reserves in compliance with SEC definitions and regulations. Ovintiv’s policies assign responsibilities for compliance in booking reserves and require that reserve estimates be made by its QREs. QRE is defined as a registered professional licensed to practice engineering, geology, geophysics and an individual who has a minimum of five years practical experience, with at least three recent years of experience in the evaluation of reserves.

Ovintiv’s Vice-President, Corporate Reserves & Chief Reservoir Engineering and eight other staff (collectively, the “Corporate Reserves Group”) under this individual’s direction, oversee the internal preparation, review and approval of the reserves estimates. The Corporate Reserves Group reports to the Executive Vice-President, Land & Exploration and is separate and independent from the preparation of reserves estimates which are within operations who report to Ovintiv’s Executive Vice-President & Chief Operating Officer. The Corporate Reserves Group maintains Ovintiv’s internal policies that prescribe procedures and standards to be followed for preparing, estimating and recording reserves, which includes updating the Company’s reserves manual, and also conducts periodic internal audits of the procedures, records and controls relating to the preparation of reserves estimates. Ovintiv’s QREs receive ongoing education on the fundamentals of SEC definitions and reserves reporting through the review of the Company’s reserves manual and internal training programs administered by the Corporate Reserves Group. The Corporate Reserves Group also oversees the engagement of independent qualified reserves evaluators (“IQREs”) or independent qualified reserves auditors (“IQRAs”), if any, retained by the Company.

As a member of the Corporate Reserves Group, the Company’s Director, Corporate Reserves reports to Ovintiv’s Vice-President, Corporate Reserves & Chief Reservoir Engineering and is primarily responsible for overseeing the preparation of proved reserves estimates. The Director, Corporate Reserves has a Bachelor of Science with a degree in Petroleum Engineering from the University of Alberta, is a member of the Association of Professional Engineers and Geoscientists of Alberta (APEGA) and the Society of Petroleum Evaluation Engineers (Calgary Chapter).

Annually, each play is reviewed in detail by the QREs, the Corporate Reserves Group, the Company’s executive officers and an internal Reserves Review Committee, as appropriate. The Corporate Reserves Group also conducts a separate review to ensure the effectiveness of the disclosure controls and that the reserves estimates are free from material misstatement. The final reserves estimates are reviewed by Ovintiv’s Reserves Committee of the Board of Directors (the “Reserves Committee”), for approval by the Board of Directors. The Reserves Committee comprises directors that are independent and familiar with estimating oil and gas reserves and disclosure requirements. The Reserves Committee provides additional oversight to the Company’s reserves process, meeting with management periodically to review the reserves process, the portfolio of properties results and related disclosures. The Reserves Committee is also responsible for reviewing the qualifications and appointment of IQREs or IQRAs, if any, retained by the Company, including recommending the selection of such IQREs or IQRAs to the Board of Directors for its approval, and will meet with such IQREs or IQRAs to review their reports.

For year-ended December 31, 2019, the Company involved IQRAs to audit the Company’s internal oil and gas reserve estimates for certain properties. In 2019, Netherland, Sewell & Associates, Inc. audited 52 percent of the Company’s estimated U.S. proved reserve volumes and McDaniel & Associates Consultants Ltd. audited 27 percent of the Company’s estimated Canadian proved reserve volumes. An audit of reserves is an examination of a company’s oil and gas reserves by an independent petroleum consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.

Proved oil and gas reserves are those quantities of oil, natural gas and NGLs which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years.

The Company’s reserve estimates are conducted from fundamental petrophysical, geological, engineering, financial and accounting data. Reserves are estimated based on production decline analysis, analogy to producing offsets, detailed reservoir modeling, volumetric calculations or a combination of these methods, in all cases having regard to economic considerations and using technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. Data used in assessments include information obtained directly from the subsurface through wellbores such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. In the case of producing reserves, the emphasis is on decline analysis where volumetric analysis is considered to limit forecasts to reasonable levels. Non-producing reserves are estimated by analogy to producing offsets, with consideration of volumetric estimates of in place quantities. All locations to which proved undeveloped reserves have been assigned are subject to a development plan adopted by the Company’s management. The tools used to interpret the data included proprietary and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs were used to increase the quality of and confidence in the reserves estimates when available. The method or combination of methods used to estimate the reserves of each reservoir are based on the unique circumstances of each reservoir and the dataset available at the time of the estimate.

In general, estimates of economically recoverable 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 crude oil and natural gas, royalty rates, the assumed effects of regulation by governmental agencies, and future operating costs, all of which may vary materially from actual results. For those reasons, among others, estimates of the economically recoverable crude oil and natural gas reserves attributable to any particular group of properties and estimates of future net revenues associated with reserves may vary and such variations may be material. The actual production, revenues, taxes and development, and operating expenditures with respect to the reserves associated with the Company's properties may vary from the information presented herein, and such variations could be material.

The SEC regulations require that proved reserves be estimated using existing economic conditions (constant pricing). Based on this methodology, the Company’s reserves have been calculated utilizing the 12-month average trailing historical price for each of the years presented prior to the effective date of the report. The 12-month average is calculated as an unweighted average of the first-day-of-the-month price for each month. The reserves estimates provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.

Ovintiv does not file any estimates of total net proved reserves with any U.S. federal authority or agency other than the SEC and the Department of Energy (“DOE”). Reserve estimates filed with the SEC correspond with the estimates of the Company’s reserves contained in its reports. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of Ovintiv’s reserves that are filed with the SEC, however, the DOE requires reports to include the interests of all owners in wells that Ovintiv operates and to exclude all interests in wells that Ovintiv does not operate. Ovintiv is also required to provide reserves data prepared in accordance with Canadian securities regulatory requirements, specifically National Instrument 51-101, Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) which is filed concurrently on SEDAR at www.sedar.com under Ovintiv’s issuer profile. The primary differences between NI 51-101 reporting requirements and SEC requirements include the disclosure of proved and probable reserves estimated using forecast prices and costs, presentation of reserves and production before royalties and granular product type disclosures. The reserves data prepared in accordance with NI 51-101 do not form part of this Annual Report on Form 10-K.

The reserves and other oil and gas information set forth below has an effective date of December 31, 2019 and was prepared as of January 14, 2020. The audit reports prepared by the IQRAs are attached in Exhibits 99.1 and 99.2 of this Annual Report on Form 10-K.

The following table is a summary of the Company’s proved reserves and estimates of future net cash flows and discounted future net cash flows from proved reserves information relating to proved reserves which can also be found in Note 29 of Ovintiv’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

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Proved Reserves

The table below summarizes the Company’s total proved reserves by oil, NGLs and natural gas and by geographic area for the year ended December 31, 2019 and other summary operating data.

	2019
	U.S.	Canada	Total
Proved Reserves: (1)
Oil (MMbbls):
Developed	291.0	1.2	292.2
Undeveloped	431.4	0.1	431.5
Total	722.4	1.3	723.7
Natural Gas Liquids (MMbbls):
Developed	211.3	68.4	279.8
Undeveloped	198.1	110.7	308.8
Total	409.4	179.1	588.5
Natural Gas (Bcf):
Developed	1,375	1,439	2,815
Undeveloped	1,066	1,378	2,444
Total	2,441	2,818	5,259
Total Proved Reserves (MMBOE):
Developed	732	310	1,041
Undeveloped	807	340	1,148
Total	1,539	650	2,189
Percent Proved Developed	48%	48%	48%
Percent Proved Undeveloped	52%	52%	52%
Production (MBOE/d) (2)	331.9	231.5	563.4
Capital Investments (millions)	2,134	480	2,614
Total Net Producing Wells (3)	5,137	1,914	7,051
Standardized Measure of Discounted Net Cash Flows: (4)
Pre-Tax (millions)	10,641	1,575	12,216
Taxes (millions)	600	-	600
After-Tax (millions)	10,041	1,575	11,616

(1) Numbers may not add due to rounding.

(2) Total Production excludes China. Production from China during 2019 was 1.5 MBOE/d. The Company exited its China Operations effective July 31, 2019. Total Company production including China during 2019 was 564.9 MBOE/d.

(3) Total net producing wells includes producing wells and wells mechanically capable of production.

(4) The Pre-Tax standardized measure of discounted cash flows (“standardized measure”) is a non-GAAP measure. The Company believes the Pre-Tax standardized measure is a useful measure in addition to the After-Tax standardized measure, as it assists in both the estimation of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The After-Tax standardized measure is dependent on the unique tax situation of each individual company, while the Pre-Tax standardized measure is based on prices and discount factors, which are more consistent between peer companies. See Note 29 of Ovintiv’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K for the standardized measure.

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Changes to the Company’s proved reserves during 2019 are summarized in the table below:

	2019
	Oil (MMbbls)	NGLs (MMbbls)	Natural Gas (Bcf)	Total (MMBOE)
Beginning of year (1)	351.8	280.8	3,499	1,215.7
Revisions and improved recovery (2)	(55.6)	(17.1)	(515)	(158.7)
Extensions and discoveries	230.6	158.4	1,298	605.3
Purchase of reserves in place	262.0	217.2	1,904	796.6
Sale of reserves in place	(5.1)	(0.5)	(351)	(64.1)
Production	(60.0)	(50.2)	(576)	(206.2)
End of year	723.7	588.5	5,259	2,188.8
Developed	292.2	279.8	2,815	1,041.1
Undeveloped	431.5	308.8	2,444	1,147.7
Total	723.7	588.5	5,259	2,188.8

(1) Numbers may not add due to rounding.

(2) Changes in reserve estimates resulting from application of improved recovery techniques are included in revisions of previous estimates.

In 2019, the Company’s proved reserves of 2,188.8 MMBOE increased 973.1 MMBOE from 2018 primarily due to extensions and discoveries of 605.3 MMBOE from successful drilling and delineation of the Permian, Anadarko, Montney, Eagle Ford, Bakken and Duvernay. Approximately 64 percent of the 2019 extensions and discoveries were crude oil, condensate and NGLs. Revisions of previous estimates of 158.7 MMBOE included negative revisions from changes in the approved development plan of 97.5 MMBOE and lower 12-month average trailing price of 118.4 MMBOE, which was offset by positive forecast changes other than price of 57.3 MMBOE resulting from well performance and development strategy.

Purchases of 796.6 MMBOE were primarily due to the acquisition of Newfield properties. Production for 2019 was 206.2 MMBOE. Sales of 64.1 MMBOE were primarily due to the divestiture of Arkoma.

Proved reserves are estimated based on the average beginning-of-month prices during the 12-month period for the respective year. The average prices used to compute proved reserves at December 31, 2019 were WTI: $55.93 per bbl, Edmonton Condensate: C$68.80 per bbl, Henry Hub: $2.58 per MMBtu, and AECO: C$1.76 per MMBtu. Prices for natural gas, oil and NGLs are inherently volatile.

Proved Undeveloped Reserves  

Changes to the Company’s proved undeveloped reserves during 2019 are summarized in the table below:

(MMBOE)	2019
Beginning of year	611.0
Revisions of prior estimates	(108.6)
Extensions and discoveries	551.0
Conversions to developed	(132.6)
Purchase of reserves in place	234.3
Sale of reserves in place	(7.5)
End of Year	1,147.7

* Numbers may not add due to rounding.

As of December 31, 2019, there were no proved undeveloped reserves that will remain undeveloped for five years or more.

Extensions and discoveries of 551.0 MMBOE of proved undeveloped reserves were the result of successful drilling and delineation in the Permian, Anadarko, Montney, Eagle Ford, Bakken and Duvernay. Revisions of previous estimates of proved undeveloped reserves were revised down by 108.6 MMBOE primarily due to the removal of proved undeveloped locations of 97.5 MMBOE resulting from changes in the development plan related to Permian, Montney, Eagle Ford, and Duvernay, where specific locations previously planned to be drilled within five years were shifted to a later development timeframe or removed and replaced with different locations that are included in extensions and discoveries. In addition, revisions of previous estimates included a positive revision of 10.2 MMBOE

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from increased well performance and 11.7 MMBOE from infill drilling locations in the Eagle Ford. Lower average beginning-of-month prices during the 12-month period reduced the proved undeveloped reserves by 33.0 MMBOE.

Conversions of proved undeveloped reserves to proved developed status were 132.6 MMBOE, equating to 22 percent of the total prior year-end proved undeveloped reserves. Approximately 47 percent of proved undeveloped reserves conversions occurred in Canada in Montney and Duvernay and 53 percent occurred in the U.S. in Permian and Eagle Ford. The Company spent approximately $1,069 million to develop proved undeveloped reserves in 2019, of which approximately 25 percent related to the Canadian properties and 75 percent related to the U.S. properties.

Purchases of proved undeveloped reserves of 234.3 MMBOE were due to the acquisition of Newfield properties.

Sales Volumes, Prices and Production Costs  

The following table summarizes the Company’s production by final product sold, average sales price, and production cost per BOE for each of the last three years by geographic area:

	Production			Average Sales Price (1)			Average Production Cost (2)
	Oil (MMbbls)	NGLs (MMbbls)	Natural Gas (Bcf)	Oil ($/bbl)	NGLs ($/bbl)	Natural Gas ($/Mcf)	($/BOE)
2019
USA (3)	59.2	28.6	200	56.19	15.83	1.90	8.54
Canada (4)	0.2	21.6	376	53.19	40.25	2.01	11.76
China (5)	0.6	-	-	66.37	-	-	23.95
Total	60.0	50.2	576	56.27	26.33	1.97	9.90
2018
USA (4)	32.7	10.5	55	64.05	27.21	2.28	8.19
Canada (6)	0.1	18.0	368	52.54	48.05	2.24	12.00
Total	32.8	28.5	423	64.00	40.31	2.25	10.49
2017
USA (4)	27.7	8.7	97	49.14	22.30	3.03	9.42
Canada (6)	0.1	10.6	306	42.33	45.35	2.16	11.46
Total	27.8	19.3	403	49.10	34.98	2.37	10.52

(1) Excludes the impact of commodity derivatives.

(2) Excludes ad valorem, severance and property taxes.

(3) Annual production from fields that comprise greater than 15% of the Company’s total proved reserves as at December 31, 2019 related to:

Midland county in Permian: 10.2 MMbbls of oil, 4.2 MMbbls of NGLs and 22 Bcf of natural gas;

Stack in Anadarko: 13.2 MMbbls of oil, 10.0 MMbbls of NGLs and 72 Bcf of natural gas.

(4) There were no fields that comprised greater than 15% of the Company’s total proved reserves for the periods ended.

(5) The Company acquired offshore China operations as part of the Newfield acquisition on February 13, 2019. Effective July 31, 2019, the Company terminated the production sharing contract with CNOOC and exited China. Production reported are presented for the period from February 14, 2019 through July 31, 2019.

(6) Annual production from the Dawson North field in Montney, which was greater than 15% of the Company’s total proved reserves for the periods ended: 2018 - 164 Bcf of natural gas and 8.5 MMbbls of NGLs; and 2017 - 81 Bcf of natural gas and 2.3 MMbbls of NGLs.

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Drilling and other exploratory and development activities ^{(1, 2)}

The following tables summarize the Company’s gross participation and net interest in wells drilled for the periods indicated by geographic area.

	Exploratory				Development				Total
	Productive		Dry		Productive		Dry		Productive		Dry
	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net	Gross	Net
2019
USA	-	-	-	-	392	236	-	-	392	236	-	-
Canada	1	1	-	-	125	91	-	-	126	92	-	-
Total	1	1	-	-	517	327	-	-	518	328	-	-
2018
USA	-	-	-	-	187	170	-	-	187	170	-	-
Canada	1	1	-	-	213	138	-	-	214	139	-	-
Total	1	1	-	-	400	308	-	-	401	309	-	-
2017
USA	-	-	-	-	183	168	-	-	183	168	-	-
Canada	2	1	-	-	189	116	-	-	191	117	-	-
Total	2	1	-	-	372	284	-	-	374	285	-	-

(1) “Gross” wells are the total number of wells in which the Company has a working interest.

(2) “Net” wells are the number of wells obtained by aggregating the Company’s working interest in each of its gross wells.

Drilling and other exploratory and development activities ^{(1, 2)}

The following table summarizes the number of wells in the process of drilling or in active completion stages and the number of wells suspended or waiting on completion by geographic area at December 31, 2019.

	Wells in the Process of Drilling or in Active Completion				Wells Suspended or Waiting on Completion (3)
	Exploratory		Development		Exploratory		Development
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
2019
USA	-	-	31	27	-	-	17	14
Canada	-	-	15	10	-	-	20	17
Total	-	-	46	37	-	-	37	31

(1) “Gross” wells are the total number of wells in which the Company has a working interest.

(2) “Net” wells are the number of wells obtained by aggregating the Company’s working interest in each of its gross wells.

(3) Wells suspended or waiting on completion include exploratory and development wells where drilling has occurred, but the wells are awaiting the completion of hydraulic fracturing or other completion activities or the resumption of drilling in the future.

Oil and gas properties, wells, operations, and acreage

The following table summarizes the number of producing wells and wells mechanically capable of production by geographic area at December 31, 2019.

Productive Wells (1, 2)	Oil (3)		Natural Gas (4)		Total
	Gross	Net	Gross	Net	Gross	Net
2019
USA	6,542	4,670	959	467	7,501	5,137
Canada	30	17	2,385	1,897	2,415	1,914
Total	6,572	4,687	3,344	2,364	9,916	7,051

(1) “Gross” wells are the total number of wells in which the Company has a working interest.

(2) “Net” wells are the number of wells obtained by aggregating the Company’s working interest in each of its gross wells.

(3) Includes 49 gross oil wells (25 net oil wells) containing multiple completions.

(4) Includes 1,988 gross natural gas wells (1,590 net natural gas wells) containing multiple completions.

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The following table summarizes the Company’s developed, undeveloped and total landholdings by geographic area as at December 31, 2019.  

Landholdings (1 - 7)		Developed		Undeveloped		Total
(thousands of acres)		Gross	Net	Gross	Net	Gross	Net
United States
	— Federal/State	265	206	72	61	337	267
	— Freehold	971	653	96	46	1,067	699
	— Fee	63	11	278	100	341	111
Total United States		1,299	870	446	207	1,745	1,077
Canada
Onshore	— Crown	794	519	1,534	1,050	2,328	1,569
	— Freehold	43	28	61	47	104	75
	— Fee	1	1	3	3	4	4
Offshore	— Crown	20	20	56	12	76	32
Total Canada		858	568	1,654	1,112	2,512	1,680
Total		2,157	1,438	2,100	1,319	4,257	2,757

(1) Fee lands are those lands in which the Company has a fee simple interest in the mineral rights and has either: (i) not leased out all the mineral zones; (ii) retained a working interest; or (iii) one or more substances or products that have not been leased. The current fee lands acreage summary includes all fee titles owned by the Company that have one or more zones that remain unleased or available for development.

(2) Crown/Federal/State lands are those owned by the federal, provincial or state government or First Nations, in which the Company has purchased a working interest lease.

(3) Freehold lands are owned by individuals (other than a government or the Company), in which the Company holds a working interest lease.

(4) Excludes interests in royalty acreage.

(5) Gross acres are the total area of properties in which the Company has a working interest.

(6) Net acres are the sum of the Company’s fractional working interest in gross acres.

(7) Undeveloped acreage refers to those acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves.

Of the total 2.7 million net acres, approximately 0.6 million net acres is held by production. The table above includes acreage subject to leases that will expire over the next three years: 2020 – approximately 163,000 net acres; 2021 – approximately 161,000 net acres; and 2022 – approximately 122,000 net acres, if the Company does not establish production or take any other action to extend the terms. For acreage that the Company intends to further develop, Ovintiv will perform operational and administrative actions to continue the lease terms that are set to expire. As a result, it is not expected that a significant portion of the Company’s net acreage will expire before such actions occur.  

Title to Properties  

As is customary in the oil and natural gas industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time Ovintiv acquires properties. The Company believes that title to all of the various interests set forth in the above table is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in Ovintiv’s operations. The interests owned by Ovintiv may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in the Company’s operations.

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MARKETING ACTIVITIES

Market Optimization activities are managed by Ovintiv’s Midstream, Marketing & Fundamentals team, which is responsible for the sale of the Company’s proprietary production and enhancing the associated netback price. In marketing production, Ovintiv looks to minimize market related shut-ins, maximize realized prices and manage concentration of credit-risk exposure. Market Optimization activities include third party purchases and sales of product to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. In conjunction with certain divestitures, the Company has also agreed to market and transport certain portions of the acquirer’s production with remaining terms of less than two years.

Ovintiv’s produced oil, NGLs and natural gas, are primarily marketed to refiners, local distributing companies, energy marketing companies and electronic exchanges. Prices received by Ovintiv are based primarily upon prevailing market index prices in the region in which it is sold. Prices are impacted by regional and global supply and demand and by competing fuels in such markets.

Ovintiv’s oil production is sold under short-term and long-term contracts that range up to six years or under dedication agreements, for which prices received by Ovintiv are based primarily upon the prevailing index prices in the relevant region where the product is sold. The Company also has firm transport contracts to deliver oil to other downstream markets. Ovintiv’s NGLs production is sold under short-term and long-term contracts that range up to nine years, or under dedication arrangements at the relevant market price at the time the product is sold. Ovintiv's natural gas production is sold under short-term and long-term delivery contracts with terms ranging up to four years in duration, at the relevant monthly or daily market price at the time the product is sold. The Company also has firm transport contracts to deliver natural gas production to other downstream markets, including Dawn.

Ovintiv also seeks to mitigate the market risk associated with future cash flows by entering into various financial derivative instruments used to manage price risk relating to produced oil, NGLs and natural gas. Details of contracts related to Ovintiv’s various financial risk management positions are found in Note 25 of Ovintiv’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

The Company enters into various contractual agreements to sell oil, NGLs and natural gas, some of which require the delivery of fixed and determinable quantities. As of December 31, 2019, the Company was committed to deliver approximately 9,000 Mbbls of oil and NGLs and approximately 195,300 MMcf of natural gas in the Canadian Operations and approximately 115,800 Mbbls of oil and approximately 395,800 MMcf of natural gas in the USA Operations with varying contract terms up to six years. During 2019, the Company incurred deficiency fees of approximately $24 million in the USA Operations, related to crude oil minimum volume sales contracts related to its Uinta production in Utah, i) one contract is for approximately 15,000 barrels of oil per day through May 2020 and ii) the second contract is for 20,000 barrels of oil per day through August 2025. Given the limited access to transportation and refining facilities resulting from the paraffin content in Uinta oil production, volatility in commodity prices and changes in capital and development plans, deficiency fees ranging from $3.50 to $6.50 per barrel may be incurred during the remaining term of the contracts commitment periods.

Certain transportation and processing commitments result in the following financial commitments:

($ millions)	1 Year	2-3 Years	4-5 Years	> 5 years	Total
Transportation & Processing
USA Operations
Oil & NGLs	6	14	10	12	42
Natural Gas	263	368	265	124	1,020
Total USA Operations	269	382	275	136	1,062
Canadian Operations
Oil & NGLs	75	172	162	299	708
Natural Gas	390	767	510	1,728	3,395
Total Canadian Operations	465	939	672	2,027	4,103
Total USA and Canadian Operations	734	1,321	947	2,163	5,165

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In general, Ovintiv expects to fulfill delivery commitments with production from proved developed reserves, with longer term delivery commitments to be filled from the Company’s proved undeveloped reserves. Where proved reserves are not sufficient to satisfy the Company’s delivery commitments, Ovintiv can and may use spot market purchases to satisfy the respective commitments. In addition, for the Company’s long-term transportation and processing agreements, Ovintiv also expects to fulfill delivery commitments from the future development of resources not yet characterized as proved reserves. Likewise, where delivery commitments are not transferred along with property divestitures, Ovintiv may market and transport certain portions of the acquirer’s production to meet the delivery requirements.

In addition, production from the Company’s reserves are not subject to any priorities or curtailments that may affect quantities delivered to its customers or any priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond the Company’s control that may affect Ovintiv’s ability to meet contractual obligations other than those discussed in Item 1A. Risk Factors of this Annual Report on Form 10-K.  

MAJOR CUSTOMERS

In connection with the marketing and sale of the Company’s production and purchased oil, NGLs and natural gas for the year ended December 31, 2019, the Company had one customer, Vitol Inc., which individually accounted for more than 10 percent of the Company’s consolidated revenues (2018 – one customer, Royal Dutch Shell and 2017 – two customers, Royal Dutch Shell Group and Flint Hills Resources). Ovintiv does not believe that the loss of any single customer would have a material adverse effect on the Company’s financial condition or results of operations. Further information on Ovintiv’s major customers are found in Note 2 of Ovintiv’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

COMPETITION

The Company’s competitors include national, integrated and independent oil and gas companies, as well as oil and gas marketers and other participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. All aspects of the oil and gas industry are highly competitive and Ovintiv actively competes with other companies in the industry, particularly in the following areas:

• Exploration for and development of new sources of oil, NGLs and natural gas reserves;

• Reserves and property acquisitions;

• Transportation and marketing of oil, NGLs, natural gas and diluents;

• Access to services and equipment to carry out exploration, development and operating activities; and

• Attracting and retaining experienced industry personnel.

The oil and gas industry also competes with other industries focused on providing alternative forms of energy to consumers. Competitive forces can lead to cost increases or result in an oversupply of oil, NGLs or natural gas.

EMPLOYEES

At December 31, 2019, the Company employed 2,571 employees as set forth in the following table.

	Employees
U.S.	1,526
Canada	1,045
Total	2,571

The Company also engages a number of contractors and service providers.

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ENVIRONMENTAL AND REGULATORY MATTERS

As Ovintiv is an owner or lessee and operator of oil and gas properties and facilities in the United States and Canada, the Company is subject to numerous federal, state, provincial, local, tribal and foreign country laws and regulations relating to pollution, protection of the environment and the handling of hazardous materials. These laws and regulations generally require Ovintiv to remove or remedy the effect of its activities on the environment at present and former operating sites, including dismantling production facilities, remediating damage caused by the use or release of specified substances, and require suspension or cessation of operations in affected areas. The following are significant areas of government control and regulation affecting Ovintiv’s operations:

Exploration and Development Activities

Our operations are subject to federal, tribal, state, provincial and local laws and regulations. These laws and regulations relate to matters that include: acquisition of seismic data; issuance of permits; location, drilling and casing of wells; well design; hydraulic fracturing; well production; use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations; surface usage and the restoration of properties upon which wells have been drilled and facilities have been constructed; plugging and abandoning of wells; transportation of production; and calculation and disbursement of royalty payments and production and other taxes.

Certain of our U.S. oil and natural gas leases are granted or approved by the federal government and administered by the Bureau of Indian Affairs, the Office of Natural Resources Revenue or the Bureau of Land Management (BLM), all of which are federal agencies. BLM leases contain relatively standardized terms and require compliance with detailed regulations. Many onshore leases contain stipulations limiting activities that may be conducted on the lease. Some stipulations are unique to particular geographic areas and may limit the time during which activities on the lease may be conducted, the manner in which certain activities may be conducted or, in some cases, may ban surface activity. Under certain circumstances, the BLM may require that our operations on federal leases be suspended or terminated. Any such suspension or termination could materially and adversely affect Ovintiv’s interests.

The Company’s operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In addition, conservation laws generally limit the venting or flaring of natural gas and impose certain requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas that can be produced from the Company’s wells and the number of wells or the locations that can be drilled.

Environmental and Occupational Regulations

The Company is subject to many federal, state, provincial, local and tribal laws and regulations concerning occupational health and safety as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to:

• the discharge of pollutants into federal, provincial and state waters; 

• assessing the environmental impact of seismic acquisition, drilling or construction activities; 

• the generation, storage, transportation and disposal of waste materials, including hazardous substances; 

• the emission of certain gases into the atmosphere; 

• the protection of private and public surface and ground water supplies;

• the sourcing and disposal of water; 

• the protection of endangered species and habitat; 

• the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations;

• the development of emergency response and spill contingency plans; and

• employee health and safety.

Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil, and criminal penalties; the imposition of investigatory, remedial, and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the permitting, development or expansion of projects; and the issuance of injunctions restricting or prohibiting some or all of the Company’s activities in a particular area. Although environmental requirements have a substantial impact upon the energy

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industry as a whole, Ovintiv does not believe that these requirements affect the Company differently, to any material degree, as compared to other companies in the oil and natural gas industry. For further information regarding regulations relating to environmental protection, see Item 1A. Risk Factors of this Annual Report on Form 10-K.

Operating and capital costs incurred to comply with the requirements of these laws and regulations are necessary business costs in the oil and gas industry. As a result, Ovintiv has established policies for continuing compliance with environmental laws and regulations. The Corporate Responsibility, Environment, Health and Safety Committee of the Board of Directors reviews and recommends environmental policy to the Board of Directors for approval and oversees compliance with government laws and regulations. Monitoring and reporting programs for environmental, health and safety performance in day-to-day operations, as well as inspections and assessments, are designed to provide assurance that environmental and regulatory standards are met. The Company has established operating procedures and training programs designed to limit the environmental impact of the Company’s field facilities and identify, communicate and comply with changes in existing laws and regulations. Contingency plans are in place for a timely response to an environmental event and remediation/reclamation programs are in place and utilized to restore the environment. In addition, the Board of Directors is advised of significant contraventions thereof, and receives updates on trends, issues or events which could have a significant impact on the Company.

The Company believes that it is in material compliance with existing environmental and occupational health and safety regulations. Further, the Company believes that the cost of maintaining compliance with these existing laws and regulations will not have a material adverse effect on its business, financial condition or results of operations. In addition, Ovintiv maintains insurance coverage for insurable risks against certain environmental and occupational health and safety risks that is consistent with insurance coverage held by other similarly situated industry participants, but the Company is not fully insured against all such risks. However, it is possible that developments, such as new or more stringently applied existing laws and regulations as well as claims for damages to property or persons resulting from the Company’s operations, could result in substantial costs and liabilities to the Company. As a result, Ovintiv is unable to predict with any reasonable degree of certainty future exposures concerning such matters.

EXECUTIVE OFFICERS OF THE REGISTRANT

The Company’s Executive Officers are set out in the table below:

Name	Age (1)	Years Served as Executive Officer (2)	Corporate Office
Douglas J. Suttles	59	7	Chief Executive Officer
Joanne L. Alexander	53	5	Executive Vice-President, General Counsel & Corporate Secretary
Corey D. Code	46	1	Executive Vice-President & Chief Financial Officer
Gregory D. Givens	46	1	Executive Vice-President & Chief Operating Officer
David G. Hill	58	6	Executive Vice-President, Land & Exploration
Michael G. McAllister	61	9	President
Brendan M. McCracken	44	1	Executive Vice-President, Corporate Development & External Relations
Michael Williams	60	6	Executive Vice-President, Corporate Services
Renee E. Zemljak	55	10	Executive Vice-President, Midstream, Marketing & Fundamentals

(1) As of February 21, 2020.

(2) Includes the years served as executive officer of Encana.

Mr. Suttles was appointed Chief Executive Officer of the Company in June 2013. Prior to that, Mr. Suttles was an independent businessman performing consulting services in the oil and gas industry and serving on the boards of one public and one private company from 2011 until 2013. Mr. Suttles was also Chief Operating Officer at BP Exploration & Production from 2009 until 2011.

Ms. Alexander was appointed Executive Vice-President & General Counsel of the Company in January 2015. Prior to that, Ms. Alexander was Senior Vice-President, General Counsel and Corporate Secretary of Precision Drilling Corporation (a public oil and gas services company) from 2008 to 2014.

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Mr. Code was appointed Executive Vice-President & Chief Financial Officer of the Company in May 2019. Mr. Code joined one of the Company’s predecessor companies in 1999 and assumed a variety of leadership roles, including his previous position as Vice-President, Investor Relations and Strategy in 2018, Vice-President, Investor Relations in 2017, and Treasurer and Vice President, Portfolio Management in 2013.

Mr. Givens was appointed Executive Vice-President & Chief Operating Officer of the Company in September 2019. Mr. Givens joined the Company in 2018 serving as Vice-President and General Manager of Texas Operations. Prior to joining the Company, Mr. Givens was Vice-President Eagle Ford of EP Energy (a public oil and gas company) from 2012 to 2017 and worked in various technical and leadership roles from 1996 onwards for El Paso Exploration & Production Company and Sonat Exploration Company which were predecessor companies to EP Energy.

Mr. Hill was appointed Executive Vice-President, Land & Exploration of the Company in November 2013. Mr. Hill joined the Company in 2002 and assumed a variety of leadership roles, including his previous position as Vice-President, Natural Gas Economy Operations. Prior to these positions, Mr. Hill was President of TICORA Geosciences (a privately held geosciences company) from 2000 to 2002.

Mr. McAllister was appointed President of the Company in September 2019. Mr. McAllister joined one of the Company’s predecessor companies in 2000 and assumed a variety of leadership roles, including his previous positions as Executive Vice-President & Chief Operating Officer in 2013 and President & Senior Vice-President, Canadian Division in 2011. Before joining the Company, Mr. McAllister worked in various technical and leadership roles for Texaco Canada and Imperial Oil Resources (a public oil and gas company).

Mr. McCracken was appointed Executive Vice-President, Corporate Development & External Relations of the Company in September 2019. Mr. McCracken joined one of the Company’s predecessor companies in 1997 and assumed a variety of engineering, commercial and leadership roles, including his previous position as Vice-President & General Manager of Canadian Operations in 2017.

Mr. Williams was appointed Executive Vice-President, Corporate Services of the Company in March 2014. Prior to that, Mr. Williams was Executive Vice-President of Corporate Services with Tervita Corporation (a private energy services company) from 2011 to 2014 and Chief Administration Officer for TransAlta Corporation (a public power company) from 2002 to 2011.

Ms. Zemljak was appointed Executive Vice-President, Midstream, Marketing & Fundamentals of the Company in November 2009. Ms. Zemljak joined one of the Company’s predecessor companies in 2000 and assumed a variety of leadership roles, including her previous position as Vice-President of USA Marketing in 2002. Prior to joining the Company, Ms. Zemljak worked in various roles for Montana Power (formerly a public power company).

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ITEM 1A. Risk Factors

If any event arising from the risk factors set forth below occurs, Ovintiv’s business, prospects, financial condition, results of operations, cash flows or the trading prices of securities and in some cases its reputation could be materially adversely affected. When assessing the materiality of the foregoing risk factors, Ovintiv takes into account a number of qualitative and quantitative factors, including, but not limited to, financial, operational, environmental, regulatory, reputational and safety aspects of the identified risk factor.

A substantial or extended decline in oil, NGLs or natural gas prices and price differentials could have a material adverse effect on Ovintiv’s financial condition.

Ovintiv’s financial performance and condition are substantially dependent on the prevailing prices of oil, NGLs and natural gas. Low oil, NGLs and natural gas prices and significant U.S. and Canadian price differentials will have an adverse effect on the Company’s operations and financial condition and the value and amount of its reserves. Prices for oil, NGLs and natural gas fluctuate in response to changes in the supply and demand for the commodities and related products, market uncertainty and a variety of additional factors beyond the Company’s control.

Oil prices are largely determined by international and domestic supply and demand. Factors which affect oil prices include the actions of the OPEC, world economic conditions, government regulation, political stability in the Middle East and elsewhere, the foreign and domestic supply of oil, the price of foreign imports, the availability of alternate fuel sources, transportation and infrastructure constraints and weather conditions. Historically, NGLs prices have generally been correlated with oil prices, and are determined based on supply and demand in international and domestic NGLs markets. Natural gas prices realized by Ovintiv are affected primarily by North American supply and demand, weather conditions, transportation and infrastructure constraints, prices and availability of alternate sources of energy (including refined products, coal, and renewable energy initiatives) and by technological advances affecting energy consumption.

A substantial or extended decline in the price of oil, NGLs and natural gas could result in a delay or cancellation of existing or future drilling, development or construction programs or curtailment or shut-in of production at some properties or could result in unutilized long-term transportation and drilling commitments, all of which could have an adverse effect on the Company’s revenues, profitability and cash flows.

Oil and natural gas producers in North America, and particularly in Canada, currently receive discounted prices for their production relative to certain international prices due to constraints on their ability to transport and sell such production to international markets. A failure to resolve such constraints may result in continued discounted or reduced commodity prices realized by oil and natural gas producers, including Ovintiv.

On at least an annual basis, Ovintiv conducts an assessment of the carrying value of its assets in accordance with the applicable accounting standards. If oil, NGLs and natural gas prices decline further, the carrying value of Ovintiv’s assets could be subject to financial downward revisions, and the Company’s net earnings could be adversely affected.

Ovintiv’s ability to operate and complete projects is dependent on factors outside of its control which may have a material adverse effect on its business, financial condition or results of operations.

The Company’s ability to operate, generate sufficient cash flows, and complete projects depends upon numerous factors beyond the Company’s control. In addition to commodity prices and continued market demand for its products, these non-controllable factors include general business and market conditions, economic recessions and financial market turmoil, the overall state of the capital markets, including investor appetite for investments in the oil and gas industry generally and the Company’s securities in particular, the ability to secure and maintain cost effective financing for its commitments, legislative, environmental and regulatory matters, changes to free trade agreements, reliance on industry partners and service providers, unexpected cost increases, royalties, taxes, volatility in oil, NGLs and natural gas prices, the availability of drilling and other equipment, the ability to access lands, the ability to access water for hydraulic fracturing operations, physical impacts from adverse weather conditions and other natural disasters, the availability and proximity of processing and pipeline capacity, transportation interruptions and constraints, technology failures, accidents, the availability of skilled labour and reservoir quality. In addition, some of these risks may be magnified due to the concentrated nature of funding certain assets within the

30

Company’s portfolio of oil and natural gas properties that are operated within limited geographic areas. As a result, a number of the Company’s assets could experience any of the same risks and conditions at the same time, resulting in a relatively greater impact on the Company’s financial condition and results of operations compared to other companies that may have a more geographically diversified portfolio of properties.

Fluctuations in oil, NGLs and natural gas prices can create fiscal challenges for the oil and gas industry. These conditions have impacted companies in the oil and gas industry and the Company’s spending and operating plans and may continue to do so in the future. There may be unexpected business impacts from market uncertainty, including volatile changes in currency exchange rates, inflation, interest rates, defaults of suppliers and general levels of investing and consuming activity, as well as a potential impact on the Company’s credit ratings, which could affect its liquidity and ability to obtain financing.

The Company undertakes a variety of projects including exploration and development projects and the construction or expansion of facilities and pipelines. Project delays may delay expected revenues and project cost overruns could make projects uneconomic.

All of Ovintiv’s operations are subject to regulation and intervention by governments that can affect or prohibit the drilling, completion and tie-in of wells, production, the construction or expansion of facilities and the operation and abandonment of fields. Contract rights can be cancelled or expropriated. Changes to government regulation could impact the Company’s existing and planned projects.

Ovintiv’s proved reserves are estimates and any material inaccuracies in our reserves estimates or assumptions underlying our reserves estimates could cause quantities and net present value of our reserves to be overstated or understated.

There are numerous uncertainties inherent in estimating quantities of oil, NGLs and natural gas reserves, including many factors beyond the Company’s control. The reserves data in this Annual Report on Form 10-K and other published reserves and resources data represents estimates only. In general, estimates of economically recoverable oil, NGLs and natural gas reserves and the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as commodity prices, future operating and capital costs, availability of future capital, historical production from the properties and the assumed effects of regulation by governmental agencies, including with respect to royalty payments, all of which may vary considerably from actual results. All such estimates are to some degree uncertain, and classifications of reserves and resources are only attempts to define the degree of uncertainty involved.

For those reasons, estimates of the economically recoverable oil, NGLs 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 expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Ovintiv’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves may vary from such estimates, and such variances could be material. Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.

The estimates of reserves included in this Annual Report on Form 10-K are prepared in accordance with SEC regulations and require, subject to limited exceptions, that proved undeveloped reserves may only be classified as proved reserves if the related wells are scheduled to be drilled within five years after the date of booking. Reserves to be developed and produced in the future are based upon certain expectations and assumptions, including the allocation of capital, which may be subject to change. Proved undeveloped reserves may be reclassified to unproved due to delays in the development of reserves, or projects becoming uneconomical due to increases in costs to drill such reserves, or lower future net revenues from further decreases in commodity prices.

Commodity prices used to estimate reserves included in this Annual Report on Form 10-K are calculated as the average oil and natural gas price during the 12 months ending in the current reporting period, determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period. Significant future price changes can have a material effect on the quantity and value of the Company's proved reserves. The

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standardized measure of discounted future net cash flows included in this Annual Report on Form 10-K will not represent the current market value of Ovintiv’s estimated reserves. In addition, these reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

If Ovintiv fails to acquire or find additional reserves, the Company’s reserves and production will decline materially from their current levels.

Ovintiv’s future oil, NGLs and natural gas reserves and production, and therefore its cash flows, are highly dependent upon its success in developing its current reserves base and acquiring, discovering or developing additional reserves. Without reserves additions through exploration, acquisition or development activities, the Company’s reserves and production will decline over time as reserves are depleted.

The business of exploring for, developing or acquiring reserves is capital intensive. In addition, part of Ovintiv’s strategy is focused on a limited number of core assets which results in a concentration of capital and increased potential risks. To the extent that cash flows from the Company’s operations are insufficient and external sources of capital become limited, Ovintiv’s ability to make the necessary capital investments to maintain and expand its oil, NGLs and natural gas reserves and production will be impaired. In addition, there can be no certainty that Ovintiv will be able to find and develop or acquire additional reserves to replace production at acceptable costs.

In addition, Ovintiv’s operations utilize horizontal multi-pad drilling, tighter drill spacing and completions techniques that evolve over time as learnings are captured and applied. The use of this technology may increase the risk of unintentional communication with other wells and the potential for acceleration of current reserves or an increase in recovery factor from the reservoir. If drilling and completions results are less than anticipated, the production volumes may be lower than anticipated.

Ovintiv may not realize anticipated benefits or be subject to unknown risks from acquisitions.

Ovintiv has completed a number of acquisitions to strengthen its position and to create the opportunity to realize certain benefits, including, among other things, potential cost savings. Achieving the benefits of acquisitions depends in part on successfully consolidating functions and integrating operations and procedures in a timely and efficient manner, as well as being able to realize the anticipated growth opportunities and synergies from combining the acquired businesses and operations. Acquisitions could also result in difficulties in being able to hire, train or retain qualified personnel to manage and operate such properties.

Acquiring oil and natural gas properties requires the Company to assess reservoir and infrastructure characteristics, including estimated recoverable reserves, future production, commodity prices, revenues, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain and, as such, the acquired properties may not produce as expected, may not have the anticipated reserves and may be subject to increased costs and liabilities.

Although the acquired properties are reviewed prior to completion of an acquisition, such reviews are not capable of identifying all existing or potentially adverse conditions. This risk may be magnified where the acquired properties are in geographic areas where the Company has not historically operated. Further, the Company may not be able to obtain or realize upon contractual indemnities from the seller for liabilities created prior to an acquisition and it may be required to assume the risk of the physical condition of the properties that may not perform in accordance with its expectations.

The Company’s business is subject to environmental regulation in all jurisdictions in which it operates and any changes in such regulation could negatively affect its results of operations.

All phases of the oil, NGLs and natural gas businesses are subject to environmental regulation pursuant to a variety of U.S. and Canadian federal, and other state, provincial, territorial, tribal, and municipal laws and regulations (collectively, “environmental regulation”).

Environmental regulation imposes, among other things, restrictions, liabilities and obligations in connection with the use, generation, handling, storage, transportation, treatment and disposal of chemicals, hazardous substances and

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waste associated with the finding, production, transmission and storage of the Company’s products including the hydraulic fracturing of wells, the decommissioning of facilities and in connection with spills, releases and emissions of various substances to the environment. It also imposes restrictions, liabilities and obligations in connection with the availability and management of fresh, potable or brackish water sources that are being used, or whose use is contemplated, in connection with oil and natural gas operations.

Environmental regulation also requires that wells, facility sites and other properties associated with Ovintiv’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and changes to certain existing projects, may require the submission and approval of environmental impact assessments or permit applications. Compliance with environmental regulation can require significant expenditures, including expenditures for clean-up costs and damages arising out of contaminated properties and failure to comply with environmental regulation may result in the imposition of fines and penalties.

Although it is not expected that the costs of complying with environmental regulation will have a material adverse effect on Ovintiv’s financial condition or results of operations, no assurance can be made that the costs of complying with environmental regulation in the future will not have such an effect as discussed below.

Climate Change - A number of federal, provincial and state governments have announced intentions to regulate greenhouse gases and certain air pollutants. These governments are currently developing regulatory and policy frameworks to deliver on their announcements. The Canadian federal government along with certain provinces and territories, including Alberta and British Columbia, have announced a pan-Canadian climate change framework that is consistent with the outcome reached at the 21^st Conference of the Parties in Paris and which includes imposing an economy wide cost on carbon emissions in Canada by 2023. The Alberta government introduced the Technology Innovation and Emissions Reduction (TIER) system on January 1, 2020 replacing the previous Carbon Competitiveness Incentive Regulation. The TIER regulation applies to any facility that has emitted 100,000 tonnes or more of carbon dioxide equivalent (CO2e) greenhouse gases (GHGs) in 2016, or any subsequent year or is a facility emitting less than 100,000 tonnes of carbon dioxide equivalent GHG emissions per year but has opted-in to the TIER system. The TIER system provides regulated facilities with several compliance options, including on-site emission reductions, the use of emissions performance credits, the use of Alberta-based emissions offsets, and/or the payment into a compliance fund at C$30/tonne of CO2e. British Columbia has an established carbon levy of C$30 per tonne of CO₂e, increasing by C$5 per tonne of CO₂e per year starting April 1, 2018 until it reaches C$50 per tonne of CO₂e in 2021. Additionally, the Alberta and British Columbia governments remain committed to achieving a 45 percent reduction in methane gas emissions from oil and gas operations by 2025, relative to 2014 levels, to be achieved through equipment replacement and leak detection and repair regulations. The federal Greenhouse Gas Pollution Pricing Act (GGPPA) came into force in Alberta on January 1, 2020. The GGPPA imposes a federal fuel charge to all fossil fuels used in applicable jurisdictions in Canada, including those in the conventional oil and gas sector. The GGPPA includes provisions to exempt facilities that are subject to provincial requirements deemed equivalents to federal requirements; both Alberta’s and British Columbia’s upstream oil and gas greenhouse gas regulatory systems have been determined to be equivalent to the federal system and are therefore exempt from the provisions of the GGPPA. In the United States policy makers at both the federal and state levels have introduced legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases. For example, both the U.S. Environmental Protection Agency and the BLM have previously issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry. Since the change in presidential administrations in 2016 however, the agencies have attempted to revise or rescind their previously issued methane standards. Litigation concerning these methane regulations and subsequent attempts to revise or rescind them is ongoing. Nevertheless, many state and local officials have stated their intent to intensify efforts to regulate greenhouse gas emissions, including methane, from the oil and gas industry. Ovintiv’s cost of complying with emerging climate and cost of carbon regulations is not currently forecast to be material to the Company, however as these and additional federal and regional programs are in their early implementation stage or under development, Ovintiv is unable to predict the total future impact of the potential regulations upon its business. Therefore, it is possible that the Company could face future increases in operating costs in order to comply with legislation governing emissions. Further, certain local governments, stakeholders and other groups have made claims against companies in the oil and gas industry, including the Company, relating to the purported causes and impact of climate change. These claims have, among other things, resulted in litigation, stockholder proposals and local ballot initiatives targeted against certain companies and the oil and gas industry generally. As these claims are in their early stages, the Company is unable to assess the impact of such claims on its business, but the defense of

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such matters may be costly and time consuming and could have a material adverse effect on the Company’s reputation.

Hydraulic Fracturing - The U.S. federal government and certain U.S. state and Canadian federal and provincial governments continue to review certain aspects of the scientific, regulatory and policy framework under which hydraulic fracturing operations are conducted. Most of these governments are primarily engaged in the collection, review and assessment of technical information regarding the hydraulic fracturing process and have not provided specific details with respect to any significant actual, proposed or contemplated changes to the hydraulic fracturing regulatory construct. However, certain environmental and other groups continue to suggest that additional federal, provincial, territorial, state and municipal laws and regulations may be needed to more closely regulate the hydraulic fracturing process and have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources.

Further, certain governments in jurisdictions where the Company does not currently operate have considered or implemented moratoriums on hydraulic fracturing until further studies can be completed and some governments have adopted, and others have considered adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. Any new laws, regulations or permitting requirements regarding hydraulic fracturing could lead to operational delays, increased operating costs or third party or governmental claims, and could increase the Company’s cost of compliance and doing business as well as reduce the amount of oil and natural gas that the Company is ultimately able to produce from its reserves. The Company recognizes that additional hydraulic fracturing ballot initiatives and/or federal, state, provincial and/or local rule-making, including rules specific to U.S. federal lands, limiting or restricting oil and gas development activities are a possibility in the future.

As these federal and regional programs are in their early implementation stage or under development, Ovintiv is unable to predict the total impact of the potential regulations upon its business. Therefore, it is possible that the Company could face increases in operating costs or curtailment of production in order to comply with legislation governing hydraulic fracturing.

Seismic Activity – Some areas of North America are experiencing increasing localized frequency of seismic activity which has been associated with oil and gas operations. Although the occurrence and risk of seismicity in relation to oil and gas operations is generally very low, it has been linked to deep disposal of wastewater and has been correlated with hydraulic fracturing activities which has prompted legislative and regulatory initiatives intended to address these concerns. These initiatives have the potential to require additional monitoring, restrict the injection of produced water in certain disposal wells and/or modify or curtail hydraulic fracturing operations which could lead to operational delays, increase compliance costs or otherwise adversely impact the Company’s operations.

Ovintiv’s risk management activities may prevent the Company from fully benefiting from price increases and expose the Company to other risks.

The nature of the Company’s operations results in exposure to fluctuations in commodity prices and foreign currency exchange rates. The Company monitors its exposure to such fluctuations and, where the Company deems it appropriate, utilizes derivative financial instruments and physical delivery contracts to mitigate the potential impact of declines in oil, NGLs and natural gas prices and fluctuations in foreign currency exchange rates.

Under U.S. GAAP, derivative financial instruments that do not qualify or are not designated as hedges for accounting purposes are fair valued with the resulting changes recognized in current period net earnings. The utilization of derivative financial instruments may therefore introduce significant volatility into the Company’s reported net earnings.

The terms of the Company’s various risk management agreements and the amount of estimated production hedged may limit the benefit to the Company of commodity price increases. The Company may also suffer financial loss if the Company is unable to produce oil, NGLs and natural gas, or if counterparties to the Company’s risk management agreements fail to fulfill their obligations under the agreements, particularly during periods of declining commodity prices.

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Downgrades in Ovintiv’s credit ratings could increase its cost of capital and limit its access to capital, suppliers or counterparties.

Rating agencies regularly evaluate the Company, basing their ratings of long-term and short-term debt on a number of factors. This includes the Company’s financial strength as well as factors not entirely within its control, including conditions affecting the oil and gas industry generally and the wider state of the economy. One of the Company’s credit ratings is below an investment-grade credit rating. There can be no assurance that the Company’s other credit ratings will not also be downgraded, including below an investment-grade credit rating.

The Company’s borrowing costs and ability to raise funds are directly impacted by its credit ratings. A downgrade may increase the cost of borrowing under the Company’s existing credit facilities, limit access to commercial paper programs maintained by the Company and its subsidiaries, limit access to private and public markets to raise short-term and long-term debt, and negatively impact the Company’s cost of capital.

Credit ratings may also be important to suppliers or counterparties when they seek to engage in certain transactions. Downgrades in one or more of the Company’s credit ratings below investment-grade may require the Company to post collateral, letters of credit, cash or other forms of security as financial assurance of the Company’s performance under certain contractual arrangements with marketing counterparties, facility construction contracts, and pipeline and midstream service providers. Additionally, certain of these arrangements contain financial assurance language that may, under certain circumstances, permit the Company’s counterparties to request additional collateral.

In connection with certain over-the-counter derivatives contracts and other trading agreements, the Company could be required to provide additional collateral or to terminate transactions with certain counterparties based on its credit rating. The occurrence of any of the foregoing could adversely affect the Company’s ability to execute portions of its business strategy, including hedging, and could have a material adverse effect on its liquidity and capital position.  

The Company’s level of indebtedness may limit its financial flexibility.

As at December 31, 2019, the Company had long-term unsecured notes of $6,161 million, $698 million in outstanding commercial paper and no outstanding balance under its revolving credit facilities. The terms of the Company’s various financing arrangements, including but not limited to the indentures relating to its outstanding senior notes and its revolving credit facilities, impose restrictions on its ability and, in some cases, the ability of the Company’s subsidiaries, to take a number of actions that it or they may otherwise desire to take, including: (i) incurring additional debt, including guarantees of indebtedness; (ii) creating liens on the Company’s or its subsidiaries’ assets; and (iii) selling certain of the Company’s or its subsidiaries’ assets.

The Company’s level of indebtedness could affect its operations by:

• requiring it to dedicate a portion of cash flows from operations to service its indebtedness, thereby reducing the availability of cash flow for other purposes;

• reducing its competitiveness compared to similar companies that have less debt;

• limiting its ability to obtain additional future financing for working capital, capital investments and acquisitions;

• limiting its flexibility in planning for, or reacting to, changes in its business and industry; and

• increasing its vulnerability to general adverse economic and industry conditions.

The Company’s ability to meet its debt obligations and service those debt obligations depends on future performance. General economic conditions, oil, NGLs or natural gas prices, and financial, business and other factors affect the Company’s operations and future performance. Many of these factors are beyond the Company’s control. If the Company is unable to satisfy its obligations with cash on hand, the Company could attempt to refinance debt or repay debt with proceeds from a public offering of securities or selling certain assets. No assurance can be given that the Company will be able to generate sufficient cash flow to pay the interest obligations on its debt, or that funds from future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance its debt, or on terms that will be favourable to the Company. Further, future acquisitions may decrease the Company’s liquidity by using a significant portion of its available cash or borrowing capacity to finance such acquisitions, and such acquisitions could result in a significant increase in the Company’s interest expense or financial leverage if it incurs additional debt to finance such acquisitions.

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Ovintiv’s operations are subject to the risk of business interruption, property and casualty losses. The Company’s insurance may not fully protect us against these risks and liabilities.

The Company’s business is subject to the operating risks normally associated with the exploration for, development of and production of oil, NGLs and natural gas and the operation of midstream facilities. These risks include blowouts, explosions, fire, gaseous leaks, migration of harmful substances and liquid spills, loss of well control, surface spills and uncontrolled ground releases of fluids during hydraulic fracturing or other similar activities, and acts of vandalism and terrorism, any of which could cause personal injury, result in damage to, or destruction of, oil and natural gas wells or formations or production facilities and other property, equipment and the environment, as well as interrupt operations.

In addition, all of Ovintiv’s operations will be subject to all of the risks normally incident to the transportation, processing, storing and marketing of oil, NGLs and natural gas and other related products, drilling and completion of oil and natural gas wells, and the operation and development of oil and natural gas properties, including encountering unexpected formations or pressures, premature declines of reservoir pressure or productivity, blowouts, equipment failures and other accidents, sour gas releases, uncontrollable flows of oil, natural gas or well fluids, adverse weather conditions and other natural disasters, spills and migration of hazardous chemicals, pollution and other environmental risks.

The Company maintains insurance against some, but not all, of these risks and losses. The occurrence of a significant event against which Ovintiv is not fully insured could have a material adverse effect on the Company’s financial position.

Ovintiv is dependent on partners to fund development projects conducted through joint ventures and partnerships, which if such funding is unavailable may adversely affect the Company’s operations and financial condition.

Some of Ovintiv’s projects are conducted through joint ventures, partnerships or other arrangements, where Ovintiv is dependent on its partners to fund their contractual share of the capital and operating expenditures related to such projects. If these partners do not approve or are unable to fund their contractual share of certain capital or operating expenditures, suspend or terminate such arrangements or otherwise fulfill their obligations, this may result in project delays or additional future costs to Ovintiv, all of which may affect the viability of such projects.

These partners may also have strategic plans, objectives and interests that do not coincide with and may conflict with those of Ovintiv. While certain operational decisions may be made solely at the discretion of Ovintiv in its capacity as operator of certain projects, major capital and strategic decisions affecting such projects may require agreement among the partners. While Ovintiv and its partners generally seek consensus with respect to major decisions concerning the direction and operation of the project assets, no assurance can be provided that the future demands or expectations of any party, including Ovintiv, relating to such assets will be met satisfactorily or in a timely manner. Failure to satisfactorily meet such demands or expectations may affect Ovintiv’s or its partners’ participation in the operation of such assets or the timing for undertaking various activities, which could negatively affect Ovintiv’s operations and financial results. Further, Ovintiv is involved from time to time in disputes with its partners and, as such, it may be unable to dispose of assets or interests in certain arrangements if such disputes cannot be resolved in a satisfactory or timely manner.

The Company may be unable to dispose of certain assets and may be required to retain liabilities for certain matters.

The Company may identify certain assets for disposition, which could increase capital available for other activities or reduce the Company’s existing indebtedness. Various factors could materially affect the Company’s ability to dispose of those assets or complete announced transactions, including current commodity prices, the availability of purchasers willing to purchase certain assets at prices and on terms acceptable to the Company, approval by the Board of Directors, associated asset retirement obligations, due diligence, favourable market conditions, the assignability of joint venture, partnership or other arrangements and stock exchange, regulatory and third party approvals. These factors may also reduce the proceeds or value to Ovintiv.

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The Company may also retain certain liabilities for certain matters in a sale transaction. The magnitude of any such retained liabilities or indemnification obligations may be difficult to quantify at the time of the transaction and could ultimately be material. Further, certain third parties may be unwilling to release the Company from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after the sale of certain assets, the Company may remain secondarily liable for the obligations guaranteed or supported to the extent that the purchaser of the assets fails to perform its obligations.

The market price of shares of common stock of Ovintiv may be subject to volatility.

The market price of the shares of common stock of Ovintiv may be volatile. The value of an investment in the shares of common stock of Ovintiv may decrease or increase abruptly, and such volatility may bear little or no relation to Ovintiv’s performance. The price of the shares of common stock of Ovintiv may fall in response to market appraisal of the Company’s strategy or if Company’s results of operations and/or prospects are below the expectations of market analysts or stockholders. In addition, stock markets have, from time to time, experienced significant price and volume fluctuations that have affected the market price of securities, and may, in the future, experience similar fluctuations which may be unrelated to Ovintiv’s operating performance and prospects but nevertheless affect the price of the shares of common stock of Ovintiv. Broad market fluctuations, as well as economic conditions generally may adversely affect the market price of the shares of common stock of Ovintiv.

The decision to pay dividends and the amount of such dividends is subject to the discretion of the Board of Directors based on numerous factors and may vary from time to time.

Although the Company currently intends to pay quarterly cash dividends to its stockholders, these cash dividends may vary from time to time and could be increased, reduced or suspended. The amount of cash available to the Company to pay dividends, if any, can vary significantly from period to period for a number of reasons, including, among other things: Ovintiv’s operational and financial performance; fluctuations in the costs to produce oil, NGLs and natural gas; the amount of cash required or retained for debt service or repayment; amounts required to fund capital expenditures and working capital requirements; access to equity markets; foreign currency exchange rates and interest rates; and the risk factors set forth in this Annual Report on Form 10-K.

The decision whether or not to pay dividends and the amount of any such dividends are subject to the discretion of the Board of Directors, which regularly evaluates the Company’s proposed dividend payments and the requirements under the DGCL. In addition, the level of dividends per share of common stock will be affected by the number of outstanding shares of common stock and other securities that may be entitled to receive cash dividends or other payments. Dividends may be increased, reduced or suspended depending on the Company’s operational success and the performance of its assets. The market value of the shares of common stock may deteriorate if the Company is unable to meet dividend expectations in the future, and that deterioration may be material.

Changes to, or the interpretation of, regulations related to income tax laws, royalty regimes, environmental laws or other regulations could adversely affect the Company’s business, financial position, cash flows or results of operations.

Income tax laws, royalty regimes, environmental laws, free trade agreements or other laws and regulations may be interpreted in a manner that adversely affects the Company or its securityholders. Changes to existing laws and regulations or the adoption of new laws and regulations could also increase the Company’s cost of compliance and adversely affect the Company’s business, financial position, cash flows or results of operations.

Tax authorities having jurisdiction over the Company or its stockholders could change their administrative practices or may disagree with the manner in which the Company calculates its tax liabilities or structures its arrangements, to the detriment of the Company or its securityholders. There are tax matters under review for which the timing of resolution is uncertain. While Ovintiv believes that the provision for income taxes is adequate, the completion of the Reorganization may affect the timing of audit and reassessment of taxes by certain tax authorities, which reassessments may lack technical merit and may possibly be material.

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Ovintiv does not operate all of its properties and assets and has limited control over factors that could adversely affect the Company’s financial performance.

Other companies operate a portion of the assets in which Ovintiv has ownership interests. Ovintiv may have limited ability to exercise influence over operation of these assets or their associated costs. Ovintiv’s dependence on the operator and other working interest owners for these properties and assets, and its limited ability to influence operations and associated costs, could materially adversely affect the Company’s financial performance. The success and timing of Ovintiv’s activities on assets operated by others therefore will depend upon factors that are outside of the Company’s control, including timing and amount of capital expenditures, timing and amount of operating and maintenance expenditures, the operator’s expertise and financial resources, approval of other participants, selection of technology and risk management practices.

Fluctuations in exchange rates could affect expenses or result in realized and unrealized losses.

Worldwide prices for oil and natural gas are set in U.S. dollars. Following the U.S. Domestication, the functional currency of Ovintiv will be U.S. dollars therefore the financial results will be consolidated in U.S. dollars. However, the Canadian dollar will be the functional currency for Ovintiv’s Canadian subsidiaries. As Ovintiv has operations in Canada, a portion of the Company’s revenues and expenses will be denominated in Canadian dollars. Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar could impact the Company’s revenue and expenses and have an adverse effect on the Company’s financial performance and condition.

In addition, Ovintiv’s Canadian subsidiaries may hold U.S. dollar denominated assets and liabilities. Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar could result in realized and unrealized losses.

The inability of our customers and other contractual counterparties to satisfy their obligations to Ovintiv may have a material adverse effect on the Company.

Ovintiv is exposed to the risks associated with counterparty performance including credit risk and performance risk. Ovintiv may experience material financial losses in the event of customer payment default for commodity sales and financial derivative transactions. Ovintiv’s liquidity may also be impacted if any lender under the Company’s existing credit facilities is unable to fund its commitment. Performance risk can impact Ovintiv’s operations by the non-delivery of contracted products or services by counterparties, which could impact project timelines or operational efficiency.

The Company is subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in the Company’s favour.

Ovintiv may be subject to claims, litigation, administrative proceedings and regulatory actions. The outcome of these matters may be difficult to assess or quantify, and there cannot be any assurance that such matters will be resolved in the Company’s favour. If Ovintiv is unable to resolve such matters favourably, the Company or its directors, officers or employees may become involved in legal proceedings that could result in an onerous or unfavourable decision, including fines, sanctions, monetary damages or the inability to engage in certain operations or transactions. The defence of such matters may also be costly, time consuming and could divert the attention of management and key personnel from the Company’s operations. Ovintiv may also be subject to adverse publicity associated with such matters, regardless of whether such allegations are valid or whether the Company is ultimately found liable. As a result, such matters could have a material adverse effect on the Company’s reputation, financial position, results of operations or liquidity. See Item 3 of this Annual Report on Form 10-K.

Ovintiv relies on certain key personnel, and if the Company is unable to attract and retain key personnel necessary for its business, Ovintiv’s operations may be negatively impacted.

The Company relies on certain key personnel for the development of its business. The experience, knowledge and contributions of the Company’s existing management team and directors to the immediate and near-term operations and direction of the Company are likely to continue to be of central importance for the foreseeable future. As such, the unexpected loss of services from or retirement of such key personnel could have a material adverse effect on the Company. In addition, the competition for qualified personnel in the oil and gas industry means there can be no

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assurance that the Company will be able to attract and retain such personnel with the required specialized skills necessary for its business.

The Company has certain indemnification obligations to certain counterparties that could have a material adverse effect on Ovintiv.

The Company has agreed to indemnify or be indemnified by numerous counterparties for certain liabilities and obligations associated with businesses or assets retained or transferred by the Company. Specifically, in relation to a corporate reorganization to split into two independent publicly traded energy companies, Encana and Cenovus Energy Inc. (“Cenovus”) each agreed to indemnify the other for certain liabilities and obligations associated with, among other things, in the case of Encana’s indemnity, the business and assets retained by Encana, and in the case of Cenovus’s indemnity, the business and assets transferred to Cenovus. The Company also has indemnification obligations under certain acquisition and divestiture activities it has undertaken.

Ovintiv cannot determine whether it will be required to indemnify certain counterparties for any substantial obligations. Ovintiv also cannot be assured that, if a counterparty is required to indemnify Ovintiv and its affiliates for any substantial obligations, such counterparties will be able to satisfy such obligations. Any indemnification claims against Ovintiv pursuant to the provisions of the transaction agreements could have a material adverse effect on Ovintiv.

The Company could be adversely affected by security threats, including cyber-security threats and related disruptions.

The Company has become increasingly dependent upon information technology systems to conduct daily operations. The Company depends on various information technology systems to estimate reserve quantities, process and record financial and operating data, analyze seismic and drilling information, and communicate with employees and third-party partners. This growing dependence on technology is accompanied by greater sensitivity to cyber-attacks and information systems breaches. Unauthorized access to information systems by employees or third parties could lead to corruption or exposure of confidential, fiduciary or proprietary information, interruption to communications or operations or disruption to the Company’s business activities or its competitive position. In addition, the Company’s vendors, suppliers and other business partners may separately suffer disruptions as a result of such security breaches. The potential for such occurrences subjects the Company’s operations to increased risks that could have a material adverse effect on the Company’s business, financial condition and results of operations. To protect its information assets and systems, the Company applies technical and process controls, which are reviewed by the appropriate senior management with oversight from the Company’s Board of Directors. These controls are in line with industry standards and are reviewed annually with peer companies in order to guide Ovintiv’s focus on information security initiatives. However, these controls may not adequately prevent cyber-security breaches.

There is no assurance that the Company will not suffer losses associated with cyber-security breaches in the future. As cyber-attacks continue to evolve, the Company may be required to expend additional resources to investigate, mitigate and remediate any potential vulnerabilities. The Company may also be subject to regulatory investigations or litigation relating to cyber-security issues.

The Company’s operations may be affected by indigenous treaty, title and other rights.

Indigenous peoples have claimed indigenous treaty, title and other rights in respect of areas within the United States and Canada. The Company is not aware of any material claims that have been made in respect of its properties or assets; however, the legal basis of an indigenous land claim is a matter of considerable legal complexity and the impact of the assertion of such a claim, or the possible effect of a settlement of such claim, upon the Company cannot be predicted with any degree of certainty. In addition, no assurance can be given that any recognition of indigenous rights or claims whether by way of a negotiated settlement or by judicial pronouncement (or through the grant of an injunction prohibiting exploration or development activities pending resolution of any such claim) would not delay or even prevent the Company’s exploration and development activities. If a material claim were to arise and be successful, such claim could have a material and adverse effect on the Company’s business, financial condition and results of operations. In addition, the process of addressing such claim, regardless of the outcome,

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could be expensive and time consuming and could result in delays which could have a material and adverse effect on the Company’s business, financial condition and results of operations.

In addition to the foregoing, the Company may become subject to various laws and regulations that apply to operators and other parties operating within the boundaries of Native American reservations in the United States. These laws and regulations may result in the imposition of certain fees, taxes, environmental standards, lease conditions or requirements to employ specified contractors or service providers. Any one of these requirements, or any delay in obtaining the approvals or permits necessary to operate within the boundaries of Native American tribal lands, could adversely impact the Company’s operations and ability to explore and develop new properties.

Further, in Canada, the province of British Columbia enacted legislation to implement the United Nations Declaration on the Rights of Indigenous Peoples (“UNDRIP”) in the fall of 2019 and the Canadian federal government has announced its intention to do the same. In British Columbia the legislation provides a framework for recognizing the constitutional and human rights of indigenous peoples and aligning British Columbia’s laws with the internationally recognized standards of UNDRIP. As the legislation is at an early stage of implementation, Ovintiv is unable to predict the total impact of the potential regulations upon its business. Although the Company does not anticipate any near-term impacts to its business as a result of such legislation, the enactment of provincial and federal legislation to implement the standards of UNDRIP has the potential to increase permitting times and change the processes and costs associated with project development and operations.

Ovintiv may fail to realize certain benefits of the Reorganization, including as a result of the shares of common stock of Ovintiv not being included in U.S. stock market indices or sold and/or not permitted to be held by certain Canadian-focused funds.

The success of the Reorganization will depend, in part, on the ability of Ovintiv to realize the anticipated benefits associated with the Reorganization and associated reorganization of Ovintiv’s corporate structure, and Ovintiv may not be able to realize such benefits on a timely basis or at all.

If shares of common stock of Ovintiv are not included in U.S. stock market indices, or are sold by certain retail and institutional shareholders or investment funds (including Canadian-focused funds) that cannot own shares of a U.S. company under their internal guidelines, this could result in increased selling pressure and/or decreased demand for our shares that would increase stock price volatility or cause the market price of the shares of common stock of Ovintiv to fall. As a result of the foregoing, certain of these investors may be required under their internal guidelines to sell their shares at times when, or at prices for which, they would otherwise not have sold. If an investor sells its shares at a time when the market price is lower than their cost basis in the shares, the investor will suffer a loss that could be significant to such investor. Further, given that inclusion and continued inclusion in a stock market index or fund is subject to numerous factors which can be applied subjectively by the entity managing the index or fund, there are no assurances that Ovintiv will be included in any U.S. stock market indices or funds in a timely manner, or at all.

The Reorganization may result in material Canadian federal income tax (including material Canadian “emigration tax”) and/or material U.S. federal income tax for the Company.

For Canadian federal income tax purposes, based on and subject to certain assumptions and estimates of fair market value, the Company does not expect the Reorganization to give rise to material corporate-level Canadian federal income tax. However, the U.S. Domestication, which occurred as part of the Reorganization, caused Ovintiv to cease to be resident in Canada for the purpose of the Income Tax Act (Canada) and as a result Ovintiv was deemed to have a taxation year end immediately prior to the U.S. Domestication. Ovintiv was also deemed to have disposed of each of its properties immediately before its deemed taxation year end for proceeds of disposition equal to the fair market value of such properties and to have reacquired such properties immediately thereafter at a cost amount equal to fair market value. Ovintiv will be required to include in its taxable income under the Income Tax Act (Canada) any income and net taxable capital gains realized as a result of the deemed disposition of its properties. Ovintiv also will be subject to an additional “emigration tax” on the amount by which the fair market value, immediately before its deemed taxation year end resulting from the Reorganization, of all of the properties owned by Ovintiv exceeds the total of certain of its liabilities and the paid-up capital of all the issued and outstanding shares of Ovintiv immediately before the deemed taxation year end.

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While the Company expects that the deemed disposition of Ovintiv’s properties that occurred as part of the Reorganization and the computation relevant for emigration tax will not result in any material Canadian federal income tax (including material “emigration tax”) to Ovintiv at the estimates of fair market value, there is no certainty that the fair market value of the properties of Ovintiv as estimated will be accepted by Canadian federal tax authorities, which may result in additional taxes payable as a result of the Reorganization.

For U.S. federal income tax purposes, based on and subject to certain assumptions and estimates of fair market value, the Company does not expect the Reorganization to give rise to material corporate-level U.S. federal income tax. However, Ovintiv could be subject to U.S. federal income taxation in connection with the U.S. Domestication to the extent, if any, that, at the time of such U.S. Domestication (a) the aggregate fair market value of all of the outstanding shares of common stock of Ovintiv exceeds (b) the U.S. tax basis in Ovintiv’s assets (computed under U.S. federal income tax principles) less liabilities assumed by Ovintiv. There can be no assurance that the fair market value of the shares of common stock of Ovintiv as estimated and the determination of Ovintiv’s U.S. tax basis in its assets will be accepted by the IRS or that the IRS will not otherwise challenge the Company’s position that it is not subject to U.S. federal income tax in connection with the Reorganization.

Ovintiv’s effective tax rate may change in the future, including as a result of the U.S. Domestication.

As a result of the U.S. Domestication, Ovintiv may be subject to current U.S. federal income taxes on the earnings of Ovintiv’s non-U.S. subsidiaries in a manner that may adversely impact the Company’s effective tax rate. In addition, recently enacted U.S. tax reform legislation has significantly changed the U.S. federal income taxation of U.S. corporations, including by reducing the U.S. corporate income tax rate, limiting interest deductions, permitting immediate expensing of certain capital expenditures, requiring current taxation of certain “global intangible low-taxed income” of non-U.S. subsidiaries (regardless of whether any distributions are made by such subsidiaries), adopting elements of a territorial tax system, revising the rules governing net operating losses, and introducing new anti-base erosion provisions. The legislation is unclear in many respects and could be subject to potential amendments and technical corrections, as well as interpretations and implementing regulations by the U.S. Treasury Department and the Internal Revenue Service, any of which could lessen or increase certain adverse impacts of the legislation.

In light of these factors, there can be no assurance that Ovintiv’s effective income tax rate will not change in future periods, including as a result of the U.S. Domestication, which could have a material adverse effect on Ovintiv’s income tax position.

The enforcement of rights against Ovintiv in Canada may be limited.

Ovintiv is incorporated in Delaware and many of the Company’s directors, officers and experts reside outside of Canada. Accordingly, it may not be possible for Ovintiv stockholders to effect service of process within Canada upon Ovintiv or many of its directors, officers or experts, or to enforce judgments obtained in Canadian courts against Ovintiv or many of its directors, officers or experts.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

Ovintiv is involved in various legal claims and actions arising in the normal course of the Company’s operations. Although the outcome of these claims cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on Ovintiv’s financial position, cash flows or results of operations. If an unfavourable outcome were to occur, there exists the possibility of a material impact on the Company’s consolidated net earnings or loss for the period in which the effect becomes reasonably estimable. See Item 1A. Risk Factors, “The Company is subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in the Company’s favour.” of this Annual Report on Form 10-K.

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For additional information, see Note 27 of Ovintiv’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

MARKET INFORMATION, STOCKHOLDERS, AND DIVIDEND INFORMATION

Market Information

Ovintiv’s shares of common stock are listed and posted for trading on the NYSE and TSX under the symbol “OVV”.

Holders

The Company is authorized to issue up to 775,000,000 shares of common stock consisting of: (i) 750,000,000 shares of common stock, par value US$0.01 per share, and (ii) 25,000,000 shares of preferred stock, par value US$0.01 per share. As at February 19, 2020, there were 259,821,141 shares of common stock outstanding held by 19,983 stockholders of record, and no shares of preferred stock outstanding.

Dividend Information

In 2019, on a pre-Share Consolidation basis, the Company paid a quarterly dividend of US$0.01875 per share (2018: US$0.015 per share) and US$0.075 per share annually (2018: US$0.06 per share annually). On a post-Share Consolidation basis, the Company’s quarterly dividend payment was US$0.09375 per share (2018: US$0.075 per share) and US$0.375 per share annually (2018: US$0.30 per share annually) in 2019. On February 19, 2020 the Board of Directors declared a dividend of US$0.09375 per share of Ovintiv common stock payable on March 31, 2020.

Dividend payments are not guaranteed and the amount of cash to be distributed as dividends in the future may change. Any decision to pay dividends will be determined at the discretion of the Board of Directors 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 dividend requirements in the DGCL; and (iv) any agreements relating to the Company’s indebtedness that restrict the declaration and payment of dividends. See Item 1A. Risk Factors of this Annual Report on Form 10-K, “The decision to pay dividends and the amount of such dividends is subject to the discretion of the Board of Directors based on numerous factors and may vary from time to time”. The Company currently pays dividends quarterly to stockholders of record as of the 15th day (or the previous business day) of the last month of each calendar quarter, with the last business day of the same month being the corresponding payment date.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

Information concerning securities authorized for issuance under equity compensation plans is set forth in the Proxy Statement relating to the Company’s 2020 annual meeting of stockholders, which is incorporated herein by reference.

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS

There were no purchases of equity securities by the issuer during the three months ended December 31, 2019.

RECENT SALES OF UNREGISTERED EQUITY SECURITIES

None.

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PERFORMANCE GRAPH

The following performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933, as amended (the “Securities Act”) or the Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.

The following graph compares the cumulative five-year total return to stockholders of the Company’s common shares relative to the cumulative total returns of the S&P Composite Index and a peer group of 24 comparable companies operating in the same industry as the Company on December 31 for each of the years indicated. The companies included in the peer group are: Antero Resources Corporation; Apache Corporation; Baytex Energy Corporation; Cabot Oil & Gas Corporation; Canadian Natural Resources Ltd.; Chesapeake Energy Corporation; Concho Resources Inc.; Continental Resources Inc.; Crescent Point Energy Corporation; Devon Energy Corporation; Enerplus Corporation; EOG Resources Inc.; EP Energy Corporation; Hess Corporation; Marathon Oil Corporation; Murphy Oil Corporation; Noble Energy Inc.; Obsidian Energy Ltd.; Pengrowth Energy Corporation; Pioneer Natural Resources Company; Range Resources Corporation; Southwestern Energy Company; Vermilion Energy Inc.; and Whiting Petroleum Corporation. The graph was prepared assuming $100 was invested on December 31, 2014 in the Company’s common shares, the S&P 500 and the peer groups, and dividends have been reinvested subsequent to the initial investment. The graph is included for historical comparative purposes only and should not be considered indicative of future share performance.

Comparison of 5-Year Cumulative Total Return Among

the Company, the S&P 500 and a Peer Group

Fiscal Year Ended December 31	2014	2015	2016	2017	2018	2019
The Company	$   100.00	$   38.00	$   88.00	$   101.00	$   44.00	$   36.00
Peer Group	100.00	53.00	80.00	70.00	48.00	47.00
S&P 500	100.00	101.00	113.00	138.00	132.00	174.00

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Item 6: Selected Financial Data

The following table sets forth selected financial data of the Company and its consolidated subsidiaries over the five-year period ended December 31, 2019, which has been derived from the Company’s audited Consolidated Financial Statements. The financial information below should be read in conjunction with Item 7 and Item 8 of this Annual Report on Form 10-K.

Year Ended December 31 (US$ millions, unless otherwise specified)	2019			2018			2017			2016			2015
Statement of Earnings Data (1)
Revenues		6,726			5,939			4,443			2,918			4,422
Impairments		-			-			-			1,396			6,473
Operating Income (Loss)		598			1,694			1,068			(1,881	)		(6,298	)
Gain (Loss) on Divestitures, Net		3			5			404			390			14
Net Earnings (Loss) Attributable to Common Shareholders		234			1,069			827			(944	)		(5,165	)
Per Share Data (2)
Net Earnings (Loss) per Common Share Basic & Diluted		0.90			5.57			4.25			(5.35	)		(31.42	)
Dividends Declared per Common Share		0.375			0.30			0.30			0.30			1.40
Weighted Average Common Shares Outstanding Basic & Diluted (millions)		261.2			192.0			194.6			176.5			164.4
Balance Sheet Data (1)
Cash and Cash Equivalents		190			1,058			719			834			271
Total Assets		21,487			15,344			15,267			14,653			15,614
Finance Lease Obligations and The Bow Office Building (3)		121			1,435			1,639			1,570			1,591
Long-Term Debt, Including Current Portion		6,974			4,198			4,197			4,198			5,333
Total Shareholders’ Equity		9,930			7,447			6,728			6,126			6,167
Statement of Cash Flow Data (1)
Cash From (Used In) Operating Activities		2,921			2,300			1,050			625			1,681
Non-GAAP Cash Flow (4)		2,931			2,115			1,343			838			1,430
Capital Expenditures		2,626			1,975			1,796			1,132			2,232
Net Acquisitions & (Divestitures)		(132	)		(476	)		(682	)		(1,052	)		(1,838	)
Foreign Exchange Rates (US$ per C$1)
Average		0.754		0.772			0.771			0.755			0.782
Period End		0.770		0.733			0.797			0.745			0.723
Production Volumes
Oil (Mbbls/d)		164.4			89.9			76.3			73.7			87.0
Total NGLs (Mbbls/d) (5)		137.5			78.2			52.8			48.4			46.4
Total Oil & NGLs (Mbbls/d)		301.9			168.1			129.1			122.1			133.4
Natural Gas (MMcf/d)		1,577			1,158			1,104			1,383			1,635
Total Production (MBOE/d)		564.9			361.2			313.2			352.7			405.9
Commodity Prices, Including Realized Gains (Losses) on Risk Management
Oil ($/bbl)		57.40			56.84			49.76			48.68			49.68
Total NGLs ($/bbl) (5)		28.63			37.21			34.72			23.90			21.66
Oil & NGLs ($/bbl)		44.29			47.71			43.61			38.85			39.93
Natural Gas ($/Mcf)		2.28			2.76			2.42			2.10			3.89
Total ($/BOE)		30.05			31.06			26.51			21.69			28.81

(1) Items that affect the comparability of the above five-year selected financial data include the January 1, 2019 adoption of ASC Topic 842, Leases, and the Newfield acquisition as described in Notes 1 and 8, respectively, of the audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

(2) Per share data reflects the Share Consolidation as described in Note 1 of the audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

(3) Upon adoption of ASC Topic 842, Leases, on January 1, 2019, The Bow office building was determined to be an operating lease as described in Note 1 of the audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

(4) Non-GAAP Cash Flow is a non-GAAP measure and has no standardized meaning under U.S. GAAP. It is used by Management and investors to help assist in measuring Ovintiv’s ability to finance capital programs and meet financial obligations. It is not intended to replace cash from (used in) operating activities as a measure. Non-GAAP Cash Flow is defined and reconciled in the Non-GAAP Measures section under Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

(5) Includes plant condensate.

Supplemental Quarterly Financial Information (Unaudited)

See Note 30 of the Company’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10‑K.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The MD&A is intended to provide a narrative description of the Company’s business from management’s perspective. This MD&A should be read in conjunction with the audited Consolidated Financial Statements and accompanying notes for the period ended December 31, 2019 (“Consolidated Financial Statements”), which are included in Item 8 of this Annual Report on Form 10-K.

On January 24, 2020, Encana Corporation (“Encana”) completed a corporate reorganization, which included a Share Consolidation, as described in Items 1 and 2 of this Annual Report on Form 10-K, Note 1 of the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K and the Subsequent Event section of this MD&A. Subsequent to the corporate reorganization, Ovintiv Inc. and its subsidiaries (collectively, “Ovintiv”) continue to carry on the business which was previously conducted by Encana and its subsidiaries. References to the “Company” are to Encana Corporation and its subsidiaries prior to the completion of the Reorganization and to Ovintiv Inc. and its subsidiaries following the completion of the Reorganization.

Common industry terms and abbreviations are used throughout this MD&A and are defined in the Definitions, Conversions and Conventions sections of this Annual Report on Form 10-K. This MD&A includes the following sections:

• Executive Overview

• Results of Operations

• Liquidity and Capital Resources

• Accounting Policies and Estimates

• Non-GAAP Measures

Executive Overview

Strategy

By executing on its strategy as outlined in Items 1 and 2 of this Annual Report on Form 10-K, Ovintiv focuses on enhancing long-term shareholder value and generating cash flow growth from high margin, scalable, top tier assets located in some of the best plays in North America, referred to as the “Core Assets”. As at December 31, 2019, the Core Assets comprised Permian and Anadarko in the U.S., and Montney in Canada. These top tier assets form a multi-basin portfolio of oil, NGLs and natural gas producing plays enabling flexible and efficient investment of capital that support sustainable cash flow generation. The Company’s other upstream assets, including Eagle Ford, Duvernay, Bakken (previously referred to as Williston) and Uinta, continue to deliver operating cash flows for the Company.

In executing its strategy, Ovintiv focuses on its core values of One, Agile and Driven, which guide the organization to be flexible, responsive, innovative and determined. The Company is committed to excellence with a passion to drive corporate financial performance and succeed as a team.

For additional information on reporting segments and the plays in which the Company operates, refer to Items 1 and 2 of this Annual Report on Form 10-K. On February 13, 2019, the Company completed the acquisition of Newfield Exploration Company (“Newfield”); as such, the post-acquisition results of operations of Newfield are included in the Company’s consolidated results beginning February 14, 2019. For additional information on the business combination and segmented results, refer to Notes 8 and 2, respectively, to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

In evaluating its operations and assessing its leverage, Ovintiv reviews performance-based measures such as Non-GAAP Cash Flow, Non-GAAP Cash Flow Margin, Total Costs and debt-based metrics such as Debt to Adjusted Capitalization and Net Debt to Adjusted EBITDA, which are non-GAAP measures and do not have any standardized meaning under U.S. GAAP. These measures may not be similar to measures presented by other issuers and should not be viewed as a substitute for measures reported under U.S. GAAP. Additional information regarding these measures, including reconciliations to the closest GAAP measure, can be found in the Non-GAAP Measures section of this MD&A.

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For the period ended December 31, 2019, the Company elected to exclude from this MD&A the discussion of the results of operations for the period ended December 31, 2017, being the earliest of the three years included in the Consolidated Financial Statements, as set forth in the SEC’s amendment to Item 303 of Regulation S-K, which was effective May 2, 2019. For additional information on the Company’s financial condition, changes in financial condition and results of operations for the period ended December 31, 2017, refer to Item 7 of the 2018 Annual Report on Form 10-K.

Highlights

During 2019, the Company met or exceeded all of the targets set in its full year 2019 guidance by executing its 2019 capital plan, generating cash from operating activities and returning capital to shareholders through dividends and share buybacks. Subsequent to the successful completion of the Newfield acquisition, the Company fully integrated the businesses and captured synergies that exceeded previously announced expectations. Higher upstream product revenues in 2019 compared to 2018 resulted from higher production volumes, partially offset by lower average realized prices, excluding the impact of risk management activities. Total production volumes increased 56 percent compared to 2018 primarily due to the Newfield acquisition and successful drilling programs. Decreases in average realized liquids and natural gas prices of 20 percent and 12 percent, respectively, were primarily due to lower benchmark prices. The Company continued to focus on optimizing realized prices from the diversification of the Company’s downstream markets.

Significant Developments

• Completed the acquisition of all issued and outstanding shares of common stock of Newfield on February 13, 2019, whereby the Company issued approximately 543.4 million common shares, on a pre-Share Consolidation basis. The acquired operations are focused on the development of oil-rich properties primarily located in the Anadarko Basin in Oklahoma. Following the acquisition, Newfield’s senior notes totaling $2.45 billion remain outstanding.

• Purchased, for cancellation, approximately 196.7 million common shares, on a pre-Share Consolidation basis, for total consideration of approximately $1,250 million, thereby fully executing the Company’s previously announced NCIB and substantial issuer bid.

• Terminated the production sharing contract with China National Offshore Oil Corporation (“CNOOC”), which governed the Company’s China Operations, effective July 31, 2019. Subsequently, the Company no longer has operations in China.

• Completed the sale of the Company’s Arkoma natural gas assets on August 27, 2019, comprising approximately 140,000 net acres in Oklahoma, for proceeds of $155 million, after closing adjustments.

Financial Results

• Reported net earnings of $234 million, including a net loss on risk management in revenues of $361 million, before tax, restructuring charges of $138 million, before tax, net foreign exchange gains of $119 million, before tax, and acquisition costs of $33 million, before tax.

• Generated cash from operating activities of $2,921 million, Non-GAAP Cash Flow of $2,931 million and Non‑GAAP Cash Flow Margin of $14.21 per BOE. Cash from operating activities exceeded capital expenditures by $295 million.

• Held cash and cash equivalents of $190 million and had $4.0 billion in available credit facilities, of which the Company’s $2.5 billion revolving credit facility supported the issuance of $698 million of commercial paper at year end.

• Achieved Net Debt to Adjusted EBITDA of 2.0 times.

• Returned capital to shareholders through the purchase, for cancellation, of approximately 196.7 million common shares, on a pre-Share Consolidation basis. The Company also paid dividends of $0.075 per common share, on a pre-Share Consolidation basis, totaling $102 million.

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Capital Investment

• Reported total capital spending of $2,626 million which was within the full year 2019 guidance of $2.55 billion to $2.65 billion.

• Directed $2,030 million, or 77 percent, of total capital spending to the Core Assets.

• Reduced well costs in Anadarko through the deployment of cube development by approximately $1.9 million per well in 2019 compared to Newfield’s 2018 well costs, exceeding the Company’s previously announced expected savings of $1 million per well.

• Focused on highly efficient capital activity and short-cycle high margin projects providing flexibility to respond to fluctuations in commodity prices.

Production

• Average liquids and natural gas production volumes exceeded the full year 2019 guidance ranges of 297.0 Mbbls/d to 301.0 Mbbls/d and 1,560 MMcf/d to 1,575 MMcf/d, respectively.

• Produced average liquids volumes of 301.9 Mbbls/d which accounted for 53 percent of total production volumes. Average oil and plant condensate production volumes of 217.3 Mbbls/d were 72 percent of total liquids production volumes.

• Produced average natural gas volumes of 1,577 MMcf/d which accounted for 47 percent of total production volumes.

Revenues and Operating Expenses

• Focused on market diversification to optimize realized commodity prices and revenues through a combination of derivative financial instruments and physical transportation contracts.

• Continued to utilize pipeline transportation capacity to the Houston and Dawn markets, thereby benefiting from reduced exposure to Midland, Waha and AECO differentials.

• Incurred Total Costs of $12.59 per BOE, a decrease compared to 2018 of $0.41 per BOE, outperforming the expected full year 2019 guidance range of $12.60 per BOE to $12.90 per BOE. Total Costs includes production, mineral and other property taxes, upstream transportation and processing expense, upstream operating expense and administrative expense. Total Costs excludes the impact of long-term incentive and restructuring costs. Significant items impacting Total Costs in 2019 include:

o Lower upstream transportation and processing expense in 2019 compared to 2018 of $0.80 per BOE primarily due to the higher proportion of total production volumes from the USA Operations, which benefit from lower than average per BOE transportation and processing costs. Production volumes in the USA Operations were higher in 2019 compared to 2018 due to the Newfield acquisition; and

o Higher administrative expense, excluding long-term incentive costs and restructuring costs, in 2019 compared to 2018 of $0.16 per BOE primarily due to the change in accounting treatment for The Bow office building. Additional information on the adoption of ASC Topic 842 can be found in Notes 1 and 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

• Reduced operating and administrative costs through workforce reductions and operating efficiencies by $200 million on an annualized basis, compared to the combined costs of Newfield and the Company prior to the acquisition. These synergies surpass the Company’s original estimate of $125 million and exclude restructuring costs incurred in 2019. Total restructuring costs incurred were $138 million.

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Subsequent Event

On January 24, 2020, Encana completed a corporate reorganization, which included a plan of arrangement (the “Arrangement”) that involved, among other things, a share consolidation by Encana on the basis of one post-consolidation share for each five pre-consolidation shares (the “Share Consolidation”), and Ovintiv Inc. ultimately acquired all of the issued and outstanding common shares of Encana in exchange for shares of common stock of Ovintiv Inc. on a one-for-one basis. Following completion of the Arrangement, Ovintiv Inc. migrated from Canada and became a Delaware corporation, domiciled in the U.S. (the “U.S. Domestication”). The Arrangement and the U.S. Domestication together are referred to as the “Reorganization”. Ovintiv continues to carry on business previously conducted by Encana and its subsidiaries prior to the completion of the Reorganization. Additional information on the Reorganization can be found in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

2020 Outlook

Industry Outlook

The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices during 2020 are expected to reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment. At a meeting in December 2019, OPEC and certain non-OPEC countries (collectively “OPEC”) agreed to deepen and extend crude oil production cuts, originally instated in January 2019, through the first quarter of 2020 seeking to balance the global oil market in response to changing fundamentals. Risks to the global economy, including trade disputes, U.S. sanctions policy, U.S. production growth and potential oil supply outages in major producing countries resulting from geopolitical instability, could further contribute to price volatility in 2020. OPEC is scheduled to meet again in March 2020 to review production levels which could potentially result in other supply adjustments and contribute to price fluctuations.

Natural gas prices in 2020 will be affected by the timing of supply and demand growth and the effects of seasonal weather. Potential for improvement in longer-term U.S. natural gas prices remains limited as production growth continues to create additional downward pressure on U.S. natural gas prices. Despite a strengthening AECO price relative to NYMEX, natural gas prices in western Canada are expected to remain low due to the weak NYMEX price environment.

Company Outlook

Ovintiv is well positioned in the current price environment to balance liquids growth while generating cash flows in excess of capital expenditures. The Company enters into derivative financial instruments which mitigate price volatility and help sustain revenues during periods of lower prices. A portion of the Company’s production is sold at prevailing market prices which also allows Ovintiv to participate in potential price increases. As at December 31, 2019, the Company has hedged approximately 165 Mbbls/d of expected crude oil and condensate production and 1,188 MMcf/d of expected natural gas production for 2020. Additional information on the Company’s hedging program can be found in Note 25 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Markets for crude oil and natural gas are exposed to different price risks. While the market price for crude oil tends to move in the same direction as the global market, regional differentials may develop. Natural gas prices may vary between geographic regions depending on local supply and demand conditions. Ovintiv proactively utilizes transportation contracts to diversify the Company’s sales markets, thereby reducing significant exposure to any given market. Through a combination of derivative financial instruments and transportation capacity, Ovintiv continues to limit exposure to regional pricing in 2020.

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Capital Investment

Total anticipated 2020 capital investment of approximately $2.7 billion is expected to be funded from 2020 cash generated from operating activities. Capital investment is expected to be primarily allocated to the Core Assets with a focus on maximizing returns from high margin liquids and to other upstream assets to optimize operating free cash flows. In 2020, the Company expects to generate cash flows in excess of capital expenditures.

Ovintiv continually strives to improve well performance and lower costs through innovative techniques. The Company's large-scale cube development model utilizes multi-well pads and advanced completion designs to maximize returns and resource recovery from its reservoirs. The impact of Ovintiv’s disciplined capital program and continuous innovation create flexibility to allocate capital in changing commodity markets and to continue growing cash flows.

Production

In 2020, Ovintiv expects liquids production volumes of 318.0 Mbbls/d to 332.0 Mbbls/d and natural gas production volumes of 1,520 MMcf/d to 1,580 MMcf/d.

Operating Expenses

For 2020, Ovintiv expects Total Costs of $12.20 per BOE to $12.50 per BOE which includes production, mineral and other taxes, upstream transportation and processing expense, upstream operating expense and administrative expense. Total Costs excludes the impact of long-term incentive costs. Ovintiv expects to continue pursuing innovative ways to reduce upstream operating and administrative expenses and expects efficiency improvements and effective supply chain management, including favorable price negotiations, to offset any inflationary pressures.

Additional information on Ovintiv’s 2020 Corporate Guidance can be accessed on the Company’s website at www.ovintiv.com.

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Results of Operations

Selected Financial Information

($ millions)	2019			2018
Product and Service Revenues
Upstream product revenues	$	5,847		$	4,223
Market optimization		1,159			1,224
Service revenues		7			10
Total Product and Service Revenues		7,013			5,457
Gains (Losses) on Risk Management, Net		(361	)		415
Sublease Revenues		74			67
Total Revenues		6,726			5,939
Total Operating Expenses (1)		6,128			4,245
Operating Income (Loss)		598			1,694
Total Other (Income) Expenses		283			531
Net Earnings (Loss) Before Income Tax		315			1,163
Income Tax Expense (Recovery)		81			94
Net Earnings (Loss)	$	234		$	1,069

(1) Total Operating Expenses include non-cash items such as DD&A, accretion of asset retirement obligations and long-term incentive costs.

Subsequent to the completion of the Newfield acquisition on February 13, 2019, the post‑acquisition results of the operations of Newfield are included in the Company’s consolidated results beginning February 14, 2019. As a result of the business combination and the addition of the Anadarko asset to the Company’s portfolio, the Core Assets were redefined to include Permian and Anadarko in the U.S. and Montney in Canada. The 2018 Core Assets production presentation has been updated to align with the Company’s 2019 Core Assets and reflects Permian and Montney.

Revenues

Ovintiv’s revenues are substantially derived from sales of oil, NGLs and natural gas production. Increases or decreases in Ovintiv’s revenue, profitability and future production are highly dependent on the commodity prices the Company receives. Prices are market driven and fluctuate due to factors beyond the Company’s control, such as supply and demand, seasonality and geopolitical and economic factors. The USA Operations realized prices generally reflect WTI and NYMEX benchmark prices, as well as other downstream oil benchmarks, including Houston. The Canadian Operations realized prices are linked to Edmonton Condensate and AECO, as well as other downstream natural gas benchmarks, including Dawn. The other downstream benchmarks reflect the diversification of the Company’s markets. Recent trends in benchmark prices relevant to the Company are shown in the table below.

Benchmark Prices

(average for the period)	2019		2018
Oil & NGLs
WTI ($/bbl)	$	57.03	$	64.77
Houston ($/bbl)		62.12		69.00
Edmonton Condensate (C$/bbl)		70.15		78.88
Natural Gas
NYMEX ($/MMBtu)	$	2.63	$	3.09
AECO (C$/Mcf)		1.62		1.53
Dawn (C$/MMBtu)		3.19		4.07

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Production Volumes and Realized Prices

	Production Volumes (1)				Realized Prices (2)
	2019		2018		2019		2018
Oil (Mbbls/d, $/bbl)
USA Operations		162.3		89.5	$	56.19	$	64.05
Canadian Operations		0.6		0.4		53.19		52.54
China Operations (3)		1.5		-		66.37		-
Total		164.4		89.9		56.27		64.00
NGLs – Plant Condensate (Mbbls/d, $/bbl)
USA Operations		10.5		3.8		44.05		52.33
Canadian Operations		42.4		35.2		51.79		56.31
Total		52.9		39.0		50.25		55.92
NGLs – Other (Mbbls/d, $/bbl)
USA Operations		67.9		25.2		11.44		23.39
Canadian Operations		16.7		14.0		11.11		27.32
Total		84.6		39.2		11.37		24.79
Total Oil & NGLs (Mbbls/d, $/bbl)
USA Operations		240.7		118.5		43.04		55.03
Canadian Operations		59.7		49.6		40.36		48.08
China Operations (3)		1.5		-		66.37		-
Total		301.9		168.1		42.63		52.98
Natural Gas (MMcf/d, $/Mcf)
USA Operations		547		151		1.90		2.28
Canadian Operations		1,030		1,007		2.01		2.24
Total		1,577		1,158		1.97		2.25
Total Production (MBOE/d, $/BOE)
USA Operations		331.9		143.7		34.36		47.80
Canadian Operations		231.5		217.5		19.35		21.34
China Operations (3)		1.5		-		66.37		-
Total		564.9		361.2		28.29		31.86
Production Mix (%)
Oil & Plant Condensate		38		36
NGLs – Other		15		11
Total Oil & NGLs		53		47
Natural Gas		47		53
Production Growth – Year Over Year (%) (4)
Total Oil & NGLs		80		30
Natural Gas		36		5
Total Production		56		15
Core Assets Production (5)
Oil (Mbbls/d)		109.3		59.1
NGLs – Plant Condensate (Mbbls/d)		44.7		30.7
NGLs – Other (Mbbls/d)		73.8		30.0
Total Oil & NGLs (Mbbls/d)		227.8		119.8
Natural Gas (MMcf/d)		1,353		980
Total Production (MBOE/d)		453.5		283.0
% of Total Production		80		78

(1) Average daily.

(2) Average per-unit prices, excluding the impact of risk management activities.

(3) The Company acquired its China Operations as part of the Newfield business combination on February 13, 2019. Subsequently, the Company terminated its production sharing contract with CNOOC and exited its China Operations effective July 31, 2019. Production from China Operations is presented for the period from February 14, 2019 through July 31, 2019.

(4) Includes production impacts of acquisitions and divestitures.

(5) Core Assets production presentation aligns with the Company’s 2019 Core Assets, which include Permian, Anadarko and Montney. Core Assets production for 2018 has been updated and reflects Permian and Montney.

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Upstream Product Revenues

($ millions)	Oil			NGLs - Plant Condensate			NGLs - Other			Natural Gas			Total (1)
2018 Upstream Product Revenues	$	2,100		$	797		$	355		$	952		$	4,204
Increase (decrease) due to:
Sales prices		(184	)		(85	)		(205	)		(129	)		(603	)
Production volumes		1,460			259			201			313			2,233
2019 Upstream Product Revenues	$	3,376		$	971		$	351		$	1,136		$	5,834

(1) Revenues for 2019 exclude certain other revenue and royalty adjustments with no associated production volumes of $13 million (2018 - royalty adjustments of $19 million).

Oil Revenues

2019 versus 2018

Oil revenues increased $1,276 million compared to 2018 primarily due to:

• Higher average oil production volumes of 74.5 Mbbls/d increased revenues by $1,460 million. Higher volumes were primarily due to the Newfield acquisition (64.9 Mbbls/d) and successful drilling programs in Anadarko, Permian and Bakken (15.6 Mbbls/d), partially offset by natural declines in Eagle Ford (3.2 Mbbls/d) and the sale of the San Juan assets in the fourth quarter of 2018 (2.3 Mbbls/d); and

• Lower average realized oil prices of $7.73 per bbl, or 12 percent, decreased revenues by $184 million. The decrease reflected lower WTI and Houston benchmark prices which were down 12 percent and 10 percent, respectively, partially offset by strengthening regional pricing relative to the WTI benchmark price in the USA Operations.

NGL Revenues

2019 versus 2018

NGL revenues increased $170 million compared to 2018 primarily due to:

• Higher average plant condensate production volumes of 13.9 Mbbls/d increased revenues by $259 million. Higher volumes were primarily due to successful drilling programs in Montney and Anadarko (9.4 Mbbls/d) and the Newfield acquisition (4.9 Mbbls/d); and

• Higher average other NGL production volumes of 45.4 Mbbls/d increased revenues by $201 million. Higher volumes were primarily due to the Newfield acquisition (31.3 Mbbls/d) and successful drilling programs in Anadarko, Montney and Permian (15.3 Mbbls/d);

partially offset by:

• Lower average realized other NGL prices of $13.42 per bbl, or 54 percent, decreased revenues by $205 million reflecting lower other NGL benchmark prices and lower regional pricing; and

• Lower average realized plant condensate prices of $5.67 per bbl, or 10 percent, decreased revenues by $85 million. The decrease reflected lower WTI and Edmonton Condensate benchmark prices which were down 12 percent and 11 percent, respectively, partially offset by fluctuations in regional pricing relative to the WTI and Edmonton Condensate benchmark prices.

Natural Gas Revenues

2019 versus 2018

Natural gas revenues increased $184 million compared to 2018 primarily due to:

• Higher average natural gas production volumes of 419 MMcf/d increased revenues by $313 million primarily due to the Newfield acquisition (368 MMcf/d) and successful drilling programs in Montney, Anadarko, Permian and Bakken (82 MMcf/d), partially offset by lower production in Other Upstream Operations

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primarily due to natural declines (23 MMcf/d) and the sale of the San Juan assets in the fourth quarter of 2018 (8 MMcf/d); and

• Lower average realized natural gas prices of $0.28 per Mcf, or 12 percent, decreased revenues by $129 million reflecting lower Dawn and NYMEX benchmark prices which were down 22 percent and 15 percent, respectively, partially offset by a higher proportion of total production volumes in the USA Operations with higher regional pricing resulting from the Newfield acquisition and a higher AECO benchmark price which was up six percent.

Gains (Losses) on Risk Management, Net

As a means of managing commodity price volatility, Ovintiv enters into commodity derivative financial instruments on a portion of its expected oil, NGL and natural gas production volumes. The Company’s commodity price mitigation program reduces volatility and helps sustain revenues during periods of lower prices. Additional information on the Company’s commodity price positions as at December 31, 2019 can be found in Note 25 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

The following table provides the effects of the Company’s risk management activities on revenues.

	$ millions							Per-Unit
	2019			2018			2019			2018
Realized Gains (Losses) on Risk Management
Commodity Price (1)
Oil ($/bbl)	$	68		$	(235	)	$		1.13	$	(7.16	)
NGLs - Plant Condensate ($/bbl)		33			(91	)	$		1.70	$	(6.36	)
NGLs - Other ($/bbl)		82			2		$		2.67	$	0.14
Natural Gas ($/Mcf)		180			218		$		0.31	$	0.51
Other (2)		6			2		$		-	$	-
Total ($/BOE)		369			(104	)	$		1.76	$	(0.80	)
Unrealized Gains (Losses) on Risk Management		(730	)		519
Total Gains (Losses) on Risk Management, Net	$	(361	)	$	415

(1) Includes realized gains and losses related to the USA and Canadian Operations.

(2) Other primarily includes realized gains or losses from Market Optimization and other derivative contracts with no associated production volumes.

Ovintiv recognizes fair value changes from its risk management activities each reporting period. The changes in fair value result from new positions and settlements that occur during each period, as well as the relationship between contract prices and the associated forward curves. Realized gains or losses on risk management activities related to commodity price mitigation are included in the USA Operations, Canadian Operations and Market Optimization revenues as the contracts are cash settled. Unrealized gains or losses on fair value changes of unsettled contracts are included in the Corporate and Other segment.

Market Optimization Revenues

Market Optimization product revenues relate to activities that provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. The Company also purchases and sells third-party volumes under long-term marketing arrangements associated with the Company’s previous divestitures.

($ millions)	2019		2018
Market Optimization	$	1,159	$	1,224

2019 versus 2018

Market Optimization product revenues decreased $65 million compared to 2018 primarily due to:

• Lower benchmark prices ($232 million) and lower sales of third-party purchased natural gas volumes ($44 million);

54

partially offset by:

• Higher sales of third-party purchased liquids volumes ($211 million) due to:

o Changing market conditions resulting in additional third-party purchases to meet sales commitments in the Canadian Operations in the first quarter of 2019; and

o Price optimization activities and additional third-party purchases to meet sales commitments in the USA Operations in the third quarter of 2019.

Sublease Revenues

Sublease revenues primarily include amounts related to the sublease of office space in The Bow office building recorded in the Corporate and Other segment. Additional information on office sublease income can be found in Note 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Operating Expenses

Production, Mineral and Other Taxes

Production, mineral and other taxes include production and property taxes. Production taxes are generally assessed as a percentage of oil, NGLs and natural gas production revenues. Property taxes are generally assessed based on the value of the underlying assets.

	$ millions				$/BOE
	2019		2018			2019		2018
USA Operations	$	238	$	131		$	1.96	$	2.50
Canadian Operations		16		16		$	0.19	$	0.20
Total	$	254	$	147		$	1.23	$	1.11

2019 versus 2018

Production, mineral and other taxes increased $107 million compared to 2018 primarily due to:

• Higher production volumes and property values resulting from the Newfield acquisition ($115 million) and higher production volumes and assessed property values in Permian ($14 million);

partially offset by:

• Lower production tax mainly as a result of lower commodity prices ($16 million) and the sale of the San Juan assets in the fourth quarter of 2018 ($6 million).

Transportation and Processing

Transportation and processing expense includes transportation costs incurred to move product from production points to sales points including gathering, compression, pipeline tariffs, trucking and storage costs. Ovintiv also incurs costs related to processing provided by third parties or through ownership interests in processing facilities to bring raw production to sales‑quality product.

	$ millions				$/BOE
	2019		2018		2019		2018
USA Operations	$	466	$	124	$	3.85	$	2.37
Canadian Operations		859		828	$	10.16	$	10.42
Upstream Transportation and Processing		1,325		952	$	6.42	$	7.22
Market Optimization		233		131
Total	$	1,558	$	1,083

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2019 versus 2018

Transportation and processing expense increased $475 million compared to 2018 primarily due to:

• Higher production volumes resulting from the Newfield acquisition and successful drilling in Anadarko and Bakken ($341 million), rate escalation in certain transportation contracts relating to previously divested assets and incremental transportation costs associated with third‑party purchased volumes ($99 million), successful drilling in Montney and Permian ($82 million) and higher costs relating to the diversification of the Company’s downstream markets ($21 million);

partially offset by:

• Lower commodity prices ($21 million), lower U.S./Canadian dollar exchange rate ($18 million) and lower activity in Deep Panuke where the Company ceased production in the second quarter of 2018 ($11 million).

Upstream transportation and processing decreased $0.80 per BOE compared to 2018 primarily due to a higher proportion of total production volumes in the USA Operations resulting from the Newfield acquisition.

Operating

Operating expense includes costs paid by the Company, net of amounts capitalized, to operate oil and natural gas properties in which the Company has a working interest. These costs primarily include labor, service contract fees, chemicals, fuel, water hauling and workovers.

	$ millions					$/BOE
	2019			2018			2019		2018
USA Operations	$	566		$	305		$	4.65	$	5.80
Canadian Operations		125			118		$	1.46	$	1.45
China Operations (1)		16			-		$	27.79	$	-
Upstream Operating Expense (2)		707			423		$	3.41	$	3.18
Market Optimization		28			16
Corporate & Other		(3	)		15
Total	$	732		$	454

(1) The Company acquired its China Operations as part of the Newfield business combination on February 13, 2019. Subsequently, the Company terminated its production sharing contract with CNOOC and exited its China Operations effective July 31, 2019. Upstream Operating Expense for China Operations is presented for the period from February 14, 2019 through July 31, 2019.

(2) 2019 Upstream Operating Expense per BOE includes long-term incentive costs of $0.06/BOE (2018 - recovery of long-term incentive costs of $0.06/BOE).

2019 versus 2018

Operating expense increased $278 million compared to 2018 primarily due to:

• The Newfield acquisition and successful drilling in Anadarko ($249 million), the impact of changes in capital programs primarily in Montney and Other Upstream Operations ($30 million), long-term incentive costs in 2019 compared to a recovery in 2018 resulting from a larger decrease in the share price in 2018 compared to 2019 ($29 million) and higher activity in Permian ($21 million);

partially offset by:

• Lower activity in Eagle Ford and Montney ($15 million), lower salaries and benefits due to reduced headcount in Eagle Ford, Montney and Deep Panuke ($10 million) and the sale of the San Juan assets in the fourth quarter of 2018 ($10 million).

Additional information on the Company’s long-term incentives can be found in Note 22 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

56

Purchased Product

Purchased product expense includes purchases of oil, NGLs and natural gas from third parties that are used to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. The Company also purchases and sells third-party volumes under long-term marketing arrangements associated with the Company’s previous divestitures.

($ millions)	2019		2018
Market Optimization	$	1,043	$	1,100

2019 versus 2018

Purchased product expense decreased $57 million compared to 2018 primarily due to:

• Lower benchmark prices ($227 million) and lower third-party purchased natural gas volumes ($41 million);

partially offset by:

• Higher third-party purchased liquids volumes ($211 million) due to:

o Changing market conditions resulting in additional third-party purchases to meet sales commitments in the Canadian Operations in the first quarter of 2019; and

o Price optimization activities and additional third-party purchases to meet sales commitments in the USA Operations in the third quarter of 2019.

Depreciation, Depletion & Amortization

Proved properties within each country cost centre are depleted using the unit-of-production method based on proved reserves as discussed in Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Depletion rates are impacted by impairments, acquisitions, divestitures and foreign exchange rates, as well as fluctuations in 12-month average trailing prices which affect proved reserves volumes. Corporate assets are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets.

In 2019, the 12-month average trailing prices have generally declined. Further declines in the 12‑month average trailing commodity prices could reduce proved reserves values and result in the recognition of future ceiling test impairments. Future ceiling test impairments can also result from changes to reserves estimates, future development costs, capitalized costs and unproved property costs. Proceeds received from oil and natural gas divestitures are generally deducted from the Company’s capitalized costs and can reduce the risk of ceiling test impairments.

Additional information can be found under Upstream Assets and Reserve Estimates in the Critical Accounting Estimates section of this MD&A.

	$ millions				$/BOE
	2019		2018			2019		2018
USA Operations	$	1,593	$	860		$	13.15	$	16.39
Canadian Operations		383		361		$	4.53	$	4.55
Upstream DD&A		1,976		1,221		$	9.61	$	9.26
Market Optimization		-		1
Corporate & Other		39		50
Total	$	2,015	$	1,272

57

2019 versus 2018

DD&A increased $743 million compared to 2018 primarily due to:

• Higher production volumes in the USA and Canadian Operations ($1,053 million and $26 million, respectively), partially offset by lower depletion rates in the USA Operations ($319 million).

The depletion rate in the USA Operations decreased $3.24 per BOE compared to 2018 primarily due to higher reserve volumes mainly in Permian, as well as additional reserve volumes acquired with the Newfield acquisition.

Administrative

Administrative expense represents costs associated with corporate functions provided by Ovintiv staff. Costs primarily include salaries and benefits, general office, information technology, restructuring and long-term incentive costs.

	$ millions						$/BOE
	2019		2018			2019			2018
Administrative, excluding Long-Term Incentive and
Restructuring Costs	$	328	$	190		$		1.59	$	1.43
Long-term incentive costs		23		(33	)			0.11		(0.25	)
Restructuring costs		138		-				0.67		-
Total Administrative (1)	$	489	$	157		$		2.37	$	1.18

(1) 2019 includes $92 million of operating lease expense related to The Bow office building (2018 - nil).

2019 versus 2018

Administrative expense in 2019 increased $332 million compared to 2018 primarily due to restructuring costs ($138 million), the impact from adopting ASC Topic 842, “Leases”, as discussed further below ($116 million) and administrative costs associated with the Newfield acquisition ($39 million), including non-recurring integration expenses of $12 million and long-term incentive costs in 2019 compared to a recovery in 2018 resulting from a larger decrease in the share price in 2018 compared to 2019 ($56 million).

During 2019, the Company completed workforce reductions in conjunction with the Newfield acquisition to better align staffing levels and the organizational structure. Additional information on restructuring charges can be found in Note 21 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

On January 1, 2019, the Company adopted ASC Topic 842 which requires all operating leases to be recognized on the balance sheet. As a result, The Bow office building was determined to be an operating lease with the lease payments recorded in administrative expense starting in 2019. Previously, payments related to The Bow office building were recognized as interest expense and principal repayment. Prior periods have not been restated and are reported in accordance with ASC Topic 840, “Leases”. Additional information on the adoption of ASC Topic 842 can be found in Notes 1 and 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Other (Income) Expenses

($ millions)	2019			2018
Interest	$	382		$	351
Foreign exchange (gain) loss, net		(119	)		168
(Gain) loss on divestitures, net		(3	)		(5	)
Other (gains) losses, net		23			17
Total Other (Income) Expenses	$	283		$	531

58

Interest

Interest expense primarily includes interest on the Company’s long-term debt arising from U.S. dollar denominated unsecured notes. Additional information on changes in interest can be found in Note 4 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

2019 versus 2018

Interest expense increased $31 million compared to 2018 primarily due to:

• Higher interest expense on long-term debt primarily relating to Newfield’s outstanding senior notes and issuances under the Company’s U.S. commercial paper (“U.S. CP”) program ($112 million), and an interest recovery due to the resolution of certain tax items relating to prior taxation years in 2018 ($17 million);

partially offset by:

• The change in accounting treatment for The Bow office building as a result of the adoption of ASC Topic 842 ($63 million), lower interest expense resulting from the repayment of the Company’s $500 million senior note in the second quarter of 2019 ($20 million) and capitalized interest ($10 million).

Additional information on the adoption of ASC Topic 842 can be found in Notes 1 and 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Foreign Exchange (Gain) Loss, Net

Foreign exchange gains and losses primarily result from the impact of fluctuations in the Canadian to U.S. dollar exchange rate. Additional information on changes in foreign exchange gains or losses can be found in Note 5 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Additional information on foreign exchange rates and the effects of foreign exchange rate changes can be found in Items 6 and 7A of this Annual Report on Form 10-K.

Following the completion of the Reorganization, including the U.S. Domestication, on January 24, 2020, as described in the Subsequent Event section of this MD&A, the U.S. dollar denominated unsecured notes issued by Encana Corporation were assumed by Ovintiv Inc., a company incorporated in Delaware with a U.S. dollar functional currency. Accordingly, these U.S. dollar denominated unsecured notes, along with certain intercompany notes, will no longer attract foreign exchange translation gains or losses.

2019 versus 2018

In 2019, the Company recorded a net foreign exchange gain of $119 million compared to a loss in 2018 of $168 million primarily due to:

• Unrealized foreign exchange gains on the translation of U.S. dollar financing debt and risk management contracts issued from Canada compared to losses in 2018 ($601 million) and realized foreign exchange gains on the settlement of U.S. dollar financing debt issued from Canada compared to losses in 2018 ($28 million);

partially offset by:

• Unrealized foreign exchange losses on the translation of intercompany notes compared to gains 2018 ($345 million).

Other (Gains) Losses, Net

Other (gains) losses, net, primarily includes other non-recurring revenues or expenses and may also include items such as interest income, interest received from tax authorities, transaction costs relating to acquisitions, reclamation charges relating to decommissioned assets and adjustments related to other assets.

2019

Other losses in 2019 primarily includes legal fees and transaction costs related to the Newfield acquisition of $33 million, partially offset by interest income on short-term investments of $10 million.

59

2018

Other losses in 2018 primarily included the write-down of long-term receivables relating to Other Upstream Operations of $20 million, acquisition costs relating to the merger agreement with Newfield of $7 million, and reclamation charges relating to decommissioned assets of $4 million, partially offset by interest income on short-term investments of $8 million and the recovery of sales taxes relating to previously divested investments of $7 million.

Income Tax

($ millions)	2019			2018
Current Income Tax Expense (Recovery)	$	(13	)	$	(55	)
Deferred Income Tax Expense (Recovery)		94			149
Income Tax Expense (Recovery)	$	81		$	94
Effective Tax Rate	25.7%			8.1%

Income Tax Expense (Recovery)

2019 versus 2018

Total income tax expense in 2019 decreased $13 million compared to 2018, primarily due to lower net earnings before income tax of $848 million in 2019 compared to 2018, partially offset by the impact of the foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings, the impact of the Alberta corporate tax rate reduction discussed below and the current income tax recovery in 2018 of $55 million resulting from the resolution of certain tax items relating to prior taxation years.

On June 28, 2019, Alberta Bill 3, the Job Creation Tax Cut (Alberta Corporate Tax Amendment) Act, was signed into law resulting in a reduction of the Alberta corporate tax rate from 12 percent to 11 percent effective July 1, 2019, with further one percent rate reductions to take effect every year on January 1 until the general corporate tax rate is eight percent on January 1, 2022. During 2019, the deferred tax expense of $94 million includes an adjustment of $55 million resulting from the re-measurement of the Company’s deferred tax position due to the Alberta corporate tax rate reduction.

Effective Tax Rate

The Company’s annual effective income tax rate is primarily impacted by earnings, income tax related to foreign operations, the effect of legislative changes, including the Alberta corporate tax rate reduction discussed above, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding. Additional information on income taxes can be found in Note 6 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

The Company’s effective tax rate for 2019 of 25.7 percent is slightly lower than the Canadian statutory tax rate of 26.6 percent primarily due to partnership tax allocations in excess of funding, as well as the resolution of certain tax items relating to prior taxation years, partially offset by the remeasurement of the Company’s deferred tax position resulting from the Alberta corporate tax rate reduction discussed above.

The effective tax rate for 2018 of 8.1 percent was lower than the Canadian statutory rate of 27 percent primarily due to the impact of the foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings, partnership tax allocations in excess of funding and the successful resolution of certain tax items relating to prior taxation years.

The determination of income and other tax liabilities of the Company and its subsidiaries requires interpretation of complex domestic and foreign tax laws and regulations, that are subject to change. The Company’s interpretation of taxation laws may differ from the interpretation of the tax authorities. As a result, there are tax matters under review for which the timing of resolution is uncertain. The Company believes that the provision for income taxes is adequate.

Following the U.S. Domestication, the applicable statutory rate will be the U.S. Federal income tax rate.

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Liquidity and Capital Resources

Sources of Liquidity

The Company has the flexibility to access cash equivalents and a range of funding alternatives at competitive rates through committed revolving credit facilities as well as debt and equity capital markets. The Company closely monitors the accessibility of cost-effective credit and ensures that sufficient liquidity is in place to fund capital expenditures and dividend payments. In addition, the Company may use cash and cash equivalents, cash from operating activities, or proceeds from asset divestitures to fund its operations or to manage its capital structure as discussed below. At December 31, 2019, $57 million in cash and cash equivalents was held by U.S. subsidiaries.

The Company’s capital structure consists of total shareholders’ equity plus long-term debt, including the current portion. The Company’s objectives when managing its capital structure are to maintain financial flexibility to preserve Ovintiv’s access to capital markets and its ability to meet financial obligations and finance internally generated growth, as well as potential acquisitions. The Company has a practice of maintaining capital discipline and strategically managing its capital structure by adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares, purchasing shares for cancellation, issuing new debt or repaying existing debt.

($ millions, except as indicated)	2019			2018
Cash and Cash Equivalents	$	190		$	1,058
Available Credit Facility (1)		4,000			4,000
Issuance of U.S. Commercial Paper		(698	)		-
Total Liquidity	$	3,492		$	5,058
Long-Term Debt, including current portion (2)	$	6,974		$	4,198
Total Shareholders’ Equity (3)	$	9,930		$	7,447
Debt to Capitalization (%) (4)		41			36
Debt to Adjusted Capitalization (%) (5)		28			22

(1) Includes available credit facilities of $2.5 billion in Canada and $1.5 billion in the U.S. (collectively, the “Credit Facilities”).

(2) Long-Term Debt as at December 31, 2019, includes outstanding U.S. CP totaling $698 million and the senior notes acquired in conjunction with the Newfield business combination on February 13, 2019, totaling $2,450 million.

(3) Shareholders’ Equity reflects the common shares issued to Newfield shareholders on February 13, 2019, totaling $3,478 million and the common shares purchased, for cancellation, under the Company’s NCIB and substantial issuer bid programs.

(4) Calculated as long-term debt, including the current portion, divided by shareholders’ equity plus long-term debt, including the current portion.

(5) A non-GAAP measure which is defined in the Non-GAAP Measures section of this MD&A.

As at December 31, 2019, the Company had $698 million of commercial paper outstanding under its U.S. CP program to provide for short‑term funding requirements, which is supported by the Company’s $2.5 billion revolving credit facility. Further details on the U.S. CP program can be found in the Sources and Uses of Cash section of this MD&A.

Ovintiv is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under the Credit Facilities. Management monitors Debt to Adjusted Capitalization, which is a non-GAAP measure defined in the Non-GAAP Measures section of this MD&A, as a proxy for the Company’s financial covenant under the Credit Facilities, which requires debt to adjusted capitalization to be less than 60 percent. As at December 31, 2019, the Company’s Debt to Adjusted Capitalization was 28 percent. The definitions used in the covenant under the Credit Facilities adjust capitalization for cumulative historical ceiling test impairments recorded in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. Additional information on financial covenants can be found in Note 15 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

The Company’s debt-based metrics have increased over the prior year due to the increase in long-term debt resulting from the Newfield acquisition. Further details on the Company’s debt-based metrics can be found in the Non-GAAP Measures section of this MD&A.

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Sources and Uses of Cash

During 2019, the Company primarily generated cash through operating activities. The following table summarizes the sources and uses of the Company’s cash and cash equivalents.

($ millions)	Activity Type	2019			2018
Sources of Cash, Cash Equivalents and Restricted Cash
Cash from operating activities	Operating	$	2,921		$	2,300
Proceeds from divestitures	Investing		197			493
Corporate acquisition, net of cash and restricted cash acquired	Investing		94			-
Net issuance of revolving long-term debt	Financing		698			-
			3,910			2,793
Uses of Cash and Cash Equivalents
Capital expenditures	Investing		2,626			1,975
Acquisitions	Investing		65			17
Repayment of long-term debt	Financing		500			-
Purchase of common shares	Financing		1,250			250
Dividends on common shares	Financing		102			56
Other	Investing/Financing		240			146
			4,783			2,444
Foreign Exchange Gain (Loss) on Cash, Cash Equivalents     and Restricted Cash Held in Foreign Currency			5			(10	)
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash		$	(868	)	$	339

Operating Activities

Cash from operating activities in 2019 was $2,921 million and was primarily a reflection of the impacts from the Newfield acquisition, increases in production volumes, the effects of the commodity price mitigation program and changes in non-cash working capital, partially offset by lower average realized commodity prices.

Additional detail on changes in non-cash working capital can be found in Note 26 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Ovintiv expects it will continue to meet the payment terms of its suppliers.

Non-GAAP Cash Flow in 2019 was $2,931 million and was primarily impacted by the items affecting cash from operating activities which are discussed below and in the Results of Operations section of this MD&A.

2019 versus 2018

Net cash from operating activities increased $621 million compared to 2018 primarily due to:

• Higher production volumes ($2,233 million) and realized gains on risk management in revenues in 2019 compared to realized losses in 2018 ($473 million);

partially offset by:

• Lower realized commodity prices ($603 million), higher transportation and processing expense ($475 million), higher operating and administrative expense, excluding non-cash long-term incentive costs ($265 million and $167 million, respectively), changes in non-cash working capital ($158 million), restructuring costs ($138 million), higher interest on long-term debt ($118 million), higher production, mineral and other taxes ($107 million), lower current tax recovery in 2019 compared to 2018 ($42 million) and acquisition costs ($33 million).

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Investing Activities

Capital expenditures, divestitures and acquisitions have been the Company’s primary investing activities over the past two years and are summarized in Notes 2, 8 and 9 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

2019 and 2018

Cash used in investing activities in 2019 was $2,556 million primarily due to capital expenditures. Capital expenditures increased $651 million compared to 2018 due to an increase in the Company’s capital program for 2019 relating to the Anadarko asset acquired in the Newfield acquisition ($712 million). Cash from operating activities exceeded capital expenditures by $295 million.

Corporate acquisition in 2019 was $94 million which reflected the net cash acquired upon the Newfield business combination.

Acquisitions in 2019 were $65 million, which primarily included seismic purchases, water rights and property purchases with liquids-rich potential.

Acquisitions in 2018 were $17 million, which primarily included property purchases with liquids-rich potential.

Divestitures in 2019 were $197 million, which primarily included the sale of the Company’s Arkoma natural gas assets in Oklahoma, comprising approximately 140,000 net acres. Proceeds from the sale of the Arkoma natural gas assets were used to reduce the Company’s long-term debt.

Divestitures in 2018 were $493 million, which primarily included the sale of the San Juan assets in New Mexico, comprising approximately 182,000 net acres.

Financing Activities

Net cash used in financing activities over the past two years has been impacted by the Company’s strategy to enhance liquidity, strengthen its balance sheet and return value to shareholders through the purchase of common shares. The Company has paid dividends each of the past two years and increased its dividend in the first quarter of 2019.

2019 versus 2018

Net cash used in financing activities in 2019 increased $842 million compared to 2018 primarily due to the purchase of common shares under a NCIB ($787 million) and substantial issuer bid ($213 million) as discussed below, repayment of long‑term debt ($500 million), as well as increased dividends paid ($46 million) in 2019 compared to 2018, partially offset by the net issuance of commercial paper under the Company’s U.S. CP program ($698 million). Further detail on the Company’s U.S. CP program can be found below.

The transactions affecting the changes in financing activities are discussed in more detail below.

2019 and 2018

The Company’s long-term debt totaled $6,974 million at December 31, 2019 (2018 - $4,198 million). On May 15, 2019, the Company repaid the $500 million 6.50 percent senior note using proceeds from the U.S. CP program.

Following the completion of the Newfield acquisition on February 13, 2019, Newfield’s senior notes totaling $2.45 billion remained outstanding as at December 31, 2019. These include a $750 million 5.75 percent senior note due January 30, 2022, a $1.0 billion 5.625 percent senior note due July 1, 2024 and a $700 million 5.375 percent senior note due January 1, 2026. For additional information on long-term debt, refer to Note 15 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. The increase in long‑term debt resulting from the Newfield acquisition increased the Company’s debt-based metrics. Further details on the Company’s debt‑based metrics can be found in the Non-GAAP Measures section of this MD&A.

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At December 31, 2019, the Company had access to two credit facilities, one available in Canada for $2.5 billion and one available in the U.S. for $1.5 billion, totaling $4.0 billion. At December 31, 2019, no amounts were outstanding under the Credit Facilities. The Credit Facilities provide financial flexibility and allow the Company to fund its operations, development activities or capital programs. Subsequent to the Reorganization as described in the Subsequent Event section of this MD&A, the Credit Facilities were replaced with committed revolving U.S. dollar denominated credit facilities totaling $4.0 billion, which include a $2.5 billion revolving credit facility for Ovintiv Inc. and a $1.5 billion revolving credit facility for a Canadian subsidiary. These facilities mature in July 2024, and are fully revolving up to maturity.

At December 31, 2019, the Company had $698 million of commercial paper outstanding under its U.S. CP program with an average term of 49 days and a weighted average interest rate of approximately 2.28 percent, which was supported by the Company’s $2.5 billion revolving credit facility. Subsequent to the Reorganization, Ovintiv has access to two U.S. commercial paper programs, which include a $1.5 billion program for Ovintiv Inc. and a $1.0 billion program for a Canadian subsidiary.

At December 31, 2019, the Credit Facilities, together with cash and cash equivalents less any outstanding commercial paper, provided the Company with total liquidity of $3.5 billion. The Company also had approximately $149 million in undrawn letters of credit issued in the normal course of business primarily as collateral security, to support future abandonment liabilities and for transportation arrangements.

At December 31, 2019, the Company had a U.S. shelf registration statement and a Canadian shelf prospectus under which the Company had the ability to issue from time to time, debt securities, common shares, Class A preferred shares, subscription receipts, warrants, units, share purchase contracts and share purchase units in the U.S. and/or Canada. At December 31, 2019, $6.0 billion was accessible under the Canadian shelf prospectus. Following completion of the Reorganization, the Company intends to renew its U.S. shelf registration statement and Canadian shelf prospectus.

Dividends

The Company pays quarterly dividends to shareholders at the discretion of the Board of Directors.

($ millions, except as indicated)	2019		2018
Dividend Payments	$	102	$	57
Dividend Payments ($/share) (1)	$	0.375	$	0.30

(1) Dividend payments per share reflect the Share Consolidation. Accordingly, the comparative period has been restated. On a pre-Share Consolidation basis, dividend payments were $0.075 per common share for 2019 and $0.06 per common share for 2018.

The Company increased its dividend by 25 percent in the first quarter of 2019 as part of the Company’s commitment to returning capital to shareholders. Dividends paid in 2019 increased $45 million compared to 2018 due to additional common shares issued as part of the Newfield acquisition, in addition to the 25 percent increase in the dividend per share, partially offset by common shares purchased, for cancellation, under the Company’s substantial issuer bid and NCIB programs.

On February 19, 2020, the Board of Directors declared a dividend of $0.09375 per Ovintiv common share payable on March 31, 2020 to common stockholders of record as of March 13, 2020.

The dividends paid in 2018 included $1 million in common shares issued in lieu of cash dividends under the Company’s Dividend Reinvestment Plan (“DRIP”). On February 28, 2019, the Company announced the suspension of its DRIP effective immediately and in conjunction with the Reorganization, the DRIP was terminated.

Substantial Issuer Bid

On August 29, 2019, the Company used cash on hand and issued commercial paper totaling approximately $213 million to purchase, for cancellation, approximately 47.3 million of its outstanding common shares, on a pre-Share Consolidation basis or 9.5 million common shares on a post-Share Consolidation basis, under its previously announced substantial issuer bid.

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For additional information on the substantial issuer bid, refer to Note 18 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Normal Course Issuer Bid

On February 27, 2019, the Company received approval from the TSX to purchase, for cancellation, up to approximately 149.4 million common shares, on a pre-Share Consolidation basis, pursuant to a NCIB over a 12-month period commencing March 4, 2019 and ending March 3, 2020. In 2019, the Company used cash on hand of approximately $1,037 million to purchase, for cancellation, approximately 149.4 million common shares, on a pre-Share Consolidation basis or approximately 29.9 million common shares on a post-Share Consolidation basis.

In 2018, the Company used cash on hand of approximately $250 million to purchase, for cancellation, approximately 20.7 million common shares, on a pre-Share Consolidation basis or approximately 4.1 million common shares on a post-Share Consolidation basis, under the previous NCIB which commenced on February 28, 2018 and expired on February 27, 2019.

For additional information on the NCIB, refer to Note 18 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Off-Balance Sheet Arrangements

The Company may enter into off-balance sheet arrangements and transactions that can give rise to material off‑balance sheet obligations. The Company’s material off-balance sheet arrangements include transportation and processing agreements, and short-term leases and non-lease components associated with drilling rigs and building leases, as outlined in the Contractual Obligations table below, as well as undrawn letters of credit and minimum volumes sales contracts, all of which are customary agreements in the oil and gas industry. Other than the items discussed above, there are no other transactions, arrangements, or relationships with unconsolidated entities or persons that are reasonably likely to materially affect the Company’s liquidity or the availability of, or requirements for, capital resources.

Contractual Obligations

Contractual obligations arising from long-term debt, operating and finance leases, risk management liabilities and asset retirement obligations are recognized on the Company’s Consolidated Balance Sheet. The following table outlines the Company’s undiscounted obligations and commitments at December 31, 2019:

	Expected Future Payments
($ millions)	2020			2021-2022			2023-2024			Thereafter			Total
Long-Term Debt	$	-		$	2,048		$	1,000		$	3,811		$	6,859
Interest Payments on Long-Term Debt		377			709			610			2,179			3,875
Operating Leases (1)		133			218			174			1,101			1,626
Finance Leases (2)		99			95			16			22			232
Risk Management Liabilities		114			53			13			5			185
Asset Retirement Obligation		192			113			74			1,514			1,893
Obligations		915			3,236			1,887			8,632			14,670
Transportation and Processing		734			1,321			947			2,163			5,165
Drilling and Field Services (3)		90			6			-			-			96
Building Leases (3)		14			26			14			8			62
Commitments		838			1,353			961			2,171			5,323
Total Contractual Obligations	$	1,753		$	4,589		$	2,848		$	10,803		$	19,993
Sublease Income	$	(49	)	$	(95	)	$	(88	)	$	(546	)	$	(778	)

(1) Includes The Bow office building.

(2) Includes interest payments totaling $22 million.

(3) Includes short-term leases with terms less than 12 months and non-lease operating cost components.

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Interest Payments on Long-Term Debt and Finance Leases represent scheduled cash payments on the respective obligations. Additional information can be found in Notes 15 and 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Operating leases include drilling rigs, compressors, marine vessels, camps, office and buildings, certain land easements and various equipment utilized in the development and production of oil, NGLs and natural gas. Upon transition to ASC Topic 842 on January 1, 2019, The Bow office building was determined to be an operating lease. The Company has subleased approximately 50 percent of The Bow office space under the lease agreement. The Bow Office Building Sublease Recoveries in the table above include the amounts expected to be recovered from the sublease. Additional information on the change in accounting treatment for The Bow office building upon transition to ASC Topic 842 and subleases can be found in Notes 1 and 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Finance Leases relates to an office building and the obligation related to the Deep Panuke Production Field Centre. Additional information can be found in Note 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Risk Management Liabilities represents Ovintiv’s net liability position with counterparties. Additional information can be found in Note 25 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Asset Retirement Obligation represents estimated costs arising from the obligation to fund the disposal of long-lived assets upon their abandonment. The majority of Ovintiv’s asset retirement obligations relate to the plugging of wells and related abandonment of oil and gas properties including an offshore production platform, processing plants and land or seabed restoration. Revisions to estimated retirement obligations can result from changes in regulatory requirements, changes in retirement cost estimates, revisions to estimated inflation rates and estimated timing of abandonment. Additional information can be found in Note 17 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Transportation and Processing commitments relate to contractual obligations for capacity rights with third-party pipelines and processing facilities. Drilling and Field Services commitments represent minimum future expenditures for drilling, well servicing and equipment commitment rights. Significant development commitments with joint venture partners are partially satisfied by Commitments included in the table above. Building Leases consist of various field and office building leases used in Ovintiv’s daily operations. Drilling and Field Services, and Building Leases include short-term leases with terms less than 12 months and non-lease operating cost components. Additional information can be found in Notes 1 and 14 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

Ovintiv has two minimum volume sales contracts related to its Uinta oil production in Utah. Under the terms of the agreements, the Company is committed to deliver approximately 15 Mbbls/d through May 2020 and approximately 20 Mbbls/d through August 2025. During 2019, the Company incurred deficiency fees of approximately $24 million. Deficiency fees ranging from $3.50 to $6.50 per barrel may be incurred during the remaining term of the commitment periods. Based on forecasted production levels, $15 million in deficiency fees are expected to be incurred related to these delivery commitments in 2020. For additional information on these commitments, refer to the Marketing Activities section included in Items 1 and 2 of this Annual Report on Form 10-K.

Further to the commitments disclosed above, Ovintiv also has various obligations that become payable if certain events occur including variable interests arising from gathering and compression agreements and guarantees on transportation commitments resulting from completed property divestitures as described in Notes 20, 25 and 27, respectively, to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

In addition, Ovintiv has purchase orders for the purchase of inventory and other goods and services, which typically represent authorization to purchase rather than binding agreements. The Company also has obligations to fund its defined benefit pension and other post-employment benefit plans, as well as unrecognized tax benefits where the settlement is not expected within the next 12 months as described in Notes 23 and 6, respectively, to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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Ovintiv may have potential exposures related to previously divested properties where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on their solvency and ability to continue as a going concern. If a purchaser becomes the subject of a proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, Ovintiv could be required to perform such actions under applicable federal laws and regulations. While the Company believes that the risk of such event occurring is low, the Company could be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

Contingencies

For information on contingencies, refer to Note 27 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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Accounting Policies and Estimates

Critical Accounting Estimates

The preparation of financial statements in accordance with U.S. GAAP requires management to make informed judgments and estimates that affect the reported amounts of assets, liabilities, revenues, and expenses. For a discussion of the Company’s significant accounting policies refer to Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve judgment. The following discussion outlines the accounting policies and practices involving the use of estimates that are critical to determining Ovintiv’s financial results. Changes in the estimates and assumptions discussed below could materially affect the amount or timing of the financial results of the Company.

Description	Judgments and Uncertainties
Upstream Assets and Reserve Estimates As Ovintiv follows full cost accounting for oil, NGL and natural gas activities, reserves estimates are a key input to the Company’s depletion, gain or loss on divestitures and ceiling test impairment calculations. In addition, these reserves are the basis for the Company’s supplemental oil and gas disclosures.	Due to the inter-relationship of various judgments made to reserve estimates and the volatile nature of commodity prices, it is generally not possible to predict the timing or magnitude of ceiling test impairments.
Ovintiv estimates its proved oil and gas reserves according to the definition of proved reserves provided by the SEC. The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data and must demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods and government regulations. The estimation of reserves is a subjective process.	Revisions to reserve estimates are necessary due to changes in and among other things, development plans, projected future rates of production, the timing of future expenditures, reservoir performance, economic conditions, governmental restrictions as well as changes in the expected recovery associated with infill drilling, all of which are subject to numerous uncertainties and various interpretations. Downward revisions in proved reserve estimates due to changes in reserve estimates may increase depletion expense and may also result in a ceiling test impairment.
Reserves are calculated using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.	Decreases in prices may result in reductions in certain proved reserves due to reaching economic limits at an earlier projected date and impact earnings through depletion expense and ceiling test impairments.
Ovintiv manages its business using estimates of reserves and resources based on forecast prices and costs as it gives consideration to probable and possible reserves and future changes in commodity prices.	Ovintiv believes that the discounted after-tax future net cash flows from proved reserves required to be used in the ceiling test calculation are not indicative of the fair market value of Ovintiv’s oil and natural gas properties or the future net cash flows expected to be generated from such properties.
Business Combinations Ovintiv follows the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any deficiency of the purchase price over the estimated fair values of the net assets acquired is recorded as a gain in net earnings.	The most significant assumptions relate to the estimated fair values assigned to proved and unproved oil and natural gas properties. The assumptions made in performing these valuations include discount rates, future commodity prices and costs, the timing of development activities, projections of oil and gas reserves, estimates to abandon and reclaim producing wells and tax amortization benefits available to a market participant. Changes in key assumptions may cause the acquisition accounting to be revised, including the recognition of additional goodwill or discount on acquisition. There is no assurance the underlying assumptions or estimates associated with the valuation will occur as initially expected.
Fair value estimates are determined based on information that existed at the time of the acquisition, utilizing expectations and assumptions that would be available to and made by a market participant. When market-observable prices are not available to value assets and liabilities, the Company may use the cost, income, or market valuation approaches depending on the quality of information available to support management’s assumptions.	Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future through impairments of goodwill. In addition, differences between the future commodity prices when acquiring assets and the historical 12-month average trailing price to calculate ceiling test impairments of upstream assets may impact net earnings.

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Description	Judgments and Uncertainties
Goodwill Impairments Goodwill is assessed for impairment at least annually in December, at the reporting unit level which are Ovintiv’s country cost centres. To assess whether goodwill is impaired, the carrying amount of each reporting unit is determined and compared to the fair value of the reporting unit. If the carrying amount of the reporting unit is higher than its related fair value, then goodwill is measured and written down to the reporting unit’s implied fair value of goodwill. The implied fair value of goodwill is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit as if the reporting entity had been acquired in a business combination. Any excess of the carrying value of goodwill over the implied fair value of goodwill is recognized as an impairment and charged to net earnings.	The most significant assumptions used to determine a reporting unit’s fair value include estimations of oil and natural gas reserves, including both proved reserves and risk-adjusted unproved reserves, estimates of market prices considering forward commodity price curves as of the measurement date, market discount rates and estimates of operating, administrative, and capital costs adjusted for inflation. In addition, management may support fair value estimates determined with comparable companies that are actively traded in the public market, recent comparable asset transactions, and transaction premiums. This would require management to make certain judgments about the selection of comparable companies utilized.
Because quoted market prices for the Company’s reporting units are not available, management applies judgment in determining the estimated fair value of reporting units for purposes of performing goodwill impairment tests. Ovintiv may use a combination of the income and the market valuation approaches.	Downward revisions of estimated reserves quantities, increases in future cost estimates, sustained decreases in oil or natural gas prices, or divestiture of a significant component of the reporting unit could reduce expected future cash flows and fair value estimates of the reporting units and possibly result in an impairment of goodwill in future periods.
The Company has assessed its goodwill for impairment at December 31, 2019 and no impairment was recognized. The reporting units’ fair values were substantially in excess of the carrying values and as a result was not at risk of failing step one of the impairment test as at December 31, 2019.
Asset Retirement Obligation Asset retirement obligations are those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, an offshore production platform, processing plants, and restoring land or seabed at the end of oil and gas production operations. The fair value of estimated asset retirement obligations is recognized on the Consolidated Balance Sheet when incurred and a reasonable estimate of fair value can be made. The asset retirement cost, equal to the initially estimated fair value of the asset retirement obligation, is capitalized as part of the cost of the related long-lived asset. Changes in the estimated obligation are recognized as a change in the asset retirement obligation and the related asset retirement cost. Actual expenditures incurred are charged against the accumulated asset retirement obligation. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.	Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety, and public relations considerations. The asset retirement obligation is estimated by discounting the expected future cash flows of the settlement. The discounted cash flows are based on estimates of such factors as reserves lives, retirement costs, timing of settlements, credit-adjusted risk-free rates and inflation rates. Changes in these estimates impact net earnings through accretion of the asset retirement obligation in addition to depletion of the asset retirement cost included in property, plant and equipment.
Derivative Financial Instruments Ovintiv uses derivative financial instruments to manage its exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. The Company’s policy is not to utilize derivative financial instruments for speculative purposes. Realized gains or losses from financial derivatives are recognized in net earnings as the contracts are settled. Unrealized gains and losses are recognized in net earnings at the end of each respective reporting period based on the changes in fair value of the contracts.	Ovintiv’s derivative financial instruments primarily relate to commodities including oil, NGLs and natural gas. The most significant assumptions used in determining the fair value to the Company’s commodity derivatives financial instruments include estimates of future commodity prices, implied volatilities of commodity prices, discount rates and estimates of counterparty credit risk. These pricing and discounting variables are sensitive to the period of the contract and market volatility as well as regional price differentials. Changes in these estimates and assumptions can impact net earnings through decreased revenues or increased expenses.
Derivative financial instruments are measured at fair value with changes in fair value recognized in net earnings. Fair value estimates are determined using quoted prices in active markets, inferred based on market prices of similar assets and liabilities or valued using internally developed estimates. The Company may use various valuation techniques including the discounted cash flow or option valuation models. As Ovintiv has chosen not to elect hedge accounting treatment for the Company’s derivative financial instruments, changes in the fair values of derivative financial instruments can have a significant impact on Ovintiv’s results of operations. Generally, changes in fair values of derivative financial instruments do not impact the Company’s liquidity or capital resources. Settlements of derivative financial instruments do have an impact on the Company’s liquidity and results of operation.

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Description	Judgments and Uncertainties
Income Taxes Ovintiv follows the liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the enacted income tax rates and laws expected to apply when the assets are realized and liabilities are settled. Current income taxes are measured at the amount expected to be recoverable from or payable to the taxing authorities based on the income tax rates and laws enacted at the end of the reporting period. The effect of a change in the enacted tax rates or laws is recognized in net earnings in the period of enactment.	Tax interpretations, regulations and legislation, including U.S. Tax Reform, and potential Treasury Department regulations and guidance, in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and interpretation. As such, income taxes are subject to measurement uncertainty and the interpretations can impact net earnings through the income tax expense arising from the changes in deferred income tax assets or liabilities.
Deferred income tax assets are routinely assessed for realizability. If it is more likely than not that deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets.	Ovintiv considers available positive and negative evidence when assessing the realizability of deferred tax assets, including historic and expected future taxable earnings, available tax planning strategies and carry forward periods. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions, particularly related to oil and gas prices. As a result, the assumptions used in determining expected future taxable earnings are consistent with those used in the goodwill impairment assessment.
Ovintiv’s interim income tax expense is determined using an estimated annual effective income tax rate applied to year-to-date net earnings before income tax plus the effect of legislative changes and amounts in respect of prior periods.	The estimated annual effective income tax rate is impacted by expected annual earnings, statutory rate and other foreign differences, non-taxable capital gains and losses, tax differences on divestitures and transactions, and partnership tax allocations in excess of funding.
Ovintiv recognizes the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. A recognized tax position is initially and subsequently measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon settlement with a taxing authority. Liabilities for unrecognized tax benefits that are not expected to be settled within the next 12 months are included in other liabilities and provisions.	The Company routinely assesses potential uncertain tax positions and, if required, establishes accruals for such amounts. The accruals are adjusted based on changes in facts and circumstances. Material changes to Ovintiv’s income tax accruals may occur in the future based on the progress of ongoing audits, changes in legislation or resolution of pending matters.
The Company’s unremitted earnings from its foreign subsidiaries are considered to be permanently reinvested, as a result the Company does not calculate a deferred tax liability for domestic income taxes on these foreign earnings.	Determination of unrecognized deferred income tax liabilities is not practicable due to the significant uncertainty in assumptions that would be required including determining the nature of any future remittances, that could be distributions in the form of non-taxable returns of capital or taxable earnings and associated withholding taxes, or determining the tax rates on any future remittances that could vary significantly depending on the available approaches to repatriate the earnings.
Contingent Liabilities Ovintiv is subject to various legal proceedings, environmental remediation, commercial and regulatory claims and liabilities that arise in the ordinary course of business. The Company accrues losses when such losses are probable and reasonably estimable, except for contingencies acquired in a business combination which are recorded at fair value at the time of the acquisition. If a loss is probable but the Company cannot estimate a specific amount for that loss, the best estimate within the range is accrued and if no amount is better within the range, the minimum amount is accrued.	The establishment and evaluation of a contingent loss is based on advice from legal counsel, advisors or consultants and management’s judgement. Actual costs can vary from such estimates for various reasons including: i) differing interpretation of the law, opinions on responsibility and assessments on the amount of damages; ii) changes in status of litigation or claims and information available; iii) differing interpretation of regulations by regulators or the courts; iv) changes in laws and regulations; and v) additional or developing information relating to extent and nature of environmental remediation and technology improvements. The Company continually monitors known and potential legal, environmental and other claims or contingencies based on available information.  Future changes in facts and circumstances not currently foreseeable could result in the actual liabilities recorded exceeding the estimated amounts accrued.

Recent Accounting Pronouncements

For recently issued accounting policies, refer to Note 1 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.

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Non-GAAP Measures

Certain measures in this document do not have any standardized meaning as prescribed by U.S. GAAP and, therefore, are considered non-GAAP measures. These measures may not be comparable to similar measures presented by other issuers and should not be viewed as a substitute for measures reported under U.S. GAAP. These measures are commonly used in the oil and gas industry and by Ovintiv to provide shareholders and potential investors with additional information regarding the Company’s liquidity and its ability to generate funds to finance its operations. Non-GAAP measures include: Non-GAAP Cash Flow, Non-GAAP Cash Flow Margin, Total Costs, Debt to Adjusted Capitalization and Net Debt to Adjusted EBITDA. Management’s use of these measures is discussed further below.

Non-GAAP Cash Flow and Non-GAAP Cash Flow Margin

Non-GAAP Cash Flow is a non-GAAP measure defined as cash from (used in) operating activities excluding net change in other assets and liabilities, net change in non-cash working capital and current tax on sale of assets.

Non-GAAP Cash Flow Margin is a non-GAAP measure defined as Non-GAAP Cash Flow per BOE of production.

Management believes these measures are useful to the Company and its investors as a measure of operating and financial performance across periods and against other companies in the industry, and are an indication of the Company’s ability to generate cash to finance capital programs, to service debt and to meet other financial obligations. These measures are used, along with other measures, in the calculation of certain performance targets for the Company’s management and employees.

($ millions, except as indicated)	2019			2018
Cash From (Used in) Operating Activities	$	2,921		$	2,300
(Add back) deduct:
Net change in other assets and liabilities		(97	)		(60	)
Net change in non-cash working capital		87			245
Current tax on sale of assets		-			-
Non-GAAP Cash Flow (1)	$	2,931		$	2,115
Production Volumes (MMBOE)		206.2			131.8
Non-GAAP Cash Flow Margin ($/BOE)	$	14.21		$	16.05

(1) 2019 includes restructuring costs of $138 million and acquisition costs of $33 million.

Total Costs

Total Costs is a non-GAAP measure defined as the summation of production, mineral and other taxes, upstream transportation and processing expense, upstream operating expense and administrative expense, excluding the impact of long-term incentive and restructuring costs. Management believes this measure is useful to the Company and its investors as a measure of operational efficiency across periods.

($ millions, except as indicated)	2019		2018
Production, Mineral and Other Taxes	$	254	$	147
Upstream Transportation and Processing		1,325		952
Upstream Operating		707		423
Administrative		489		157
Deduct (add back):
Long-term incentive costs		35		(41	)
Restructuring costs		138		-
Total Costs	$	2,602	$	1,720
Divided by:
Production Volumes (MMBOE)		206.2		131.8
Total Costs ($/BOE) (1)	$	12.59	$	13.00

(1) Calculated using whole dollars and volumes.

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Debt to Adjusted Capitalization

Debt to Adjusted Capitalization is a non-GAAP measure which adjusts capitalization for historical ceiling test impairments that were recorded as at December 31, 2011. Management monitors Debt to Adjusted Capitalization as a proxy for the Company’s financial covenant under the Credit Facilities which require debt to adjusted capitalization to be less than 60 percent. Adjusted Capitalization includes debt, total shareholders’ equity and an equity adjustment for cumulative historical ceiling test impairments recorded as at December 31, 2011 in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP.

($ millions, except as indicated)	December 31, 2019		December 31, 2018
Long-Term Debt, including current portion	$	6,974	$	4,198
Total Shareholders’ Equity		9,930		7,447
Equity Adjustment for Impairments at December 31, 2011		7,746		7,746
Adjusted Capitalization	$	24,650	$	19,391
Debt to Adjusted Capitalization	28%		22%

The increase in Debt to Adjusted Capitalization is primarily due to the increase in long-term debt resulting from the Newfield acquisition.

Net Debt to Adjusted EBITDA

Net Debt to Adjusted EBITDA is a non-GAAP measure whereby Net Debt is defined as long-term debt, including the current portion, less cash and cash equivalents and Adjusted EBITDA is defined as trailing 12-month net earnings (loss) before income taxes, DD&A, impairments, accretion of asset retirement obligation, interest, unrealized gains/losses on risk management, foreign exchange gains/losses, gains/losses on divestitures and other gains/losses.

Management believes this measure is useful to the Company and its investors as a measure of financial leverage and the Company’s ability to service its debt and other financial obligations. This measure is used, along with other measures, in the calculation of certain financial performance targets for the Company’s management and employees.

($ millions, except as indicated)	December 31, 2019			December 31, 2018
Long-Term Debt, including current portion	$	6,974		$	4,198
Less:
Cash and cash equivalents		190			1,058
Net Debt		6,784			3,140
Net Earnings		234			1,069
Add back (deduct):
Depreciation, depletion and amortization		2,015			1,272
Accretion of asset retirement obligation		37			32
Interest		382			351
Unrealized (gains) losses on risk management		730			(519	)
Foreign exchange (gain) loss, net		(119	)		168
(Gain) loss on divestitures, net		(3	)		(5	)
Other (gains) losses, net		23			17
Income tax expense (recovery)		81			94
Adjusted EBITDA	$	3,380		$	2,479
Net Debt to Adjusted EBITDA (times)		2.0			1.3

The increase in Net Debt is primarily due to the increase in long-term debt resulting from the Newfield acquisition, whereas Adjusted EBITDA only includes Newfield’s results of operations for the post-acquisition period from February 14, 2019 to December 31, 2019.

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Item 7A: Quantitative and Qualitative Disclosures About Market Risk

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about the Company’s potential exposure to market risks. The term “market risk” refers to the Company’s risk of loss arising from adverse changes in oil, NGL and natural gas prices, foreign currency exchange rates and interest rates. The following disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably possible losses. The forward-looking information provides indicators of how the Company views and manages ongoing market risk exposures.  

COMMODITY PRICE RISK

Commodity price risk arises from the effect fluctuations in future commodity prices, including oil, NGLs and natural gas, may have on future revenues, expenses and cash flows. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to the Company’s natural gas production. Pricing for oil and natural gas production is volatile and unpredictable as discussed in Item 1A. “Risk Factors” of this Annual Report on Form 10-K. To partially mitigate exposure to commodity price risk, the Company may enter into various derivative financial instruments including futures, forwards, swaps, options and costless collars. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors and may vary from time to time. Both exchange traded and over-the-counter traded derivative instruments may be subject to margin-deposit requirements, and the Company may be required from time to time to deposit cash or provide letters of credit with exchange brokers or counterparties to satisfy these margin requirements. For additional information relating to the Company’s derivative and financial instruments, see Note 25 under Item 8 of this Annual Report on Form 10-K.

The table below summarizes the sensitivity of the fair value of the Company’s risk management positions to fluctuations in commodity prices, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact of commodity price changes. Fluctuations in commodity prices could have resulted in unrealized gains (losses) impacting pre-tax net earnings as follows:

	December 31, 2019
	10% Price			10% Price
(US$ millions)	Increase			Decrease
Crude oil price	$	(280	)	$	257
NGL price		(19	)		19
Natural gas price		(71	)		59

FOREIGN EXCHANGE RISK

Foreign exchange risk arises from changes in foreign exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. As the Company operates in the United States and Canada, fluctuations in the exchange rate between the U.S. and Canadian dollars can have a significant effect on the Company’s reported results. Although the Company’s financial results for the year ended December 31, 2019 are consolidated in Canadian dollars, the Company reports its results in U.S. dollars as most of its revenues are closely tied to the U.S. dollar and to facilitate a more direct comparison to other North American oil and gas companies.

Following the Reorganization, including the U.S. Domestication, the functional currency of Ovintiv Inc. became U.S. dollars, and accordingly, the financial results will be consolidated and reported in U.S. dollars.

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The table below summarizes selected foreign exchange impacts on the Company’s financial results when compared to the same periods in the prior years.

	2019							2018
	$ millions				$/BOE			$ millions				$/BOE
Increase (Decrease) in:
Capital Investment		$	(17	)					$	(3	)
Transportation and Processing Expense (1)			(18	)	$	(0.09	)			(1	)		$	(0.01	)
Operating Expense (1)			(3	)		(0.01	)			-				-
Administrative Expense			(4	)		(0.02	)			(2	)			(0.01	)
Depreciation, Depletion and Amortization (1)			(8	)		(0.04	)			-				-

(1) Reflects upstream operations.

Foreign exchange gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated and settled, and primarily include:

• U.S. dollar denominated financing debt issued from Canada

• U.S. dollar denominated risk management assets and liabilities held in Canada

• U.S. dollar denominated cash and short-term investments held in Canada

• Foreign denominated intercompany loans

To partially mitigate the effect of foreign exchange fluctuations on future commodity revenues and expenses, the Company may enter into foreign currency derivative contracts. As at December 31, 2019, the Company has entered into $425 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7483 to C$1, which mature monthly throughout 2020.

As at December 31, 2019, the Company had $4.4 billion in U.S. dollar long-term debt and $160 million in U.S. dollar finance lease obligations issued from Canada that were subject to foreign exchange exposure.

The table below summarizes the sensitivity to foreign exchange rate fluctuations, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact from Canadian to U.S. foreign currency exchange rate changes. Fluctuations in foreign currency exchange rates could have resulted in unrealized gains (losses) impacting pre-tax net earnings as follows:

	December 31, 2019
(US$ millions)	10% Rate Increase			10% Rate Decrease
Foreign currency exchange	$	(226	)	$	277

INTEREST RATE RISK

Interest rate risk arises from changes in market interest rates that may affect the fair value or future cash flows from the Company’s financial assets or liabilities. The Company may partially mitigate its exposure to interest rate changes by holding a mix of both fixed and floating rate debt and may also enter into interest rate derivatives to partially mitigate effects of fluctuations in market interest rates.

As at December 31, 2019, the Company had floating rate debt of $698 million. Accordingly, the sensitivity in net earnings for each one percent change in interest rates on floating rate debt was $5 million (2018 - nil).

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Item 8: Financial Statements and Supplementary Data

Management Report

Management’s Responsibility for Consolidated Financial Statements

The accompanying Consolidated Financial Statements of the Company are the responsibility of Management. The Consolidated Financial Statements have been prepared by Management in United States dollars in accordance with generally accepted accounting principles in the United States and include certain estimates that reflect Management’s best judgments.

Ovintiv’s Board of Directors has approved the information contained in the Consolidated Financial Statements. The Board of Directors fulfills its responsibility regarding the financial statements mainly through its Audit Committee, which has a written mandate that complies with the requirements of Canadian and United States securities legislation and the Audit Committee guidelines of the New York Stock Exchange. The Audit Committee meets at least on a quarterly basis.

Management’s Assessment of Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over the Company’s financial reporting. The internal control system was designed to provide reasonable assurance to the Company’s Management regarding the preparation and presentation of the Consolidated Financial Statements.

Internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management has assessed the design and effectiveness of the Company’s internal control over financial reporting as at December 31, 2019. In making its assessment, Management has used the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission to evaluate the effectiveness of the Company’s internal control over financial reporting. Based on our evaluation, Management has concluded that the Company’s internal control over financial reporting was effective as at that date.  

PricewaterhouseCoopers LLP, an independent firm of chartered professional accountants, was appointed by a vote of shareholders at the Company’s last annual meeting to audit and provide independent opinions on both the Consolidated Financial Statements and the Company’s internal control over financial reporting as at December 31, 2019, as stated in their Auditor’s Report. PricewaterhouseCoopers LLP has provided such opinions.

/s/ Douglas J. Suttles Douglas J. Suttles Chief Executive Officer   February 21, 2020 /s/ Corey D. Code Corey D. Code Executive Vice-President & Chief Financial Officer

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Auditor’s Report

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of Ovintiv Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying Consolidated Balance Sheets of Ovintiv Inc. (successor issuer to Encana Corporation) and its subsidiaries (collectively, the “Company”) as of December 31, 2019 and 2018, and the related Consolidated Statements of Earnings, Comprehensive Income, Changes in Shareholders’ Equity and Cash Flows for each of the three years in the period ended December 31, 2019, including the related notes (collectively referred to as the “Consolidated Financial Statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

In our opinion, the Consolidated Financial Statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO.

Change in Accounting Principle

As discussed in Note 1 to the Consolidated Financial Statements, the Company changed the manner in which it accounts for leases in 2019 due to the adoption of ASC Topic 842, Leases.

Basis for Opinions

The Company's management is responsible for these Consolidated Financial Statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Assessment of Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s Consolidated Financial Statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission (“SEC”) and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Consolidated Financial Statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the Consolidated Financial Statements included performing procedures to assess the risks of material misstatement of the Consolidated Financial Statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the Consolidated Financial Statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the Consolidated Financial Statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the Consolidated Financial Statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the Consolidated Financial Statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the Consolidated Financial Statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The impact of estimates of proved oil, Natural Gas Liquids (“NGL”) and natural gas reserves on net oil and natural gas proved properties

As described in Notes 1 and 10 to the Consolidated Financial Statements, the Company has net oil and natural gas proved properties balance of $11,211 million at December 31, 2019 and depreciation, depletion, and amortization (“DD&A”) expense of $2,015 million for the year ended December 31, 2019. The Company uses the full cost method of accounting for its acquisition, exploration, and development activities. Capitalized costs accumulated within each cost centre are depleted using the unit-of-production method based on proved oil, NGL and natural gas reserves. Proved oil, NGL and natural gas reserve estimates are key inputs to the Company’s depletion and ceiling test impairment calculations. A ceiling test impairment is recognized in net earnings when the carrying amount of a country cost centre exceeds the country cost centre ceiling. Management estimates its proved oil, NGL and natural gas reserves according to the definition of proved reserves provided by the SEC. Management’s estimates of proved oil, NGL and natural gas reserves are made using available geological and reservoir data as well as production performance data. Proved oil, NGL and natural gas reserves are those quantities of oil and natural gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods and government regulations. The assumptions used by management to determine estimates of the proved oil, NGL and natural gas reserves and the ceiling test impairment calculation include the average beginning-of-the-month prices during the 12-month period for the year, future production estimates, future production and development costs and estimates for abandonment and dismantlement costs associated with asset retirement obligations. The estimation of reserves is a subjective process. In determining the estimates of the proved oil, NGL and natural gas reserves, management utilizes the services of specialists, specifically petroleum engineers.  

The principal considerations for our determination that performing procedures relating to the impact of estimates of proved oil, NGL and natural gas reserves on net oil and natural gas proved properties is a critical audit matter are that there was significant judgment used by management, including the use of specialists, when developing the estimates of the proved oil, NGL and natural gas reserves and performing the ceiling test impairment calculation, which in turn led to a high degree of auditor judgment, effort and subjectivity in performing procedures to evaluate the significant assumptions used in developing those estimates including the average beginning-of-the-month prices

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during the 12-month period for the year, future production estimates, future production and development costs and estimates for abandonment and dismantlement costs associated with asset retirement obligations.  

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil, NGL and natural gas reserves, the country cost centre ceiling and DD&A expense. These procedures also included, among others, evaluating management’s impairment calculation and testing the unit-of-production rate used to calculate depletion expense, testing the completeness, accuracy and relevance of underlying data and evaluating the appropriateness of the significant assumptions used by management in developing these estimates, including assumptions related to the average beginning-of-the-month prices during the 12-month period for the year, future production estimates, future production and development costs, and estimates for abandonment and dismantlement costs associated with asset retirement obligations. The work of management’s specialists was used in performing procedures to evaluate the reasonableness of the estimates of proved oil, NGL and natural gas reserves. As a basis for using this work, the specialists’ qualifications and objectivity were understood, as well as their methods and assumptions. The procedures also included testing of data used by the specialist and an evaluation of their findings. Evaluating the significant assumptions also involved evaluating whether the assumptions used were reasonable considering the past performance of the Company and whether they were consistent with evidence obtained in other areas of the audit.

Valuation of proved and unproved properties - Acquisition of Newfield Exploration Company (“Newfield”)

As described in Notes 1 and 8 to the Consolidated Financial Statements, on February 13, 2019 the Company completed the acquisition of the issued and outstanding common stock of Newfield. The transaction was accounted for under the acquisition method, which requires that the assets acquired, and the liabilities assumed be recognized at their fair values as of the acquisition date, with any excess of the purchase price over the estimated fair value of the net assets acquired recorded as goodwill. The purchase price of the transaction was for net consideration of $3,483 million. The assets acquired included the proved properties and unproved properties which were valued at $5,903 million and $838 million, respectively. Management estimated the fair value of the proved and unproved properties using a discounted cash flow model. Management applied significant judgement in estimating the proved and probable reserves and the fair value of the proved and unproved properties acquired, which involved the use of significant estimates and assumptions as applicable which includes discount rates, future commodity prices and costs, the timing of development activities, projections of oil, NGL and natural gas reserves and estimates to abandon and reclaim producing wells. In determining the estimates of the proved and probable oil, NGL and natural gas reserves, management utilizes the services of specialists, specifically petroleum engineers.

The principal considerations for our determination that performing procedures relating to the valuation of proved and unproved properties in the acquisition of Newfield is a critical audit matter are that there was a significant amount of judgement required by management, including the use of specialists, when developing the estimates of proved and probable oil, NGL and natural gas reserves and the fair value measurement of proved and unproved properties acquired. This led to a high degree of auditor judgment and effort in evaluating the relevant assumptions relating to the estimates, such as the discount rates, future commodity prices and costs, the timing of development activities, projections of oil, NGL and natural gas reserves and estimates to abandon and reclaim producing wells. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in evaluating the audit evidence obtained.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the Consolidated Financial Statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuation of the proved and unproved properties and controls over the development of the assumptions used in this valuation.  These procedures also included, among others, reading the purchase agreement, testing management’s process for estimating the fair value of the proved and unproved properties, using professionals with specialized skill and knowledge to assist in doing so. Testing management’s process included testing the completeness, accuracy and relevance of underlying data used in management’s discounted cash flow model, the appropriateness of the discounted cash flow model and evaluating the reasonableness of the discount rates used in the discounted cash flow model by considering the cost of capital of comparable businesses and the implied discount rates of other market transactions.  Assessing the reasonableness of the assumptions related to the estimates included evaluating the future commodity prices by comparing to other third-party pricing forecasts, and evaluating future costs, the timing of development activities,

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projections of oil, NGL and natural gas reserves and estimates to abandon and reclaim producing wells to a market participant by considering the past performance of the properties and evaluating the reasonableness of the fair value based on the fair value of other comparable acquired businesses. The work of management’s specialists was used in performing procedures to evaluate the reasonableness of the estimates of proved and probable oil, NGL and natural gas reserves. As a basis for using this work, the specialists’ qualifications and objectivity were understood, as well as their methods and assumptions. The procedures also included testing of data used by the specialist and an evaluation of their findings.

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants

Calgary, Canada

February 21, 2020

We have served as the Company’s or its predecessors’ auditor since 1958.

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Consolidated Statement of Earnings

For the years ended December 31 (US$ millions, except per share amounts)		2019			2018			2017
Revenues	(Notes 2, 3)
Product and service revenues		$	7,013		$	5,457		$	3,892
Gains (losses) on risk management, net	(Note 25)		(361	)		415			482
Sublease revenues			74			67			69
Total Revenues			6,726			5,939			4,443
Operating Expenses	(Note 2)
Production, mineral and other taxes			254			147			112
Transportation and processing	(Notes 14, 25)		1,558			1,083			845
Operating	(Notes 14, 22, 23)		732			454			506
Purchased product			1,043			1,100			788
Depreciation, depletion and amortization			2,015			1,272			833
Accretion of asset retirement obligation	(Note 17)		37			32			37
Administrative	(Notes 14, 21, 22, 23)		489			157			254
Total Operating Expenses			6,128			4,245			3,375
Operating Income (Loss)			598			1,694			1,068
Other (Income) Expenses
Interest	(Notes 4, 15)		382			351			363
Foreign exchange (gain) loss, net	(Notes 5, 25)		(119	)		168			(279	)
(Gain) loss on divestitures, net	(Note 9)		(3	)		(5	)		(404	)
Other (gains) losses, net	(Notes 8, 23)		23			17			(42	)
Total Other (Income) Expenses			283			531			(362	)
Net Earnings (Loss) Before Income Tax			315			1,163			1,430
Income tax expense (recovery)	(Note 6)		81			94			603
Net Earnings (Loss)		$	234		$	1,069		$	827
Net Earnings (Loss) per Common Share (1)
Basic & Diluted	(Note 18)	$	0.90		$	5.57		$	4.25
Weighted Average Common Shares Outstanding (millions) (1)
Basic & Diluted	(Note 18)		261.2			192.0			194.6

(1) Net earnings (loss) per common share and weighted average common shares outstanding reflect the Share Consolidation as described in Note 1. Accordingly, the comparative periods have been restated.

Consolidated Statement of Comprehensive Income

For the years ended December 31 (US$ millions)		2019		2018			2017
Net Earnings (Loss)		$	234	$	1,069		$	827
Other Comprehensive Income (Loss), Net of Tax
Foreign currency translation adjustment	(Note 19)		28		(53	)		(171	)
Pension and other post-employment benefit plans	(Notes 19, 23)		20		9			3
Other Comprehensive Income (Loss)			48		(44	)		(168	)
Comprehensive Income (Loss)		$	282	$	1,025		$	659

See accompanying Notes to Consolidated Financial Statements

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Consolidated Balance Sheet

As at December 31 (US$ millions)			2019			2018
Assets
Current Assets
Cash and cash equivalents			$	190		$	1,058
Accounts receivable and accrued revenues		(Note 7)		1,235			789
Risk management	(Notes 24, 25)			148			554
Income tax receivable				296			275
				1,869			2,676
Property, Plant and Equipment, at cost:		(Note 10)
Oil and natural gas properties, based on full cost accounting
Proved properties				51,210			41,241
Unproved properties				3,714			3,730
Other		(Note 1)		904			2,122
Property, plant and equipment				55,828			47,093
Less: Accumulated depreciation, depletion and amortization				(40,637	)		(38,121	)
Property, plant and equipment, net		(Note 2)		15,191			8,972
Other Assets	(Notes 1, 10, 11, 14)			1,213			147
Risk Management	(Notes 24, 25)			2			161
Deferred Income Taxes		(Note 6)		601			835
Goodwill	(Notes 2, 8, 12)			2,611			2,553
		(Note 2)	$	21,487		$	15,344
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities		(Note 13)	$	2,239		$	1,490
Current portion of operating lease liabilities	(Notes 1, 14)			78			-
Income tax payable				1			1
Risk management	(Notes 24, 25)			114			25
Current portion of long-term debt		(Note 15)		-			500
				2,432			2,016
Long-Term Debt		(Note 15)		6,974			3,698
Operating Lease Liabilities	(Notes 1, 14)			977			-
Other Liabilities and Provisions	(Notes 1, 14, 16)			464			1,769
Risk Management	(Notes 24, 25)			68			22
Asset Retirement Obligation		(Note 17)		425			365
Deferred Income Taxes		(Note 6)		217			27
				11,557			7,897
Commitments and Contingencies		(Note 27)
Shareholders’ Equity
Share capital   2019 issued and outstanding: 259.8 million shares (2018: 190.5 million shares) (1)		(Note 18)		7,061			4,656
Paid in surplus		(Note 18)		1,402			1,358
Retained earnings				421			435
Accumulated other comprehensive income		(Note 19)		1,046			998
Total Shareholders’ Equity				9,930			7,447
			$	21,487		$	15,344

(1) Common shares outstanding, for the current and prior period, reflect the Share Consolidation as described in Note 1.

See accompanying Notes to Consolidated Financial Statements

Approved by the Board of Directors
/s/ Clayton H. Woitas	/s/ Bruce G. Waterman
Clayton H. Woitas	Bruce G. Waterman
Director	Director

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Consolidated Statement of Changes in Shareholders’ Equity

											Accumulated
											Other		Total
			Share			Paid in		Retained			Comprehensive		Shareholders’
For the year ended December 31, 2019 (US$ millions)			Capital			Surplus		Earnings			Income		Equity
Balance, December 31, 2018			$	4,656		$	1,358	$	435		$	998	$	7,447
Net Earnings (Loss)				-			-		234			-		234
Dividends on Common Shares ($0.375 per share (1))		(Note 18)		-			-		(102	)		-		(102	)
Common Shares Purchased under Substantial Issuer Bid		(Note 18)		(257	)		44		-			-		(213	)
Common Shares Purchased under Normal     Course Issuer Bid		(Note 18)		(816	)		-		(221	)		-		(1,037	)
Common Shares Issued	(Notes 8, 18)			3,478			-		-			-		3,478
Other Comprehensive Income (Loss)		(Note 19)		-			-		-			48		48
Impact of Adoption of Topic 842		(Note 1)		-			-		75			-		75
Balance, December 31, 2019			$	7,061		$	1,402	$	421		$	1,046	$	9,930

							Retained			Accumulated
							Earnings			Other			Total
		Share			Paid in		(Accumulated			Comprehensive			Shareholders’
For the year ended December 31, 2018 (US$ millions)		Capital			Surplus		Deficit)			Income			Equity
Balance, December 31, 2017		$	4,757		$	1,358	$	(429	)	$	1,042		$	6,728
Net Earnings (Loss)			-			-		1,069			-			1,069
Dividends on Common Shares ($0.30 per share (1))	(Note 18)		-			-		(57	)		-			(57	)
Common Shares Purchased under Normal     Course Issuer Bid	(Note 18)		(102	)		-		(148	)		-			(250	)
Common Shares Issued Under     Dividend Reinvestment Plan	(Note 18)		1			-		-			-			1
Other Comprehensive Income (Loss)	(Note 19)		-			-		-			(44	)		(44	)
Balance, December 31, 2018		$	4,656		$	1,358	$	435		$	998		$	7,447

						Retained			Accumulated
						Earnings			Other			Total
		Share		Paid in		(Accumulated			Comprehensive			Shareholders’
For the year ended December 31, 2017 (US$ millions)		Capital		Surplus		Deficit)			Income			Equity
Balance, December 31, 2016		$	4,756	$	1,358	$	(1,198	)	$	1,210		$	6,126
Net Earnings (Loss)			-		-		827			-			827
Dividends on Common Shares ($0.30 per share (1))	(Note 18)		-		-		(58	)		-			(58	)
Common Shares Issued Under     Dividend Reinvestment Plan	(Note 18)		1		-		-			-			1
Other Comprehensive Income (Loss)	(Note 19)		-		-		-			(168	)		(168	)
Balance, December 31, 2017		$	4,757	$	1,358	$	(429	)	$	1,042		$	6,728

(1) Dividends per share reflect the Share Consolidation as described in Note 1. On a pre-Share Consolidation basis, dividends were $0.075 per share for the year ended December 31, 2019 (2018 - $0.06 per share; 2017 - $0.06 per share).

See accompanying Notes to Consolidated Financial Statements

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Consolidated Statement of Cash Flows

For the years ended December 31 (US$ millions)		2019			2018			2017
Operating Activities
Net earnings (loss)		$	234		$	1,069		$	827
Depreciation, depletion and amortization			2,015			1,272			833
Accretion of asset retirement obligation	(Note 17)		37			32			37
Deferred income taxes	(Note 6)		94			149			666
Unrealized (gain) loss on risk management	(Note 25)		730			(519	)		(442	)
Unrealized foreign exchange (gain) loss	(Note 5)		(23	)		233			(291	)
Foreign exchange on settlements	(Note 5)		(96	)		(46	)		24
(Gain) loss on divestitures, net	(Note 9)		(3	)		(5	)		(404	)
Other			(57	)		(70	)		93
Net change in other assets and liabilities			(97	)		(60	)		(40	)
Net change in non-cash working capital	(Note 26)		87			245			(253	)
Cash From (Used in) Operating Activities			2,921			2,300			1,050
Investing Activities
Capital expenditures	(Note 2)		(2,626	)		(1,975	)		(1,796	)
Acquisitions	(Note 9)		(65	)		(17	)		(54	)
Corporate acquisition, net of cash and restricted cash acquired	(Note 8)		94			-			-
Proceeds from divestitures	(Note 9)		197			493			736
Net change in investments and other			(156	)		(56	)		77
Cash From (Used in) Investing Activities			(2,556	)		(1,555	)		(1,037	)
Financing Activities
Net issuance (repayment) of revolving long-term debt	(Note 15)		698			-			-
Repayment of long-term debt	(Note 15)		(500	)		-			-
Purchase of common shares	(Note 18)		(1,250	)		(250	)		-
Dividends on common shares	(Note 18)		(102	)		(56	)		(57	)
Finance lease payments and other financing arrangements	(Note 14)		(84	)		(90	)		(82	)
Cash From (Used in) Financing Activities			(1,238	)		(396	)		(139	)
Foreign Exchange Gain (Loss) on Cash, Cash Equivalents
and Restricted Cash Held in Foreign Currency			5			(10	)		11
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash			(868	)		339			(115	)
Cash, Cash Equivalents and Restricted Cash, Beginning of Year			1,058			719			834
Cash, Cash Equivalents and Restricted Cash, End of Year		$	190		$	1,058		$	719
Cash, End of Year		$	44		$	52		$	51
Cash Equivalents, End of Year			146			1,006			668
Restricted Cash, End of Year			-			-			-
Cash, Cash Equivalents and Restricted Cash, End of Year		$	190		$	1,058		$	719
Supplementary Cash Flow Information	(Note 26)

See accompanying Notes to Consolidated Financial Statements

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1. Summary of Significant Accounting Policies

A) NATURE OF OPERATIONS

On January 24, 2020, Encana Corporation (“Encana”) completed a corporate reorganization, which included a plan of arrangement (the “Arrangement”) that involved, among other things, a share consolidation by Encana on the basis of one post-consolidation share for each five pre-consolidation shares (the “Share Consolidation”), and Ovintiv Inc. ultimately acquired all of the issued and outstanding common shares of Encana in exchange for shares of common stock of Ovintiv Inc. on a one-for-one basis. Following completion of the Arrangement, Ovintiv Inc. migrated from Canada and became a Delaware corporation, domiciled in the U.S. (the “U.S. Domestication”). The Arrangement and the U.S. Domestication together are referred to as the “Reorganization”. Ovintiv Inc. and its subsidiaries (collectively, “Ovintiv”) continue to carry on the business of the exploration for, the development of, and the production and marketing of oil, NGLs and natural gas, which was previously conducted by Encana and its subsidiaries prior to the completion of the Reorganization. References to the “Company” are to Encana Corporation and its subsidiaries prior to the completion of the Reorganization and to Ovintiv Inc. and its subsidiaries following the completion of the Reorganization.

B) BASIS OF PRESENTATION

The Consolidated Financial Statements include the accounts of the Company and are presented in conformity with U.S. GAAP and the rules and regulations of the SEC.

In these Consolidated Financial Statements, unless otherwise indicated, all dollar amounts are expressed in U.S. dollars. The Company’s financial results are consolidated in Canadian dollars; however, the Company has adopted the U.S. dollar as its reporting currency to facilitate a more direct comparison to other North American oil and gas companies. All references to US$ or to $ are to United States dollars and references to C$ are to Canadian dollars.

The Arrangement, as described above, will be accounted for as a reorganization of entities under common control. Accordingly, the resulting transactions will be recognized using historical carrying amounts. On January 24, 2020, Ovintiv became the reporting entity upon completion of the Reorganization.

As the Share Consolidation described above was completed prior to the issuance of these Consolidated Financial Statements, common shares and per-share amounts disclosed herein reflect the post-Share Consolidation shares unless otherwise specified.

Following the U.S. Domestication, on January 24, 2020, the functional currency of Ovintiv Inc. became U.S. dollars, and accordingly, the financial results will be consolidated and reported in U.S. dollars.

C) PRINCIPLES OF CONSOLIDATION

The Consolidated Financial Statements include the accounts of the Company and entities in which it holds a controlling interest. All intercompany balances and transactions are eliminated on consolidation. Undivided interests in oil and natural gas exploration and production joint ventures and partnerships are consolidated on a proportionate basis. Investments in non-controlled entities over which the Company has the ability to exercise significant influence are accounted for using the equity method.

D) FOREIGN CURRENCY TRANSLATION

Monetary assets and liabilities of the Company that are denominated in foreign currencies are translated at the rates of exchange in effect at the period end date. Any gains or losses are recorded in the Consolidated Statement of Earnings. Foreign currency revenues and expenses are translated at the rates of exchange in effect at the time of the transaction.  

Assets and liabilities of foreign operations are translated at period end exchange rates, while the related revenues and expenses are translated using average rates during the period. Translation gains and losses relating to foreign operations are included in accumulated other comprehensive income (“AOCI”). Recognition of accumulated translation gains and losses into net earnings occurs upon complete or substantially complete liquidation of the Company’s investment in the foreign operation.

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For financial statement presentation, assets and liabilities are translated into the reporting currency at period end exchange rates, while revenues and expenses are translated using average rates over the period. Gains and losses relating to the financial statement translation are included in AOCI. Following the U.S. Domestication, the functional currency of Ovintiv Inc. became U.S. dollars, and accordingly, the financial results will be consolidated and reported in U.S. dollars.

E) USE OF ESTIMATES

Preparation of the Consolidated Financial Statements in conformity with U.S. GAAP requires Management to make informed estimates and assumptions and use judgments that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the period. Such estimates primarily relate to unsettled transactions and events as of the date of the Consolidated Financial Statements. Accordingly, actual results may differ from estimated amounts as future events occur.

Significant items subject to estimates and assumptions are:

• Estimates of proved reserves used for depletion and ceiling test impairment calculations

• Estimated fair value of long-term assets used for impairment calculations

• Fair value of reporting units used for the assessment of goodwill

• Estimates of future taxable earnings used to assess the realizable value of deferred tax assets

• Estimates of incremental borrowing rates and lease terms used in the measurement of right-of-use (“ROU”) assets and lease liabilities

• Fair value of asset retirement costs and related obligations

• Fair value of derivative instruments

• Fair value attributed to assets acquired and liabilities assumed in business combinations

• Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate

• Accruals for long-term performance-based compensation arrangements, including whether or not the performance criteria will be met and measurement of the ultimate payout amount

• Recognized values of pension assets and obligations, as well as the pension costs charged to net earnings, depend on certain actuarial and economic assumptions

• Accruals for legal claims, environmental risks and exposures

F) REVENUES FROM CONTRACTS WITH CUSTOMERS

Revenues from contracts with customers associated with the Company’s oil, NGLs and natural gas and third party processing and gathering are recognized when control of the good or service is transferred to the customer, and title or risk of loss transfers to the customer. Transaction prices are determined at inception of the contract and allocated to the performance obligations identified. Variable consideration is estimated and included in the transaction price, unless the variable consideration is constrained.

For product sales, the performance obligations are satisfied at a point in time when the product is delivered to the customer and control is transferred. Payment from the customer is due when the product is delivered to the custody point. Revenues for product sales are presented on an after-royalties basis. For arrangements to gather and process natural gas for third parties, performance obligations are satisfied over time as the service is provided to the customer. Payment from the customer is due when the customer receives the benefit of the service and the product is delivered to the custody point or plant tailgate. Revenues associated with services provided where the Company acts as agent are recorded on a net basis.

G) PRODUCTION, MINERAL AND OTHER TAXES

Costs paid by the Company for taxes based on production or revenues from oil, NGLs and natural gas are recognized when the product is produced. Costs paid by the Company for taxes on the valuation of upstream assets and reserves are recognized when incurred.

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H) TRANSPORTATION AND PROCESSING

Costs paid by the Company for the transportation and processing of oil, NGLs and natural gas are recognized when the product is delivered and the services made available or provided.  

I) OPERATING

Operating costs paid by the Company, net of amounts capitalized, are recognized for oil and natural gas properties in which the Company has a working interest.

J) EMPLOYEE BENEFIT PLANS

The Company sponsors defined contribution and defined benefit plans, providing pension and other post-employment benefits to its employees in Canada and the U.S. As of January 1, 2003, the defined benefit pension plan was closed to new entrants.

Pension expense for the defined contribution pension plan is recorded as the benefits are earned by the employees covered by the plans. The Company accrues for its obligations under its employee defined benefit plans, net of plan assets. The cost of defined benefit pensions and other post-employment benefits is actuarially determined using the projected benefit method based on length of service and reflects Management’s best estimate of salary escalation, mortality rates, retirement ages of employees and expected future health care costs. The expected return on plan assets is based on historical and projected rates of return for assets in the investment plan portfolio. The actual return is based on the fair value of plan assets. The projected benefit obligation is discounted using the market interest rate on high-quality corporate debt instruments as at the measurement date.  

Defined benefit pension plan expenses include the cost of pension benefits earned during the current year, the interest cost on pension obligations, the expected return on pension plan assets, the amortization of adjustments arising from pension plan amendments, the amortization of net prior service costs, and the amortization of the excess of the net actuarial gains or losses over 10 percent of the greater of the benefit obligation and the fair value of plan assets. Amortization is on a straight-line basis over a period covering the expected average remaining service lives of employees covered by the plans. All components of the net defined periodic benefit cost, excluding the service cost component, are included in other (gains) losses, net.

K) INCOME TAXES

The Company follows the liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for the effect of any temporary difference between the accounting and income tax basis of an asset or liability, using the enacted income tax rates and laws expected to apply when the assets are realized and liabilities are settled. Current income taxes are measured at the amount expected to be recoverable from or payable to the taxing authorities based on the income tax rates and laws enacted at the end of the reporting period. The effect of a change in the enacted tax rates or laws is recognized in net earnings in the period of enactment. Income taxes are recognized in net earnings except to the extent that they relate to items recognized directly in shareholders’ equity, in which case the income taxes are recognized directly in shareholders’ equity.

Deferred income tax assets are assessed routinely for realizability. If it is more likely than not that deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets. The Company considers available positive and negative evidence when assessing the realizability of deferred tax assets including historic and expected future taxable earnings, available tax planning strategies and carry forward periods. The assumptions used in determining expected future taxable earnings are consistent with those used in the goodwill impairment assessment. 

The Company recognizes the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination by a taxing authority. A recognized tax position is initially and subsequently measured as the largest amount of tax benefit that is greater than 50 percent likely of being realized upon settlement with a taxing authority. Liabilities for unrecognized tax benefits that are not expected to be settled within the next 12 months are included in other liabilities and provisions. Interest related to unrecognized tax benefits is recognized in interest expense.

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L) EARNINGS PER SHARE AMOUNTS

Basic net earnings per common share is computed by dividing the net earnings by the weighted average number of common shares outstanding during the period. Diluted net earnings per common share amounts are calculated giving effect to the potential dilution that would occur if stock options were exercised or other contracts to issue common shares were exercised, fully vested, or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. The treasury stock method assumes that proceeds received from the exercise of in-the-money stock options and other dilutive instruments are used to repurchase common shares at the average market price.

M) CASH AND CASH EQUIVALENTS

Cash and cash equivalents include cash on hand and short-term investments, such as money market deposits or similar type instruments, with a maturity of three months or less when purchased. Outstanding disbursements issued in excess of applicable bank account balances are excluded from cash and cash equivalents and are recorded in accounts payable and accrued liabilities.

N) PROPERTY, PLANT AND EQUIPMENT

UPSTREAM

The Company uses the full cost method of accounting for its acquisition, exploration and development activities. Accordingly, all costs directly associated with the acquisition of, the exploration for, and the development of oil, NGLs and natural gas reserves, including costs of undeveloped leaseholds, dry holes and related equipment, are capitalized on a country-by-country cost center basis. Capitalized costs exclude costs relating to production, general overhead or similar activities.

Capitalized costs accumulated within each cost center are depleted using the unit-of-production method based on proved reserves. Depletion is calculated using the capitalized costs, including estimated retirement costs, plus the undiscounted future expenditures, based on current costs, to be incurred in developing proved reserves.

Costs associated with unproved properties are excluded from the depletion calculation until it is determined that proved reserves are attributable or impairment has occurred. Unproved properties are assessed separately for impairment on a quarterly basis. Costs that have been impaired are included in the costs subject to depletion within the full cost pool.  

Under the full cost method of accounting, the carrying amount of the Company’s oil and natural gas properties within each country cost center is subject to a ceiling test at the end of each quarter. A ceiling test impairment is recognized in net earnings when the carrying amount of a country cost center exceeds the country cost center ceiling. The carrying amount of a cost center includes capitalized costs of proved oil and natural gas properties, net of accumulated depletion and the related deferred income taxes.

The cost center ceiling is the sum of the estimated after-tax future net cash flows from proved reserves, using the 12-month average trailing prices and unescalated future development and production costs, discounted at 10 percent, plus unproved property costs. The 12-month average trailing price is calculated as the average of the price on the first day of each month within the trailing 12-month period. Any excess of the carrying amount over the calculated ceiling amount is recognized as an impairment in net earnings.  

Proceeds from the divestiture of properties are normally deducted from the full cost pool without recognition of a gain or loss unless the deduction significantly alters the relationship between capitalized costs and proved reserves in the cost center, in which case a gain or loss is recognized in net earnings. Generally, a gain or loss on a divestiture would be recognized when 25 percent or more of the Company’s proved reserves quantities are sold in a particular country cost center. For divestitures that result in the recognition of a gain or loss on the sale and constitute a business, goodwill is allocated to the divestiture.

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CORPORATE

Costs associated with office furniture, fixtures, leasehold improvements, information technology and aircraft are carried at cost and depreciated on a straight-line basis over the estimated service lives of the assets, which range from three to 25 years. Assets under construction are not subject to depreciation until put into use. Land is carried at cost.

O) CAPITALIZATION OF COSTS

Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred. Interest on borrowings associated with major development projects is capitalized during the construction phase.

P) BUSINESS COMBINATIONS

Business combinations are accounted for using the acquisition method. The acquired identifiable net assets are measured at fair value at the date of acquisition. Deferred taxes are recognized for any differences between the fair value of net assets acquired and the related tax bases. Any excess of the purchase price over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the purchase price below the fair value of the net assets acquired is recorded as a gain in net earnings. Associated transaction costs are expensed when incurred.

Q) GOODWILL

Goodwill represents the excess of purchase price over fair value of net assets acquired and is assessed for impairment at least annually at December 31. Goodwill and all other assets and liabilities are allocated to reporting units, which are the Company’s country cost centers. To assess impairment, the carrying amount of each reporting unit is determined and compared to the fair value of the reporting unit. If the carrying amount of the reporting unit, including goodwill, is higher than its related fair value then goodwill is written down to the reporting unit’s implied fair value of goodwill. The implied fair value of goodwill is determined by deducting the fair value of the reporting unit’s assets and liabilities from the fair value of the reporting unit as if the reporting entity had been acquired in a business combination. Any excess of the carrying value of goodwill over the implied fair value of goodwill is recognized as an impairment and charged to net earnings. Subsequent measurement of goodwill is at cost less any accumulated impairments.

R) IMPAIRMENT OF LONG-TERM ASSETS

The carrying value of long-term assets, excluding goodwill and upstream assets included in property, plant and equipment, is assessed for impairment when indicators suggest that the carrying value of an asset or asset group may not be recoverable. If the carrying amount exceeds the sum of the undiscounted cash flows expected to result from the continued use and eventual disposition of the asset or asset group, an impairment is recognized for the excess of the carrying amount over its estimated fair value.

S) ASSET RETIREMENT OBLIGATION

Asset retirement obligations are those legal obligations where the Company will be required to retire tangible long-lived assets such as producing well sites, an offshore production platform, processing plants, and restoring land or seabed at the end of oil and gas production operations. The asset retirement obligation is initially measured at its fair value and recorded as a liability with an offsetting retirement cost that is capitalized as part of the related long-lived asset in the Consolidated Balance Sheet. The estimated fair value is measured by reference to the expected future cash flows required to satisfy the obligation, discounted at the Company’s credit-adjusted risk-free rate. Changes in the estimated obligation resulting from revisions to estimated timing or amount of future cash flows are recognized as a change in the asset retirement obligation and the related asset retirement cost.

Amortization of asset retirement costs are included in depreciation, depletion and amortization in the Consolidated Statement of Earnings. Increases in the asset retirement obligations resulting from the passage of time are recorded as accretion of asset retirement obligation in the Consolidated Statement of Earnings.

Actual expenditures incurred are charged against the accumulated asset retirement obligation.

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T) STOCK-BASED COMPENSATION

Stock-based compensation arrangements are accounted for at fair value. Fair values are determined using observable share prices and/or pricing models such as the Black-Scholes-Merton option-pricing model. For equity-settled stock-based compensation plans, fair values are determined at the grant date and are recognized over the vesting period as compensation costs with a corresponding credit to shareholders’ equity. For cash-settled stock-based compensation plans, fair values are determined at each reporting date and periodic changes are recognized as compensation costs, with a corresponding change to liabilities. Compensation costs are recognized over the vesting period using the accelerated attribution method for awards with a graded vesting feature. Forfeitures are estimated based on the Company’s historical turnover rates.

U) LEASES

Leases for the right to use an asset are classified as either an operating or finance lease. Upon commencement of the lease, a ROU asset and corresponding lease liability are recognized in the Consolidated Balance Sheet for all operating and finance leases. The Company has elected the short-term lease exemption, which does not require a ROU asset or lease liability to be recognized in the Consolidated Balance Sheet when the lease term is 12 months or less and does not include an option to purchase the underlying asset that the lessee is reasonably certain to exercise.  

Upon commencement of the lease, ROU assets are recognized based on the initial measurement of the lease liability and adjusted for any lease payments made before commencement date of the lease, less any lease incentives and including any initial direct costs incurred. Lease liabilities are initially measured at the present value of future minimum lease payments over the lease term. The discount rate used to determine the present value is the rate implicit in the lease unless that rate cannot be determined, in which case the Company’s incremental borrowing rate is used.  

Rights to extend or terminate a lease are included in the lease term when there is reasonable certainty the right will be exercised. Factors used to assess reasonable certainty of rights to extend or terminate a lease include current and forecasted drillings plans, anticipated changes in development strategies, historical practice in extending similar contracts and current market conditions.

Operating lease ROU assets and liabilities are subsequently measured at the present value of the lease payments not yet paid and discounted at the initial discount rate at commencement of the lease, less any impairments to the ROU asset. Operating lease expense and revenue from subleases are recognized in the Consolidated Statement of Earnings on a straight-line basis over the lease term. Finance lease ROU assets are amortized on a straight-line basis over the estimated useful life of the asset if the lessee is reasonably certain to exercise a purchase option or ownership of the leased asset transfers at the end of the lease term, otherwise the leased assets are amortized over the lease term. Amortization of finance lease ROU assets is included in depreciation, depletion and amortization in the Consolidated Statement of Earnings.

Variable lease payments include changes in index rates, mobilization and demobilization costs related to oil and gas equipment and certain costs associated with office and building leases. Variable lease payments are recognized when incurred. Lease and non-lease components are accounted for as a single lease component for compression, coolers and office subleases.

V) FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques include the market, income and cost approach. The market approach uses information generated by market transactions involving identical or comparable assets or liabilities; the income approach converts estimated future amounts to a present value; the cost approach is based on the amount that currently would be required to replace an asset.  

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Inputs used in determining fair value are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. The three input levels of the fair value hierarchy are as follows:

• Level 1 - Inputs represent quoted prices in active markets for identical assets or liabilities, such as exchange-traded commodity derivatives.

• Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly, such as quoted market prices for similar assets or liabilities in active markets or other market corroborated inputs.

• Level 3 - Inputs that are not observable from objective sources, such as forward prices supported by little or no market activity or internally developed estimates of future cash flows used in a present value model.

In determining fair value, the Company utilizes the most observable inputs available. If a fair value measurement reflects inputs at multiple levels within the hierarchy, the fair value measurement is characterized based on the lowest level of input that is significant to the fair value measurement.

The carrying amount of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities reported in the Consolidated Balance Sheet approximates fair value. The fair value of long-term debt is disclosed in Note 15. Fair value information related to pension plan assets is included in Note 23. Recurring fair value measurements are performed for risk management assets and liabilities and other derivative contracts as discussed in Note 24.  

Certain non-financial assets and liabilities are initially measured at fair value, such as asset retirement obligations and assets and liabilities acquired in business combinations or certain non-monetary exchange transactions.

W) RISK MANAGEMENT ASSETS AND LIABILITIES

Risk management assets and liabilities are derivative financial instruments used by the Company to manage economic exposure to market risks relating to commodity prices, foreign currency exchange rates and interest rates. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.

Derivative instruments that do not qualify for the normal purchases and sales exemption are measured at fair value with changes in fair value recognized in net earnings. The fair values recorded in the Consolidated Balance Sheet reflect netting the asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. Realized gains or losses from financial derivatives related to oil, NGLs and natural gas commodity prices are recognized in revenues as the contracts are settled. Realized gains or losses from foreign currency exchange swaps are recognized in foreign exchange (gain) loss as the contracts are settled.

Realized gains or losses recognized from other derivative contracts related to certain payment obligations are presented in revenues as the obligations are settled. Unrealized gains and losses recognized are presented in revenues, and transportation and processing expense accordingly, at the end of each respective reporting period based on the changes in fair value of the contracts.    

X) COMMITMENTS AND CONTINGENCIES

Liabilities for loss contingencies arising from claims, assessments, litigation, environmental and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. These accruals are adjusted as additional information becomes available or circumstances change.

Y) RECENT ACCOUNTING PRONOUNCEMENTS

Changes in Accounting Policies and Practices  

On January 1, 2019, the Company adopted ASC Topic 842, Leases (“Topic 842”) and related amendments, using the modified retrospective approach recognizing a cumulative effect adjustment at the beginning of the reporting period in which Topic 842 was applied. Results for reporting the periods beginning after January 1, 2019, are

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presented in accordance with Topic 842, while prior periods have not been restated and are reported in accordance with ASC Topic 840, Leases (“Topic 840”). On transition, the Company elected certain practical expedients permitted under Topic 842 which include:

• No reassessment of the classification of leases previously assessed under Topic 840, whether expired or existing contracts contain leases, or initial direct costs of existing leases; and

• Application of Topic 842 prospectively to all new or modified land easements after January 1, 2019.

The Company also elected the short-term lease exemption, which does not require a ROU asset or lease liability to be recognized in the Consolidated Balance Sheet when the lease term is 12 months or less. The policy and disclosures required under Topic 842 are included in Note 14, Leases.  

In accordance with Topic 842, the Company recognized a ROU asset and corresponding lease liability for all operating leases in the Consolidated Balance Sheet, other than leases with lease terms of 12 months or less. Prior to the adoption of Topic 842, operating leases were not recognized in the Consolidated Balance Sheet. There was no impact to finance leases on transition to Topic 842. The impact from recognizing operating leases on the Company’s Consolidated Balance Sheet is as follows:

										Restated
	Reported as at			Impact of						Balances as at
(US$ millions)	December 31, 2018			Adoption						January 1, 2019
Property, Plant and Equipment, at cost:
Oil and natural gas properties, based on full cost accounting
Proved properties	$	41,241		$	-					$	41,241
Unproved properties		3,730			-						3,730
Other		2,122			(1,261	)					861
Property, plant and equipment		47,093			(1,261	)					45,832
Less: accumulated depreciation, depletion and amortization		(38,121	)		128						(37,993	)
Property, plant and equipment, net		8,972			(1,133	)		(1	)		7,839
Other Assets		147			1,015		(1), (2		)		1,162
Deferred Income Taxes		835			(28	)					807
Total Assets		15,344			(146	)					15,198
Current Liabilities
Accounts payable and accrued liabilities		1,490			(12	)		(1	)		1,478
Current portion of operating lease liabilities		-			67			(2	)		67
Income tax payable		1			-						1
Risk management		25			-						25
Current portion of long-term debt		500			-						500
		2,016			55						2,071
Operating Lease Liabilities		-			948			(2	)		948
Other Liabilities and Provisions		1,769			(1,224	)		(1	)		545
Total Liabilities		7,897			(221	)					7,676
Retained Earnings		435			75			(1	)		510
Total Shareholders’ Equity		7,447			75						7,522
Total Liabilities and Shareholders’ Equity	$	15,344		$	(146	)				$	15,198

(1) In accordance with Topic 840, the Company accounted for The Bow office building as a failed sales leaseback and at the effective date of January 1, 2019, The Bow office building remained as such. On transition to Topic 842, the Company re-assessed whether a sale would have occurred at the effective date and determined that a sale occurred. As a result, the Company derecognized the asset and financing liability resulting from the failed sale leaseback transaction measured under Topic 840, recognizing the difference as an adjustment to retained earnings in the Consolidated Balance Sheet. Upon transition to Topic 842, The Bow office building was determined to be an operating lease for which a ROU asset and corresponding liability was recorded at the present value of remaining minimum lease payments.

(2) ROU assets for operating leases were measured at the amount equal to the lease liability and the unamortized balance of any lease incentives prior to the transition date. The lease liabilities for operating leases were measured at the present value of the remaining minimum lease payments outstanding as at January 1, 2019.

Although Topic 842 did not have a material impact on the Consolidated Statements of Earnings or Cash Flows, the change in the accounting of The Bow office building resulted in: i) operating lease expense under Topic 842 reported in administrative expense, whereas for the comparative periods presented under Topic 840, the Company recorded depreciation and interest expense in the Consolidated Statement of Earnings; and ii) cash outflows

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presented in cash used in operating activities under Topic 842, whereas for the comparative periods presented under Topic 840, interest and financing cash outflows are presented in cash used in operating activities and cash used in financing activities, respectively, in the Consolidated Statement of Cash Flows.        

On January 1, 2019, the Company adopted ASU 2018-02 “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”. The amendments allow for a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act (“U.S. Tax Reform”). While the Company has other post-employment benefit plans which were affected by the U.S. Tax Reform, the impact was not material to the Company’s Consolidated Financial Statements. As a result, the Company did not take the election provided in the amendment.

New Standards Issued Not Yet Adopted

On January 1, 2020, Ovintiv will adopt the following ASUs issued by the FASB, which are not expected to have a material impact on the Consolidated Financial Statements:

• ASU 2017-04, “Simplifying the Test for Goodwill Impairment”.  The amendment eliminates the second step of the goodwill impairment test which requires the Company to measure the impairment based on the excess amount of the carrying value of the reporting unit’s goodwill over the implied fair value of its goodwill. Under this amendment, the goodwill impairment will be measured based on the excess amount of the reporting unit’s carrying value over its respective fair value. The amendment will be applied prospectively at the date of adoption.

• ASU 2016-13, “Financial Instruments - Credit Losses: Measurement of Credit Losses on Financial Instruments” under Topic 326. The standard amends the impairment model which requires utilizing a forward-looking expected loss methodology in place of the incurred loss methodology for financial instruments, including trade receivables. The standard requires entities to consider a broader range of information to estimate expected credit losses, resulting in earlier recognition of credit losses. The standard will be applied using the modified retrospective approach. The Company estimates the impact from adoption will result in a non-cash cumulative adjustment to retained earnings of less than $10 million, net of tax, on the Consolidated Balance Sheet.

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2. Segmented Information

The Company’s reportable segments are determined based on the following operations and geographic locations:

• USA Operations includes the exploration for, development of, and production of oil, NGLs and natural gas and other related activities within the U.S. cost center.  

• Canadian Operations includes the exploration for, development of, and production of oil, NGLs and natural gas and other related activities within the Canadian cost center.

• China Operations included the exploration for, development of, and production of oil and other related activities within the China cost center. The Company terminated its production sharing contract with China National Offshore Oil Corporation (“CNOOC”) and exited its China Operations effective July 31, 2019.

• Market Optimization is primarily responsible for the sale of the Company’s proprietary production. These results are reported in the USA and Canadian Operations. Market optimization activities include third party purchases and sales of product to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. These activities are reflected in the Market Optimization segment. Market Optimization sells substantially all of the Company’s upstream production to third-party customers. Transactions between segments are based on market values and are eliminated on consolidation.

Corporate and Other mainly includes unrealized gains or losses recorded on derivative financial instruments. Once the instruments are settled, the realized gains and losses are recorded in the reporting segment to which the derivative instruments relate. Corporate and Other also includes amounts related to sublease rentals.

As of February 14, 2019, the Company’s segmented results reflect the business combination as discussed in Note 8.

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Results of Operations

Segment Information

	USA Operations							Canadian Operations						China Operations (1)
For the years ended December 31	2019		2018			2017		2019		2018		2017		2019		2018		2017
Revenues
Product and service revenues	$	4,163	$	2,512		$	1,860	$	1,654	$	1,721	$	1,169	$	37	$	-	$	-
Gains (losses) on risk management, net		158		(199	)		18		211		100		22		-		-		-
Sublease revenues		-		-			-		-		-		-		-		-		-
Total Revenues		4,321		2,313			1,878		1,865		1,821		1,191		37		-		-
Operating Expenses
Production, mineral and other taxes		238		131			92		16		16		20		-		-		-
Transportation and processing		466		124			164		859		828		578		-		-		-
Operating		566		305			331		125		118		122		16		-		-
Depreciation, depletion and amortization		1,593		860			530		383		361		236		-		-		-
Total Operating Expenses		2,863		1,420			1,117		1,383		1,323		956		16		-		-
Operating Income (Loss)	$	1,458	$	893		$	761	$	482	$	498	$	235	$	21	$	-	$	-

	Market Optimization									Corporate & Other							Consolidated
	2019			2018			2017			2019			2018		2017		2019			2018			2017
Revenues
Product and service revenues	$	1,159		$	1,224		$	863		$	-		$	-	$	-	$	7,013		$	5,457		$	3,892
Gains (losses) on risk management, net		-			(5	)		-			(730	)		519		442		(361	)		415			482
Sublease revenues		-			-			-			74			67		69		74			67			69
Total Revenues		1,159			1,219			863			(656	)		586		511		6,726			5,939			4,443
Operating Expenses
Production, mineral and other taxes		-			-			-			-			-		-		254			147			112
Transportation and processing		233			131			103			-			-		-		1,558			1,083			845
Operating		28			16			35			(3	)		15		18		732			454			506
Purchased product		1,043			1,100			788			-			-		-		1,043			1,100			788
Depreciation, depletion and amortization		-			1			1			39			50		66		2,015			1,272			833
Accretion of asset retirement obligation		-			-			-			37			32		37		37			32			37
Administrative		-			-			-			489			157		254		489			157			254
Total Operating Expenses		1,304			1,248			927			562			254		375		6,128			4,245			3,375
Operating Income (Loss)	$	(145	)	$	(29	)	$	(64	)	$	(1,218	)	$	332	$	136		598			1,694			1,068
Other (Income) Expenses
Interest																		382			351			363
Foreign exchange (gain) loss, net																		(119	)		168			(279	)
(Gain) loss on divestitures, net																		(3	)		(5	)		(404	)
Other (gains) losses, net																		23			17			(42	)
Total Other (Income) Expenses																		283			531			(362	)
Net Earnings (Loss) Before Income Tax																		315			1,163			1,430
Income tax expense (recovery)																		81			94			603
Net Earnings (Loss)																	$	234		$	1,069		$	827

(1) The Company terminated its production sharing contract with CNOOC and exited its China Operations effective July 31, 2019.

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Intersegment Information

	Market Optimization
	Marketing Sales									Upstream Eliminations									Total
For the years ended December 31	2019			2018			2017			2019			2018			2017			2019			2018			2017
Revenues	$	7,489		$	5,724		$	3,939		$	(6,330	)	$	(4,505	)	$	(3,076	)	$	1,159		$	1,219		$	863
Operating Expenses
Transportation and processing		635			457			291			(402	)		(326	)		(188	)		233			131			103
Operating		28			16			35			-			-			-			28			16			35
Purchased product		6,973			5,279			3,676			(5,930	)		(4,179	)		(2,888	)		1,043			1,100			788
Depreciation, depletion and    amortization		-			1			1			-			-			-			-			1			1
Operating Income (Loss)	$	(147	)	$	(29	)	$	(64	)	$	2		$	-		$	-		$	(145	)	$	(29	)	$	(64	)

Revenues by Geographic Region

	United States								Canada
For the years ended December 31	2019			2018		2017			2019			2018		2017
Revenues
Product revenues
Oil	$	3,329		$	2,093	$	1,360		$	10		$	7	$	7
NGLs		452			289		193			870			863		481
Natural gas		380			126		296			756			826		662
Other revenues (1)		966			1,058		773			287			262		189
Gains (losses) on risk management, net		(142	)		216		(40	)		(219	)		199		522
Total Revenues	$	4,985		$	3,782	$	2,582		$	1,704		$	2,157	$	1,861

	China (2)						Total
	2019		2018		2017		2019			2018		2017
Revenues
Product revenues
Oil	$	37	$	-	$	-	$	3,376		$	2,100	$	1,367
NGLs		-		-		-		1,322			1,152		674
Natural gas		-		-		-		1,136			952		958
Other revenues (1)		-		-		-		1,253			1,320		962
Gains (losses) on risk management, net		-		-		-		(361	)		415		482
Total Revenues	$	37	$	-	$	-	$	6,726		$	5,939	$	4,443

(1) Includes market optimization and other revenues such as purchased product sold to third parties, sublease revenues and gathering and processing services provided to third parties.

(2) The Company terminated its production sharing contract with CNOOC and exited its China Operations effective July 31, 2019.

Export Sales

Sales of oil, NGLs and natural gas produced or purchased in Canada delivered to customers outside of Canada were $150 million for the year ended December 31, 2019 (2018 - $135 million; 2017 - $64 million).

Major Customers

In connection with the marketing and sale of the Company’s own and purchased oil, NGLs and natural gas for the year ended December 31, 2019, the Company had one customer which individually accounted for more than 10 percent of the Company’s product revenues. Sales to this customer, secured by a financial institution with an investment grade credit rating, totaled approximately $866 million which comprised $866 million in the United States and nil in Canada (2018 - one customer with sales of approximately $752 million; 2017 - two customers with sales of approximately $709 million and $412 million, respectively).

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Capital Expenditures by Segment

For the years ended December 31	2019		2018		2017
USA Operations	$	2,134	$	1,332	$	1,358
Canadian Operations		480		632		426
Market Optimization		2		-		1
Corporate & Other		10		11		11
	$	2,626	$	1,975	$	1,796

Goodwill, Property, Plant and Equipment and Total Assets by Segment

	Goodwill				Property, Plant and Equipment				Total Assets
As at December 31	2019		2018		2019		2018		2019		2018
USA Operations	$	1,938	$	1,913	$	13,757	$	6,591	$	16,613	$	9,104
Canadian Operations		673		640		1,205		999		2,122		1,852
Market Optimization		-		-		2		1		253		295
Corporate & Other		-		-		227		1,381		2,499		4,093
	$	2,611	$	2,553	$	15,191	$	8,972	$	21,487	$	15,344

Goodwill, Property, Plant and Equipment and Total Assets by Geographic Region

	Goodwill				Property, Plant and Equipment				Total Assets
As at December 31	2019		2018		2019		2018		2019		2018
United States	$	1,938	$	1,913	$	13,825	$	6,669	$	16,996	$	10,108
Canada		673		640		1,366		2,303		4,457		5,211
Other Countries		-		-		-		-		34		25
	$	2,611	$	2,553	$	15,191	$	8,972	$	21,487	$	15,344

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3. Revenues from Contracts with Customers

The following table summarizes the Company’s revenues from contracts with customers.

Revenues

	USA Operations						Canadian Operations						China Operations (1)
For the years ended December 31	2019		2018		2017		2019		2018		2017		2019		2018		2017
Revenues from Customers
Product revenues (2)
Oil	$	3,341	$	2,099	$	1,373	$	10	$	7	$	7	$	37	$	-	$	-
NGLs		454		290		193		878		870		485		-		-		-
Natural gas		379		126		305		774		849		680		-		-		-
Service revenues
Gathering and processing		2		4		11		5		6		9		-		-		-
Product and Service Revenues	$	4,176	$	2,519	$	1,882	$	1,667	$	1,732	$	1,181	$	37	$	-	$	-

	Market Optimization						Corporate & Other						Consolidated
	2019		2018		2017		2019		2018		2017		2019		2018		2017
Revenues from Customers
Product revenues (2)
Oil	$	249	$	89	$	115	$	-	$	-	$	-	$	3,637	$	2,195	$	1,495
NGLs		7		8		10		-		-		-		1,339		1,168		688
Natural gas		877		1,109		704		-		-		-		2,030		2,084		1,689
Service revenues
Gathering and processing		-		-		-		-		-		-		7		10		20
Product and Service Revenues	$	1,133	$	1,206	$	829	$	-	$	-	$	-	$	7,013	$	5,457	$	3,892

(1) The Company terminated its production sharing contract with CNOOC and exited its China Operations effective July 31, 2019.

(2) Includes revenues from production and revenues of product purchased from third parties, but excludes intercompany marketing fees transacted between the Company’s operating segments.

The Company’s revenues from contracts with customers consists of product sales including oil, NGLs and natural gas, as well as the provision of gathering and processing services to third parties. The Company had no contract asset or liability balances during the periods presented. For the year ended December 31, 2019, receivables and accrued revenues from contracts with customers were $1,095 million (2018 - $662 million).

Product sales are sold under short-term contracts with terms that are less than one year at either fixed or market index prices or under long-term contracts exceeding one year at market index prices.  

The Company’s gathering and processing services are provided on an interruptible basis with transaction prices that are for fixed prices and/or variable consideration. Variable consideration received is related to recovery of plant operating costs or escalation of the fixed price based on a consumer price index. As the service contracts are interruptible, with service provided on an “as available” basis, there are no unsatisfied performance obligations remaining at December 31, 2019.

As at December 31, 2019, all remaining performance obligations are priced at market index prices or are variable volume delivery contracts. As such, the variable consideration is allocated entirely to the wholly unsatisfied performance obligation or promise to deliver units of production, and revenue is recognized at the amount for which the Company has the right to invoice the product delivered. As the period between when the product sales are transferred and the Company receives payments is generally 30 to 60 days, there is no financing element associated with customer contracts. In addition, the Company does not disclose unsatisfied performance obligations for customer contracts with terms less than 12 months.

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4. Interest

For the years ended December 31	2019		2018		2017
Interest Expense on:
Debt	$	359	$	267	$	267
The Bow office building (See Note 1)		-		63		63
Finance leases (See Note 14)		13		16		20
Other		10		5		13
	$	382	$	351	$	363

Upon adoption of Topic 842 on January 1, 2019, The Bow office building was determined to be an operating lease with lease costs recognized in administrative expense. Previously, payments related to The Bow were recognized as interest expense and principal repayments. See Notes 1 and 14 for further information.

5. Foreign Exchange (Gain) Loss, Net

For the years ended December 31	2019			2018			2017
Unrealized Foreign Exchange (Gain) Loss on:
Translation of U.S. dollar financing debt issued from Canada	$	(207	)	$	358		$	(243	)
Translation of U.S. dollar risk management contracts issued from Canada		(12	)		24			(44	)
Translation of intercompany notes		196			(149	)		(4	)
		(23	)		233			(291	)
Foreign Exchange on Settlements of:
U.S. dollar financing debt issued from Canada		(25	)		3			14
U.S. dollar risk management contracts issued from Canada		(3	)		(10	)		(15	)
Intercompany notes		(71	)		(49	)		10
Other Monetary Revaluations		3			(9	)		3
	$	(119	)	$	168		$	(279	)

The unrealized foreign exchange (gain) loss on translation of U.S. dollar financing debt issued from Canada for the year ended December 31, 2017 disclosed in the table above included an out-of-period adjustment in respect of unrealized losses on a foreign-denominated finance lease obligation since December 2013. The cumulative impact recognized within foreign exchange (gain) loss in the Company’s Consolidated Statement of Earnings for the year ended December 31, 2017 was $68 million, before tax ($47 million, after tax). The Company determined that the adjustment was not material to the Consolidated Financial Statements for the year ended December 31, 2017 or any prior periods.

Following the completion of the Reorganization, including the U.S. Domestication, on January 24, 2020 as described in Note 1, the U.S. dollar denominated unsecured notes issued by Encana Corporation from Canada were assumed by Ovintiv Inc., a company incorporated in Delaware with a U.S. dollar functional currency. Accordingly, these U.S. dollar denominated unsecured notes, along with certain intercompany notes, will no longer attract foreign exchange translation gains or losses.

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6. Income Taxes

The provision for income taxes is as follows:

For the years ended December 31	2019			2018			2017
Current Tax
United States	$	3		$	4		$	(9	)
Canada		(16	)		(62	)		(59	)
Other Countries		-			3			5
Total Current Tax Expense (Recovery)		(13	)		(55	)		(63	)
Deferred Tax
United States		147			195			611
Canada		(53	)		(46	)		55
Other Countries		-			-			-
Total Deferred Tax Expense (Recovery)		94			149			666
Income Tax Expense (Recovery)	$	81		$	94		$	603

During the years ended December 31, 2019, 2018 and 2017, the current income tax recovery was primarily due to the resolution of certain tax items relating to prior taxation years.

On June 28, 2019, Alberta Bill 3, the Job Creation Tax Cut (Alberta Corporate Tax Amendment) Act, was signed into law resulting in a reduction of the Alberta corporate tax rate from 12 percent to 11 percent effective July 1, 2019, with further one percent rate reductions to take effect every year on January 1 until the general corporate tax rate is eight percent on January 1, 2022. During the year ended December 31, 2019, the deferred tax expense of $94 million includes an adjustment of $55 million resulting from the re-measurement of the Company’s deferred tax position due to the Alberta corporate tax rate reduction.

On December 22, 2017, U.S. Tax Reform was signed into law making significant changes to the U.S. tax code, including a reduction of the U.S. federal corporate tax rate from 35 percent to 21 percent. During the year ended December 31, 2017, the deferred tax expense of $666 million included a provisional tax adjustment of $327 million resulting from the re-measurement of the Company’s tax position due to U.S. Tax Reform. The adjustment of $327 million included a $26 million valuation allowance re-measurement with respect to U.S. foreign tax credits and U.S. charitable donations. As at December 31, 2018, the Company had completed its assessment of the income tax effects in respect of the provisional adjustment related to U.S. Tax Reform and there was no change to the amount recognized in 2017.

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The following table reconciles income taxes calculated at the Canadian statutory rate with the actual income taxes:

For the years ended December 31	2019			2018			2017
Net Earnings (Loss) Before Income Tax
United States	$	585		$	929		$	476
Canada		(280	)		19			512
Other Countries		10			215			442
Total Net Earnings (Loss) Before Income Tax		315			1,163			1,430
Canadian Statutory Rate (1)		26.6	%		27.0	%		27.0	%
Expected Income Tax		84			314			386
Effect on Taxes Resulting From:
Income tax related to foreign operations		(18	)		(106	)		(73	)
Statutory rate difference		11			-			-
Effect of legislative changes		55			-			299
Non-taxable capital (gains) losses		(11	)		22			(39	)
Tax differences on divestitures and transactions		-			-			77
Partnership tax allocations in excess of funding		(20	)		(68	)		(54	)
Amounts in respect of prior periods		(23	)		(54	)		(49	)
Change in valuation allowance		(7	)		8			54
Other		10			(22	)		2
	$	81		$	94		$	603
Effective Tax Rate		25.7	%		8.1	%		42.2	%

(1) Following the U.S. Domestication as described in Note 1, the applicable statutory tax rate will be the U.S. federal income tax rate.

The effective tax rate of 25.7 percent for the year ended December 31, 2019 is lower than the Canadian statutory rate of 26.6 percent primarily due to partnership tax allocations in excess of funding as well as the resolution of certain tax items relating to prior taxation years, partially offset by the re-measurement of the Company’s deferred tax position resulting from the Alberta corporate tax rate reduction discussed above. For the year ended December 31, 2018, the effective tax rate of 8.1 percent is lower than the Canadian statutory rate of 27 percent primarily due to the impact of foreign jurisdictional tax rates relative to the Canadian statutory tax rate applied to jurisdictional earnings, partnership tax allocations in excess of funding and the successful resolution of certain tax items relating to prior taxation years. For the year ended December 31, 2017, the effective tax rate was 42.2 percent, which was higher than the Canadian statutory tax rate of 27 percent primarily due to U.S. Tax Reform, which increased the Company’s effective tax rate by 22.9 percent, and the successful resolution of certain tax items relating to prior taxation years.

The net deferred income tax asset (liability) consists of:

As at December 31	2019			2018
Deferred Income Tax Assets
Property, plant and equipment	$	168		$	278
Risk management		8			-
Compensation plans		46			66
Interest and other deferred deductions		32			79
Unrealized foreign exchange losses		-			6
Non-capital and net capital losses carried forward (1)		1,703			1,107
Foreign tax credits		198			198
Other		14			38
Less: valuation allowance		(215	)		(195	)
Deferred Income Tax Liabilities
Property, plant and equipment		(1,554	)		(591	)
Risk management		(4	)		(168	)
Unrealized foreign exchange gains		(2	)		-
Other		(10	)		(10	)
Net Deferred Income Tax Asset	$	384		$	808

(1) The U.S. Domestication as described in Note 1, does not impact the availability of the U.S. and Canadian losses carried forward to future years.

100

As at December 31, 2019, the Company has recorded a valuation allowance against U.S. foreign tax credits, U.S. charitable donations, and federal and state losses in the amounts of $156 million (2018 - $156 million), $2 million (2018 - $3 million) and $57 million (2018 - $30 million), respectively, and Canadian unrealized foreign exchange losses in the amount of nil (2018 - $6 million) as it is more likely than not that these benefits will not be realized based on expected future taxable earnings as determined in accordance with the Company’s accounting policies. The valuation allowance change of $27 million for federal and state losses was recognized as part of the purchase price allocation for the Newfield Exploration Company acquisition described in Note 8.

The net deferred income tax asset (liability) for the following jurisdictions is reflected in the Consolidated Balance Sheet as follows:

As at December 31	2019			2018
Deferred Income Tax Assets
United States	$	2		$	287
Canada		599			548
		601			835
Deferred Income Tax Liabilities
United States		(189	)		-
Canada		(28	)		(27	)
		(217	)		(27	)
Net Deferred Income Tax Asset	$	384		$	808

Tax basis, loss carryforwards, charitable donations and tax credits available are as follows:

As at December 31	2019		Expiration Date
United States
Tax basis	$	6,960	Indefinite
Non-capital losses (Federal)		5,754	2020-2039 (1)
Charitable donations		9	2020 - 2024
Foreign tax credits		198	2020 - 2024
Canada
Tax pools	$	1,652	Indefinite
Net capital losses		10	Indefinite
Non-capital losses		1,636	2027 - 2039
Charitable donations		3	2022

(1) Includes non-capital losses of $1,120 million which have an indefinite expiration date.

As at December 31, 2019, approximately $16 million (2018 - $10 million) of the Company’s unremitted earnings from its foreign subsidiaries were considered to be permanently reinvested and, accordingly, the Company has not recognized a deferred income tax liability in respect of such earnings. If such earnings were to be remitted, the Company may be subject to income taxes and foreign withholding taxes. However, determination of any potential amount of unrecognized deferred income tax liabilities is not practicable. During 2019, nil (2018 - $3.4 billion) of unremitted earnings of certain foreign subsidiaries were repatriated, using existing tax attributes, with nominal tax expense.

The following table presents changes in the balance of the Company’s unrecognized tax benefits excluding interest:

For the years ended December 31	2019			2018
Balance, Beginning of Year	$	(248	)	$	(306	)
Additions for tax positions taken in the current year		-			(4	)
Additions for tax positions of prior years		(1	)		(2	)
Reductions for tax positions of prior years		4			-
Lapse of statute of limitations		34			19
Settlements		-			22
Foreign currency translation		(11	)		23
Balance, End of Year	$	(222	)	$	(248	)

101

The unrecognized tax benefit is reflected in the Consolidated Balance Sheet as follows:

As at December 31	2019			2018
Other Liabilities and Provisions (See Note 16)	$	(159	)	$	(167	)
Deferred Income Tax Asset		(63	)		(81	)
Balance, End of Year	$	(222	)	$	(248	)

If recognized, all of the Company’s unrecognized tax benefits as at December 31, 2019 would affect the Company’s effective income tax rate. The Company does not anticipate that the amount of unrecognized tax benefits will significantly change during the next 12 months.

The Company recognizes interest accrued in respect of unrecognized tax benefits in interest expense. During 2019, the Company recognized an expense of nil (2018 - recovery of $11 million; 2017 - expense of $12 million) in interest expense. As at December 31, 2019, the Company had a liability of $5 million (2018 - $5 million) for interest accrued in respect of unrecognized tax benefits.

Included below is a summary of the tax years, by jurisdiction, that remain statutorily open for examination by the taxing authorities.

Jurisdiction	Taxation Year
United States - Federal	2016 - 2019
United States - State	2015 - 2019
Canada - Federal	2012 - 2019
Canada - Provincial	2012 - 2019
Other	2019

The Company and its subsidiaries file income tax returns primarily in the United States and Canada. Issues in dispute for audited years and audits for subsequent years are ongoing and in various stages of completion.

102

7. Accounts Receivable and Accrued Revenues

As at December 31	2019			2018
Trade Receivables and Accrued Revenues
Oil, NGLs and natural gas	$	765		$	319
Midstream and marketing		353			365
Derivative financial instruments		7			36
Corporate and other		24			15
Total Trade Receivables and Accrued Revenues		1,149			735
Prepaids		48			15
Deposits and Other		41			44
		1,238			794
Allowance for Doubtful Accounts		(3	)		(5	)
	$	1,235		$	789

The Company’s trade receivables balance primarily consists of oil, NGLs and natural gas sales receivables, marketing revenues and joint interest receivables. Trade receivables are non-interest bearing. In determining the recoverability of trade receivables, the Company considers the age of the outstanding receivable and the credit worthiness of the counterparties. The Company charges uncollectible trade receivables to the allowance for doubtful accounts when it is determined no longer collectible. See Note 25 for further information about credit risk.

8. Business Combination

Newfield Exploration Company Acquisition

On February 13, 2019, the Company completed the business combination with Newfield Exploration Company, a Delaware corporation (“Newfield”), pursuant to its Agreement and Plan of Merger with Newfield (the “Merger”). As a result of the Merger, Newfield stockholders received 2.6719 Encana common shares, on a pre-Share Consolidation basis, for each share of Newfield common stock that was issued and outstanding immediately prior to the effective date of the Merger. The Company issued approximately 543.4 million Encana common shares, on a pre-Share Consolidation basis, representing a value of $3.5 billion and paid approximately $5 million in cash in respect of Newfield’s cash-settled incentive awards. Following the acquisition, Newfield’s senior notes totaling $2.45 billion remained outstanding. Transaction costs of approximately $33 million were included in other (gains) losses, net.

Newfield’s operations focused on the exploration and development of oil and gas properties located in Anadarko and Arkoma in Oklahoma, Bakken in North Dakota and Uinta in Utah, as well as offshore oil assets located in China. The assets acquired generated revenues of $2,100 million and net earnings of $101 million for the period from February 14, 2019 to December 31, 2019. The results of Newfield’s operations have been included in the Company’s Consolidated Financial Statements as of February 14, 2019.  

103

Purchase Price Allocation

The transaction was accounted for under the acquisition method, which requires that the assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date, with any excess of the purchase price over the estimated fair value of identified net assets acquired recorded as goodwill. The purchase price allocation represents the consideration paid and the fair values of the assets acquired, and liabilities assumed as of the acquisition date.

Purchase Price Allocation
Consideration:
Fair value of Encana's common shares issued (1)	$	3,478
Fair value of Newfield liability awards paid in cash (2)		5
Total Consideration	$	3,483
Assets Acquired:
Cash and cash equivalents	$	46
Accounts receivable and accrued revenues		486
Other current assets		50
Proved properties		5,903
Unproved properties		838
Other property, plant and equipment		22
Restricted cash		53
Other assets		105
Goodwill (3)		25
Liabilities Assumed:
Accounts payable and accrued liabilities (3)		(795	)
Long-term debt		(2,603	)
Operating lease liabilities		(76	)
Other long-term liabilities (3)		(65	)
Asset retirement obligation		(184	)
Deferred income taxes (3)		(322	)
Total Purchase Price	$	3,483

(1) The fair value was based on the NYSE closing price of the pre-Share Consolidation Encana common shares of $6.40 on February 13, 2019.

(2) The fair value was based on a price of $6.50 per notional unit which was determined using a volume-weighted average of the trading price of pre-Share Consolidation Encana common shares on the NYSE on each of the five consecutive trading days ending on the trading day that was three trading days prior to February 13, 2019.

(3) Since the completion of the business combination on February 13, 2019, additional information related to pre-acquisition liabilities and contingencies was obtained resulting in a measurement period adjustment. Changes in the fair value estimates comprised an increase in other liabilities of $16 million, of which approximately $11 million is presented in accounts payable and accrued liabilities and $5 million is presented in other long-term liabilities, a decrease in deferred tax liabilities of $4 million and a corresponding increase in goodwill of $12 million.

The Company used the income approach valuation technique for the fair value of assets acquired and liabilities assumed. The carrying amounts of cash and cash equivalents, accounts receivable and accrued revenues, restricted cash, other current assets, and accounts payable and accrued liabilities approximate their fair values due to their nature and/or the short-term maturity of the instruments. The fair values of long-term debt, ROU assets and operating lease liabilities were categorized within Level 2 of the fair value hierarchy and were determined using quoted prices and rates from an available pricing source. The fair values of the proved and unproved properties, other property, plant and equipment, other assets, other long-term liabilities and asset retirement obligation were categorized within Level 3 and were determined using relevant market assumptions, including discount rates, future commodity prices and costs, timing of development activities, projections of oil and gas reserves, and estimates for abandonment and reclamation.

Goodwill arose from the Newfield acquisition primarily from the requirement to recognize deferred taxes on the difference between the fair value of the assets acquired and liabilities assumed and the respective carry-over tax basis. Goodwill is not amortized and is not deductible for tax purposes.

104

Unaudited Pro Forma Financial Information

The following unaudited pro forma financial information combines the historical financial results of the Company with Newfield and has been prepared as though the acquisition had occurred on January 1, 2018. The pro forma information is not intended to reflect the actual results of operations that would have occurred if the business combination had been completed at the date indicated. In addition, the pro forma information is not intended to be a projection of the Company’s results of operations for any future period.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred of approximately $71 million and severance payments made to employees which totaled $138 million for the year ended December 31, 2019. The pro forma financial information does not include any cost savings or other synergies that may result from the Merger or any costs that have been incurred to integrate the assets.

For the years ended December 31 (US$ millions, except per share amounts)	2019		2018
Revenues	$	7,005	$	8,481
Net Earnings (Loss)	$	376	$	1,786
Net Earnings (Loss) per Common Share (1)
Basic & Diluted	$	1.44	$	5.94

(1) Net earnings (loss) per common share reflect the Share Consolidation as described in Note 1.

9. Acquisitions and Divestitures

For the years ended December 31	2019			2018			2017
Acquisitions
USA Operations	$	65		$	-		$	23
Canadian Operations		-			17			31
Total Acquisitions		65			17			54
Divestitures
USA Operations		(196	)		(438	)		(695	)
Canadian Operations		(1	)		(55	)		(41	)
Total Divestitures		(197	)		(493	)		(736	)
Net Acquisitions & (Divestitures)	$	(132	)	$	(476	)	$	(682	)

ACQUISITIONS

Acquisitions in 2019 in the USA Operations primarily included seismic purchases, water rights and property purchases with oil and liquids rich potential. Acquisitions in 2018 and 2017 in the USA and Canadian Operations primarily included property purchases with oil and liquids rich potential.

DIVESTITURES

In 2019, amounts received from the sale of assets were $197 million (2018 - $493 million; 2017 - $736 million).

Amounts received from the Company’s divestiture transactions have been deducted from the respective U.S. and Canadian full cost pools, except for divestitures that result in a significant alteration between capitalized costs and proved reserves in a country cost center. For divestitures that result in a gain or loss and constitute a business, goodwill is allocated to the divestiture.  

USA Operations

In 2019, divestitures in the USA Operations primarily included the sale of the Arkoma natural gas assets located in Oklahoma.

In 2018, divestitures in the USA Operations primarily included the sale of the San Juan assets located in northwestern New Mexico.

105

In 2017, divestitures in the USA Operations primarily included the sale of the Piceance natural gas assets located in northwestern Colorado for proceeds of approximately $605 million, after closing and other adjustments, and the sale of the Tuscaloosa Marine Shale assets in Mississippi and Louisiana. For the year ended December 31, 2017, the Company recognized a gain of approximately $406 million, before tax, on the sale of the Company’s Piceance assets in the U.S. cost center and allocated goodwill of $216 million to the transaction.

Canadian Operations

In 2018, divestitures in the Canadian Operations primarily included the sale of certain Pipestone assets located in Alberta.

In 2017, divestitures in the Canadian Operations primarily included the sale of certain properties that did not complement the Company’s existing portfolio of assets.

10. Property, Plant and Equipment, Net

As at December 31	2019							2018
	Cost		Accumulated DD&A			Net		Cost		Accumulated DD&A			Net
USA Operations
Proved properties	$	35,870	$	(25,623	)	$	10,247	$	27,189	$	(24,099	)	$	3,090
Unproved properties		3,491		-			3,491		3,493		-			3,493
Other		19		-			19		8		-			8
		39,380		(25,623	)		13,757		30,690		(24,099	)		6,591
Canadian Operations
Proved properties		15,284		(14,320	)		964		13,996		(13,261	)		735
Unproved properties		223		-			223		237		-			237
Other		18		-			18		27		-			27
		15,525		(14,320	)		1,205		14,260		(13,261	)		999
Market Optimization		9		(7	)		2		7		(6	)		1
Corporate & Other		914		(687	)		227		2,136		(755	)		1,381
	$	55,828	$	(40,637	)	$	15,191	$	47,093	$	(38,121	)	$	8,972

USA and Canadian Operations’ property, plant and equipment include internal costs directly related to exploration, development and construction activities of $228 million, which have been capitalized during the year ended December 31, 2019 (2018 - $147 million).

For the years ended December 31, 2019, December 31, 2018 and December 31, 2017, the Company did not recognize any ceiling test impairments in the U.S. or Canadian cost centers. The 12-month average trailing prices used in the ceiling test calculations reflect benchmark prices adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality. The benchmark prices are disclosed in Note 29.

Finance Lease Arrangements

The Company has two lease arrangements that are accounted for as finance leases, which include an office building and an offshore production platform. As at December 31, 2019, the total carrying value of assets under finance lease was $37 million (2018 - $41 million), net of accumulated amortization of $677 million (2018 - $650 million). Long-term liabilities for the finance lease arrangements are included in other liabilities and provisions in the Consolidated Balance Sheet and are disclosed in Note 16.

106

Other Arrangement

As at December 31, 2018, Corporate and Other property, plant and equipment and total assets include a carrying value of $1,133 million related to The Bow office building. Upon adoption of Topic 842 on January 1, 2019, The Bow office building was determined to be an operating lease as discussed in Note 1. As at December 31, 2019, other assets included a ROU asset of $906 million related to The Bow office building.

11. Other Assets

As at December 31	2019		2018
Operating Lease ROU Assets (See Note 14)	$	1,047	$	-
Long-Term Investments		28		22
Long-Term Receivables		81		79
Deferred Charges		6		9
Other		51		37
	$	1,213	$	147

12. Goodwill

As at December 31	2019		2018
United States
Balance, beginning of year	$	1,913	$	1,913
Additions during the year (See Note 8)		25		-
Balance, end of year		1,938		1,913
Canada
Balance, beginning of year		640		696
Foreign currency translation adjustment		33		(56	)
Balance, end of year		673		640
Total Goodwill	$	2,611	$	2,553

During 2019, the Company recognized goodwill of $25 million in conjunction with the Newfield acquisition in the United States as described in Note 8. The change in the Canada goodwill balance reflects movements due to foreign currency translation. During 2018, the Company had no additions or dispositions relating to goodwill.

Goodwill was assessed for impairment as at December 31, 2019 and December 31, 2018. The fair values of the United States and Canada reporting units were determined to be greater than the respective carrying values of the reporting units. Accordingly, no goodwill impairments were recognized. The Company has not recognized any historical cumulative goodwill impairments.

107

13. Accounts Payable and Accrued Liabilities

As at December 31	2019		2018
Trade Payables	$	355	$	233
Capital Accruals		351		277
Royalty and Production Accruals		598		311
Other Accruals		534		295
Interest Payable		83		69
Current Portion of Long-Term Incentive Costs (See Note 22)		40		131
Current Portion of Finance Lease Obligations (See Note 14)		89		84
Current Portion of Asset Retirement Obligation (See Note 17)		189		90
	$	2,239	$	1,490

Payables and accruals are non-interest bearing. Interest payable represents amounts accrued related to unsecured notes as disclosed in Note 15.

14. Leases

Operating leases include drilling rigs, compressors, marine vessels, camps, office and buildings, certain land easements and various equipment utilized in the development and production of oil, NGLs and natural gas. Finance leases include an office building and an offshore production platform. Subleases relate to office and building leases.

The tables below summarize the Company’s operating and finance lease costs and include ROU assets and lease liabilities, amounts recognized in net earnings during the period and other lease information.

As at December 31 (US$ millions, unless otherwise specified)	2019
Consolidated Balance Sheet (1):
Operating Lease ROU Assets, in Other Assets	$	1,047
Finance Lease ROU Assets, in Other Property Plant and Equipment		37
Operating Lease Liabilities:
Current		78
Long-term		977
Finance Lease Liabilities:
Current, in accounts payable and accrued liabilities		89
Long-term, in other liabilities and provisions		121
Weighted Average Discount Rate
Operating leases	5.41%
Finance leases	5.97%
Weighted Average Remaining Lease Term
Operating leases	16.3 years
Finance leases	3.2 years

(1) Total ROU assets and liabilities are recorded at the gross contractual amount. A portion of the future lease payments will be recovered from other working interest owners based on their proportionate share when incurred.

108

For the year ended December 31	2019
Lease Costs (1):
Operating Lease Costs, Excluding Short-Term Leases	$	181
Finance Lease Costs:
Amortization of ROU assets		4
Interest on lease liabilities		13
Total Finance Lease Costs		17
Short-Term Lease Costs		340
Variable Lease Costs		13
Sublease Income:
Operating lease income		56
Variable lease income		18
Other Information (2):
Cash Paid for Amounts Included in the Measurement of Lease Liabilities:
Operating cash outflows from operating leases		217
Investing cash outflows from operating leases		296
Operating cash outflows from finance leases		13
Financing cash outflows from finance leases		84
Supplemental Non-Cash Information:
New ROU operating lease assets and liabilities		20

(1) Lease costs include amounts capitalized into property, plant and equipment in the Consolidated Balance Sheet and lease expense recognized in the Consolidated Statement of Earnings.

(2) Rights to extend or terminate a lease are included in the lease term when there is reasonable certainty the right will be exercised. Lease contracts include rights to extend leases after the initial term, ranging from month-to-month to less than 10 years.

Operating lease expense is reflected in the Consolidated Statement of Earnings as follows:

For the year ended December 31	2019
Operating Lease Expense
Transportation and processing	$	3
Operating		107
Administrative (1)		116
Total Operating Lease Expense	$	226

(1) Includes $92 million for the year ended December 31, 2019, related to The Bow office building.

109

For the years ended December 31, 2018 and 2017, total operating lease expense recorded in the Consolidated Statement of Earnings was $83 million and $80 million, respectively, and did not include The Bow office building. See Notes 1 and 4 for further information on The Bow office building.

The following table outlines the Company’s future lease payments and lease liabilities related to the Company’s operating and finance leases as at December 31, 2019:

	2020			2021			2022			2023			2024			Thereafter			Total
Operating Leases (1)
Expected Future Lease Payments	$	133		$	117		$	101		$	88		$	86		$	1,101		$	1,626
Less: Discounting																				571
Present Value of Future Operating    Lease Payments																			$	1,055
Sublease Income (undiscounted)	$	(41	)	$	(42	)	$	(37	)	$	(37	)	$	(37	)	$	(529	)	$	(723	)
Finance Leases
Expected Future Lease Payments	$	99		$	87		$	8		$	8		$	8		$	22		$	232
Less: Discounting																				22
Present Value of Future Finance    Lease Payments																			$	210
Sublease Income (undiscounted) (2)	$	(8	)	$	(8	)	$	(8	)	$	(7	)	$	(7	)	$	(17	)	$	(55	)

(1) Lease payments are presented based on the gross contractual amount. A portion of the future lease payments will be recovered from other working interest owners based on their proportionate share when incurred.

(2) Classified as operating lease.

There are no commitments for leases with terms greater than one year that have not yet commenced at December 31, 2019.

15. Long-Term Debt

As at December 31	Note	2019			2018
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings	A	$	698		$	-
U.S. Unsecured Notes:	B
6.50% due May 15, 2019			-			500
3.90% due November 15, 2021			600			600
5.75% due January 30, 2022 (See Note 8)			750			-
5.625% due July 1, 2024  (See Note 8)			1,000			-
5.375% due January 1, 2026  (See Note 8)			700			-
8.125% due September 15, 2030			300			300
7.20% due November 1, 2031			350			350
7.375% due November 1, 2031			500			500
6.50% due August 15, 2034			750			750
6.625% due August 15, 2037			462			462
6.50% due February 1, 2038			505			505
5.15% due November 15, 2041			244			244
Total Principal	F		6,859			4,211
Increase in Value of Debt Acquired	C		149			22
Unamortized Debt Discounts and Issuance Costs	D		(34	)		(35	)
Total Long-Term Debt		$	6,974		$	4,198
Current Portion	E	$	-		$	500
Long-Term Portion			6,974			3,698
		$	6,974		$	4,198

110

A) REVOLVING CREDIT AND TERM LOAN BORROWINGS

At December 31, 2019, the Company had in place committed revolving U.S. dollar denominated bank credit facilities totaling $4.0 billion which included $2.5 billion on a revolving bank credit facility for Encana Corporation and $1.5 billion on a revolving bank credit facility for a U.S. subsidiary. The facilities are extendible from time to time, but not more than once per year, for a period not longer than five years plus 90 days from the date of the extension request, at the option of the lenders and upon notice from the Company. The facilities mature in July 2022, and are fully revolving up to maturity.  

At December 31, 2019, the Company had $698 million of commercial paper outstanding under its U.S. CP program maturing at various dates with a weighted average interest rate of approximately 2.28 percent. These amounts are supported by Encana Corporation’s $2.5 billion revolving credit facility, which is unsecured and bears interest at the lenders’ rates for Canadian prime, U.S. base rate, Bankers’ Acceptances or LIBOR, plus applicable margins. The U.S. subsidiary facility, which remained unused as at December 31, 2019, bears interest at either the lenders’ U.S. base rate or LIBOR, plus applicable margins.

The Company is subject to a financial covenant in its credit facility agreements whereby financing debt to adjusted capitalization cannot exceed 60 percent. Financing debt primarily includes total long-term debt and finance lease obligations. Adjusted capitalization is calculated as the sum of total financing debt, shareholders’ equity and a $7.7 billion equity adjustment for cumulative historical ceiling test impairments recorded in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. As at December 31, 2019, the Company is in compliance with all financial covenants.  

Standby fees paid in 2019 relating to revolving credit and term loan agreements were approximately $11 million (2018 - $15 million; 2017 - $15 million).

Subsequent to the Reorganization as described in Note 1, the Encana Corporation and U.S. subsidiary bank credit facilities noted above were replaced with committed revolving U.S. dollar denominated bank credit facilities totaling $4.0 billion, which included a $2.5 billion revolving bank credit facility for Ovintiv Inc. and a $1.5 billion revolving bank credit facility for a Canadian subsidiary. These facilities mature in July 2024, and are fully revolving up to maturity.

B) UNSECURED NOTES

Shelf Prospectuses

Encana renewed its shelf prospectus in Canada in 2018 and filed a shelf registration statement in the U.S. in 2017, whereby the Company may issue from time to time debt securities, common shares, Class A preferred shares, subscription receipts, warrants, units, share purchase contracts and share purchase units in Canada and/or the U.S. At December 31, 2019, $6.0 billion was accessible under the Canadian shelf prospectus.

U.S. Unsecured Notes

Unsecured notes include medium-term notes and senior notes that are issued from time to time under trust indentures and have equal priority with respect to the payment of both principal and interest.

C) INCREASE IN VALUE OF DEBT ACQUIRED

Certain of the notes and debentures of the Company were acquired in business combinations and were accounted for at their fair value at the dates of acquisition. The difference between the fair value and the principal amount of the debt is being amortized over the remaining life of the outstanding debt acquired, which has a weighted average remaining life of approximately six years.

D) UNAMORTIZED DEBT DISCOUNTS AND ISSUANCE COSTS

Long-term debt premiums and discounts are capitalized within long-term debt and are being amortized using the effective interest method. During 2019 and 2018, no debt premiums or discounts were capitalized. Issuance costs are amortized over the term of the related debt.

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E) CURRENT PORTION OF LONG-TERM DEBT

As at December 31, 2019, the current portion of long-term debt was nil (2018 - $500 million).

F) MANDATORY DEBT PAYMENTS

	Principal		Interest
As at December 31	Amount		Amount
2020	$	-	$	377
2021		600		377
2022		1,448		332
2023		-		305
2024		1,000		305
Thereafter		3,811		2,179
Total	$	6,859	$	3,875

The revolving credit facilities are fully revolving for a period of up to five years. Based on the maturity dates of the credit facilities at December 31, 2019, the payments are included in 2022.

As at December 31, 2019, total long-term debt had a carrying value of $6,974 million and a fair value of $7,657 million (2018 - carrying value of $4,198 million and a fair value of $4,511 million). The estimated fair value of long-term borrowings is categorized within Level 2 of the fair value hierarchy and has been determined based on market information of long-term debt with similar terms and maturity, or by discounting future payments of interest and principal at interest rates expected to be available to the Company at period end.  

16. Other Liabilities and Provisions

As at December 31	2019		2018
The Bow Office Building	$	-	$	1,224
Finance Lease Obligations (See Note 14)		121		211
Unrecognized Tax Benefits (See Note 6)		159		167
Pensions and Other Post-Employment Benefits (See Note 23)		119		105
Long-Term Incentive Costs (See Note 22)		38		34
Other Derivative Contracts (See Notes 24, 25)		7		10
Other		20		18
	$	464	$	1,769

Upon adoption of Topic 842 on January 1, 2019, The Bow office building was determined to be an operating lease. See Notes 1 and 14 for further information.

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17. Asset Retirement Obligation

As at December 31	2019			2018
Asset Retirement Obligation, Beginning of Year	$	455		$	514
Liabilities Incurred		15			17
Liabilities Acquired (See Note 8)		184			-
Liabilities Settled and Divested		(141	)		(56	)
Change in Estimated Future Cash Outflows		47			(20	)
Accretion Expense		37			32
Foreign Currency Translation		17			(32	)
Asset Retirement Obligation, End of Year	$	614		$	455
Current Portion (See Note 13)	$	189		$	90
Long-Term Portion		425			365
	$	614		$	455

18. Share Capital

AUTHORIZED

As at December 31, 2019, the Company was authorized to issue an unlimited number of no par value common shares and Class A Preferred Shares limited to a number equal to not more than 20 percent of the issued and outstanding number of common shares at the time of issuance. No Class A Preferred Shares were outstanding.

Subsequent to the Reorganization, the Company is authorized to issue 775 million shares of common stock, par value $0.01 per share, and 25 million shares of preferred stock, par value $0.01 per share.

ISSUED AND OUTSTANDING

As at December 31	2019						2018						2017
	Number (1) (millions)			Amount			Number (1) (millions)			Amount			Number (1) (millions)		Amount
Common Shares Outstanding, Beginning of Year		190.5		$	4,656			194.6		$	4,757			194.6	$	4,756
Common Shares Purchased		(39.4	)		(1,073	)		(4.1	)		(102	)		-		-
Common Shares Issued		108.7			3,478			-			-			-		-
Common Shares Issued Under Dividend Reinvestment Plan		-			-			-			1			-		1
Common Shares Outstanding, End of Year		259.8		$	7,061			190.5		$	4,656			194.6	$	4,757

(1) Number of common shares reflects the Share Consolidation as described in Note 1. Accordingly, the comparative periods have been restated.

On February 13, 2019, the Company completed the acquisition of all the issued and outstanding shares of common stock of Newfield whereby Encana issued approximately 543.4 million common shares, on a pre-Share Consolidation basis, to Newfield shareholders (approximately 108.7 million post-Share Consolidation shares), representing a pre-Share Consolidation exchange ratio of 2.6719 Encana common shares for each share of Newfield common stock held. See Note 8 for further information on the business combination.

Upon completion of the Reorganization as described in Note 1, the amount recognized in share capital as at December 31, 2019 in excess of Ovintiv’s established par value will be reclassified to paid in surplus. Accordingly, approximately $7,058 million will be reclassified in 2020.

SUBSTANTIAL ISSUER BID

On June 10, 2019, the Company announced its intention to purchase, for cancellation, up to $213 million of Encana common shares through a substantial issuer bid (“SIB”) which commenced on July 8, 2019. On August 29, 2019, the Company purchased approximately 47.3 million Encana common shares at a price of $4.50 per share, on a pre-Share Consolidation basis (approximately 9.5 million post-Share Consolidation shares at a converted price of $22.50

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per share), for an aggregate purchase price of approximately $213 million, of which $257 million was charged to share capital and $44 million was credited to paid in surplus.

The purchase was made in accordance with the terms and conditions of the SIB, with consideration allocated to share capital equivalent to the average carrying amount of the shares, with the excess of the carrying amount over the purchase consideration credited to paid in surplus.

NORMAL COURSE ISSUER BID

On February 27, 2019, the Company announced that the TSX accepted the Company’s notice of intention to purchase, for cancellation, up to approximately 149.4 million Encana common shares, on a pre-Share Consolidation basis (approximately 29.9 million post-Share Consolidation shares), pursuant to a NCIB over a 12-month period from March 4, 2019 to March 3, 2020.

During the year ended December 31, 2019, the Company purchased approximately 149.4 million Encana common shares, on a pre-Share Consolidation basis (approximately 29.9 million post-Share Consolidation shares), under its current NCIB for total consideration of approximately $1,037 million. Of the amount paid, $816 million was charged to share capital and $221 million was charged to retained earnings.

All purchases were made in accordance with the NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the average carrying amount of the shares, with any excess allocated to retained earnings.

For the year ended December 31, 2018, the Company purchased approximately 20.7 million Encana common shares, on a pre-Share Consolidation basis (approximately 4.1 million post-Share Consolidation shares), under the previous NCIB which was in place from February 28, 2018 to February 27, 2019 for total consideration of approximately $250 million. Of the amount paid, $102 million was charged to share capital and $148 million was charged to retained earnings.

DIVIDEND REINVESTMENT PLAN

On February 28, 2019, the Company suspended its dividend reinvestment plan (“DRIP”) and in conjunction with the Reorganization as described in Note 1, the DRIP was terminated. During the year ended December 31, 2018, Encana issued 69,329 common shares on a pre-Share Consolidation basis (approximately 13,866 post-Share Consolidation shares), totaling $0.6 million under the DRIP. During the year ended December 31, 2017, Encana issued 58,480 common shares on a pre-Share Consolidation basis (approximately 11,696 post-Share Consolidation shares), totaling $0.6 million.

DIVIDENDS

During the year ended December 31, 2019, on a pre-Share Consolidation basis, the Company declared and paid dividends of $0.075 per Encana common share, totaling $102 million (2018 - $0.06 per Encana common share, totaling $57 million; 2017 -  $0.06 per Encana common share, totaling $58 million). On a post-Share Consolidation basis, the dividends declared and paid were $0.375 per common share in 2019 and $0.30 per common share in 2018 and 2017, respectively.

On a pre-Share Consolidation basis, the Company’s quarterly dividend payment was $0.01875 per Encana common share in 2019 and $0.015 per common share in 2018 and 2017, respectively. On a post-Share Consolidation basis, the Company’s quarterly dividend payment was $0.09375 per common share in 2019 and $0.075 per common share in 2018 and 2017, respectively.

For the year ended December 31, 2018, the dividends paid included $0.6 million in Encana common shares, as disclosed above, which were issued in lieu of cash dividends under the DRIP (2017 - $0.6 million).

On February 19, 2020, the Board of Directors declared a dividend of $0.09375 per share of Ovintiv common stock payable on March 31, 2020 to common stockholders of record as of March 13, 2020.

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EARNINGS PER COMMON SHARE

The following table presents the computation of net earnings (loss) per common share:

For the years ended December 31 (US$ millions, except per share amounts)	2019		2018		2017
Net Earnings (Loss)	$	234	$	1,069	$	827
Number of Common Shares (1):
Weighted average common shares outstanding - Basic		261.2		192.0		194.6
Effect of dilutive securities		-		-		-
Weighted Average Common Shares Outstanding - Diluted		261.2		192.0		194.6
Net Earnings (Loss) per Common Share (1)
Basic & Diluted	$	0.90	$	5.57	$	4.25

(1) Net earnings (loss) per common share and weighted average common shares outstanding reflect the Share Consolidation as described in Note 1. Accordingly, the comparative periods have been restated.

STOCK OPTION PLAN

The Company has share-based compensation plans that allow employees to purchase shares of common stock of the Company. Option exercise prices are not less than the market value of the shares of common stock on the date the options are granted. Options granted are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire seven years after the date granted. Options granted before February 2015 expire five years after the date granted.

All options outstanding as at December 31, 2019 have associated Tandem Stock Appreciation Rights (“TSARs”) attached. In lieu of exercising the option, the associated TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of the Company’s shares of common stock at the time of the exercise over the original grant price. In addition, certain stock options granted are performance-based. The Performance TSARs vest and expire under the same terms and conditions as the underlying option. Vesting is also subject to the Company attaining prescribed performance relative to predetermined key measures. Historically, most holders of options with TSARs have elected to exercise their stock options as a Stock Appreciation Right (“SAR”) in exchange for a cash payment. As a result, outstanding TSARs are not considered potentially dilutive securities. See Note 22 for further information on the Company’s outstanding and exercisable TSARs and Performance TSARs.

At December 31, 2019, there were 36.8 million Encana common shares, on a pre-Share Consolidation basis (7.4 million shares on a post-Share Consolidation basis), reserved for issuance under stock option plans and the Company’s other stock-based compensation plans.

RESTRICTED SHARE UNITS

The Company has a share-based compensation plan whereby eligible employees and Directors are granted Restricted Share Units (“RSUs”). A RSU is a conditional grant to receive the equivalent of a share of common stock upon vesting of the RSUs and in accordance with the terms and conditions of the compensation plan and grant agreements. The Company currently settles vested RSUs in cash. As a result, RSUs are currently not considered potentially dilutive securities. See Note 22 for further information on the Company’s outstanding RSUs.

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19. Accumulated Other Comprehensive Income

For the years ended December 31	2019			2018			2017
Foreign Currency Translation Adjustment
Balance, Beginning of Year	$	976		$	1,029		$	1,200
Change in Foreign Currency Translation Adjustment		28			(53	)		(171	)
Balance, End of Year	$	1,004		$	976		$	1,029
Pension and Other Post-Employment Benefit Plans
Balance, Beginning of Year	$	22		$	13		$	10
Other Comprehensive Income Before Reclassifications:
Net actuarial gains and (losses) (See Note 23)		58			14			7
Income taxes		(12	)		(3	)		(2	)
Net prior service costs from plan amendment (See Note 23)		(31	)		-			-
Income taxes		6			-			-
Amounts Reclassified from Other Comprehensive Income:
Reclassification of net actuarial (gains) and losses to    net earnings (See Note 23)		(2	)		(1	)		-
Income taxes		-			-			-
Reclassification of net prior service costs to net earnings (See Note 23)		1			(1	)		(1	)
Income taxes		-			-			-
Curtailment in net defined periodic benefit cost (See Note 23)		-			-			(1	)
Income taxes		-			-			-
Balance, End of Year	$	42		$	22		$	13
Total Accumulated Other Comprehensive Income	$	1,046		$	998		$	1,042

During the year ended December 31, 2019, the Company amended the other post-employment benefits arrangements in conjunction with the integration of the Newfield business acquired. The plan amendment resulted in an increase to pension liabilities with a corresponding loss recognized in other comprehensive income.

20. Variable Interest Entities

Veresen Midstream Limited Partnership

Veresen Midstream Limited Partnership (“VMLP”) provides gathering, compression and processing services under various agreements related to the Company’s development of liquids and natural gas production in the Montney play. As at December 31, 2019, VMLP provides approximately 1,206 MMcf/d of natural gas gathering and compression and 939 MMcf/d of natural gas processing under long-term service agreements with remaining terms ranging from 12 to 26 years and have various renewal terms providing up to a potential maximum of 10 years.

The Company has determined that VMLP is a VIE and that the Company holds variable interests in VMLP. The Company is not the primary beneficiary as the Company does not have the power to direct the activities that most significantly impact VMLP’s economic performance. These key activities relate to the construction, operation, maintenance and marketing of the assets owned by VMLP. The variable interests arise from certain terms under the various long-term service agreements and include: i) a take or pay for volumes in certain agreements; ii) an operating fee of which a portion can be converted into a fixed fee once VMLP assumes operatorship of certain assets; and iii) a potential payout of minimum costs in certain agreements. The potential payout of minimum costs will be assessed in the eighth year of the assets’ service period and is based on whether there is an overall shortfall of total system cash flows from natural gas gathered and compressed under certain agreements. The potential payout amount can be reduced in the event VMLP markets unutilized capacity to third party users. The Company is not required to provide any financial support or guarantees to VMLP.

As a result of the Company’s involvement with VMLP, the maximum total exposure, which represents the potential exposure to the Company in the event the assets under the agreements are deemed worthless, is estimated to be $2,091 million as at December 31, 2019. The estimate comprises the take or pay volume commitments and the

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potential payout of minimum costs. The take or pay volume commitments associated with certain gathering and processing assets are included in Note 27 under Transportation and Processing. The potential payout requirement is highly uncertain as the amount is contingent on future production estimates, pace of development and the amount of capacity contracted to third parties. As at December 31, 2019, there were no accounts payable and accrued liabilities outstanding related to the take or pay commitment.

21. Restructuring Charges

In February 2019, in conjunction with the Newfield business combination as described in Note 8, the Company announced workforce reductions to better align staffing levels and the organizational structure with the Company’s strategy. During 2019, the Company incurred total restructuring charges of $138 million, before tax, primarily related to severance costs. As at December 31, 2019, $8 million remained accrued and is expected to be paid in 2020.

Restructuring charges are included in administrative expense presented in the Corporate and Other segment in the Consolidated Statement of Earnings.

For the years ended December 31	2019		2018		2017
Severance and Benefits	$	133	$	-	$	-
Outplacement, Moving and Other Expenses		5		-		-
Restructuring Expenses	$	138	$	-	$	-

As at December 31	2019			2018		2017
Outstanding Restructuring Accrual, Beginning of Year	$	-		$	-	$	7
Current Year Restructuring Expenses Incurred		138			-		-
Restructuring Costs Paid		(130	)		-		(7	)
Outstanding Restructuring Accrual, End of Year (1)	$	8		$	-	$	-

(1) Included in accounts payable and accrued liabilities in the Consolidated Balance Sheet.

22. Compensation Plans

The Company has a number of compensation arrangements under which the Company awards various types of long-term incentive grants to eligible employees and Directors. They may include TSARs, SARs, Performance Share Units (“PSUs”), Deferred Share Units (“DSUs”) and RSUs. These compensation arrangements are share-based.  

The Company accounts for TSARs, SARs, PSUs, and RSUs as cash-settled share-based payment transactions and, accordingly, accrues compensation costs over the vesting period based on the fair value of the rights determined using the Black-Scholes-Merton and other fair value models.

The following weighted average assumptions were used to determine the fair value of the share units outstanding:

	US$ Share Units
As at December 31	2019	2018	2017
Risk Free Interest Rate	1.69%	1.85%	1.67%
Dividend Yield	1.60%	1.04%	0.45%
Expected Volatility Rate (1)	44.98%	51.28%	57.87%
Expected Term	2.8 yrs	1.4 yrs	1.4 yrs
Market Share Price - Pre-Share Consolidation	US$4.69	US$5.78	US$13.33
Market Share Price - Post-Share Consolidation (See Note 1)	US$23.45	US$28.90	US$66.65

(1) Volatility was estimated using historical rates.

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	C$ Share Units
As at December 31	2019	2018	2017
Risk Free Interest Rate	1.69%	1.85%	1.67%
Dividend Yield	1.64%	0.99%	0.46%
Expected Volatility Rate (1)	43.61%	48.68%	54.10%
Expected Term	2.4 yrs	1.8 yrs	1.5 yrs
Market Share Price - Pre-Share Consolidation	C$6.08	C$7.88	C$16.77
Market Share Price - Post-Share Consolidation (See Note 1)	C$30.40	C$39.40	C$83.85

(1) Volatility was estimated using historical rates.

The Company has recognized the following share-based compensation costs:

For the years ended December 31	2019			2018			2017
Total Compensation Costs of Transactions Classified as Cash-Settled	$	59		$	(65	)	$	165
Less: Total Share-Based Compensation Costs Capitalized		(20	)		19			(55	)
Total Share-Based Compensation Expense (Recovery)	$	39		$	(46	)	$	110
Recognized on the Consolidated Statement of Earnings in:
Operating	$	16		$	(13	)	$	34
Administrative		23			(33	)		76
	$	39		$	(46	)	$	110

As at December 31, 2019, the liability for share-based payment transactions totaled $78 million (2018 - $165 million), of which $40 million (2018 - $131 million) is recognized in accounts payable and accrued liabilities and $38 million (2018 - $34 million) is recognized in other liabilities and provisions in the Consolidated Balance Sheet.

As at December 31	2019		2018		2017
Liability for Cash-Settled Share-Based Payment Transactions:
Unvested	$	65	$	148	$	274
Vested		13		17		53
	$	78	$	165	$	327

The following sections outline certain information related to the Company’s compensation plans as at December 31, 2019. All outstanding and exercisable units presented in the following sections, as well as the weighted average exercise prices, reflect the Share Consolidation as described in Note 1.

A) TANDEM STOCK APPRECIATION RIGHTS

All options to purchase common shares issued to eligible Canadian-based employees under the Company’s Stock Option Plan have associated TSARs attached. In lieu of exercising the option, the associated TSARs give the option holder the right to receive a cash payment equal to the excess of the market price of the Company’s common shares at the time of exercise over the original grant price. TSARs granted vest and are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire seven years after the date granted. TSARs granted before February 2015 expired five years after the date granted.

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The following tables summarize information related to the TSARs:

As at December 31	2019					2018
(thousands of units)	Outstanding TSARs			Weighted Average Exercise Price (C$)		Outstanding TSARs			Weighted Average Exercise Price (C$)
Outstanding, Beginning of Year		2,073			67.23		3,054			74.35
Granted		249			44.83		174			68.80
Exercised - SARs		(8	)		27.80		(74	)		37.20
Exercised - Options		-			-		-			-
Forfeited		(21	)		76.32		(62	)		78.00
Expired		(687	)		102.73		(1,019	)		90.30
Outstanding, End of Year		1,606			48.65		2,073			67.23
Exercisable, End of Year		1,179			45.89		1,459			75.10

As at December 31, 2019	Outstanding TSARs						Exercisable TSARs
Range of Exercise Price (C$)	Number of TSARs (thousands of units)		Weighted Average Remaining Contractual Life (years)		Weighted Average Exercise Price (C$)		Number of TSARs (thousands of units)		Weighted Average Exercise Price (C$)
0.00 to 49.99		950		3.97		32.18		705		27.80
50.00 to 99.99		656		3.37		72.51		474		72.79
		1,606		3.73		48.65		1,179		45.89

During the year, the Company recorded a reduction of compensation costs of $6 million related to the TSARs (2018 - reduction of compensation costs of $35 million; 2017 - compensation costs of $12 million).

As at December 31, 2019, there was approximately $0.3 million of unrecognized compensation costs (2018 - $0.2 million) related to unvested TSARs. The costs are expected to be recognized over a weighted average period of 1.9 years.

B) STOCK APPRECIATION RIGHTS

U.S. dollar denominated SARs are granted to eligible U.S.-based employees, which entitle the employee to receive a payment equal to the excess of the market price of the Company’s common shares at the time of exercise over the original grant price of the right. SARs granted vest and are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire seven years after the date granted. SARs granted before February 2015 expired five years after the date granted. The Company currently settles vested SARs in cash.

The following tables summarize information related to the U.S. dollar denominated SARs:

As at December 31	2019					2018
(thousands of units)	Outstanding SARs			Weighted Average Exercise Price (US$)		Outstanding SARs			Weighted Average Exercise Price (US$)
Outstanding, Beginning of Year		820			67.08		1,269			71.25
Granted		344			34.29		75			55.10
Exercised		(5	)		20.30		(88	)		29.45
Forfeited		(18	)		91.59		(61	)		54.40
Expired		(352	)		95.67		(375	)		89.70
Outstanding, End of Year		789			39.84		820			67.08
Exercisable, End of Year		378			41.92		621			75.95

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As at December 31, 2019	Outstanding SARs						Exercisable SARs
Range of Exercise Price (US$)	Number of SARs (thousands of units)		Weighted Average Remaining Contractual Life (years)		Weighted Average Exercise Price (US$)		Number of SARs (thousands of units)		Weighted Average Exercise Price (US$)
0.00 to 49.99		513		5.23		29.67		170		20.30
50.00 to 99.99		276		2.95		58.76		208		59.53
		789		4.43		39.84		378		41.92

During the year, the Company recorded compensation costs of nil related to the SARs (2018 - a reduction of compensation costs of $12 million; 2017 - compensation costs of $6 million).  

As at December 31, 2019, there was approximately $0.7 million of unrecognized compensation costs (2018 - $0.3 million) related to unvested U.S. dollar denominated SARs. The costs are expected to be recognized over a weighted average period of 1.9 years.  

C) PERFORMANCE SHARE UNITS

PSUs are granted to eligible employees, which entitle the employee to receive, upon vesting, a payment equal to the value of one common share for each PSU held, subject to the terms and conditions of the PSU Plan. PSUs vest three years from the date granted, provided the employee remains actively employed with the Company on the vesting date. The Company currently settles vested PSUs in cash. Based on the performance assessment, up to a maximum of two times the original PSU grant may be eligible to vest in respect of the year being measured. The respective proportion of the original PSU grant deemed eligible to vest for each year will be valued and the notional cash value deposited to a PSU account, with payout deferred to the final vesting date.

The ultimate value of the PSUs will depend upon the Company’s performance relative to predetermined strategic milestones as well as the performance of a specified peer group over a three-year period.

The following table summarizes information related to the PSUs:

(thousands of units)	U.S. Dollar Denominated Outstanding PSUs						Canadian Dollar Denominated Outstanding PSUs
As at December 31	2019			2018			2019			2018
Unvested and Outstanding, Beginning of Year		652			675			1,190			1,200
Granted		767			182			787			320
Vested and Released		(643	)		(158	)		(1,150	)		(323	)
Units, in Lieu of Dividends		11			4			12			7
Forfeited		(14	)		(51	)		(29	)		(14	)
Unvested and Outstanding, End of Year		773			652			810			1,190

During the year, the Company recorded compensation costs of $25 million related to the outstanding PSUs (2018 - compensation costs of $10 million; 2017 - compensation costs of $48 million).  

As at December 31, 2019, there was approximately $19 million of unrecognized compensation costs (2018 - $16 million) related to unvested PSUs. The costs are expected to be recognized over a weighted average period of 1.4 years.

D) DEFERRED SHARE UNITS

The Company has in place a program whereby Directors and certain key employees are issued DSUs, which vest immediately, are equivalent in value to a common share and are settled in cash.  

Under the DSU Plan, employees have the option to convert either 25 or 50 percent of their annual High Performance Results (“HPR”) award into DSUs. The number of DSUs converted is based on the value of the award divided by the closing value of the Company’s share price at the end of the performance period of the HPR award.

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For both Directors and employees, DSUs can only be redeemed following departure from the Company in accordance with the terms of the respective DSU Plan and must be redeemed prior to December 15^th of the year following the departure from the Company.

The following table summarizes information related to the DSUs:

(thousands of units)	Canadian Dollar Denominated Outstanding DSUs
As at December 31	2019			2018
Outstanding, Beginning of Year		191			179
Granted		13			7
Converted from HPR awards		11			4
Units, in Lieu of Dividends		3			1
Redeemed		(1	)		-
Outstanding, End of Year		217			191

During the year, the Company recorded a reduction of compensation costs of $1 million related to the outstanding DSUs (2018 - reduction of compensation costs of $6 million; 2017 - compensation costs of $3 million).

E) RESTRICTED SHARE UNITS

RSUs are granted to eligible employees and Directors. An RSU is a conditional grant to receive the equivalent of a common share upon vesting of the RSUs and in accordance with the terms and conditions of the RSU Plans and grant agreements.

RSUs issued to employees vest three years from the date granted, provided the employee remains actively employed with the Company on the vesting date. RSUs issued to Directors fully vest on the grant date and have no required term of service. The RSUs issued to Directors are settled three years from the date granted or following the Director’s departure from the Company, whichever is earlier.

The Company currently settles RSUs granted to eligible employees and Directors in cash.

The following table summarizes information related to the RSUs:

(thousands of units)	U.S Dollar Denominated Outstanding RSUs						Canadian Dollar Denominated Outstanding RSUs
As at December 31	2019			2018			2019			2018
Unvested and Outstanding, Beginning of Year		2,118			2,107			2,175			2,206
Granted		1,456			548			768			516
Units, in Lieu of Dividends		33			14			25			14
Vested and Released		(1,165	)		(453	)		(1,203	)		(510	)
Forfeited		(172	)		(98	)		(96	)		(51	)
Unvested and Outstanding, End of Year		2,270			2,118			1,669			2,175

During the year, the Company recorded compensation costs of $41 million related to the outstanding RSUs (2018 - a reduction of compensation costs of $22 million; 2017 - compensation costs of $98 million).

As at December 31, 2019, there was approximately $39 million of unrecognized compensation costs (2018 -$30 million) related to unvested RSUs. The costs are expected to be recognized over a weighted average period of 1.5 years.

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23. Pension and Other Post-Employment Benefits

The Company sponsors defined benefit and defined contribution plans, providing pension and other post-employment benefits (“OPEB”) to its employees in the U.S. and Canada. As of January 1, 2003, the defined benefit pension plan was closed to new entrants. The average remaining service period of active employees participating in the defined benefit pension plan is six years and the average remaining life expectancy of inactive employees is 13 years. The average remaining service period of the active employees participating in the OPEB plan is eight years.  

The Company is required to file an actuarial valuation of its pension plans with the provincial regulator at least every three years, or more frequently if directed by the regulator. The most recent filing was dated December 31, 2017 and the next required filing is expected to be as at December 31, 2020.

The following tables set forth changes in the benefit obligations and fair value of plan assets for the Company’s defined benefit pension and other post-employment benefit plans for the years ended December 31, 2019 and 2018, as well as the funded status of the plans and amounts recognized in the Consolidated Financial Statements as at December 31, 2019 and 2018.

	Defined Benefits						OPEB
As at December 31	2019			2018			2019			2018
Change in Benefit Obligations
Projected Benefit Obligation, Beginning of Year	$	196		$	226		$	73		$	85
Service Cost		1			1			10			7
Interest Cost		7			7			4			3
Actuarial (Gains) Losses		10			(7	)		(52	)		(15	)
Exchange Differences		9			(17	)		1			(2	)
Employee Contributions		-			-			1			1
Benefits Paid		(14	)		(14	)		(9	)		(6	)
Plan Acquisition		-			-			24			-
Plan Amendment		-			-			31			-
Curtailment		-			-			4			-
Projected Benefit Obligation, End of Year	$	209		$	196		$	87		$	73
Change in Plan Assets
Fair Value of Plan Assets, Beginning of Year	$	182		$	210		$	-		$	-
Actual Return on Plan Assets		23			-			-			-
Exchange Differences		9			(16	)		-			-
Employee Contributions		-			-			1			1
Employer Contributions		-			2			8			5
Benefits Paid		(14	)		(14	)		(9	)		(6	)
Transfers to Defined Contribution Plan		-			-			-			-
Fair Value of Plan Assets, End of Year	$	200		$	182		$	-		$	-
Funded Status of Plan Assets, End of Year	$	(9	)	$	(14	)	$	(87	)	$	(73	)
Total Recognized Amounts in the      Consolidated Balance Sheet Consist of:
Other Assets	$	12		$	4		$	-		$	-
Current Liabilities		-			-			(9	)		(6	)
Non-Current Liabilities		(21	)		(18	)		(78	)		(67	)
Total	$	(9	)	$	(14	)	$	(87	)	$	(73	)
Total Recognized Amounts in Accumulated      Other Comprehensive Income Consist of:
Net Actuarial (Gains) Losses	$	21		$	28		$	(97	)	$	(48	)
Net Prior Service Costs		(5	)		(5	)		26			(4	)
Total Recognized in Accumulated Other Comprehensive      Income, Before Tax	$	16		$	23		$	(71	)	$	(52	)

The accumulated defined benefit obligation for all defined benefit plans was $295 million as at December 31, 2019 (2018 - $267 million).  

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The following table sets forth the defined benefit plans with accumulated benefit obligation and projected benefit obligation in excess of the fair value of the plan assets:

	Defined Benefits						OPEB
As at December 31	2019			2018			2019			2018
Projected Benefit Obligation	$	(72	)	$	(67	)	$	(87	)	$	(73	)
Accumulated Benefit Obligation		(72	)		(66	)		(87	)		(73	)
Fair Value of Plan Assets		51			49			-			-

Following are the weighted average assumptions used by the Company in determining the defined benefit pension and other post-employment benefit obligations:

	Defined Benefits				OPEB
As at December 31	2019	2018			2019	2018
Discount Rate	3.00%		3.50	%	2.95%		4.04	%
Rates of Increase in Compensation Levels	3.09%		3.12	%	6.27%		6.27	%

The following sets forth total benefit plans expense recognized by the Company:

	Pension Benefits						OPEB
For the years ended December 31	2019		2018		2017		2019		2018		2017
Net Defined Periodic Benefit Cost	$	2	$	1	$	-	$	16	$	7	$	3
Defined Contribution Plan Expense		29		24		24		-		-		-
Total Benefit Plans Expense	$	31	$	25	$	24	$	16	$	7	$	3

Of the total benefit plans expense, $31 million (2018 - $23 million; 2017 - $25 million) was included in operating expense and $9 million (2018 - $9 million; 2017 - $8 million) was included in administrative expense. Excluding service costs, net defined periodic benefit costs of $7 million (2018 - nil; 2017 - curtailment of $6 million) were recorded in other (gains) losses, net.

The net defined periodic benefit cost is as follows:

	Defined Benefits									OPEB
For the years ended December 31	2019			2018			2017			2019			2018			2017
Service Cost	$	1		$	1		$	1		$	10		$	7		$	8
Interest Cost		7			7			7			4			3			3
Expected Return on Plan Assets		(7	)		(8	)		(9	)		-			-			-
Amounts Reclassified from Accumulated
Other Comprehensive Income:
Amortization of net actuarial (gains) and losses		1			1			1			(3	)		(2	)		(1	)
Amortization of net prior service costs		-			-			-			1			(1	)		(1	)
Curtailment from net prior service costs		-			-			-			-			-			(1	)
Curtailment		-			-			-			4			-			(5	)
Total Net Defined Periodic Benefit Cost (1)	$	2		$	1		$	-		$	16		$	7		$	3

(1) The components of total net defined periodic benefit cost, excluding the service cost component, are included in other (gains) losses, net.

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The amounts recognized in other comprehensive income are as follows:

	Defined Benefits									OPEB
For the years ended December 31	2019			2018			2017			2019			2018			2017
Net Actuarial (Gains) Losses	$	(6	)	$	1		$	1		$	(52	)	$	(15	)	$	(8	)
Net Prior Service Costs from Plan Amendment		-			-			-			31			-			-
Amortization of Net Actuarial Gains and (Losses)		(1	)		(1	)		(1	)		3			2			1
Amortization of Net Prior Service Costs		-			-			-			(1	)		1			1
Curtailment of Net Prior Service Costs		-			-			-			-			-			1
Total Amounts Recognized in Other Comprehensive     (Income) Loss, Before Tax	$	(7	)	$	-		$	-		$	(19	)	$	(12	)	$	(5	)
Total Amounts Recognized in Other Comprehensive     (Income) Loss, After Tax	$	(5	)	$	-		$	-		$	(15	)	$	(9	)	$	(3	)

The estimated net actuarial gains and net prior service costs for the pension and other post-retirement plans that will be amortized from accumulated other comprehensive income into the defined periodic benefit plan expense in 2020 is $8 million.

Following are the weighted average assumptions used by the Company in determining the net periodic pension and other post-retirement benefit costs:

	Defined Benefits									OPEB
For the years ended December 31	2019			2018			2017			2019			2018			2017
Discount Rate		3.50	%		3.25	%		3.50	%		4.16	%		3.46	%		3.76	%
Long-Term Rate of Return on Plan Assets		4.00	%		4.25	%		5.25	%		-			-			-
Rates of Increase in Compensation Levels		3.12	%		3.49	%		3.49	%		6.53	%		6.36	%		6.10	%

The Company’s assumed health care cost trend rates are as follows:

For the years ended December 31	2019			2018			2017
Health Care Cost Trend Rate for Next Year		6.61	%		6.99	%		6.98	%
Rate to Which the Cost Trend Rate is Assumed to Decline (Ultimate Trend Rate)		5.00	%		5.00	%		5.00	%
Year that the Rate Reaches the Ultimate Trend Rate	2026			2026			2025

A one percent change in the assumed health care cost trend rate over the projected period would have the following effects:

	1% Increase		1% Decrease
Effect on Total of Service and Interest Cost Components	$	2	$	(2	)
Effect on Other Post-Retirement Benefit Obligations	$	3	$	(3	)

The Company expects to contribute $6 million to its defined benefit pension plans in 2020. The Company’s OPEB plans are funded on an as required basis.

The following provides an estimate of benefit payments for the next 10 years. These estimates reflect benefit increases due to continuing employee service.

	Defined Benefit Pension Payments		Other Benefit Payments
2020	$	14	$	9
2021		14		9
2022		14		9
2023		13		8
2024		13		8
2025 - 2029		62		28

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The Company’s registered and other defined benefit pension plan assets are presented by investment asset category and input level within the fair value hierarchy as follows:

As at December 31	2019
	Level 1		Level 2		Level 3		Total
Investments:
Cash and Cash Equivalents	$	26	$	-	$	-	$	26
Fixed Income - Canadian Bond Funds		-		105		-		105
Equity - International		-		69		-		69
Fair Value of Plan Assets, End of Year	$	26	$	174	$	-	$	200
As at December 31	2018
	Level 1		Level 2		Level 3		Total
Investments:
Cash and Cash Equivalents	$	26	$	-	$	-	$	26
Fixed Income - Canadian Bond Funds		-		96		-		96
Equity - International		-		60		-		60
Fair Value of Plan Assets, End of Year	$	26	$	156	$	-	$	182

Fixed Income investments consist of Canadian bonds issued by investment grade companies. Equity investments consist of international securities, including securities held in the U.S. The fair values of these securities are based on dealer quotes, quoted market prices and net asset values. During 2018, Real Estate and Other consisted mainly of commercial properties and was valued based on a discounted cash flow model. As at December 31, 2019 and 2018, Real Estate and Other had a balance of nil.

A summary in changes in Level 3 fair value measurements is presented below:

	Real Estate and Other
As at December 31	2019		2018
Balance, Beginning of Year	$	-	$	11
Purchases, Sales and Settlements
Purchases and sales		-		-
Settlements		-		(10	)
Actual Return on Plan Assets
Relating to assets sold during the reporting period		-		(1	)
Relating to assets still held at the reporting date		-		-
Transfers In and Out of Level 3		-		-
Balance, End of Year	$	-	$	-

Registered pension plan assets were invested by the Company in the following as at December 31, 2019: 68 percent Bonds (2018 - 69 percent), and 32 percent U.S. and Foreign Equity (2018 - 31 percent). The expected long-term rate of return is 3.75 percent. The expected rate of return on pension plan assets is based on historical and projected rates of return for each asset class in the plan investment portfolio. The actual return on plan assets was $23 million (2018 - nil). The asset allocation structure is subject to diversification requirements and constraints, which reduce risk by limiting exposure to individual equity investment, credit rating categories and foreign currency exposure.

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24. Fair Value Measurements

The fair values of cash and cash equivalents, accounts receivable and accrued revenues, and accounts payable and accrued liabilities approximate their carrying amounts due to the short-term maturity of those instruments. The fair values of restricted cash and marketable securities included in other assets approximate their carrying amounts due to the nature of the instruments held. Fair value information related to pension plan assets is included in Note 23.

Recurring fair value measurements are performed for risk management assets and liabilities and other derivative contracts, as discussed further in Note 25. These items are carried at fair value in the Consolidated Balance Sheet and are classified within the three levels of the fair value hierarchy in the following tables. There have been no significant transfers between the hierarchy levels during the period.

Fair value changes and settlements for amounts related to risk management assets and liabilities are recognized in revenues, and foreign exchange gains and losses according to their purpose.

As at December 31, 2019	Level 1 Quoted Prices in Active Markets		Level 2 Other Observable Inputs		Level 3 Significant Unobservable Inputs		Total Fair Value		Netting (1)			Carrying Amount
Risk Management Assets
Commodity Derivatives:
Current assets	$	-	$	202	$	-	$	202	$	(67	)	$	135
Long-term assets		-		6		-		6		(4	)		2
Foreign Currency Derivatives:
Current assets		-		13		-		13		-			13
Risk Management Liabilities
Commodity Derivatives:
Current liabilities	$	1	$	139	$	41	$	181	$	(67	)	$	114
Long-term liabilities		-		61		11		72		(4	)		68
Other Derivative Contracts
Current in accounts payable and accrued liabilities	$	-	$	2	$	-	$	2	$	-		$	2
Long-term in other liabilities and provisions		-		7		-		7		-			7

As at December 31, 2018	Level 1 Quoted Prices in Active Markets		Level 2 Other Observable Inputs		Level 3 Significant Unobservable Inputs		Total Fair Value		Netting (1)			Carrying Amount
Risk Management Assets
Commodity Derivatives:
Current assets	$	-	$	492	$	139	$	631	$	(77	)	$	554
Long-term assets		-		177		-		177		(16	)		161
Risk Management Liabilities
Commodity Derivatives:
Current liabilities	$	-	$	81	$	-	$	81	$	(77	)	$	4
Long-term liabilities		-		38		-		38		(16	)		22
Foreign Currency Derivatives:
Current liabilities		-		21		-		21		-			21
Other Derivative Contracts
Current in accounts payable and accrued liabilities	$	-	$	4	$	-	$	4	$	-		$	4
Long-term in other liabilities and provisions		-		10		-		10		-			10

(1) Netting to offset derivative assets and liabilities where the legal right and intention to offset exists, or where counterparty master netting arrangements contain provisions for net settlement.

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The Company’s Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed price contracts, NYMEX fixed price swaptions, NYMEX three-way options, NYMEX costless collars, NYMEX call options, foreign currency swaps and basis swaps with terms to 2025. Level 2 also includes financial guarantee contracts as discussed in Note 25. The fair values of these contracts are based on a market approach and are estimated using inputs which are either directly or indirectly observable from active markets, such as exchange and other published prices, broker quotes and observable trading activity throughout the term of the instruments.

Level 3 Fair Value Measurements

As at December 31, 2019, the Company’s Level 3 risk management assets and liabilities consist of WTI three-way options, WTI costless collars and WTI sold payer swaptions with terms to 2021. The WTI three-way options are a combination of a sold call, bought put and a sold put. The WTI costless collars are a combination of a sold call and a bought put. These contracts allow the Company to participate in the upside of commodity prices to the ceiling of the call option and provide the Company with complete (collars) or partial (three-way) downside price protection through the put options. The sold payer swaptions give the counterparty the right to extend to 2021 certain 2020 WTI fixed price swaps. The fair values of these contracts are based on the income approach and are modelled using observable and unobservable inputs such as implied volatility. The unobservable inputs are obtained from third parties whenever possible and reviewed by the Company for reasonableness.

A summary of changes in Level 3 fair value measurements is presented below:

	Risk Management
	2019			2018
Balance, Beginning of Year	$	139		$	(51	)
Total Gains (Losses)		(123	)		97
Purchases, Sales, Issuances and Settlements:
Purchases, sales and issuances		-			-
Settlements		(68	)		93
Transfers Out of Level 3 (1)		-			-
Balance, End of Year	$	(52	)	$	139
Change in Unrealized Gains (Losses) Related to Assets and Liabilities    Held at End of Year	$	(52	)	$	139

(1) The Company’s policy is to recognize transfers out of Level 3 on the date of the event of change in circumstances that caused the transfer.

Quantitative information about unobservable inputs used in Level 3 fair value measurements is presented below:

As at December 31	Valuation Technique	Unobservable Input	2019	2018
Risk Management - WTI Options	Option Model	Implied Volatility	18% - 65%	29% - 73%

A 10 percent increase or decrease in implied volatility for the WTI options would cause an approximate corresponding $8 million (2018 - $6 million) increase or decrease to net risk management assets and liabilities.

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25. Financial Instruments and Risk Management

A) FINANCIAL INSTRUMENTS

The Company’s financial assets and liabilities are recognized in cash and cash equivalents, accounts receivable and accrued revenues, other assets, accounts payable and accrued liabilities, risk management assets and liabilities, long-term debt, and other liabilities and provisions.  

B) RISK MANAGEMENT ACTIVITIES

The Company uses derivative financial instruments to manage its exposure to cash flow variability from commodity prices and fluctuating foreign currency exchange rates. The Company does not apply hedge accounting to any of its derivative financial instruments. As a result, gains and losses from changes in the fair value are recognized in net earnings.

COMMODITY PRICE RISK

Commodity price risk arises from the effect that fluctuations in future commodity prices may have on future cash flows. To partially mitigate exposure to commodity price risk, the Company has entered into various derivative financial instruments. The use of these derivative instruments is governed under formal policies and is subject to limits established by the Board of Directors.

Crude Oil and NGLs - To partially mitigate crude oil and NGL commodity price risk, the Company uses WTI-based contracts such as fixed price contracts, fixed price swaptions, options and costless collars. The Company has also entered into basis swaps to manage against widening price differentials between various production areas and benchmark price points.

Natural Gas - To partially mitigate natural gas commodity price risk, the Company uses NYMEX-based contracts such as fixed price contracts, fixed price swaptions, options and costless collars. The Company has also entered into basis swaps to manage against widening price differentials between various production areas and benchmark price points.

FOREIGN EXCHANGE RISK

Foreign exchange risk arises from changes in foreign currency exchange rates that may affect the fair value or future cash flows of the Company’s financial assets or liabilities. To partially mitigate the effect of foreign exchange fluctuations on future commodity revenues and expenses, the Company may enter into foreign currency derivative contracts. As at December 31, 2019, the Company has entered into $425 million notional U.S. dollar denominated currency swaps at an average exchange rate of US$0.7483 to C$1, which mature monthly throughout 2020.

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RISK MANAGEMENT POSITIONS AS AT DECEMBER 31, 2019

	Notional Volumes	Term	Average Price		Fair Value
Crude Oil and NGL Contracts			US$/bbl
Fixed Price Contracts
WTI Fixed Price	70.0 Mbbls/d	2020		57.56	$	(22	)
Propane Fixed Price	12.0 Mbbls/d	2020		21.34		10
Butane Fixed Price	8.0 Mbbls/d	2020		23.54		(4	)
Iso-Butane Fixed Price	3.5 Mbbls/d	2020		24.36		(3	)
WTI Fixed Price Swaptions (1)	10.0 Mbbls/d	2021		58.00		(11	)
WTI Three-Way Options
Sold call / bought put / sold put	80.0 Mbbls/d	2020	61.68 / 53.44 / 43.44			(43	)
WTI Costless Collars
Sold call / bought put	15.0 Mbbls/d	2020	68.71 / 50.00			2
Basis Contracts (2)		2020				(41	)
Crude Oil and NGLs Fair Value Position						(112	)
Natural Gas Contracts			US$/Mcf
Fixed Price Contracts
NYMEX Fixed Price	803 MMcf/d	2020		2.65		107
NYMEX Fixed Price Swaptions (3)	330 MMcf/d	2021		2.56		(15	)
NYMEX Three-Way Options
Sold call / bought put / sold put	330 MMcf/d	2020	2.72 / 2.60 / 2.25			22
NYMEX Costless Collars
Sold call / bought put	55 MMcf/d	2020	2.88 / 2.50			6
NYMEX Call Options
Sold call price	230 MMcf/d	2020		3.25		7
Basis Contracts (4)		2020				(11	)
		2021				(13	)
		2022 - 2025				(27	)
Natural Gas Fair Value Position						76
Net Premiums Received on Unexpired Options						(9	)
Other Derivative Contracts
Fair Value Position						(9	)
Foreign Currency Contracts
Fair Value Position (5)		2020				13
Total Fair Value Position and Net Premiums Received					$	(41	)

(1) WTI Fixed Price Swaptions give the counterparty the option to extend certain 2020 Fixed Price swaps to 2021.

(2) The Company has entered into crude oil and NGL differential swaps associated with Midland, Magellan East Houston, Belvieu, Conway, Brent, Edmonton Condensate and WTI.

(3) NYMEX Fixed Price Swaptions give the counterparty the option to extend certain 2020 Fixed Price swaps to 2021.

(4) The Company has entered into natural gas basis swaps associated with AECO, Dawn, Chicago, Malin, Waha, Houston Ship Channel and NYMEX.

(5) The Company has entered into U.S. dollar denominated fixed-for-floating average currency swaps to protect against fluctuations between the Canadian and U.S. dollars.

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EARNINGS IMPACT OF REALIZED AND UNREALIZED GAINS (LOSSES) ON RISK MANAGEMENT POSITIONS

For the years ended December 31	2019			2018			2017
Realized Gains (Losses) on Risk Management
Commodity and Other Derivatives:
Revenues (1)	$	369		$	(104	)	$	40
Transportation and processing		-			-			(4	)
Foreign Currency Derivatives:
Foreign exchange		3			10			15
	$	372		$	(94	)	$	51
Unrealized Gains (Losses) on Risk Management
Commodity and Other Derivatives:
Revenues (2)	$	(730	)	$	519		$	442
Foreign Currency Derivatives:
Foreign exchange		34			(51	)		32
	$	(696	)	$	468		$	474
Total Realized and Unrealized Gains (Losses) on Risk Management, net
Commodity and Other Derivatives:
Revenues (1) (2)	$	(361	)	$	415		$	482
Transportation and processing		-			-			(4	)
Foreign Currency Derivatives:
Foreign exchange		37			(41	)		47
	$	(324	)	$	374		$	525

(1) Includes a realized gain of $6 million for the year ended December 31, 2019 (2018 - gain of $7 million; 2017 - gain of $7 million) related to other derivative contracts.

(2) Includes an unrealized loss of $1 million for the year ended December 31, 2019 (2018 - loss of $2 million; 2017 - loss of $2 million) related to other derivative contracts.

RECONCILIATION OF UNREALIZED RISK MANAGEMENT POSITIONS FROM JANUARY 1 TO DECEMBER 31

	2019						2018		2017
	Fair Value			Total Unrealized Gain (Loss)			Total Unrealized   Gain (Loss)		Total Unrealized   Gain (Loss)
Fair Value of Contracts, Beginning of Year	$	654
Change in Fair Value of Contracts in Place at Beginning of Year    and Contracts Entered into During the Year		(324	)	$	(324	)	$	374	$	525
Settlement of Other Derivative Contracts		6
Amortization of Option Premiums During the Year		(5	)
Fair Value of Contracts Realized During the Year		(372	)		(372	)		94		(51	)
Fair Value of Contracts Outstanding	$	(41	)	$	(696	)	$	468	$	474

Risk management assets and liabilities arise from the use of derivative financial instruments and are measured at fair value. See Note 24 for a discussion of fair value measurements.

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UNREALIZED RISK MANAGEMENT POSITIONS

As at December 31	2019			2018
Risk Management Assets
Current	$	148		$	554
Long-term		2			161
		150			715
Risk Management Liabilities
Current		114			25
Long-term		68			22
		182			47
Other Derivative Contracts
Current in accounts payable and accrued liabilities		2			4
Long-term in other liabilities and provisions		7			10
Net Risk Management Assets (Liabilities) and Other Derivative Contracts	$	(41	)	$	654

SUMMARY OF UNREALIZED RISK MANAGEMENT POSITIONS

As at December 31	2019							2018
	Risk Management							Risk Management
	Asset		Liability		Net			Asset		Liability		Net
Commodity Price Positions
Crude oil and NGLs	$	4	$	116	$	(112	)	$	380	$	13	$	367
Natural gas		133		66		67			335		13		322
Other Positions
Other derivative contracts		-		9		(9	)		-		14		(14	)
Foreign currency contracts		13		-		13			-		21		(21	)
Total Fair Value Position	$	150	$	191	$	(41	)	$	715	$	61	$	654

C) CREDIT RISK

Credit risk arises from the potential that the Company may incur a loss if a counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. While exchange-traded contracts are subject to nominal credit risk due to the financial safeguards established by the NYSE and the TSX, over-the-counter traded contracts expose the Company to counterparty credit risk. This credit risk exposure is mitigated through the use of credit policies approved by the Board of Directors governing the Company’s credit portfolio including credit practices that limit transactions according to counterparties’ credit quality. Mitigation strategies may include master netting arrangements, requesting collateral, purchasing credit insurance, and/or transacting credit derivatives. The Company executes commodity derivative financial instruments under master agreements that have netting provisions that provide for offsetting payables against receivables. As a result of netting provisions, the Company’s maximum exposure to loss under derivative financial instruments due to credit risk is limited to the net amounts due from the counterparties under the derivative contracts, as disclosed in Note 24. As at December 31, 2019, the Company had no significant credit derivatives in place and held no collateral.

As at December 31, 2019, cash equivalents include high-grade, short-term securities, placed primarily with financial institutions and companies with strong investment grade ratings. Any foreign currency agreements entered into are with major financial institutions that have investment grade credit ratings.  

A substantial portion of the Company’s accounts receivable are with customers and working interest owners in the oil and gas industry and are subject to normal industry credit risks. As at December 31, 2019, approximately 95 percent (2018 - 97 percent) of the Company’s accounts receivable and financial derivative credit exposures were with investment grade counterparties.

131

As at December 31, 2019, the Company had six counterparties whose net settlement position individually accounted for more than 10 percent of the fair value of the outstanding in-the-money net risk management contracts by counterparty. These counterparties accounted for 26 percent, 13 percent, 12 percent, 12 percent, 11 percent and 11 percent of the fair value of the outstanding in-the-money net risk management contracts. As at December 31, 2018, the Company had four counterparties whose net settlement position accounted for 30 percent, 13 percent 12 percent and 10 percent of the fair value of the outstanding in-the-money net risk management contracts.

During 2015 and 2017, the Company entered into agreements resulting from divestitures, which may require the Company to fulfill certain payment obligations on the take or pay volume commitments assumed by the purchasers. The circumstances that would require the Company to perform under the agreements include events where a purchaser fails to make payment to the guaranteed party and/or a purchaser is subject to an insolvency event. The agreements have remaining terms from two to five years with a fair value recognized of $9 million as at December 31, 2019 (2018 - $14 million). The maximum potential amount of undiscounted future payments is $129 million as at December 31, 2019, and is considered unlikely.  

26. Supplementary Information

Supplemental disclosures to the Consolidated Statement of Cash Flows are presented below:

A) NET CHANGE IN NON-CASH WORKING CAPITAL

For the years ended December 31	2019			2018			2017
Operating Activities
Accounts receivable and accrued revenues	$	109		$	(150	)	$	(21	)
Accounts payable and accrued liabilities		(44	)		141			(226	)
Current portion of operating lease liabilities		49			-			-
Income tax receivable and payable		(27	)		254			(6	)
	$	87		$	245		$	(253	)

B) NON-CASH ACTIVITIES

For the years ended December 31	2019			2018			2017
Non-Cash Investing Activities
Asset retirement obligation incurred (See Note 17)	$	15		$	17		$	11
Asset retirement obligation change in estimated future cash outflows (See Note 17)		47			(20	)		88
Property, plant and equipment accruals		(78	)		(16	)		19
Capitalized long-term incentives		(27	)		(47	)		55
Property additions/dispositions (swaps)		159			210			194
New ROU operating lease assets and liabilities (See Note 14)		(20	)		-			-
Non-Cash Financing Activities
Common shares issued in conjunction with the Newfield business    combination (See Note 8)	$	(3,478	)	$	-		$	-
Common shares issued under dividend reinvestment plan (See Note 18)		-			1			1

C) SUPPLEMENTARY CASH FLOW INFORMATION

For the years ended December 31	2019			2018			2017
Interest Paid	$	415		$	367		$	370
Income Taxes (Recovered), net of Amounts Paid	$	(22	)	$	(246	)	$	(77	)

132

27. Commitments and Contingencies

COMMITMENTS

The following table outlines the Company’s commitments as at December 31, 2019:

	Expected Future Payments
(undiscounted)	2020		2021		2022		2023		2024		Thereafter		Total
Transportation and Processing	$	734	$	679	$	642	$	528	$	419	$	2,163	$	5,165
Drilling and Field Services		90		6		-		-		-		-		96
Building Leases		14		15		11		7		7		8		62
Total	$	838	$	700	$	653	$	535	$	426	$	2,171	$	5,323

Associated with the adoption of Topic 842, all operating leases were recognized in the Consolidated Balance Sheet. Accordingly, operating leases with terms greater than one year are not included in the commitments table above. The table above includes short-term leases with contract terms less than 12 months, such as drilling rigs and field office leases, as well as non-lease operating cost components associated with building leases. See Notes 1 and 14 for additional disclosures on leases.

Included within transportation and processing in the table above are certain commitments associated with midstream service agreements with VMLP as described in Note 20. Divestiture transactions can reduce certain commitments disclosed above.

CONTINGENCIES

The Company is involved in various legal claims and actions arising in the normal course of the Company’s operations. Although the outcome of these claims cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on the Company’s financial position, cash flows or results of operations. Management’s assessment of these matters may change in the future as certain of these matters are in early stages or are subject to a number of uncertainties. For material matters that the Company believes an unfavorable outcome is reasonably possible, the Company discloses the nature and a range of potential exposures. If an unfavorable outcome were to occur, there exists the possibility of a material impact on the Company’s consolidated net earnings or loss for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated. Such accruals are based on the Company’s information known about the matters, estimates of the outcomes of such matters and experience in handling similar matters.

In conjunction with the acquisition of Newfield as described in Note 8, various legal claims and actions arising in the normal course of Newfield’s operations were assumed by the Company. On March 29, 2019, Newfield and its wholly-owned subsidiary entered into an Agreement and Mutual Release with Sapura Energy Berhad, formerly known as SapuraKencana Petroleum Berhad, and Sapura Exploration and Production Inc., formerly known as SapuraKencana Energy Inc. (collectively, “Sapura”) to settle arbitration claims arising from Sapura’s purchase of Newfield’s Malaysian business in February 2014. Under the Agreement and Mutual Release, Newfield and its wholly-owned subsidiary paid Sapura $22.5 million. The settlement amount including legal fees was included in the purchase price allocation as part of the current liabilities assumed by the Company at the acquisition date. Although the outcome of any remaining legal claims and actions assumed by the Company following the acquisition of Newfield cannot be predicted with certainty, the Company does not expect these matters to have a material adverse effect on the Company’s financial position, cash flows or results of operations.

133

28. Subsequent Events

On January 24, 2020 the Company completed the previously announced Reorganization as described in Note 1. Subsequently, Ovintiv Inc. and its subsidiaries continue to carry on the business previously conducted by Encana and its subsidiaries prior to the completion of the Reorganization. Refer to Notes 5, 15 and 18 for certain transactions and impacts associated with the Reorganization.

29. Supplementary Oil and Gas Information (unaudited)

The unaudited supplementary information on oil and gas exploration and production activities for 2019, 2018 and 2017 has been presented in accordance with the FASB’s ASC Topic 932, “Extractive Activities - Oil and Gas” and the SEC’s final rule, “Modernization of Oil and Gas Reporting”. Disclosures by geographic area include the United States and Canada.

Proved Oil and Gas Reserves

The following reserves disclosures reflect estimates of proved reserves, proved developed reserves, and proved undeveloped reserves, net of third-party royalty interests of oil, NGLs and natural gas owned at each year end and changes in proved reserves during each of the last three years.

The Company’s estimates of proved reserves are made using available geological and reservoir data as well as production performance data. These estimates are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. The results of infill drilling are treated as positive revisions due to increases to expected recovery. Other revisions are due to changes in, among other things, development plans, reservoir performance, commodity prices, economic conditions, and government restrictions. Estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.

The following reference prices were utilized in the determination of reserves and future net revenue:

	Oil & NGLs				Natural Gas
	WTI ($/bbl)		Edmonton Condensate (C$/bbl)		Henry Hub ($/MMBtu)		AECO (C$/MMBtu)
Reserves Pricing (1)
2019		55.93		68.80		2.58		1.76
2018		65.56		79.59		3.10		1.49
2017		51.34		67.65		2.98		2.32

(1) All prices were held constant in all future years when estimating net revenues and reserves.

134

PROVED RESERVES ⁽¹⁾

(12-MONTH AVERAGE TRAILING PRICES)

	Oil (MMbbls)									NGLs (MMbbls)									Natural Gas (Bcf)									Total (MMBOE)
	United States			Canada			Total			United States			Canada			Total			United States			Canada			Total
2017
Beginning of year		155.6			-			155.6			56.4			94.0			150.4			1,093			1,810			2,902			789.7
Revisions and improved recovery (2)		(16.0	)		0.2			(15.8	)		(3.6	)		(14.6	)		(18.1	)		(27	)		(31	)		(58	)		(43.6	)
Extensions and discoveries		84.9			0.2			85.1			26.5			46.4			72.9			144			727			871			303.1
Purchase of reserves in place		0.8			-			0.8			0.4			-			0.4			2			-			2			1.5
Sale of reserves in place		(5.4	)		-			(5.4	)		(3.6	)		(0.2	)		(3.8	)		(729	)		(65	)		(795	)		(141.6	)
Production		(27.7	)		(0.2	)		(27.8	)		(8.7	)		(10.6	)		(19.3	)		(97	)		(306	)		(403	)		(114.3	)
End of year		192.3			0.2			192.5			67.5			115.0			182.5			384			2,135			2,519			794.9
Developed		104.7			0.2			104.9			41.6			40.5			82.1			243			1,082			1,325			407.8
Undeveloped		87.7			-			87.7			25.8			74.5			100.3			141			1,053			1,195			387.1
Total		192.3			0.2			192.5			67.5			115.0			182.5			384			2,135			2,519			794.9
2018
Beginning of year		192.3			0.2			192.5			67.5			115.0			182.5			384			2,135			2,519			794.9
Revisions and improved recovery (2)		19.5			0.2			19.7			14.2			(17.4	)		(3.2	)		37			249			285			64.1
Extensions and discoveries		162.4			-			162.4			48.6			78.9			127.4			233			885			1,118			476.2
Purchase of reserves in place		21.3			-			21.3			7.7			-			7.7			39			-			39			35.5
Sale of reserves in place		(11.4	)		-			(11.4	)		(5.1	)		-			(5.1	)		(40	)		-			(40	)		(23.1	)
Production		(32.7	)		(0.1	)		(32.8	)		(10.6	)		(18.0	)		(28.5	)		(55	)		(368	)		(423	)		(131.9	)
End of year		351.5			0.2			351.8			122.3			158.5			280.8			598			2,901			3,499			1,215.7
Developed		150.6			0.2			150.9			59.4			60.8			120.2			295			1,707			2,002			604.7
Undeveloped		200.9			-			200.9			62.8			97.8			160.6			302			1,195			1,497			611.0
Total		351.5			0.2			351.8			122.3			158.5			280.8			598			2,901			3,499			1,215.7
2019
Beginning of year		351.5			0.2			351.8			122.3			158.5			280.8			598			2,901			3,499			1,215.7
Revisions and improved recovery (2)		(56.4	)		0.8			(55.6	)		3.1			(20.2	)		(17.1	)		(31	)		(484	)		(515	)		(158.7	)
Extensions and discoveries		230.2			0.4			230.6			96.0			62.4			158.4			521			777			1,298			605.3
Purchase of reserves in place		262.0			-			262.0			217.2			-			217.2			1,904			-			1,904			796.6
Sale of reserves in place		(5.1	)		-			(5.1	)		(0.5	)		-			(0.5	)		(351	)		-			(351	)		(64.1	)
Production		(59.8	)		(0.2	)		(60.0	)		(28.6	)		(21.6	)		(50.2	)		(200	)		(376	)		(576	)		(206.2	)
End of year		722.4			1.3			723.7			409.4			179.1			588.5			2,441			2,818			5,259			2,188.8
Developed		291.0			1.2			292.2			211.3			68.4			279.8			1,375			1,439			2,815			1,041.1
Undeveloped		431.4			0.1			431.5			198.1			110.7			308.8			1,066			1,378			2,444			1,147.7
Total		722.4			1.3			723.7			409.4			179.1			588.5			2,441			2,818			5,259			2,188.8

(1) Numbers may not add due to rounding.

(2) Changes in reserve estimates resulting from application of improved recovery techniques are included in revisions of previous estimates.

Definitions:

a. “Proved” oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations.  

b. “Developed” oil and gas reserves are reserves of any category that are expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

c. “Undeveloped” oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

135

Total Proved reserves increased 973.1 MMBOE including production of 206.2 MMBOE in 2019 due to the following:

• Revisions and improved recovery of oil, NGLs and natural gas were negative primarily due to changes in the approved development plan of 97.5 MMBOE and lower 12-month average trailing oil and NGL prices of 118.4 MMBOE, partially offset by positive performance revisions of 57.3 MMBOE resulting from well performance and development strategy.

• Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 605.3 MMBOE due to the extension of proved acreage primarily from successful drilling and delineation in the Permian, Anadarko, Montney, Eagle Ford, Bakken and Duvernay assets.

• Purchases of 796.6 MMBOE were primarily in the acquisition of Newfield Exploration.

• Sale of reserves in place decreased proved developed reserves by 64.1 MMBOE primarily due to the divestiture of the Arkoma asset located in Oklahoma.

Total Proved reserves increased 420.8 MMBOE including production of 131.9 MMBOE in 2018 due to the following:

• Revisions and improved recovery of oil, NGLs and natural gas were 64.1 MMBOE primarily due to positive forecast changes of 133.7 MMBOE and higher 12-month average trailing oil and NGL prices of 9.4 MMBOE, partially offset by proved reserves removed due to changes in the approved development plan of 79.0 MMBOE.

• Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 476.2 MMBOE due to the extension of proved acreage primarily from successful drilling and delineation in the Permian, Montney, Eagle Ford and Duvernay assets.

• Purchases of 35.5 MMBOE were primarily in the Permian asset.

• Sale of reserves in place decreased proved developed reserves by 23.1 MMBOE primarily due to the divestiture of the San Juan assets located in northwestern New Mexico.

Total Proved reserves increased 5.2 MMBOE including production of 114.3 MMBOE in 2017 due to the following:

• Revisions and improved recovery of oil, NGLs and natural gas were negative primarily due to negative revisions of 83.3 MMBOE resulting from changes in the approved development plan, which was partially offset by positive revisions of 32.6 MMBOE due to higher 12-month average trailing oil, NGL and natural gas prices.

• Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 303.1 MMBOE due to the extension of proved acreage primarily from successful drilling in the Permian, Montney and Eagle Ford assets.

• Sale of reserves in place decreased proved developed reserves by 141.6 MMBOE primarily due to the divestiture of the Piceance assets located in northwestern Colorado.

136

STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

In calculating the standardized measure of discounted future net cash flows, constant price and cost assumptions were applied to the Company’s annual future production from proved reserves to determine cash inflows. Estimates of future net cash flows from proved reserves are computed based on the average beginning-of-the-month prices during the 12-month period for the year. Future production and development costs include estimates for abandonment and dismantlement costs associated with asset retirement obligations and assume the continuation of existing economic, operating and regulatory conditions. Future income taxes are calculated by applying statutory income tax rates to future pre-tax cash flows after provision for the tax cost of the oil and natural gas properties based upon existing laws and regulations. The effect of tax credits is also considered in determining the income tax expense. The discount was computed by application of a 10 percent discount factor to the future net cash flows.

The Company cautions that the discounted future net cash flows relating to proved oil and gas reserves are an indication of neither the fair market value of the Company’s oil and gas properties, nor the future net cash flows expected to be generated from such properties. The discounted future net cash flows do not include the fair market value of exploratory properties and probable or possible oil and gas reserves, nor is consideration given to the effect of anticipated future changes in oil and natural gas prices, development, asset retirement and production costs, and possible changes to tax and royalty regulations. The prescribed discount rate of 10 percent may not appropriately reflect future interest rates.

	United States						Canada
	2019		2018		2017		2019		2018		2017
Future Cash Inflows	$	46,076	$	26,305	$	11,459	$	10,404	$	12,463	$	7,850
Less Future:
Production costs		13,064		6,399		3,661		4,791		5,231		3,516
Development costs		10,795		4,751		3,042		3,024		2,641		2,058
Income taxes		2,262		1,673		-		-		586		76
Future Net Cash Flows		19,955		13,482		4,756		2,589		4,005		2,200
Less 10% annual discount for estimated    timing of cash flows		9,914		6,532		2,025		1,014		1,351		618
Discounted Future Net Cash Flows	$	10,041	$	6,950	$	2,731	$	1,575	$	2,654	$	1,582

	Total
	2019		2018		2017
Future Cash Inflows	$	56,480	$	38,768	$	19,309
Less Future:
Production costs		17,855		11,630		7,177
Development costs		13,819		7,392		5,100
Income taxes		2,262		2,259		76
Future Net Cash Flows		22,544		17,487		6,956
Less 10% annual discount for estimated    timing of cash flows		10,928		7,883		2,643
Discounted Future Net Cash Flows	$	11,616	$	9,604	$	4,313

137

CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES

	United States									Canada
	2019			2018			2017			2019			2018			2017
Balance, Beginning of Year	$	6,950		$	2,731		$	1,236		$	2,654		$	1,582		$	439
Changes Resulting From:
Sales of oil and gas produced during the year		(3,051	)		(1,753	)		(1,291	)		(865	)		(859	)		(471	)
Discoveries and extensions, net of related costs		2,893			3,300			1,141			544			1,130			582
Purchases of proved reserves in place		5,581			468			13			-			-			-
Sales and transfers of proved reserves in place		(931	)		(202	)		(413	)		-			-			(12	)
Net change in prices and production costs		(2,471	)		1,642			2,183			(1,008	)		407			893
Revisions to quantity estimates		(850	)		526			(203	)		(550	)		121			(22	)
Accretion of discount		749			273			124			297			164			44
Development costs incurred during the year		2,115			1,315			1,366			545			665			454
Changes in estimated future development costs		(885	)		(824	)		(1,433	)		(364	)		(303	)		(279	)
Other		-			16			8			1			15			7
Net change in income taxes		(59	)		(542	)		-			321			(268	)		(53	)
Balance, End of Year	$	10,041		$	6,950		$	2,731		$	1,575		$	2,654		$	1,582

	Total
	2019			2018			2017
Balance, Beginning of Year	$	9,604		$	4,313		$	1,675
Changes Resulting From:
Sales of oil and gas produced during the year		(3,916	)		(2,612	)		(1,762	)
Discoveries and extensions, net of related costs		3,437			4,430			1,723
Purchases of proved reserves in place		5,581			468			13
Sales and transfers of proved reserves in place		(931	)		(202	)		(425	)
Net change in prices and production costs		(3,479	)		2,049			3,076
Revisions to quantity estimates		(1,400	)		647			(225	)
Accretion of discount		1,046			437			168
Development costs incurred during the year		2,660			1,980			1,820
Changes in estimated future development costs		(1,249	)		(1,127	)		(1,712	)
Other		1			31			15
Net change in income taxes		262			(810	)		(53	)
Balance, End of Year	$	11,616		$	9,604		$	4,313

138

RESULTS OF OPERATIONS

The following table sets forth revenue and direct cost information relating to the Company’s oil and gas exploration and production activities.

	United States						Canada
	2019		2018		2017		2019		2018		2017
Oil, NGL and Natural Gas Revenues, Net of    Transportation and Processing	$	3,855	$	2,189	$	1,714	$	1,006	$	993	$	613
Less:
Operating costs, production, mineral and other taxes,    and accretion of asset retirement obligation		819		445		438		162		157		164
Depreciation, depletion and amortization		1,593		860		530		383		361		236
Operating Income (Loss)		1,443		884		746		461		475		213
Income Taxes		352		191		161		111		128		58
Results of Operations	$	1,091	$	693	$	585	$	350	$	347	$	155

	China (1)						Total
	2019		2018		2017		2019		2018		2017
Oil, NGL and Natural Gas Revenues, Net of    Transportation and Processing	$	37	$	-	$	-	$	4,898	$	3,182	$	2,327
Less:
Operating costs, production, mineral and other taxes,    and accretion of asset retirement obligation		17		-		-		998		602		602
Depreciation, depletion and amortization		-		-		-		1,976		1,221		766
Operating Income (Loss)		20		-		-		1,924		1,359		959
Income Taxes		4		-		-		467		319		219
Results of Operations	$	16	$	-	$	-	$	1,457	$	1,040	$	740

(1) The Company terminated its production sharing contract with CNOOC and exited its China Operations effective July 31, 2019.

CAPITALIZED COSTS

Capitalized costs include the cost of properties, equipment and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds where no proved reserves have been identified.

	United States						Canada
	2019		2018		2017		2019		2018		2017
Proved Oil and Gas Properties	$	35,870	$	27,189	$	25,610	$	15,284	$	13,996	$	14,555
Unproved Oil and Gas Properties		3,491		3,493		4,169		223		237		311
Total Capital Cost		39,361		30,682		29,779		15,507		14,233		14,866
Accumulated DD&A		25,623		24,099		23,240		14,320		13,261		14,047
Net Capitalized Costs	$	13,738	$	6,583	$	6,539	$	1,187	$	972	$	819

	Other						Total
	2019		2018		2017		2019		2018		2017
Proved Oil and Gas Properties	$	56	$	56	$	63	$	51,210	$	41,241	$	40,228
Unproved Oil and Gas Properties		-		-		-		3,714		3,730		4,480
Total Capital Cost		56		56		63		54,924		44,971		44,708
Accumulated DD&A		56		56		63		39,999		37,416		37,350
Net Capitalized Costs	$	-	$	-	$	-	$	14,925	$	7,555	$	7,358

139

COSTS INCURRED

Costs incurred includes both capitalized costs and costs charged to expense when incurred. Costs incurred also includes internal costs directly related to acquisition, exploration, and development activities, new asset retirement costs established in the current year as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year.

	United States						Canada
	2019		2018		2017		2019		2018		2017
Acquisition Costs
Unproved	$	5	$	-	$	21	$	-	$	17	$	31
Proved		60		-		2		-		-		-
Total Acquisition Costs		65		-		23		-		17		31
Exploration Costs		5		2		4		-		1		1
Development Costs		2,129		1,330		1,354		480		631		425
Total Costs Incurred	$	2,199	$	1,332	$	1,381	$	480	$	649	$	457

	Total
	2019		2018		2017
Acquisition Costs
Unproved	$	5	$	17	$	52
Proved		60		-		2
Total Acquisition Costs		65		17		54
Exploration Costs		5		3		5
Development Costs		2,609		1,961		1,779
Total Costs Incurred	$	2,679	$	1,981	$	1,838

COSTS NOT SUBJECT TO DEPLETION OR AMORTIZATION

Upstream costs in respect of significant unproved properties are excluded from the country cost center’s depletable base as follows:

As at December 31	2019		2018
United States	$	3,491	$	3,493
Canada		223		237
	$	3,714	$	3,730

The following is a summary of the costs related to unproved properties as at December 31, 2019:

	2019		2018		2017		Prior to 2017		Total
Acquisition Costs	$	948	$	223	$	240	$	2,162	$	3,573
Exploration Costs		3		18		2		118		141
	$	951	$	241	$	242	$	2,280	$	3,714

Acquisition costs primarily include costs incurred to acquire or lease properties. Exploration costs primarily include costs related to geological and geophysical studies and costs of drilling and equipping exploratory wells. Ultimate recoverability of these costs and the timing of inclusion within the applicable country cost center’s depletable base is dependent upon either the finding of proved oil, NGL and natural gas reserves, expiration of leases or recognition of impairments.

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Included in the $3.7 billion of oil and gas properties not subject to depletion or amortization are acquired leasehold and mineral costs of approximately $3.5 billion related to the acquisition of Permian, Anadarko, Bakken and Uinta. These acquisition costs are associated with acquired acreage for which proved reserves have yet to be assigned from future development. The Company continually assesses the development timeline of the acquired acreage. The timing and amount of the transfer of property acquisition costs into the depletable base are based on several factors and may be subject to changes over time from drilling plans, drilling results, availability of capital, project economics and other assessments of the property. The inclusion of these acquisition costs in the depletable base is expected to occur within three to eight years. The remaining costs excluded from depletion are related to properties which are not individually significant.

30. Supplemental Quarterly Financial Information (unaudited)

The following summarizes quarterly financial data for the fiscal years of 2019 and 2018:

	2019
(US$ millions, except per share amounts)	Q4			Q3		Q2		Q1
Revenues	$	1,565		$	1,871	$	2,055	$	1,235
Operating Income (Loss)		(28	)		315		538		(227	)
Net Earnings (Loss) Before Income Tax	$	(68	)	$	192	$	497	$	(306	)
Income Tax Expense (Recovery)		(62	)		43		161		(61	)
Net Earnings (Loss)	$	(6	)	$	149	$	336	$	(245	)
Net Earnings (Loss) per Common Share - Basic & Diluted (1)	$	(0.02	)	$	0.56	$	1.22	$	(1.00	)

	2018
(US$ millions, except per share amounts)	Q4		Q3		Q2			Q1
Revenues	$	2,381	$	1,262	$	983		$	1,313
Operating Income (Loss)		1,354		119		(116	)		337
Net Earnings (Loss) Before Income Tax	$	1,179	$	45	$	(221	)	$	160
Income Tax Expense (Recovery)		149		6		(70	)		9
Net Earnings (Loss)	$	1,030	$	39	$	(151	)	$	151
Net Earnings (Loss) per Common Share - Basic & Diluted (1)	$	5.41	$	0.20	$	(0.79	)	$	0.78

(1) Net earnings (loss) per common share reflects the Share Consolidation as described in Note 1.

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Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

The financial statements for the fiscal years ended December 31, 2019, 2018, and 2017, included in this Annual Report on Form 10-K, have been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their audit report appearing herein. There have been no changes in or disagreements with the accountants during the periods presented.

Item 9A: Controls and Procedures

EVALUATION AND DISCLOSURE CONTROLS AND PROCEDURES

The Company’s Chief Executive Officer and Chief Financial Officer performed an evaluation of the Company’s disclosure controls and procedures as defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. The Company’s disclosure controls and procedures are designed to ensure that information required to be disclosed by the Company in reports it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is accumulated and communicated to the Company’s management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure. Based on this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures are effective as of December 31, 2019.

The Company previously limited the scope and design and subsequent evaluation of internal controls over financial reporting to exclude the controls, policies and procedures of Newfield, acquired through a business combination on February 13, 2019. During the fourth quarter of 2019, the Company completed the evaluation and integration of the controls, policies and procedures of Newfield and no material weaknesses were noted during the integration. There have been no changes to the Company’s internal control over financial reporting during the fourth quarter of 2019 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

See “Management’s Assessment of Internal Control Over Financial Reporting” under Item 8 of this Annual Report on Form 10-K.

ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM

See “Report of Independent Registered Public Accounting Firm” under Item 8 of this Annual Report on Form 10-K.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

There were no changes in the Company’s internal control over financial reporting during the fourth quarter of 2019 that materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting. See “Management’s Assessment of Internal Control Over Financial Reporting” under Item 8 of this Annual Report on Form 10-K.

Item 9B. Other Information

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

DIRECTORS AND EXECUTIVE OFFICERS

Information regarding the Board of Directors is set forth in the Proxy Statement relating to the Company’s 2020 annual meeting of stockholders, which is incorporated herein by reference.

Information regarding the Company’s executive officers is set forth in the section entitled “Executive Officers of the Registrant” under Items 1 and 2 of this Annual Report on Form 10-K.

CODE OF ETHICS

Ovintiv has adopted a code of ethics entitled the “Business Code of Conduct” (the “Code of Ethics”), that applies to its principal executive officer, principal financial officer, principal accounting officer or controller, and persons performing similar functions. The Code of Ethics is available for viewing on Ovintiv’s website at www.ovintiv.com, and is available in print to any stockholder who requests it. Requests for copies of the Code of Ethics should be made by contacting Ovintiv’s Corporate Secretary by mail at Suite 1700, 370 17^th Street, Denver, Colorado, 80202, U.S.A. or by telephone at (303) 623-2300. Ovintiv intends to disclose and summarize any amendment to, or waiver from, any provision of the Code of Ethics that is required to be so disclosed and summarized, on its website at www.ovintiv.com.

Item 11. Executive Compensation

The information required by this Item 11 is set forth in the Proxy Statement relating to the Company’s 2020 annual meeting of stockholders, which is incorporated herein by reference.

The executive compensation and related information incorporated by reference herein shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or Exchange Act, except to the extent that the Company specifically incorporates it by reference into such filing.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by this Item 12 is set forth in the Proxy Statement relating to the Company’s 2020 annual meeting of stockholders, which is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this Item 13 is set forth in the Proxy Statement relating to the Company’s 2020 annual meeting of stockholders, which is incorporated herein by reference.

Item 14. Principal Accounting Fees and Services

The information required by this Item 14 is set forth in the Proxy Statement relating to the Company’s 2020 annual meeting of stockholders, which is incorporated herein by reference.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

The following documents are filed as part of this Annual Report on Form 10-K or incorporated by reference:

1. Consolidated Financial Statements

Reference is made to the Consolidated Financial Statements and notes thereto appearing in Item 8 of this Annual Report on Form 10-K.

2. Consolidated Financial Statement Schedules

All financial statement schedules are omitted as they are inapplicable, or the required information has been included in the Consolidated Financial Statements or notes thereto.

3. Exhibits

Exhibits are listed in the exhibit index below. The exhibits include management contracts, compensatory plans and arrangements required to be filed as exhibits to the Annual Report on Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

Exhibit No	Description
2.1	Arrangement and Reorganization Agreement dated October 31, 2019 between Encana Corporation and 1847432 Alberta ULC (incorporated by reference to Exhibit 2.1 to Encana’s Current Report on Form 8-K filed on November 5, 2019, SEC File No. 001-15226).
3.1	Ovintiv Certificate of Incorporation (incorporated by reference to Exhibit 3.1 to Ovintiv’s Current Report on Form 8-K filed on January 24, 2020, SEC File No. 333-234526).
3.2	Ovintiv Bylaws (incorporated by reference to Exhibit 3.2 to Ovintiv’s Current Report on Form 8-K filed on January 24, 2020, SEC File No. 333-234526).
4.1	Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 to Ovintiv’s Current Report on Form 8-K filed on January 24, 2020, SEC File No. 333-234526).
4.2	3.90% Notes due 2021 (incorporated by reference to Exhibit 4.4 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.3	8.125% Notes due 2030 (incorporated by reference to Exhibit 4.5 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.4	7.2% Notes due 2031 (incorporated by reference to Exhibit 4.6 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.5	7.375% Notes due 2031 (incorporated by reference to Exhibit 4.7 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.6	6.50% Notes due 2034 (incorporated by reference to Exhibit 4.8 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.7	6.625% Notes due 2037 (incorporated by reference to Exhibit 4.9 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.8	6.50% Notes due 2038 (incorporated by reference to Exhibit 4.10 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.9	5.15% Notes due 2041 (incorporated by reference to Exhibit 4.11 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.10	Indenture dated as of August 13, 2007 between Encana Corporation and The Bank of New York (incorporated by reference to Exhibit 4.12 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.11	Indenture dated as of November 14, 2011 between Encana Corporation and The Bank of New York Mellon (incorporated by reference to Exhibit 7.1 to Encana’s Registration Statement on Form F-10 filed on May 7, 2012, SEC File No. 333-181196).
4.12	Indenture dated as of September 15, 2000 between Encana Corporation (as successor by amalgamation to Alberta Energy Company Ltd.) and The Bank of New York (incorporated by reference to Exhibit 4.14 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.13	First Supplemental Indenture dated as of January 1, 2003 to the Indenture dated as of September 15, 2000 between Encana Corporation and The Bank of New York (incorporated by reference to Exhibit 4.15 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.14	Second Supplemental Indenture dated as of November 20, 2012 to the Indenture dated as of September 15, 2000 between Encana Corporation and The Bank of New York (incorporated by reference to Exhibit 4.16 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).

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4.15	Indenture dated as of November 5, 2001 between Encana Corporation (as successor by amalgamation to PanCanadian Petroleum Limited) and The Bank of Nova Scotia Trust Company of New York (incorporated by reference to Exhibit 4.17 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.16	First Supplemental Indenture dated as of January 1, 2002 to the Indenture dated as of November 5, 2001 between Encana Corporation (as successor by amalgamation to PanCanadian Petroleum Limited) and The Bank of Nova Scotia Trust Company of New York (incorporated by reference to Exhibit 4.18 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.17	Second Supplemental Indenture dated as of January 1, 2003 to the Indenture dated as of November 5, 2001 between Encana Corporation and The Bank of Nova Scotia Trust Company of New York (incorporated by reference to Exhibit 4.19 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.18	Third Supplemental Indenture dated as of November 20, 2012 to the Indenture dated as of November 5, 2001 between Encana Corporation and The Bank of Nova Scotia Trust Company of New York (incorporated by reference to Exhibit 4.20 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.19	Fourth Supplemental Indenture dated as of July 24, 2013 to the Indenture dated as of November 5, 2001 between Encana Corporation and The Bank of Nova Scotia Trust Company of New York (incorporated by reference to Exhibit 4.21 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.20	Indenture dated as of October 2, 2003 between Encana Corporation and The Bank of New York (incorporated by reference to Exhibit 4.22 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
4.21	Senior Indenture, dated as of February 28, 2001 between Newfield Exploration Company, as Issuer, and First Union National Bank, as Trustee (the “Senior Indenture”) (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed on February 28, 2001, SEC File No. 001-12534).
4.22	Second Supplemental Indenture, dated as of September 30, 2011, to Senior Indenture between Newfield Exploration Company and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee (incorporated by reference to Exhibit 4.2 to Newfield’s Current Report on Form 8-K filed on September 30, 2011, SEC File No. 001-12534).
4.23	Third Supplemental Indenture, dated as of June 26, 2012, to Senior Indenture between Newfield Exploration Company and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee (incorporated by reference to Exhibit 4.2 to Newfield’s Current Report on Form 8-K filed on June 26, 2012, SEC File No. 001-12534).
4.24	Fourth Supplemental Indenture, dated as of March 10, 2015, to Senior Indenture between Newfield Exploration Company and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee (incorporated by reference to Exhibit 4.2 to Newfield’s Current Report on Form 8-K filed on March 12, 2015, SEC File No. 001-12534).
4.25	Fifth Supplemental Indenture, dated as of March 1, 2019, among Encana Corporation, as Guarantor, Newfield Exploration Company, as Issuer, and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee, to the Senior Indenture (incorporated by reference to Exhibit 4.5 to Encana’s Current Report on Form 8-K filed on March 1, 2019, SEC File No. 001-15226).
4.26	Third Supplemental Indenture, dated as of March 1, 2019, among Newfield Exploration Company, as Guarantor, Encana Corporation, as Issuer, and The Bank of New York Mellon to the Indenture, dated as of September 15, 2000, between Encana Corporation (as successor by amalgamation to Alberta Energy Company Ltd.) and The Bank of New York Mellon (formerly known as The Bank of New York), as Trustee (incorporated by reference to Exhibit 4.6 to Encana’s Current Report on Form 8-K filed on March 1, 2019, SEC File No. 001-15226).
4.27	First Supplemental Indenture, dated as of March 1, 2019, among Newfield Exploration Company, as Guarantor, Encana Corporation, as Issuer, and The Bank of New York Mellon to the Indenture, dated as of October 2, 2003, between Encana Corporation and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.7 to Encana’s Current Report on Form 8-K filed on March 1, 2019, SEC File No. 001-15226).
4.28	Fifth Supplemental Indenture, dated as of March 1, 2019, among Newfield Exploration Company, as Guarantor, Encana Corporation, as Issuer, and The Bank of New York Mellon to the Indenture, dated as of November  5, 2001, between Encana Corporation (as successor by amalgamation to PanCanadian Petroleum Limited) and The Bank of New York Mellon, as successor Trustee to The Bank of Nova Scotia Trust Company of New York (incorporated by reference to Exhibit 4.8 to Encana’s Current Report on Form 8-K filed on March 1, 2019, SEC File No. 001-15226).
4.29	First Supplemental Indenture, dated as of March 1, 2019, among Newfield Exploration Company, as Guarantor, Encana Corporation, as Issuer, and The Bank of New York Mellon to the Indenture, dated as of August 13, 2007, between Encana Corporation and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.9 to Encana’s Current Report on Form 8-K filed on March 1, 2019, SEC File No. 001-15226).

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4.30	First Supplemental Indenture, dated as of March 1, 2019, among Newfield Exploration Company, as Guarantor, Encana Corporation, as Issuer, and The Bank of New York Mellon to the Indenture, dated as of November 14, 2011, between Encana Corporation and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.10 to Encana’s Current Report on Form 8-K filed on March 1, 2019, SEC File No. 001-15226).
4.31	Fourth Supplemental Indenture, dated as of January 24, 2020, among Ovintiv Inc., as successor issuer, Encana Corporation, Newfield Exploration Company, as Guarantor, and The Bank of New York Mellon to the Indenture, dated as of September 15, 2000, between Encana Corporation (as successor by amalgamation to Alberta Energy Company Ltd.) and The Bank of New York Mellon (formerly known as The Bank of New York), as Trustee (incorporated by reference to Exhibit 4.1 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).
4.32	Second Supplemental Indenture, dated as of January 24, 2020, among Ovintiv Inc., as successor issuer, Encana Corporation, Newfield Exploration Company, as Guarantor, and The Bank of New York Mellon to the Indenture, dated as of October 2, 2003, between Encana Corporation and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.2 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).
4.33	Sixth Supplemental Indenture, dated as of January 24, 2020, among Ovintiv Inc., as successor issuer, Encana Corporation, Newfield Exploration Company, as Guarantor, and The Bank of New York Mellon to the Indenture, dated as of November 5, 2001, between Encana Corporation (as successor by amalgamation to PanCanadian Petroleum Limited) and The Bank of New York Mellon, as successor Trustee to The Bank of Nova Scotia Trust Company of New York (incorporated by reference to Exhibit 4.3 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).
4.34	Second Supplemental Indenture, dated as of January 24, 2020, among Ovintiv Inc., as successor issuer, Encana Corporation, Newfield Exploration Company, as Guarantor, and The Bank of New York Mellon to the Indenture, dated as of August 13, 2007, between Encana Corporation and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.4 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).
4.35	Second Supplemental Indenture, dated as of January 24, 2020, among Ovintiv Inc., as successor issuer, Encana Corporation, Newfield Exploration Company, as Guarantor, and The Bank of New York Mellon to the Indenture, dated as of November 14, 2011, between Encana Corporation and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.5 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).
4.36	Sixth Supplemental Indenture, dated as of January 27, 2020, among Ovintiv Inc., as Guarantor, Newfield Exploration Company, as Issuer, Ovintiv Canada ULC, as Guarantor, and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee, to the Senior Indenture (incorporated by reference to Exhibit 4.1 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).
4.37	Fifth Supplemental Indenture, dated as of January 27, 2020, among Ovintiv Canada ULC, as Guarantor, Ovintiv Inc., as Issuer, Newfield Exploration Company, as Guarantor, and The Bank of New York Mellon to the Indenture, dated as of September 15, 2000, between Ovintiv Inc. (as successor issuer) and The Bank of New York Mellon (formerly known as The Bank of New York), as Trustee (incorporated by reference to Exhibit 4.2 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).
4.38	Third Supplemental Indenture, dated as of January 27, 2020, among Ovintiv Canada ULC, as Guarantor, Ovintiv Inc., as Issuer, Newfield Exploration Company, as Guarantor, and The Bank of New York Mellon to the Indenture, dated as of October 2, 2003, between Ovintiv Inc. (as successor issuer) and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.3 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).
4.39	Seventh Supplemental Indenture, dated as of January 27, 2020, among Ovintiv Canada ULC, as Guarantor, Ovintiv Inc., as Issuer, Newfield Exploration Company, as Guarantor, and The Bank of New York Mellon to the Indenture, dated as of November 5, 2001, between Ovintiv Inc. (as successor issuer) and The Bank of New York Mellon, as successor Trustee to The Bank of Nova Scotia Trust Company of New York (incorporated by reference to Exhibit 4.4 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).
4.40	Third Supplemental Indenture, dated as of January 27, 2020, among Ovintiv Canada ULC, as Guarantor, Ovintiv Inc., as Issuer, Newfield Exploration Company, as Guarantor, and The Bank of New York Mellon to the Indenture, dated as of August 13, 2007, between Ovintiv Inc. (as successor issuer) and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.5 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).
4.41	Third Supplemental Indenture, dated as of January 27, 2020, among Ovintiv Canada ULC, as Guarantor, Ovintiv Inc., as Issuer, Newfield Exploration Company, as Guarantor, and The Bank of New York Mellon to the Indenture, dated as of November 14, 2011, between Ovintiv Inc. (as successor issuer) and The Bank of New York Mellon, as Trustee (incorporated by reference to Exhibit 4.6 to Ovintiv’s Current Report on Form 8-K filed on January 28, 2020, SEC File No. 001-39191).

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4.42	Description of Capital Stock (incorporated by reference to Exhibit 99.1 to Ovintiv’s Current Report on Form 8-K filed on January 24, 2020, SEC File No. 001-39191).
10.1	Credit Agreement, dated as of January  27, 2020, between Ovintiv Inc., as Borrower, JPMorgan Chase Bank, N.A., RBC Capital Markets, Canadian Imperial Bank of Commerce, Citibank, N.A., TD Securities, as Joint Lead Arrangers and Joint Bookrunners, BMO Capital Markets and The Bank of Nova Scotia, as Joint Lead Arrangers, Bank of Montreal and The Bank of Nova Scotia, as Documentation Agents, JPMorgan Chase Bank, N.A., as Administrative Agent, and the initial lenders and initial issuing banks named therein (the “U.S. Credit Agreement”) (incorporated by reference to Exhibit 4.1 to Ovintiv’s Current Report on Form 8-K filed on January 29, 2020, SEC File No. 001-39191).
10.2	Guarantee of the U.S. Credit Agreement, made as of January 27, 2020, by Newfield Exploration Company (incorporated by reference to Exhibit 4.2 to Ovintiv’s Current Report on Form 8-K filed on January 29, 2020, SEC File No. 001-39191).
10.3	Guarantee of the U.S. Credit Agreement, made as of January 27, 2020, by Ovintiv Canada ULC (incorporated by reference to Exhibit 4.3 to Ovintiv’s Current Report on Form 8-K filed on January 29, 2020, SEC File No. 001-39191).
10.4	Credit Agreement, dated as of January 27, 2020, among Ovintiv Canada ULC, as Borrower, Ovintiv Inc., as Guarantor, the financial institutions party thereto, as lenders, and Royal Bank of Canada, as administrative agent (incorporated by reference to Exhibit 4.4 to Ovintiv’s Current Report on Form 8-K filed on January 29, 2020, SEC File No. 001-39191).
10.5	Guarantee, dated as of March 1, 2019, by Newfield Exploration Company, guaranteeing Encana Corporation’s obligations under Encana Corporation’s Restated Credit Agreement, dated as of July  16, 2015, among Encana Corporation, as borrower, the financial and other institutions named therein, as lenders, and Royal Bank of Canada, as agent, as amended by the First Amending Agreement dated as of March 28, 2018 (incorporated by reference to Exhibit 4.11 to Encana’s Current Report on Form 8-K filed on March 1, 2019, SEC File No. 001-15226).
10.6	Form of Commercial Paper Dealer Agreement between Ovintiv Inc., as Issuer, and the Dealer party thereto (incorporated by reference to Exhibit 10.1 to Ovintiv’s Current Report on Form 8-K filed on January 29, 2020, SEC File No. 001-39191).
10.7	Form of Commercial Paper Dealer Agreement among Ovintiv Canada ULC, as Issuer, Ovintiv Inc., as Guarantor, and the Dealer party thereto (incorporated by reference to Exhibit 10.2 to Ovintiv’s Current Report on Form 8-K filed on January 29, 2020, SEC File No. 001-39191).
10.8*	Encana Corporation Employee Stock Option Plan reflective with amendments made as of April 27, 2005, as of April 25, 2007, as of April 22, 2008, as of October 22, 2008, as of November 30, 2009, as of July 20, 2010, as of February 24, 2015 and as of February 22, 2016 (incorporated by reference to Exhibit 10.6 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.9*	Form of Executive Stock Option Grant Agreement for stock options granted under the Encana Corporation Employee Stock Option Plan (incorporated by reference to Exhibit 10.7 to Encana’s Annual Report on Form 10-K filed on February 26, 2018, SEC File No. 001-15226).
10.10*	Encana Corporation Employee Stock Appreciation Rights Plan, adopted with effect from February 12, 2008, as amended December 9, 2008, November 30, 2009, April 20, 2010, July 20, 2010, February 24, 2015, February 22, 2016 and February 14, 2018 (incorporated by reference to Exhibit 10.8 to Encana’s Annual Report on Form 10-K filed on February 26, 2018, SEC File No. 001-15226).
10.11*	Form of Executive Stock Appreciation Rights Grant Agreement for stock appreciation rights granted under the Encana Corporation Employee Stock Appreciation Rights Plan (incorporated by reference to Exhibit 10.9 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.12*	Performance Share Unit Plan for Employees of Encana Corporation amended and restated with effect from January 1, 2010, and reflective with amendments made as of July 20, 2010, February 24, 2015, February 22, 2016 and February 14, 2018 (incorporated by reference to Exhibit 10.10 to Encana’s Annual Report on Form 10-K filed on February 26, 2018, SEC File No. 001-15226).
10.13*	Form of Canadian Executive PSU Grant Agreement for performance share units granted under the Performance Share Unit Plan for Employees of Encana Corporation (incorporated by reference to Exhibit 10.11 to Encana’s Annual Report on Form 10-K filed on February 26, 2018, SEC File No. 001-15226).
10.14*	Form of U.S. Executive PSU Grant Agreement for performance share units granted under the Performance Share Unit Plan for Employees of Encana Corporation (incorporated by reference to Exhibit 10.12 to Encana’s Annual Report on Form 10-K filed on February 26, 2018, SEC File No. 001-15226).
10.15*	Restricted Share Unit Plan for Employees of Encana Corporation established with effect from February 8, 2011, and reflective with amendments made as of February 24, 2015, February 22, 2016 and February 14, 2018 (incorporated by reference to Exhibit 10.13 to Encana’s Annual Report on Form 10-K filed on February 26, 2018, SEC File No. 001-15226).
10.16*	Form of Canadian Executive RSU Grant Agreement for restricted share units granted under the Restricted Share Unit Plan for Employees of Encana Corporation (incorporated by reference to Exhibit 10.14 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).

147

10.17*	Form of U.S. Executive RSU Grant Agreement for restricted share units granted under the Restricted Share Unit Plan for Employees of Encana Corporation (incorporated by reference to Exhibit 10.15 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.18*	Deferred Share Unit Plan for Employees of Encana Corporation adopted with effect from December 18, 2002 and reflective of amendments made as of October 23, 2007, October 22, 2008, and July 20, 2010 (incorporated by reference to Exhibit 10.16 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.19*	Deferred Share Unit Plan for Directors of Encana Corporation adopted with effect from December 18, 2002 and reflective with amendments made as of April 26, 2005, October 22, 2008, December 8, 2009, July 20, 2010, February 13, 2013, December 1, 2014 and February 14, 2018 (incorporated by reference to Exhibit 10.17 to Encana’s Annual Report on Form 10-K filed on February 26, 2018, SEC File No. 001-15226).
10.20*	Restricted Share Unit Plan for Directors of Encana Corporation effective February 14, 2018 (incorporated by reference to Exhibit 10.38 to Encana’s Annual Report on Form 10-K filed on February 26, 2018, SEC File No. 001-15226).
10.21*	Form of Director RSU Grant Agreement for restricted share units granted under the Restricted Share Unit Plan for Directors of Encana Corporation (incorporated by reference to Exhibit 10.39 to Encana’s Annual Report on Form 10-K filed on February 26, 2018, SEC File No. 001-15226).
10.22*	Omnibus Incentive Plan of Encana Corporation adopted with effect from February 13, 2019 (incorporated by reference to Exhibit 10.44 to Encana’s Annual Report on Form 10-K filed on February 28, 2019, SEC File No. 001-15226).
10.23*	Form of Stock Option Grant Agreement for stock options granted under the Omnibus Incentive Plan of Encana Corporation (incorporated by reference to Exhibit 10.45 to Encana’s Annual Report on Form 10-K filed on February 28, 2019, SEC File No. 001-15226).
10.24*	Form of RSU Grant Agreement for restricted share units granted to employees under the Omnibus Incentive Plan of Encana Corporation (incorporated by reference to Exhibit 10.46 to Encana’s Annual Report on Form 10-K filed on February 28, 2019, SEC File No. 001-15226).
10.25*	Form of Director RSU Grant Agreement for restricted share units granted to directors under the Omnibus Incentive Plan of Encana Corporation (incorporated by reference to Exhibit 10.47 to Encana’s Annual Report on Form 10-K filed on February 28, 2019, SEC File No. 001-15226).
10.26*	Form of PSU Grant Agreement for performance share units granted under the Omnibus Incentive Plan of Encana Corporation (incorporated by reference to Exhibit 10.48 to Encana’s Annual Report on Form 10-K filed on February 28, 2019, SEC File No. 001-15226).
10.27*	Form of Stock Appreciation Rights Grant Agreement for stock appreciation rights granted under the Omnibus Incentive Plan of Encana Corporation (incorporated by reference to Exhibit 10.49 to Encana’s Annual Report on Form 10-K filed on February 28, 2019, SEC File No. 001-15226).
10.28*	Encana Corporation Canadian Pension Plan Amended and Restated as of January 1, 2011 (incorporated by reference to Exhibit 10.26 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.29*	Amendment No. 1 to the Encana Corporation Canadian Pension Plan amended and restated as of January 1, 2011, dated as of May 29, 2014 (incorporated by reference to Exhibit 10.27 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.30*	Amendment No. 2 to the Encana Corporation Canadian Pension Plan amended and restated as of January 1, 2011, dated as of November 24, 2014 (incorporated by reference to Exhibit 10.28 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.31*	Amendment No. 3 to the Encana Corporation Canadian Pension Plan amended and restated as of January 1, 2011, dated as of November 30, 2015 (incorporated by reference to Exhibit 10.29 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.32*	Encana Corporation Canadian Supplemental Pension Plan amended and restated effective April 1, 2015 (incorporated by reference to Exhibit 10.30 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.33*	Encana Corporation Canadian Investment Plan effective September 1, 2002 (incorporated by reference to Exhibit 10.31 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.34*	Encana (USA) Retirement Plan amended and restated effective March 14, 2014 (incorporated by reference to Exhibit 10.32 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.35*	Amendment No. 1 to Encana (USA) Retirement Plan amended and restated effective March 14, 2014, dated May 1, 2014 (incorporated by reference to Exhibit 10.33 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.36*	Amendment No. 2 to Encana (USA) Retirement Plan amended and restated effective March 14, 2014, dated August 7, 2014 (incorporated by reference to Exhibit 10.34 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.37*	Amendment No. 3 to Encana (USA) Retirement Plan amended and restated effective March 14, 2014, dated December 28, 2015 (incorporated by reference to Exhibit 10.35 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).

148

10.38*	Alenco Inc. Deferred Compensation Plan amended and restated effective January 1, 2009 (incorporated by reference to Exhibit 10.36 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.39*	Amendment No. 1 to Alenco Inc. Deferred Compensation Plan amended and restated effective January 1, 2009, effective January 1, 2012 (incorporated by reference to Exhibit 10.37 to Encana’s Annual Report on Form 10-K filed on February 27, 2017, SEC File No. 001-15226).
10.40*	Fourth Amendment to the Encana (USA) Retirement Plan amended and restated effective March 14, 2014, dated May 17, 2018 (incorporated by reference to Exhibit 10.1 to Encana’s Quarterly Report on Form 10-Q filed on August 2, 2018, SEC File No. 001-15226).
10.41*	Encana (USA) Deferred Compensation Plan amended and restated effective April 1, 2018 (incorporated by reference to Exhibit 10.2 to Encana’s Quarterly Report on Form 10-Q filed on August 2, 2018, SEC File No. 001-15226).
10.42*	Retirement arrangements between Encana Corporation and Sherri A. Brillon executed March 22, 2019 (incorporated by reference to Exhibit 10.1 to Encana’s Quarterly Report on Form 10-Q filed on May 2, 2019, SEC File No. 001-15226).
10.43*	Fifth Amendment to the Encana (USA) Retirement Plan amended and restated effective March 14, 2014, dated October 8, 2018 (incorporated by reference to Exhibit 10.3 to Encana’s Quarterly Report on Form 10-Q filed on November 4, 2019, SEC File No. 001-15226).
10.44*	Sixth Amendment to the Encana (USA) Retirement Plan amended and restated effective March 14, 2014, dated August 8, 2019 (incorporated by reference to Exhibit 10.4 to Encana’s Quarterly Report on Form 10-Q filed on November 4, 2019, SEC File No. 001-15226).
10.45*	Amendment No. 4 to the Encana Corporation Canadian Pension Plan amended and restated as of January 1, 2011, dated September 13, 2019 (incorporated by reference to Exhibit 10.5 to Encana’s Quarterly Report on Form 10-Q filed on November 4, 2019, SEC File No. 001-15226).
10.46*	Change in Control Agreement between Ovintiv Inc. and Douglas J. Suttles effective January 24, 2020.
10.47*	Change in Control Agreement between Ovintiv Inc. and Joanne L. Alexander effective January 24, 2020.
10.48*	Change in Control Agreement between Ovintiv Inc. and Corey D. Code effective January 24, 2020.
10.49*	Change in Control Agreement between Ovintiv Inc. and Gregory D. Givens effective January 24, 2020.
10.50*	Change in Control Agreement between Ovintiv Inc. and David G. Hill effective January 24, 2020.
10.51*	Change in Control Agreement between Ovintiv Inc. and Michael G. McAllister effective January 24, 2020.
10.52*	Change in Control Agreement between Ovintiv Inc. and Brendan M. McCracken effective January 24, 2020.
10.53*	Change in Control Agreement between Ovintiv Inc. and Michael Williams effective January 24, 2020.
10.54*	Change in Control Agreement between Ovintiv Inc. and Renee E. Zemljak effective January 24, 2020.
10.55*	Form of Director and Officer Indemnification Agreement effective as of January 24, 2020 between Ovintiv Inc. and each of its directors and officers (incorporated by reference to Exhibit 10.1 to Ovintiv’s Current Report on Form 8-K filed on January 24, 2020, SEC File No. 001-39191).
10.56*	Amending Agreement to Omnibus Incentive Plan of Encana Corporation (incorporated by reference to Exhibit 99.9 to Ovintiv’s Post-Effective Amendment No. 1 filed on January 27, 2020, SEC File No. 333-231248).
10.57*	Amending Agreement to Encana Corporation Employee Stock Option Plan (incorporated by reference to Exhibit 99.10 to Ovintiv’s Post-Effective Amendment No. 1 filed on January 27, 2020, SEC File No. 333-231248).
10.58*	Amending Agreement to Encana Corporation Employee Stock Appreciation Rights Plan (incorporated by reference to Exhibit 99.11 to Ovintiv’s Post-Effective Amendment No. 1 filed on January 27, 2020, SEC File No. 333-231248).
10.59*	Amending Agreement to Performance Share Unit Plan for Employees of Encana Corporation (incorporated by reference to Exhibit 99.12 to Ovintiv’s Post-Effective Amendment No. 1 filed on January 27, 2020, SEC File No. 333-231248).
10.60*	Amending Agreement to Restricted Share Unit Plan for Employees of Encana Corporation (incorporated by reference to Exhibit 99.13 to Ovintiv’s Post-Effective Amendment No. 1 filed on January 27, 2020, SEC File No. 333-231248).
10.61*	Amending Agreement to Deferred Share Unit Plan for Employees of Encana Corporation (incorporated by reference to Exhibit 99.14 to Ovintiv’s Post-Effective Amendment No. 1 filed on January 27, 2020, SEC File No. 333-231248).
10.62*	Amending Agreement to Restricted Share Unit Plan for Directors of Encana Corporation (incorporated by reference to Exhibit 99.15 to Ovintiv’s Post-Effective Amendment No. 1 filed on January 27, 2020, SEC File No. 333-231248).
10.63*	Amending Agreement to Deferred Share Unit Plan for Directors of Encana Corporation (incorporated by reference to Exhibit 99.16 to Ovintiv’s Post-Effective Amendment No. 1 filed on January 27, 2020, SEC File No. 333-231248).
10.64*	Amendment No. 5 to the Encana Corporation Canadian Pension Plan amended and restated as of January 1, 2011, dated as of January 24, 2020.
14.1	Business Code of Conduct effective January 24, 2020.
21.1	Significant Subsidiaries
23.1	Consent of PricewaterhouseCoopers LLP.

149

23.2	Consent of McDaniel & Associates Consultants Ltd.
23.3	Consent of Netherland, Sewell & Associates, Inc.
24.1	Power of Attorney (included on the signature page of this report).
31.1	Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934.
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350.
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350.
99.1	Report of McDaniel & Associates Consultants Ltd.
99.2	Report of Netherland, Sewell & Associates, Inc.
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	Inline XBRL Taxonomy Schema Document.
101.CAL	Inline XBRL Calculation Linkbase Document.
101.LAB	Inline XBRL Label Linkbase Document.
101.DEF	Inline XBRL Definition Linkbase Document.
101.PRE	Inline XBRL Presentation Linkbase Document.
104	The cover page from the Company’s Annual Report on Form 10-K for the year ended December 31, 2019, has been formatted in Inline XBRL.

* Management contract or compensatory arrangement.

Item 16. Form 10-K Summary

None.

150

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

OVINTIV INC.
By:	/s/ Corey D. Code
	Name: Corey D. Code
	Title: Executive Vice-President & Chief Financial Officer

Dated: February 21, 2020

151

SIGNATURES WITH RESPECT TO OVINTIV INC.

POWERS OF ATTORNEY

Each person whose signature appears below hereby constitutes and appoints Douglas J. Suttles and Corey D. Code, and each of them, any of whom may act without the joinder of the other, the true and lawful attorney-in-fact and agent of the undersigned, with full power of substitution and resubstitution, for and in the name, place and stead of the undersigned, in any and all capacities, to sign any and all amendments, including any post-effective amendments, and supplements to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Commission, and hereby grants to such attorney-in-fact and agent, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney-in-fact and agent, or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

This Power of Attorney may be executed in multiple counterparts, each of which shall be deemed an original, but which taken together shall constitute one instrument.

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this Annual Report on Form 10-K has been signed by the following persons in the capacities and on the dates indicated. 

Signature	Capacity	Date
/s/ Clayton H. Woitas Clayton H. Woitas	Chairman of the Board of Directors	February 21, 2020
/s/ Douglas J. Suttles Douglas J. Suttles	Chief Executive Officer and Director (Principal Executive Officer)	February 21, 2020
/s/ Corey D. Code Corey D. Code	Executive Vice-President & Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)	February 21, 2020
/s/ Peter A. Dea Peter A. Dea	Corporate Director	February 21, 2020
/s/ Fred J. Fowler Fred J. Fowler	Corporate Director	February 21, 2020
/s/ Howard J. Mayson Howard J. Mayson	Corporate Director	February 21, 2020
/s/ Lee A. McIntire Lee A. McIntire	Corporate Director	February 21, 2020
/s/ Margaret A. McKenzie Margaret A. McKenzie	Corporate Director	February 21, 2020
/s/ Steven W. Nance Steven W. Nance	Corporate Director	February 21, 2020
/s/ Suzanne P. Nimocks Suzanne P. Nimocks	Corporate Director	February 21, 2020
/s/ Thomas G. Ricks Thomas G. Ricks	Corporate Director	February 21, 2020
/s/ Brian G. Shaw Brian G. Shaw	Corporate Director	February 21, 2020
/s/ Bruce G. Waterman Bruce G. Waterman	Corporate Director	February 21, 2020

152