EDGAR 10-K Filing

Company CIK: 1792580
Filing Year: 2022
Filename: 1792580_10-K_2022_0001564590-22-006978.json

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ITEM 1. BUSINESS
Items 1 and 2. Business and Properties
GENERAL
Ovintiv is a leading North American oil and natural gas exploration and production 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, 2021, all of the Company’s reserves and production were located in North America.
Ovintiv’s principal office is located at 370 - 17th 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 - 17th 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 AND APPROACH
Ovintiv is one of the largest producers of oil, NGLs and natural gas in North America. The Company is committed to safely producing products to drive progress and improve lives with respect and responsibility. Ovintiv’s products provide energy, which in turn supports better education, healthcare and equality opportunities. Ovintiv looks to pioneer innovative ways to provide safe, reliable and affordable energy.
The Company’s culture is unique and underpinned by our values. Ovintiv has a track record of driving efficiency in every part of its business. The Company manages risk by continuously driving efficiency gains, creating optionality from a high-quality multi-basin and multi-product portfolio, building flexibility into commercial agreements and an active fundamentals team that provides commodity price risk management, with results being delivered in a socially and environmentally responsible manner.
Ovintiv aims to be the leading North American producer of oil, NGLs and natural gas by generating free cash flow and delivering quality returns of both cash to shareholders and on the capital the Company invests in its multi-basin portfolio. The pillars that support the execution of the Company’s strategy include:
•
Execution Excellence - The Company is a leader in horizontal drilling utilizing cube development and innovative completions methods that leverage advanced technology. Applicable technologies and operating practices are quickly deployed across the Company’s multi-basin portfolio to achieve a 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. Ovintiv strives to be a leading operator and has a historical track record of safely delivering quality returns through the commodity price cycle.
•
Disciplined Capital Allocation - Ovintiv’s capital investment strategy focuses on a limited number of Core Assets to generate cash flow and quality returns. Ovintiv’s investment strategy is flexible, allowing for capital programs to be quickly right-sized in response to the macro commodity-price environment, which preserves excess cash flow to return to shareholders and maintains balance sheet strength.
In the fourth quarter of 2021, Ovintiv initiated an innovative capital allocation framework, whereby 25 percent of the Company’s Non-GAAP Cash Flow in excess of capital expenditures and base dividend is returned to shareholders. For further information on the capital allocation framework, refer to Item 5 of this Annual Report on Form 10-K.
•
Commercial Acumen & Risk Management - While Ovintiv’s multi-product, multi-basin portfolio and capital investment strategy provide optionality and flexibility, the Company also leverages its innovative supply chain and market fundamentals expertise to support capital allocation and quickly respond in a dynamic commodity price environment. The Company actively monitors and manages market volatility through diversification of price risks and market access risks to enhance margins and returns.
•
Drive Environmental, Social and Corporate Governance Progress - Ovintiv embraces stakeholder and societal expectations to continue to grow and change in response to climate change, diversity, equity, inclusion and governance. Ovintiv believes that strong ESG performance can directly contribute to increased efficiency, economic performance, value creation and sustainability. Since 2005, the Company has published an annual Sustainability Report which communicates Ovintiv’s ESG performance and tracks progress on key issues important to stakeholders. Additional information on Ovintiv’s ESG practices can be found on the Company’s sustainability website at sustainability.ovintiv.com.
As part of the Company’s commitment to foster innovation and drive emissions reductions, Ovintiv has established an emissions reduction task force chaired by the Company’s Chief Operations Engineer with the purpose of identifying and evaluating operational emission reduction opportunities and other environmental improvements. The Company has focused on improving wellsite and completions designs to reduce fluid usage, methane venting and fugitive emissions. Moreover, Ovintiv has looked to foster collaboration with third party partners, such as government and other organizations to knowledge share and further advance future potential emission reduction technology.
In addition, Ovintiv announced a new commitment to reduce Scope 1 and 2 GHG emissions intensity by 50 percent compared to 2019 levels, to be achieved within the next eight years. This new emissions reduction target is also tied to the Company’s employees’ annual compensation program.
The foundation of the Company’s strategy is built upon the following elements:
•
Top Tier Multi-Basin Assets - The Company holds a multi-basin portfolio of prolific oil and liquids rich plays in North America, including: the Permian in west Texas, the Anadarko in west-central Oklahoma and the Montney in northeast British Columbia and northwest Alberta. Ovintiv’s multi-basin portfolio both diversifies risk and provides optionality due to the commodity mix of the Company’s plays and their geographic locations. As of December 31, 2021, the Company’s estimated net proved reserves comprised approximately 25 percent oil, 27 percent NGLs, which includes seven percent plant condensate, and 48 percent natural gas.
•
Financial Strength - The Company has ample access to liquidity to allow the business to be managed through the commodity price cycles.
Currently, the Company has access to committed credit facilities totaling $4 billion maturing in July 2024, at attractive rates. During 2021, Ovintiv reduced total long-term debt by over $2.1 billion and is targeting a Net Debt balance of $3 billion. The Company expects to achieve its Net Debt target in the second half of 2022, assuming commodity prices of $85.00 per barrel for WTI oil and $4.50 per MMBtu for NYMEX natural gas.
•
People and Values - Ovintiv’s core values of one, agile, innovative and driven guide the Company’s actions. The foundational values of integrity, safety, sustainability, trust and respect guide the organization’s behavior and define expectations in the workplace. Ovintiv takes pride not only in what the Company achieves, but also in how its goals are accomplished.
See Management’s Discussion and Analysis of Financial Condition and Results of Operations under Item 7 of this Annual Report on Form 10-K for the impact and response of the coronavirus pandemic during 2021 on the Company.
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: (a) USA Operations; (b) Canadian Operations; and (c) 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: Bakken in North Dakota and Uinta in central Utah. The Company’s Eagle Ford assets in south Texas were sold in the second quarter of 2021.
•
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: Horn River in northeast British Columbia and Wheatland in southern Alberta. The Company’s Duvernay assets in west-central Alberta were sold in the second quarter of 2021.
•
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 to the audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.
OIL AND NATURAL GAS PROPERTIES AND ACTIVITIES
The following map reflects the location of Ovintiv’s North American landholdings and assets.
“Core Assets” refer to plays that have a deep inventory of drilling opportunities and are the primary focus of Ovintiv’s capital investment and development, providing a competitive and efficient profile. Other Upstream Operations comprise base assets that receive limited capital that is directed to maintenance or high margin locations that generate cash flows and returns.
The Company’s plays including, “Permian”, “Anadarko”, “Bakken”, “Uinta”, “Montney”, “Horn River” and “Wheatland” refer to the specific areas and locations in which Ovintiv holds an interest in the acreage.
USA Operations
Overview: In 2021, the USA Operations had total capital investment of approximately $1,125 million, drilled approximately 148 net wells primarily in Permian and Anadarko and production averaged approximately 140.0 Mbbls/d of oil, approximately 78.0 Mbbls/d of NGLs and approximately 490 MMcf/d of natural gas. At December 31, 2021, the USA Operations had an established land position of approximately 929,000 net acres including approximately 152,000 net undeveloped acres. The USA Operations accounted for 66 percent of upstream production revenues, excluding the impacts of hedging, and 63 percent of total proved reserves as at December 31, 2021.
During 2021, the Company divested its Eagle Ford assets, which included approximately 42,000 net acres, for proceeds of $764 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, 2021)
Gross
Net
Gross
Net
Gross
Net
Permian
83%
Anadarko
63%
Other Upstream Operations (2)
Bakken
68%
Uinta
82%
Other (3)
43%
Total USA Operations
1,149
1,485
62%
(1)
Excludes interests in royalty acreage.
(2)
Other Upstream Operations comprises assets that are not part of the Company’s strategic focus.
(3)
Other may include assets where the Company may pursue growth opportunities.
Producing Wells
Oil
Natural Gas
Total
(number of wells at December 31, 2021) (1)
Gross
Net
Gross
Net
Gross
Net
Permian
1,658
1,560
1,671
1,570
Anadarko
1,709
2,166
Other Upstream Operations (2)
Bakken
Uinta
1,432
1,121
1,449
1,130
Other (3)
-
-
Total USA Operations
5,442
3,663
6,055
3,875
(1)
Figures exclude wells capable of producing, but not producing.
(2)
Other Upstream Operations comprises assets that are not part of the Company’s strategic focus.
(3)
Other may include assets where the Company may pursue growth opportunities.
NGLs
Production
Oil
(Mbbls/d)
Plant Condensate
(Mbbls/d)
Other
(Mbbls/d)
Total
(Mbbls/d)
Natural Gas
(MMcf/d)
(average daily)
Permian
68.5
63.2
3.0
2.6
24.6
22.7
27.6
25.3
Anadarko
39.5
43.0
6.2
6.6
35.9
39.2
42.1
45.8
Other Upstream Operations (1)
Eagle Ford (2)
5.8
17.7
0.3
1.0
1.3
4.2
1.6
5.2
Bakken
13.3
16.1
0.8
0.7
5.0
3.6
5.8
4.3
Uinta
12.7
10.7
0.2
0.1
0.6
0.5
0.8
0.6
Other (3)
0.2
0.2
-
0.1
0.1
0.1
0.1
0.2
Total USA Operations
140.0
150.9
10.5
11.1
67.5
70.3
78.0
81.4
(1)
Other Upstream Operations comprises assets that are not part of the Company’s strategic focus.
(2)
Eagle Ford was divested during the second quarter of 2021.
(3)
Other may include assets where the Company may pursue growth opportunities.
Permian
Permian is an oil play located in west Texas in Midland, Martin, Howard, Glasscock and Upton counties. The properties within the play are characterized by exposure of up to 10 potential producing horizons spanning approximately 3,000 feet of stratigraphy or stacked pay, an extensive production history and developed infrastructure. At December 31, 2021, the Company controlled approximately 106,000 net acres in the play. The current focus of development is on the Spraberry and Wolfcamp formations in the Midland basin, where Ovintiv holds a large position. During 2021, the Company drilled 80 horizontal net wells. In 2021, production averaged approximately 68.5 Mbbls/d of oil, approximately 27.6 Mbbls/d of NGLs and approximately 132 MMcf/d of natural gas.
The Company is focused on capturing efficiency improvements and maximizing liquids and natural gas 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. Cost reductions and improved cycle times were also achieved through innovative strategies, including the use of Simul-Frac techniques, which is the process of fracking pairs of wells at the same time instead of a single well, optimization of facility designs and the use of locally sourced wet sand in completions activities. The Company’s focus on innovation and efficiency decreased drilling and completions costs by approximately 10 percent compared to the prior year.
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 12 years with optional renewal terms. In the event of pipeline capacity constraints, Ovintiv’s oil production is trucked by various third parties. 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, Garvin, Grady, Kingfisher, Major, McClain and Stephens 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. The play is characterized by silt, shale and carbonate formations which provide multiple potential oil and natural gas targets making the play ideal for cube development and long laterals. At December 31, 2021, the Company controlled approximately 352,000 net acres in the play, with development currently targeting liquids rich prospects in the Woodford, Springer, Meramec and Caney formations. During 2021, the Company drilled 51 horizontal net wells. In 2021, production averaged approximately 39.5 Mbbls/d of oil, approximately 42.1 Mbbls/d of NGLs and approximately 301 MMcf/d of natural gas.
Since acquiring the asset in February 2019, the Company has significantly reduced cycle times; decreased drilling and completion costs by utilizing cube development, Simul-Frac techniques, and locally sourced wet sand; and enhanced performance through optimizing artificial gas lift. The Company’s focus on innovation and efficiency decreased drilling and completions costs by approximately 39 percent since acquiring the asset in February 2019. In addition to reducing costs, locally sourced wet sand has reduced sand related CO2 emissions as well as airborne silica dust at the workplace and in surrounding communities.
The play has significant existing infrastructure and has ample access to major pricing hubs, including Cushing, Oklahoma, the U.S. Gulf Coast, Mont Belvieu, Texas and Conway, Kansas, and a number of Mid-Continent natural gas pipelines. The Company’s oil and natural gas production is gathered at various production facilities, with the majority of oil subsequently transported to sales points by pipeline or sold at and trucked from tank batteries. The majority of Ovintiv’s acreage and associated production is dedicated to long-term gathering and processing agreements with various third parties, which have remaining terms ranging from three to 10 years.
Other Upstream Operations
Bakken
Bakken is an oil play located primarily in McKenzie and Dunn counties of North Dakota, and in Richland county of Montana. The focus of development includes targets in the Bakken and Three Forks formations. During 2021, the Company continued to focus on maximizing liquids and natural gas recovery through spacing and stacking optimization, improving wellbore design and optimizing completions, which reduced costs and improved well performance.
At December 31, 2021, the Company controlled approximately 72,000 net acres in the play. During 2021, the Company drilled 11 horizontal net wells. Production averaged approximately 13.3 Mbbls/d of oil, approximately 5.8 Mbbls/d of NGLs and approximately 30 MMcf/d of natural gas.
The majority of Ovintiv’s acreage and associated production is dedicated to a gathering and processing agreement, which has a remaining term of 10 years. Ovintiv uses a combination of pipelines and trucks to transport oil to sales points.
Uinta
Uinta is an oil play located in northeastern Utah primarily in Duchesne and Uintah counties. The Uinta basin provides a deep inventory of multiple stacked oil horizons with approximately 2,600 feet of oil saturated reservoir rock. At December 31, 2021, the Company controlled approximately 209,000 net acres in the play. During 2021, the Company drilled six horizontal net wells. Production averaged approximately 12.7 Mbbls/d of oil, approximately 0.8 Mbbls/d of NGLs and approximately 12 MMcf/d of natural gas.
During 2021, the Company drilled six gross wells on two pads utilizing cube development which captured capital efficiencies.
Oil production from Uinta is waxy, ranging from yellow to black, and is transported primarily by truck due to the high heat pour point characteristics of the oil. The Company has oil volume minimum delivery commitments with one refinery in the Salt Lake City area through 2025. Oil production that is not subject to sales commitments is sold monthly in spot markets or transported by rail to other markets, mainly the Gulf Coast.
Canadian Operations
Overview: In 2021, the Canadian Operations had total capital investment of approximately $391 million, drilled approximately 85 horizontal net wells primarily in Montney and production averaged approximately 56.5 Mbbls/d of oil and NGLs and approximately 1,066 MMcf/d of natural gas. At December 31, 2021, the Canadian Operations had an established land position of approximately 1.3 million net acres including approximately 773,000 net undeveloped acres. The Canadian Operations accounted for 34 percent of upstream production revenues, excluding the impacts of hedging, and 37 percent of total proved reserves as at December 31, 2021.
During 2021, the Company divested of approximately 264,000 net acres primarily in Duvernay for proceeds of $238 million, after closing adjustments.
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, 2021)
Gross
Net
Gross
Net
Gross
Net
Montney
1,147
66%
Other Upstream Operations (2)
74%
Total Canadian Operations
1,118
1,839
1,263
69%
(1)
Excludes interests in royalty acreage.
(2)
Other primarily includes Wheatland and Horn River, as well as assets where the Company may pursue growth opportunities.
Producing Wells
Oil
Natural Gas
Total
(number of wells at December 31, 2021) (1)
Gross
Net
Gross
Net
Gross
Net
Montney
1,738
1,389
1,745
1,395
Other Upstream Operations (2)
Total Canadian Operations
2,295
1,855
2,308
1,866
(1)
Figures exclude wells capable of producing, but not producing.
(2)
Other primarily includes Wheatland and Horn River.
NGLs
Production
Oil
(Mbbls/d)
Plant Condensate
(Mbbls/d)
Other
(Mbbls/d)
Total
(Mbbls/d)
Natural Gas
(MMcf/d)
(average daily)
Montney
0.1
0.1
39.6
37.1
15.7
13.9
55.3
51.0
1,020
Other Upstream Operations
Duvernay (1)
0.2
0.5
0.8
3.9
0.1
1.1
0.9
5.0
Other (2)
-
-
-
-
-
-
-
-
Total Canadian Operations
0.3
0.6
40.4
41.0
15.8
15.0
56.2
56.0
1,066
1,000
(1)
Duvernay was divested during the second quarter of 2021.
(2)
Other primarily includes Wheatland and Horn River.
Montney
Montney is primarily a condensate rich natural gas play located in northeast British Columbia and northwest Alberta. The play includes properties that are primarily located in the Montney formation, where Ovintiv is currently targeting the development of condensate-rich locations, but also includes landholdings with incremental producing formations such as Cadomin and Doig. The Montney formation is characterized by up to six stacked horizons spanning over 1,000 feet of stratigraphy and is being developed exclusively with horizontal well technology. In 2021, total production from the play averaged approximately 55.4 Mbbls/d of oil and NGLs and approximately 1,020 MMcf/d of natural gas. As at December 31, 2021, the Company controlled approximately 752,000 net acres and 385,000 net undeveloped acres in the play.
Ovintiv utilizes cube development which has provided sustained efficiencies resulting in reduced cycle times and well costs. During 2021, cost reductions and efficiencies were obtained through optimizing wellbore casing designs, improved wellsite design and enhancing gas lift through innovative automation technology. The Company’s focus on innovation and efficiency decreased drilling and completions costs by approximately 11 percent compared to the prior year and increased lateral lengths of wells drilled, where the longest lateral well drilled during the year was over 15,200 feet. In 2021, the Company drilled approximately 84 horizontal net wells.
Ovintiv has access to natural gas processing capacity of approximately 1,555 MMcf/d, of which approximately 1,340 MMcf/d is under contract with third parties under varying terms and duration and approximately 215 MMcf/d of processing capacity which is owned by the Company. In addition, Ovintiv has access to liquids handling capacity of approximately 125 Mbbls/d of which approximately 93 Mbbls/d is contracted with third parties under varying terms and duration, and approximately 32 Mbbls/d is owned by the Company.
Other Upstream Operations:
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 2021, the Company’s natural gas production averaged approximately 32 MMcf/d. As at December 31, 2021, the Company had approximately 48 net producing horizontal wells and controlled approximately 187,000 net acres in the play. 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 12 years.
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, 2021, the Company had approximately 423 net producing wells and controlled approximately 140,000 net acres in the play. In 2021, natural gas production averaged approximately 4 MMcf/d.
PROVED RESERVES AND OTHER OIL AND NATURAL 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, or 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 Corporate Reserves Group, which consists of five staff, report to the Vice-President, Strategy, Corporate Reserves and Midstream who reports to Executive Vice-President & Chief Financial Officer. The Corporate Reserves Group is responsible for overseeing the internal preparation, review and approval of the reserves estimates and is separate and independent from the preparation of reserves estimates, which are prepared by operations’ teams 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 the Company’s reserves manual, and conducting 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, Reserves is primarily responsible for overseeing the preparation of proved reserves estimates. The Director, Reserves has a Bachelor of Science with a degree in Petroleum Engineering from Colorado School of Mines and is a member of the Society of Petroleum Evaluation Engineers (Denver Chapter).
Annually, each play is reviewed in detail by the QREs, the Corporate Reserves Group, the Company’s executive officers and an internal Reserves Advisory 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 natural 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 meets with such IQREs or IQRAs to review their reports.
For year-ended December 31, 2021, the Company involved IQRAs to audit the Company’s internal oil and natural gas reserve estimates for certain properties. In 2021, Netherland, Sewell & Associates, Inc. audited 43 percent of the Company’s estimated U.S. proved reserve volumes and McDaniel & Associates Consultants Ltd. audited 20 percent of the Company’s estimated Canadian proved reserve volumes. An audit of reserves is an examination of a company’s oil and natural 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 natural 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 natural 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. 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. Data used in reserves assessments may 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. Reserves are estimated based on production decline analysis, analogy to producing offsets, detailed reservoir modeling, volumetric calculations or a combination of these methods, based on the unique circumstances of each reservoir and the dataset available at the time of the estimate. The tools used to interpret the data may include proprietary and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs may be used as appropriate. In the case of producing reserves, the emphasis is on decline analysis where volumetric analysis is considered to limit forecasts to reasonable levels. Undeveloped 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. In all cases, the Company’s reserve estimates consider technologies that have been demonstrated in the field to yield repeatable and consistent results, having regard to economic considerations, as defined in the SEC regulations.
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 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 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 reserve 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, for the Company’s U.S. assets, are filed with the DOE and 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.
The reserves and other oil and natural gas information set forth below has an effective date of December 31, 2021 and was prepared as of January 14, 2022. 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 derived from proved reserves information can also be found in Note 28 to Ovintiv’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.
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, 2021 and other summary operating data.
U.S.
Canada
Total
Proved Reserves: (1)
Oil (MMbbls):
Developed
291.0
0.7
291.7
Undeveloped
266.6
0.3
266.9
Total
557.5
1.1
558.6
Natural Gas Liquids (MMbbls):
Developed
264.3
84.5
348.8
Undeveloped
170.5
85.4
255.9
Total
434.7
170.0
604.7
Natural Gas (Bcf):
Developed
1,621
2,490
4,111
Undeveloped
1,543
2,458
Total
2,536
4,033
6,570
Total Proved Reserves (MMBOE):
Developed
825.5
500.3
1,325.7
Undeveloped
589.5
343.0
932.5
Total
1,415.0
843.3
2,258.2
Percent Proved Developed
58%
59%
59%
Percent Proved Undeveloped
42%
41%
41%
Production (MBOE/d)
299.7
234.2
533.9
Capital Investments (millions)
1,125
1,516
Total Net Productive Wells (2)
4,109
1,898
6,007
Standardized Measure of Discounted Net Cash Flows: (3)
Pre-Tax (millions)
16,300
5,454
21,754
Taxes (millions)
2,009
2,979
After-Tax (millions)
14,291
4,484
18,775
(1)
Numbers may not add due to rounding.
(2)
Total net productive wells includes producing wells and wells mechanically capable of production.
(3)
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 28 to Ovintiv’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K for the standardized measure.
Changes to the Company’s proved reserves during 2021 are summarized in the table below:
2021 (1)
Oil
(MMbbls)
NGLs
(MMbbls)
Natural Gas
(Bcf)
Total
(MMBOE)
Beginning of year
592.3
580.5
4,918
1,992.5
Revisions and improved recovery (2)
(78.0
)
(50.3
)
(67.8
)
Extensions and discoveries
121.5
142.0
1,966
591.2
Purchase of reserves in place
2.6
2.5
7.3
Sale of reserves in place
(28.6
)
(21.0
)
(123
)
(70.2
)
Production
(51.2
)
(49.0
)
(568
)
(194.9
)
End of year
558.6
604.7
6,570
2,258.2
Developed
291.7
348.8
4,111
1,325.7
Undeveloped
266.9
255.9
2,458
932.5
Total
558.6
604.7
6,570
2,258.2
(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 2021, the Company’s proved reserves increased by 265.7 MMBOE from 2020 primarily due to extensions and discoveries of 591.2 MMBOE from successful drilling and technical delineation, as well as new proved undeveloped locations resulting from updated development plans in Montney, Permian and Anadarko. Approximately 45 percent of the 2021 extensions and discoveries were oil, condensate and NGLs. Revisions and improved recovery of previous estimates were negative 67.8 MMBOE primarily due to changes in the approved development plan of 396.1 MMBOE, partially offset by positive performance revisions other than price of 160.6 MMBOE, higher 12-month average trailing prices of 144.5 MMBOE and 23.2 MMBOE from infill drilling locations.
Production for 2021 was 194.9 MMBOE. Purchases of 7.3 MMBOE were primarily properties with oil and liquids rich potential in the Permian. Sales of 70.2 MMBOE were primarily due to the divestitures of the Eagle Ford assets located in south Texas and Duvernay assets located in west central Alberta.
Proved reserves are estimated based on the average first-day-of-month prices during the 12-month period for the respective year. The average prices used to compute proved reserves at December 31, 2021 were WTI: $66.56 per bbl, Edmonton Condensate: C$83.69 per bbl, Henry Hub: $3.60 per MMBtu, and AECO: C$3.26 per MMBtu. Prices for oil, NGLs and natural gas are inherently volatile.
Proved Undeveloped Reserves
Changes to the Company’s proved undeveloped reserves during 2021 are summarized in the table below:
(MMBOE)
Beginning of year
881.1
Revisions of prior estimates
(291.6
)
Extensions and discoveries
502.7
Conversions to developed
(160.2
)
Purchase of reserves in place
7.1
Sale of reserves in place
(6.5
)
End of Year *
932.5
*
Numbers may not add due to rounding.
As of December 31, 2021, there are no proved undeveloped reserves that will remain undeveloped for five years or more.
Extensions and discoveries of 502.7 MMBOE of proved undeveloped reserves were the result of successful drilling and technical delineation, as well as new proved undeveloped locations resulting from updated development plans in the Permian, Montney and Anadarko. Revisions of prior estimates of proved undeveloped reserves were negative 291.6 MMBOE primarily due to development plan changes of 396.1 MMBOE. Development plan changes relate to specific locations that were previously planned to be drilled within five years but were subsequently shifted to a later development timeframe or removed and replaced with different locations that are included in extensions and
discoveries. The downward revisions were partly offset by positive revisions of 66.2 MMBOE from improved well performance, 21.5 MMBOE from infill drilling locations and 16.8 MMBOE as a result of higher 12-month average trailing price.
Conversions of proved undeveloped reserves to proved developed status were 160.2 MMBOE, equating to 18 percent of the total prior year-end proved undeveloped reserves. Ovintiv’s five-year rolling average proved undeveloped conversion ratio is above 20 percent. Approximately 66 percent of proved undeveloped reserves conversions occurred in the Permian and Anadarko in the U.S. and 30 percent occurred in the Montney in Canada. The Company spent approximately $1,069 million to develop proved undeveloped reserves in 2021, of which approximately 79 percent related to the U.S. properties and 21 percent related to the Canadian properties.
Purchases of proved undeveloped reserves of 7.1 MMBOE and sales of proved undeveloped reserves of 6.5 MMBOE relate primarily to properties in the Permian.
Sales Volumes, Prices and Production Costs
The following table summarizes the Company’s production by final product sold, average sales price, and production cost per BOE for each of the last three years by geographic area:
Production
Average Sales Price (1)
Average Production Cost (2)
Oil
(MMbbls)
NGLs
(MMbbls)
Natural Gas
(Bcf)
Oil
($/bbl)
NGLs
($/bbl)
Natural Gas
($/Mcf)
($/BOE)
USA (3)
51.1
28.5
65.69
30.32
3.71
9.12
Canada (4)
0.1
20.5
56.71
56.48
3.52
12.37
Total
51.2
49.0
65.67
41.28
3.58
10.55
USA (3)
55.2
29.8
36.84
11.85
1.60
7.99
Canada (4)
0.2
20.5
32.58
29.37
2.01
11.45
Total
55.4
50.3
36.83
18.99
1.87
9.41
USA (3)
59.2
28.6
56.19
15.83
1.90
8.54
Canada (4)
0.2
21.6
53.19
40.25
2.01
11.76
China (5)
0.6
-
-
66.37
-
-
23.95
Total
60.0
50.2
56.27
26.33
1.97
9.90
(1)
Excludes the impact of commodity derivatives.
(2)
Excludes ad valorem, severance and property taxes.
(3)
As at December 31, 2021, there was no production from fields that comprise greater than 15 percent of the Company’s total reserves. Annual production from fields that comprise greater than 15 percent of the Company’s total proved reserves for the respective prior periods ended related to:
- Midland county in Permian: 2020 - 8.1 MMbbls of oil, 4.4 MMbbls of NGLs and 23 Bcf of natural gas; and 2019 - 10.2 MMbbls of oil, 4.2 MMbbls of NGLs and 22 Bcf of natural gas.
- Stack in Anadarko: 2019 - 13.2 MMbbls of oil, 10.0 MMbbls of NGLs and 72 Bcf of natural gas.
(4)
Annual production from fields that comprise greater than 15 percent of the Company’s total proved reserves related to B.C. Montney: 2021 - 9.1 MMbbls of NGLs and 282 Bcf of natural gas; 2020 - 10.2 MMbbls of NGLs and 272 Bcf of natural gas; and 2019 - 12.5 MMbbls of NGLs and 283 Bcf of natural gas.
(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.
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
USA
-
-
-
-
-
-
-
-
Canada
-
-
-
-
-
-
Total
-
-
-
-
-
-
USA
-
-
-
-
Canada
-
-
-
-
-
-
-
-
Total
-
-
-
-
USA
-
-
-
-
-
-
-
-
Canada
-
-
-
-
-
-
Total
-
-
-
-
-
-
(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, 2021.
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
USA
-
-
-
-
Canada
-
-
-
-
Total
-
-
-
-
(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 natural 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, 2021.
Productive Wells (1, 2)
Oil (3)
Natural Gas (4)
Total
Gross
Net
Gross
Net
Gross
Net
USA
5,637
3,816
6,353
4,109
Canada
2,339
1,887
2,352
1,898
Total
5,650
3,827
3,055
2,180
8,705
6,007
(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 5 gross oil wells (5 net oil wells) containing multiple completions.
(4)
Includes 859 gross natural gas wells (746 net natural gas wells) containing multiple completions.
The following table summarizes the Company’s developed, undeveloped and total landholdings by geographic area as at December 31, 2021.
Landholdings (1 - 7)
Developed
Undeveloped
Total
(thousands of acres)
Gross
Net
Gross
Net
Gross
Net
United States
- Freehold
- Federal
- Fee
- Tribal/Allotted
- State
Total United States
1,149
1,485
Canada
- Crown (8)
1,091
1,773
1,220
- Freehold
- Fee
Total Canada
1,118
1,839
1,263
Total
1,870
1,267
1,454
3,324
2,192
(1)
Fee lands are those lands in which the Company has a fee simple interest in the mineral rights and has either: (a) not leased out all the mineral zones; (b) retained a working interest; or (c) 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/Tribal/Allotted 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.
(8)
Includes acreage related to the Deep Panuke natural gas field located offshore Nova Scotia. The Company has permanently ceased production and the offshore platform and associated infrastructure was decommissioned.
Of the total 2.2 million net acres, approximately 2.0 million net acres is held by production. The table above includes acreage subject to leases that will expire over the next three years: 2022 - approximately 161,000 net acres; 2023 - approximately 15,000 net acres; and 2024 - approximately 3,000 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 natural 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 natural 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.
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 its production, Ovintiv looks to minimize market related curtailment, 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 one year.
Ovintiv’s produced oil, NGLs and natural gas, are primarily marketed to refiners, local distributing companies, energy marketing companies and aggregators. 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 four 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 seven 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 two 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 to 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, 2021, the Company was committed to deliver approximately 109,167 Mbbls of oil and approximately 98 MMcf of natural gas in the USA Operations and approximately 7,990 Mbbls of oil and NGLs and approximately 77 MMcf of natural gas in the Canadian Operations with varying contract terms. The Company has one oil minimum volume sales contract related to Uinta production in Utah. 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 incurred can vary and may be incurred on the remaining committed deliveries of 20 Mbbls/d through August 2025.
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
Natural Gas
Total USA Operations
1,057
Canadian Operations
Oil & NGLs
Natural Gas
1,545
3,199
Total Canadian Operations
1,723
3,794
Total USA and Canadian Operations
1,317
1,926
4,851
In general, Ovintiv expects to fulfill its delivery commitments with oil, NGLs and natural gas 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, oil, NGLs and natural gas 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 oil, NGLs and natural gas production and purchased product for the year ended December 31, 2021, the Company had one customer, Vitol Inc., which individually accounted for more than 10 percent of the Company’s consolidated revenues (2020 - one customer, Vitol Inc. and 2019 - one customer, Vitol Inc.). 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 is found in Note 2 to 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 natural gas companies, as well as oil and natural gas marketers and other participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. All aspects of the oil and natural 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 natural 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.
HUMAN CAPITAL
Ovintiv strives to be one of the most competitive energy companies in North America, bringing together the brightest minds and best technologies to fuel innovation and maximize operational performance and results. Recruiting, developing and retaining Ovintiv’s workforce is vital to the Company’s future success. Ovintiv has a history of hiring top industry talent and recruiting individuals from within and outside of the oil and natural gas industry who will thrive in the Company’s unique culture. The Company’s core values of one, agile, innovative and driven, and foundational values of integrity, safety, sustainability, trust and respect guide behaviour and define what Ovintiv expects of its employees in the workplace. These expectations reflect and support the Company’s corporate strategy, culture and organizational priorities. Ovintiv is committed to fair labor practices in its operations and adheres to all applicable workplace and employment standards.
At December 31, 2021, the Company employed 1,713 employees. The following table outlines our employees by geographic area.
Employees
U.S.
Canada
Total
1,713
The Company also engages a number of contractors and service providers.
Employee Development and Retention
Ovintiv’s success is the direct result of a talented workforce and the Company’s expectation to share ideas and work together to achieve company goals. Ovintiv’s culture is defined by constant innovation, promoting internal collaboration as a way for employees to implement successful strategies and best practices across the Company’s business. Opportunities are provided for Ovintiv’s employees to further develop leadership skills, technical and business skills through on-the-job work experiences and job rotations, development opportunities, networking and mentoring circles, as well as formal learning programs and instructor led workshops. The Company also offers new graduate and intern opportunities in both technical and professional disciplines to support the recruitment of top talent, hiring an average of 17 new graduates and 44 interns per year over the past three years. In addition, the Company has a robust approach to succession planning of key personnel which assesses the competencies, experience, leadership capabilities, and development opportunities of identified succession candidates.
Ovintiv’s compensation and benefits program is designed to attract and retain the talent necessary to achieve the Company’s business strategy by rewarding individual performance as well as company performance. The Company’s compensation model is tied to financial and operational metrics which align to Ovintiv’s strategic plan. In addition, the compensation philosophy is anchored by two key objectives: a) delivering competitive base salaries and benefits and b) rewarding short and long-term performance through the grant of an annual cash bonus and long-term incentive awards (“LTI awards”). LTI awards are primarily performance-based and are designed to incentivize delivery of the Company’s strategy and long-term value creation with the payout of these awards correlating to Ovintiv’s stock price performance. Settlement of certain awards can be either in shares of common stock or cash at the discretion of the Human Resources and Compensation Committee of the Board of Directors. Awards that settle in shares of common stock do not result in beneficial ownership until the awards are settled. See Note 22. Compensation Plans and Note 23. Pensions and Other Post-Employment Benefits to Ovintiv’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.
As of December 31, 2021, the average tenure of our employees is over nine years and voluntary turnover is less than six percent.
Diversity and Inclusion
The Company values diversity and fosters inclusion, believing that diverse perspectives and experience enhances Ovintiv’s overall effectiveness and performance. As part of the Company’s commitment to diversity and inclusion, Ovintiv has assembled an internal diversity, equity and inclusion working group accountable to the executive leadership team and made up of a broad representation of the Company’s workforce. The mandate of the group is to provide a sounding board for initiatives and communication. Ovintiv has also launched an inclusive network called Leveraging Inclusion, Networking and Knowledge (“LINK”), to help provide opportunities for all employees to engage, collaborate, learn and grow, in addition to fostering an environment where diverse perspectives are celebrated. In addition, formal training and resources have been provided to leaders of all levels on inclusive leadership and interrupting bias and have taken training on understanding the types of unconscious bias, and how they show up in the workplace.
Ovintiv strives to provide equal opportunity in recruitment, career development, promotion, training and rewards for its employees. The Company actively facilitates professional development for women and other minority groups through its internal diversity network, targeted succession planning and formal mentoring programs. In order to broaden the diversity of the Company’s talent pipeline, Ovintiv also participates in programs targeting diverse students in junior and high schools, with the purpose of advancing and strengthening its workforce.
Specific to gender diversity, women at Ovintiv comprised approximately 60 percent of the executive leadership team reporting to the Chief Executive Officer, approximately 32 percent of the senior leadership group and approximately 31 percent of all employees at December 31, 2021.
Employee Safety & Wellness
Safety is a foundational value at Ovintiv. Ensuring safety of employees, suppliers, and the community is a tenet of managing the Company’s operations. Strong safety performance reflects a well-run business and builds confidence in the communities where Ovintiv operates. Ovintiv ensures workplace safety with regular comprehensive training and orientation programs for employees and contractors. Employees and contractors are expected to comply with Ovintiv’s process safety protocols, regulatory compliance, and are required to report incidents and near-miss events. As at December 31, 2021, Ovintiv had its eighth consecutive safest year.
As a result, safety metrics under the Company’s Environment, Health and Safety (“EH&S”) scorecard are tied into the Company’s compensation program, allowing the Board of Directors to adjust annual bonus payouts up or down based on the Company’s demonstrated EH&S performance. Metrics reflected in the EH&S scorecard include Total Recordable Injury Frequency, Spill Intensity, Flaring and Venting, and Methane Intensity, all of which are described in the Proxy Statement relating to the Company’s 2022 annual meeting of shareholders, which is incorporated herein by reference.
GOVERNMENT AND ENVIRONMENTAL REGULATORY MATTERS
As Ovintiv is an operator of oil and natural 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. 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 natural 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; pollution, protection of the environment and the handling of hazardous materials; transportation of production; periodic report submittals during operations; and calculation and disbursement of royalty payments and production and other taxes. The following are significant areas of government control and regulation affecting Ovintiv’s operations:
Exploration and Development Activities
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.
In Canada, oil and natural gas mineral rights may be held by individuals, corporations or governments that have jurisdiction over the area in which such mineral rights are located. Generally, parties holding these mineral rights grant licenses or leases to third parties to facilitate the exploration and development of these mineral rights. The terms of these leases and licenses are generally established to require timely development. Notwithstanding the ownership of mineral rights, the government of the jurisdiction in which the mineral rights are located generally retains authority over the drilling and operation of oil and natural gas wells.
Drilling and Production
The Company’s operations also are subject to conservation regulations, including the regulation of the location of wells, 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 natural gas wells; and the unitization or pooling of oil and natural gas properties. In the U.S., some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases, which make it more difficult to develop oil and natural 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 natural gas that can be produced from the Company’s wells and the number of wells or the locations that can be drilled.
Royalties
Operations on U.S. Federal or Indian oil and natural gas leases must comply with numerous regulatory restrictions, including various non-discrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other permits issued by various tribal and federal agencies, including the BLM and the Office of Natural Resources Revenue (“ONRR”). The basis for royalty payments due under federal oil and natural gas leases are through regulation issued under the applicable statutory authority. State regulatory authorities establish similar standards for royalty payments due under state oil and natural gas leases. The basis for royalty payments established by ONRR and the state regulatory authorities is generally applicable to all federal and state oil and natural gas leases.
The royalty calculation in Canada is a significant factor in the profitability of Canadian oil and natural gas production. Oil and natural gas crown royalties are determined by provincial and territorial government regulation and are generally calculated as a percentage of the value of the gross production, net of allowed deductions. The royalty rate is dependent in part on prescribed references prices, well productivity, geographical locations, recovery methods, as well as type and quality of the hydrocarbon produced. For pre-payout oil and natural gas projects, the regulations prescribe lower royalty rates for oil and natural gas projects until allowable capital costs have been recovered. The calculation for wells post payout is based on a percentage of production net of allowed deductions and varies with commodity price.
Royalties payable on production from lands other than federal, state or provincial government lands are determined through negotiations between the parties.
Sales and Transportation
Although oil and natural gas prices are currently unregulated, Congress historically has been active in oil and natural gas regulation. As a result, the Company cannot predict whether new regulations might be proposed.
The availability, terms and transportation significantly affect sales of oil and natural gas. The interstate transportation and sale for resale of oil and natural gas is subject to federal regulation, including regulation of terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms of access to oil and natural gas pipeline transportation. FERC’s regulations for oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil as the transportation of oil in common carrier pipelines is also subject to rate regulation by the FERC under the Intrastate Commerce Act. To the extent that effective interstate and intrastate rates are equally applicable to all comparable shippers, the Company believes that the regulation of oil transportation rates will not affect our operations in any way that is of material difference from those of our competitors.
Project Approvals
Approvals and licenses from relevant provincial or federal government or regulatory bodies are required to carryout or make modifications to the Company’s oil and natural gas activities. The project approval process can involve environmental assessment, stakeholder and Indigenous consultation and inputs regarding project concerns and public hearings and may included various conditions and commitments which may arise throughout the process.
In 2019, the Canadian government implemented a new environmental assessment framework in Canada under the Impact Assessment Act, which may impact the way large energy projects are approved. Though the Company does not typical own, operate, permit or construct projects which fall under the scope of the Impact Assessment Act, some of the Company’s business may rely on these projects owned, operated, permitted and constructed by others.
On June 29, 2021, the Supreme Court of British Columbia declared, among other things, that the province of British Columbia has unjustifiably infringed on the rights of the Blueberry River First Nation (BRFN) by permitting the cumulative impacts of industrial development (activities which include forestry, mining, oil and natural gas,
agriculture, land clearing, hydroelectric infrastructure, roads and other industrial developments) to diminish the BRFN’s ability to meaningfully exercise its treaty rights within an area comprising approximately 9,400,000 acres in northeast British Columbia. As a result, the court ordered the Province and the BRFN to negotiate to establish ‘timely enforceable mechanisms’ to assess and manage the cumulative impact of industrial development on the BRFN’s treaty rights. The Province and the BRFNs continue to work towards an agreement with respect to new industrial development activities. Ovintiv’s Montney properties in northeast British Columbia are within the ‘Blueberry Claim Area’ referenced in the Judgement. Oil and natural gas projects, which were permitted or authorized prior to the court decision and where activities have not yet started, will proceed. While the court order has not impacted the Company’s existing production in the Montney, the Province has ceased issuing new permits, and new amendments to previously approved permits, associated with oil and natural gas development activity in northeast British Columbia pending the outcome of negotiations with the BRFN. Should the Province and the BRFN fail to reach an agreement with respect to new industrial development activities, the Company may be unable to conduct exploration and development activities on a portion of its Montney acreage located within northeast British Columbia for an extended period of time.
Investment Canada Act
The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of oil and natural gas properties may be considered to be a transaction requiring such approval.
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 (as defined herein) 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 former operating sites;
•
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. Further, certain Environmental Regulations contain citizen suit provisions which allow private parties, including environmental organizations, to directly sue alleged violators or government agencies to enforce Environmental Regulations. Although environmental requirements have a substantial impact upon the energy 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 natural gas industry. As a result, Ovintiv has established policies for continuing compliance with Environmental Regulations. The 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 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
Brendan M. McCracken
President & Chief Executive Officer
Corey D. Code
Executive Vice-President & Chief Financial Officer
Gregory D. Givens
Executive Vice-President & Chief Operating Officer
Rachel M. Moore
Executive Vice-President, Corporate Services
Renee E. Zemljak
Executive Vice-President, Midstream, Marketing & Fundamentals
(1)
As of February 18, 2022.
(2)
Includes the years served as executive officer of Encana.
Mr. McCracken was appointed President & Chief Executive Officer in August 2021. Mr. McCracken joined one of the Company’s predecessor companies in 1997 and assumed a variety of leadership roles, including his previous positions as President in December 2020, Executive Vice-President, Corporate Development & External Affairs in September 2019 and Vice-President & General Manager of Canadian Operations in 2017.
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 natural 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.
Ms. Moore was appointed Executive Vice-President, Corporate Services of the Company in June 2020. Ms. Moore joined the Company in 2015 serving as Vice-President, Human Resources. Prior to joining the Company, Ms. Moore was Executive Vice-President, Human Resources of Savanna Energy Services Corporation (a privately held oil and natural gas services company) from 2010 to 2015 and was Vice President, Human Resources of Enerflex Ltd. (a public oil and natural gas services company) from 2003 to 2010.
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
ITEM 1A. Risk Factors
Our business and operations, and our industry in general, are subject to a variety of risks. If any event arising from the risk factors set forth below occurs, our business, financial condition, results of operations, liquidity, the trading prices of our securities and in some cases our reputation could be materially and adversely affected. When assessing the materiality of the foregoing risk factors, we consider several qualitative and quantitative factors, including, but not limited to, financial, operational, environmental, regulatory, reputational and safety aspects of the identified risk factor. The risks described below may not be the only risks we face, as our business, operations and industry may also be subject to risks that we do not yet know of, or that we currently believe are immaterial.
Market Risks
A substantial or extended decline in oil, NGLs or natural gas prices, or a substantial increase in oil, NGLs and natural gas price differentials, could have a material adverse effect on our business, financial condition, results of operations, and the trading prices of our securities.
Our financial performance and condition are substantially dependent on the prevailing prices we receive for the oil, NGLs and natural gas which we produce. Prices for oil, NGLs and natural gas are inherently volatile and fluctuate in response to changes in a variety of factors beyond our control, including:
•
the international and domestic supply and demand for oil, NGLs and natural gas;
•
volatility and trading patterns in the commodity futures market;
•
global economic conditions;
•
production levels of members of OPEC, Russia, the United States or other hydrocarbon producing nations;
•
geopolitical risks, including political and civil unrest in oil and natural gas producing regions;
•
adverse weather conditions, natural disasters and other catastrophic events, such as tornadoes, flooding, severe heat or cold, earthquakes and hurricanes;
•
the price and level of North American oil, NGLs and natural gas imports and exports;
•
the level of global oil, NGLs and natural gas inventories;
•
the economic and financial impact of epidemics or other public health issues, such as the ongoing COVID-19 pandemic;
•
differing quality of production, including the gravity and sulphur content of our oil, the Btu and sulphur content of our natural gas, and the quantity of NGLs associated with our natural gas;
•
the price and availability of, and demand for, alternative sources of energy (including coal, nuclear, hydroelectric, solar and wind);
•
the effect of energy conservation efforts and technological advances in energy consumption and production, including with respect to transportation and power generation;
•
the availability and proximity of gathering, transportation, processing, refining, storage and other infrastructure facilities;
•
changes in trade relations and policies, including the imposition of tariffs by the United States or Canada;
•
conservation and environmental protection efforts, including activities by non-governmental organizations to restrict the exploration, development and production of oil, NGLs and natural gas; and
•
the nature and extent of governmental regulations, including any changes or other actions with respect to emissions, climate change, tariffs or tax laws.
We also may receive discounted prices for our oil, NGLs and natural gas production relative to certain benchmark prices (such as Brent and WTI for oil and Henry Hub and AECO for natural gas) due to constraints on our ability to transport and sell such production to certain markets. A failure to resolve such regional pricing differentials may result in our continued realization of discounted or reduced oil, NGLs and natural gas prices relative to such benchmarks.
A substantial or extended decline in oil, NGLs and natural gas prices, or a substantial increase in oil, NGLs and natural gas price differentials with respect to certain benchmarks, could result in, among other things, (a) a delay or cancellation of existing or future drilling, development or construction programs; (b) the curtailment or shut-in of production at some or all of our properties; (c) unutilized long-term transportation and drilling commitments; or (d) a decrease in the value of our oil, NGLs and natural gas reserves, each of which could have a material adverse effect on our business, financial condition, results of operations and the trading prices of our securities. Additionally,
on at least an annual basis, we assess the carrying value of our oil and natural gas properties in accordance with applicable accounting standards. If oil, NGLs and natural gas prices decline significantly for a sufficient period, the carrying value of our properties could be subject to financial impairment, and our net earnings could be materially and adversely affected.
A pandemic, epidemic or other widespread outbreak of an infectious disease, such as the ongoing COVID-19 pandemic, could materially and adversely affect the operation of our business.
Although we maintain contingency plans to manage the potential workplace impacts of a pandemic, epidemic or other widespread outbreak of an infectious disease, such as the ongoing COVID-19 pandemic, restrictive measures implemented by governments in the jurisdictions in which we operate could prevent our employees, contractors or suppliers from accessing our properties or performing critical services. Such measures may include limitations or prohibitions on cross-border travel, restrictions on large gatherings, stay-at-home orders, vaccine mandates and mandatory closures of “non-essential” businesses. In the event such measures remain in place for an extended period of time, our ability to maintain ordinary staffing levels, secure operational inputs, and execute on portions of our business could be impacted, and if a significant subset of our employees are required to work remotely, we will face an increased exposure to vulnerabilities related to digital technologies and may experience a higher rate of cyber-attacks. Additionally, concerns over the prolonged negative effects of a pandemic, epidemic or other widespread outbreak of an infectious disease, including the ongoing COVID-19 pandemic, on global economic and business prospects may contribute to decreased demand for oil, NGLs and natural gas; increased volatility in capital and commodity markets, including volatility in the prices of oil, NGLs and natural gas; substantial fluctuations in currency exchange rates, inflation rates and interest rates; increased counterparty credit and performance risk; and reduced levels of general investing and consumption.
While the full impact of a pandemic, epidemic or other widespread outbreak of an infectious disease, including the ongoing COVID-19 pandemic, is inherently uncertain, the ultimate impact will depend on several factors, including the location and severity of the virus's spread, the effectiveness and adoption rate of vaccines, the emergence of new or previously unknown variants and the effectiveness of mitigation actions taken by governmental authorities. Any pandemic, epidemic or other widespread outbreak of an infectious disease, including the ongoing COVID-19 pandemic, may reduce our spending and operating plans; reduce the value and amount of our oil, NGLs or natural gas reserves and production; cause substantial fluctuations in our stock price and credit ratings; or otherwise materially and adversely affect our business, financial condition, results of operations, and access to liquidity.
The trading price of our securities, including our common stock, is subject to volatility.
The trading price of our securities, including our common stock, may be volatile. The value of an investment in our securities may decrease or increase abruptly, and such volatility may bear little or no relation to our financial or operational performance. The price of our securities may fall in response to market appraisal of our strategy or if our results of operations and/or prospects are below the expectations of market analysts or stakeholders. In addition, equity and debt 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 our operating performance and prospects but nevertheless affect the price of our securities. Broad equity and debt market fluctuations resulting from general economic conditions, as well as our ability to meet or exceed market expectations, may materially and adversely affect the trading prices of our securities, including our common stock.
Fluctuations in exchange rates could affect expenses or result in realized and unrealized losses.
We currently have operations in Canada and, as a result, a portion of our revenues and expenses are denominated in Canadian dollars. In addition, our subsidiaries that are domiciled in Canada may hold U.S. dollar denominated assets and liabilities. Fluctuations in the exchange rate between the U.S. dollar and the Canadian dollar may result in realized and unrealized losses, which could impact our revenue and expenses and have a material adverse effect on our business, financial condition and results of operations.
Operational Risks
Our ability to operate and complete projects is dependent on numerous factors outside of our control.
We undertake a variety of projects including exploration and development projects and the construction or expansion of facilities and pipelines. Our ability to operate, generate sufficient cash flows, and timely complete projects depends upon numerous factors largely beyond our control. These factors include:
•
oil, NGLs and natural gas prices;
•
global supply and demand for oil, NGLs and natural gas;
•
the overall state of the financial markets, including investor appetite for debt and equity securities issued by oil and natural gas companies and the effects of economic recessions or depressions;
•
the ability to secure and maintain financing on acceptable terms;
•
legislative, environmental and regulatory matters;
•
oil and natural gas reservoir quality;
•
the availability of drilling rigs, completions equipment and other facilities and equipment;
•
the ability to access lands;
•
the ability to access water for hydraulic fracturing operations;
•
reliance on vendors, suppliers, contractors and service providers;
•
shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
•
changes to free trade agreements;
•
inflation and other unexpected cost increases, including with respect to materials and labor;
•
prevailing interest and foreign exchange rates;
•
royalty and tax rates;
•
physical impacts from adverse weather conditions and natural disasters;
•
transportation and processing interruptions or constraints, including the availability and proximity of pipeline and processing capacity;
•
technology failures; and
•
accidents.
In addition, part of our corporate strategy is focused on a limited number of Core Assets which results in a concentration of development capital and production. Some of the foregoing risks may be magnified due to the concentrated nature of our development activities and may result in a relatively greater impact on our financial condition and results of operations compared to other companies that may have more geographically diversified operations. Any material delays in a project or project cost overruns could result in delayed revenues and some projects becoming uneconomic, each of which could have a material and adverse effect on our business, financial condition and results of operations.
Our operations involve many risks, some of which could result in unforeseen interruptions and expose us to substantial losses and liabilities, for which our insurance may not fully protect us.
Our business is subject to the operating risks normally associated with (a) the exploration, development and production of oil, NGLs and natural gas and (b) the operation of midstream facilities, including the gathering, transportation, processing, storing and marketing of oil, NGLs and natural gas. These risks include:
•
blowouts, cratering, explosions and fires;
•
loss of well control;
•
environmental hazards, such as the uncontrollable release or spill of oil, natural gas, toxic gases (such as hydrogen sulfide), produced water (brine), drilling or completion fluids, or other pollutants into the environment, including the surface, subsurface, air and groundwater;
•
pipeline ruptures, vessel ruptures and other equipment malfunctions, failures or accidents;
•
mechanical difficulties, such as stuck oilfield drilling and service tools, pipe or cement failures and casing collapses;
•
adverse weather conditions, such as severe heat or cold, flooding, tornados and other natural disasters;
•
encountering unexpected or abnormally pressured formations;
•
premature declines of reservoir pressure or productivity; and
•
acts of vandalism and terrorism, including attacks targeting oil, NGLs and natural gas facilities and infrastructure.
If any of the foregoing risks were to materialize, we could sustain material losses as a result of:
•
injury or loss of life;
•
damage to, or destruction of, property, natural resources or equipment, including the costs of repair or replacement;
•
pollution or other environmental harm, including the costs associated with remediation, reclamation and plugging and abandonment;
•
interruptions to our ongoing operations, including the reduction or shutting-in of existing production;
•
regulatory investigations and administrative, civil and criminal penalties; and
•
injunctions resulting in limitation or suspension of current or future operations.
While we maintain insurance against some, but not all, of these risks and losses described above, our insurance may not be adequate to cover all casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. The occurrence of a significant event for which we are not fully insured may have a material adverse effect on our business, financial position and results of operations.
Oil and natural gas exploration, development and production activities involve substantial costs and risks and may not result in commercially productive reserves.
Oil and natural gas exploration, development and production activities involve numerous risks, including the risk that no commercially productive oil or natural gas reservoirs will be encountered. The cost of drilling and completing wells is often uncertain and operations may be curtailed, delayed or canceled, or become costlier, as a result of a variety of factors, including:
•
unexpected drilling conditions, including abnormal pressures or irregularities in formations;
•
equipment failures or accidents;
•
construction delays;
•
fracture stimulation accidents or failures;
•
adverse weather conditions or natural disasters;
•
title defects or restricted access to land;
•
lack of available gathering, transportation, processing, fractionation, storage, refining or export facilities;
•
lack of available capacity on interconnecting transmission pipelines;
•
access to, and the cost and availability of, the equipment, services, resources and personnel required to complete our drilling, completion and production activities; and
•
delays imposed by or resulting from compliance with or changes in environmental and other governmental, regulatory or contractual requirements.
Additionally, our operations involve utilizing some of the latest horizontal drilling and completion techniques as developed internally and by our service providers. Risks that we face while drilling and completing horizontal oil and natural gas wells include the following:
•
landing the wellbore in the desired zone within the target formation;
•
staying in the desired zone within the target formation while drilling horizontally for extended lengths;
•
controlling formation pressures during drilling;
•
running casing the entire length of the wellbore;
•
being able to run tools and other equipment consistently through the horizontal wellbore;
•
the ability to effectively fracture stimulate the reservoir with the desired number of stages; and
•
the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
Our future exploration and development activities may not be successful as a result of, among other things, the risks set forth above and, if unsuccessful, our proved oil, NGLs and natural gas reserves and production would decline, which could have a material and adverse effect on our business, financial condition and results of operation. While all development activities involve these risks, exploratory and extension development activities involve a greater risk of dry holes or failure to find commercial quantities of hydrocarbons.
The proved reserves data provided in this Annual Report on Form 10-K is an estimate only and any inaccuracies in the methodology or assumptions underlying our proved reserves estimates could cause the quantity and net present value of our oil, NGLs, and natural gas reserves to be materially overstated or understated.
There are numerous uncertainties inherent in estimating economically recoverable quantities of oil, NGLs and natural gas reserves, including many factors beyond our control. All oil, NGLs and natural gas reserve estimates are uncertain to some degree, and classifications of oil, NGLs and natural gas reserves are only attempts to define the degree of uncertainty involved. For those reasons, estimates of the quantity of oil, NGLs and natural gas economically recoverable from a group of properties and the classification of such oil, NGLs and natural gas reserves, when prepared by different engineers or by the same engineers at different times, may vary substantially. Additionally, estimates with respect to oil, NGLs and natural gas reserves are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Oil, NGLs and natural gas reserve estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations in the estimated reserves and these variations may be material.
Proved reserves data in this Annual Report on Form 10-K and other publications we make publicly available represent estimates only. In general, estimates of our oil, NGLs and natural gas reserves, and the future net cash flows therefrom, are based upon a number of factors and assumptions, including commodity prices, future operating and capital costs, availability of future capital, historical production from the same or similar 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. Our actual production, revenues, taxes and development and operating expenditures with respect to our proved reserves may vary materially from such estimates.
The estimates of proved reserves included in this Annual Report on Form 10-K are prepared in accordance with SEC regulations. Subject to limited exceptions, oil, NGLs and natural gas reserves may only be classified as proved undeveloped reserves if the wells developing such reserves are scheduled to be drilled within five years after the date of classification. The development timing of our oil, NGLs and natural gas reserves is based upon numerous expectations and assumptions, including the allocation of development capital; anticipated costs to drill, complete and operate our wells; and anticipated commodity prices. Our development expectations and assumptions are subject to change and proved undeveloped reserves may be reclassified to unproved reserves at any time. Additionally, commodity prices used to estimate proved reserves included in this Annual Report on Form 10-K are calculated as the unweighted arithmetic average of the price 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 our proved reserves. The 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 our estimated proved reserves. In addition, these proved 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 we fail to find, develop or acquire additional oil, NGLs and natural gas reserves, our reserves and production will decline materially from their current levels.
Our future oil, NGLs and natural gas reserves and production, and therefore our future cash flows, are highly dependent upon our success in developing our current reserves base and exploring for, developing or acquiring additional oil, NGLs and natural gas reserves. Typically, to maintain an oil and natural gas lease in the United States, we are required to drill at least one well that is commercially productive within the primary term of the lease and, once drilled, maintain oil or natural gas production in paying quantities from the lease. If we are unsuccessful in drilling a commercially productive well during the primary term of the lease or, once drilled, in maintaining oil or natural gas production in paying quantities from the lease, we could lose our rights to explore for and develop oil and natural gas under such lease and our right to any oil, NGLs and natural gas reserves associated with the lease. In some cases, the initial commercially productive well will only maintain the lease as to a portion of the lands covered thereby and further oil and natural gas development activities are required to maintain the entirety of the lease.
The business of exploring for, developing and acquiring oil and natural gas reserves is capital intensive. Acquisition opportunities in the oil and natural gas industry are inherently competitive, which can increase the cost of, or cause us to refrain from, completing acquisitions. To the extent that cash flows from our operations are insufficient and external sources of capital become limited or undesirable, our ability to make the necessary capital investments to
maintain and expand our oil, NGLs and natural gas reserves and production will be impaired. In addition, there can be no certainty that we will be able to find, develop or acquire additional oil, NGLs and natural gas reserves to replace current reserves and production at acceptable costs. Without additions through exploration, development or acquisition activities, our oil, NGLs and natural gas reserves and production will decline over time as the reserves are depleted, which may materially and adversely affect our business, financial condition and results of operations.
Horizontal multi-well pad drilling involves certain risks which may cause volatility in our operating results.
Our operations utilize horizontal multi-well pad drilling. In this type of development, multiple wells are drilled based upon spacing and completions techniques that evolve over time as learnings are captured and applied. Wells drilled on a multi-well pad are generally not placed on production until all wells on the pad are drilled and completed. While the use of this development technique can accelerate the production of our oil, NGLs and natural gas reserves and increase our observed recovery factor from the reservoir, it can also result in production delays as problems with a single well can adversely affect the production of all wells on the pad. Additionally, horizontal multi-well pad drilling increases the risk of unintentional communication or pressure interference between wells which may adversely affect our production. As a result, multi-well pad drilling can both cause delays in our production schedule and result in oil, NGLs and natural gas production below expectations. These delays or production interruptions may reduce our anticipated production volumes from both new and existing wells and this volatility could have a material and adverse effect on our business, financial condition and results of operations.
We are subject to both known and unknown risks and liabilities from acquisitions and any anticipated or desired benefits from such acquisitions may not be realized.
Historically, acquisitions of oil and natural gas properties, including through acreage trades, farm-ins and asset- or corporate-level acquisitions, have contributed to our growth. Acquisition opportunities in the oil and natural gas industry are inherently competitive, which can increase the cost of, or cause us to refrain from, completing acquisitions. The success of any acquisition will depend on several factors and involves potential risks and uncertainties, including, among other things:
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the inability to accurately forecast and estimate oil, NGLs and natural gas reserves, production volumes, development costs and the net cash flows attributable to such properties;
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the inability to accurately forecast commodity prices;
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the assumption of unknown liabilities, including environmental liabilities, for which we may not be indemnified or for which the indemnity may not be adequate;
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the validity of assumptions about asset- and corporate-level synergies;
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the effect on our liquidity or financial leverage when using available cash or debt to finance the acquisition or from the amount of debt assumed as part of the acquisition;
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the diversion of management's attention from other business concerns; and
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the inability to hire, train or retain qualified personnel to manage and operate the acquired assets or business.
All of these factors, among others, affect whether an acquisition will ultimately generate cash flows sufficient to provide a suitable return on investment. Even though we assess and review the properties we seek to acquire in a manner consistent with what we believe to be industry practice, such reviews are limited in scope, inexact and not capable of identifying all existing or potentially adverse conditions. This risk is magnified when the acquired properties are in a geographic area where we have not historically operated. As a result, the anticipated and desired benefits of an acquisition may not materialize, and this may have a material and adverse effect on our business, financial performance and results of operations.
We are dependent on partners to fund certain projects conducted through joint ventures and partnerships.
Some of our projects are conducted through joint ventures, partnerships or other arrangements, where we are dependent on our partners to fund their contractual share of the project’s capital and operating expenditures. If our partners do not approve their contractual share of capital or operating expenditures, are unable to fulfill their contractual obligations, or suspend or terminate their contractual arrangements with us, the projects may become delayed or we may be forced to absorb additional capital or operating expenditures, each of which may materially and adversely affect the viability of such projects and our business, financial condition and results of operations.
These partners may also have strategic plans, objectives and interests that do not coincide, and may conflict, with our plans, objectives and interests. While certain operational decisions may be made solely at our discretion in our capacity as the operator of certain projects, major capital and strategic decisions affecting such projects may require agreement among the partners. While we generally seek consensus with our partners regarding major decisions concerning the direction and operation of a project, no assurance can be provided that future demands or expectations of any party, including our demands and expectations, relating to such project will be met satisfactorily or in a timely manner. Failure to satisfactorily meet such demands or expectations may affect our or our partners’ participation in the operation of such project or the timing for undertaking various activities, which could materially and adversely affect the viability of such project and our business, financial condition and results of operations. Further, we are involved from time to time in disputes with our partners and, as such, we may be unable to dispose of certain assets or interests in certain arrangements if such disputes cannot be resolved in a satisfactory or timely manner.
We do not operate all of our assets, and, in such instances, we may have a limited ability to exercise influence over the operation and development of such assets.
Third parties operate a portion of the assets in which we have an ownership interest, and, in such instances, we may have a limited ability to exercise influence over the operation and development of such assets. The success and timing of our activities on these assets is therefore dependent upon factors that are largely outside of our control. These factors include (a) the timing and amount of capital, operating and maintenance expenditures related to the project; (b) the third-party operator’s expertise and financial resources; (c) the third-party operator’s ability to obtain required approvals from other non-operating partners; and (d) the third-party operator’s selection and implementation of adequate technology and risk management practices. The failure of one or more third-party operators to effectively and efficiently operate assets in which we have an ownership interest could result in the inefficient deployment of capital and the loss of production volumes, each of which could have a material and adverse effect on our business, financial condition and results of operations.
Our customers, counterparties and lenders may be unable to satisfy their contractual or legal obligations.
We are exposed to certain risks associated with our customers, contractual counterparties and lenders. These risks include (a) credit risks associated with (i) customers who purchase our oil, NGLs and natural gas production, (ii) the collection of receivables from our joint interest partners for their proportionate share of expenditures made on projects we operate, and (iii) counterparties to our derivative financial contracts; (b) performance risks associated with the non-delivery, or delayed delivery, of contracted products or services, including the transportation and processing of our oil, NGLs and natural gas production; and (c) liquidity risk in the event one or more lenders under our existing credit facilities are unable to perform their funding obligations. We utilize a variety of mechanisms to limit our exposure to these and similar risks, including requiring letters of credit, prepayments or collateral postings under certain conditions. Despite these mechanisms, in the event a customer, contractual counterparty or lender fails to satisfy their obligations, our business, financial condition and results of operations could be materially and adversely affected.
We retain certain indemnification obligations related to our corporate reorganization in November of 2009.
As part of our November 2009 corporate reorganization that split our predecessor, Encana, into two independent publicly traded energy companies, Encana and Cenovus Energy Inc. (“Cenovus”), Encana and 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. We are unable to predict whether we will be required to indemnify, or seek indemnity from, Cenovus for any obligations and the magnitude of such obligations. Any indemnification claims against us pursuant to the various agreements entered with Cenovus, or our failure to obtain indemnity from Cenovus for any claims we may hold, could have a material and adverse effect on our business, financial condition and results of operations.
We may be unable to dispose of certain assets and may be required to retain liabilities for certain matters.
We may identify certain assets for disposition, the proceeds of which could reduce the amount of our existing indebtedness and/or increase the amount of capital available for other business purposes, including shareholder returns and acquisitions. Various factors could materially affect our ability to dispose of the identified assets or complete any announced transactions, including commodity price volatility; the availability of counterparties willing to acquire oil and natural gas assets at prices and on terms acceptable to us; approval by our Board of Directors; associated asset retirement obligations; due diligence; general market conditions; the assignability of any associated contract, joint venture, partnership or other arrangements; and required stock exchange, governmental or third party approvals.
These factors may also reduce the value of our assets or the proceeds of any asset disposition.
We (including our predecessor entities) have retained, or in the future may retain, liabilities or indemnification obligations in connection with certain asset dispositions. While we are unable to predict the magnitude of any retained liabilities or indemnification obligations, any liabilities or indemnification obligations retained could ultimately be material. For example, under state and federal law, once an oil or natural gas well has permanently ceased production of oil or natural gas, the operator of such well is obligated to plug and abandon (“P&A”) the well, decommission production facilities and restore the well site to pre-operating conditions. U.S. state and federal regulations allow the government to call upon predecessors in interest of oil and natural gas leases associated with such well to pay for P&A, decommissioning and restoration obligations (together, “P&A Obligations”) if the current operator fails to fulfill those obligations. If purchasers of any assets previously owned by us or our predecessors (including any offshore wells or facilities), or any successor owners of those assets, are unable to meet their P&A Obligations due to bankruptcy, dissolution or other liquidity issues, we may be unable to rely on our arrangements with them, if any, to fulfill (or provide reimbursement for) those obligations. In those circumstances, the government may seek to impose the bankrupt entity’s P&A Obligations on us and any other predecessors in interest, and such payments could have a material adverse effect on our business, financial condition and results of operations.
Further, certain third parties may be unwilling to release us from guarantees or other credit support provided prior to the disposition of an asset. In those cases, after the asset disposition, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the acquirer of the assets fails to perform their obligations.
Our 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 legal basis of an indigenous land claim is a matter of considerable legal complexity and we cannot predict the impact of such a claim, or the possible effects of a settlement of such claim, 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, development or production activities pending resolution of any such claim) would not delay or even prevent our exploration, development and production activities. If a material claim were to arise and be successful, such claim could have a material and adverse effect on our business, financial condition and results of operations. In addition, the process of addressing such claim, regardless of the outcome, could be expensive and time consuming and could result in delays which could have a material and adverse effect on our business, financial condition and results of operations. For more information on the ongoing BRFN Case refer to Government and Environmental Regulatory Matters under Item 1 and 2 of this Annual Report on Form 10-K.
In addition to the foregoing, we 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 our operations and ability to explore, develop and produce 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 followed suit by adopting the UNDRIP Act on June 21, 2021. The UNDRIP legislation adopted by
both British Columbia and the Canadian federal government provide frameworks for recognizing the constitutional and human rights of indigenous peoples and aligning their respective provincial and federal laws with the internationally recognized standards of UNDRIP. Both pieces of UNDRIP legislation are at an early stage of implementation and we are unable to predict the total impact of the potential regulations upon our business. Although we do not anticipate any near-term impacts to our business as a result of such legislation, the implementation of the standards of UNDRIP has the potential to increase permitting times and change the processes and costs associated with project development and operations.
Environmental Risks and Risks Associated with Climate Change
We are subject to risks and uncertainties associated with increased Environmental Regulation in all jurisdictions in which we operate.
Our operations and properties are subject to numerous existing laws, rules and regulations governing our interactions with the environment that are enacted by U.S. and Canadian federal, state, provincial, territorial, tribal, and municipal governments (collectively, “Environmental Regulations”). Environmental Regulations impose, among other things, restrictions, liabilities and obligations in connection with (a) discharges and emissions of various substances into the environment; (b) the hydraulic fracturing of wells; (c) the handling, use, storage, transportation, treatment and disposal of chemicals, hazardous substances and waste associated with finding, producing, transmitting and storing oil, NGLs and natural gas; (d) the availability and management of fresh, potable or brackish water sources that are being used, or whose use is contemplated, in oil and natural gas operations; and (e) requirements that well sites and other properties associated with our operations be constructed, operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including new exploration and development projects and certain changes to existing exploration and development projects, may require the submission and approval of environmental impact assessments or permit applications. Expenditures required to institute and maintain compliance with new or existing Environmental Regulations can be significant. Failure to comply with Environmental Regulations may result in substantial clean-up and remediation costs arising from damaged or contaminated properties, the imposition of significant fines and penalties by regulators and costly litigation or administrative proceedings. Examples of recently proposed and final Environmental Regulations or other regulatory initiatives include the following:
Emissions - Greenhouse gases (which include, among other things, methane, carbon dioxide, nitrous oxide and various fluorinated gases; “GHGs”) are typically emitted throughout all phases of the oil and natural gas supply chain, including production, transportation, processing, refining and storage operations. Additionally, although beyond our control, end user consumption of oil and natural gas in activities such as power generation and motorized transportation also results in GHG emissions. In the United States, the U.S. Environmental Protection Agency (the “EPA”) has determined that GHG emissions present a danger to public health and the environment and has adopted Environmental Regulations that, among other things, restrict GHG emissions and require the monitoring and annual reporting of GHG emissions from specified sources. For example, in November 2021, the EPA proposed New Source Performance Standard Subpart OOOOb that seeks to impose more stringent methane and volatile organic compound emission standards for new, reconstructed, and modified sources in the oil and natural gas industry. The EPA also proposed New Source Performance Standard Subpart OOOOc, which would create, for the first-time, emission guidelines for existing oil and natural gas sources to be included in individual states’ implementation plans. These Subpart OOOOb and OOOOc standards expand upon previously issued New Source Performance Standards, Subpart OOOO and Subpart OOOOa published by the EPA in 2012 and 2016, respectively. In addition, policy makers at both the federal and state levels continue to propose more stringent Environmental Regulations designed to further limit GHG and other air emissions. Many state and local officials have stated their intent to intensify efforts to regulate GHG and other air emissions, including methane, from the oil and natural gas industry and it is anticipated that the Biden Administration will propose additional Environmental Regulations that may impose new costs on the oil and natural gas industry in an effort to accelerate reductions of GHG and other air emissions from both the production and consumption of energy.
The U.S. and Canadian federal governments, along with several provincial and state governments, have also announced intentions to adhere to certain international protocols regarding GHG emissions and regulate GHGs and certain air pollutants. In addition to federal action, many state, provincial and local
officials have stated their intent to intensify efforts to regulate GHG emissions, including methane, from the oil and natural gas industry. These governments are currently developing and/or implementing regulatory and policy frameworks to deliver on their announcements. For example, effective February 19, 2021, the United States officially rejoined the Paris Agreement, an international accord to address climate change through voluntary and non-binding commitments to reduce GHG emissions by signatory nations. Pursuant to its pledge under the Paris Agreement, the United States has committed to reducing its net GHG emissions by 50-52 percent below 2005 levels by 2030. In Canada, the Government of Canada (a) has committed to cutting Canada’s net GHG emissions by 40-45 percent below 2005 levels by 2030 in accordance with its pledge under the Paris Agreement; (b) is gradually raising the federal carbon tax to C$170/tonne CO2e by 2030; and (c) has announced its intention to impose a hard cap on GHG emissions from the oil and natural gas industry, seeking to reduce methane emissions from the oil and natural gas industry by 75 percent below 2012 levels by 2030 and ensure GHG emission reductions are on a pace and scale sufficient to reach net-zero by 2050. We actively participate in certain provincial industrial emission programs offered by both Alberta and British Columbia that allow for the generation of offsets and other rebates to incentivize emission reduction projects and mitigate carbon tax costs. We expect to continue to be able to utilize these provincial programs in the future to migrate our carbon tax costs.
Hydraulic Fracturing Operations - The U.S. and Canadian federal governments, along with certain U.S. state and Canadian provincial governments, continue to review 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 have made claims that hydraulic fracturing techniques are harmful to surface water and drinking water sources and continue to suggest that additional Environmental Regulations may be needed to more closely regulate the hydraulic fracturing process. Further, certain governments in jurisdictions where we do 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, Environmental Regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations or result in an outright ban of hydraulic fracturing in oil and natural gas operations.
Seismic Activity - Some areas of North America are experiencing an increased frequency of localized seismic activity which has been associated with oil and natural gas operations. Although the occurrence and risk of seismicity in relation to oil and natural gas operations is generally very low, it has been linked to the underground disposal of produced water and, in some instances, has been correlated with hydraulic fracturing activities. This has prompted legislative and regulatory initiatives intended to address these concerns. These initiatives have the potential to (a) require additional seismic monitoring; (b) restrict the volume of produced water injected in certain disposal wells; (c) restrict the injection of produced water in certain underground formations; and (d) modify or curtail hydraulic fracturing operations in certain areas.
The cost and effects of complying with existing and emerging Environmental Regulations (including those with respect to emissions, hydraulic fracturing operations and seismic activity) and proposed carbon taxes are not currently anticipated to be material to our operations, however federal, state, provincial and local regulations and programs are either under development or in the early stages of implementation and we are unable to accurately predict the total future impact of such regulations and programs. Increased Environmental Regulations and/or carbon taxes could (a) materially increase our cost of compliance and other operating costs; and/or (b) impede or prevent development of our oil, NGLs and natural gas assets, reducing (i) the amount of oil, NGLs and natural gas we are ultimately able to produce from our reserves and (ii) our overall quantity of oil, NGLs and natural gas reserves. The occurrence of any of the foregoing could have have a material adverse effect on our business, financial condition and results of operations.
We are subject to risks and uncertainties arising out of the threat of climate change that could reduce demand for the oil, NGLs and natural gas we produce; increase our operating costs; and limit the areas in which we may explore for, develop, and produce oil, NGLs and natural gas.
Public attention to issues concerning the existence and extent of climate change, and the role of human activity in it, continues to increase, with the oil and natural gas industry receiving heightened scrutiny regarding GHG emissions. Internationally this has resulted in existing and pending international agreements to reduce GHG emissions globally, while in Canada and the United States this has resulted in both national, regional and local legislation and regulatory programs. For example, On January 27, 2021, President Biden issued Executive Order 14008 entitled "Tackling the Climate Crisis at Home and Abroad," directing the heads of various federal agencies, to the extent consistent with applicable law and in consultation with other agencies and stakeholders, to, among other things, (a) assess climate related risks to federal agencies; (b) pause the issuance of new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and natural gas permitting and leasing practices; (c) achieve a carbon-pollution free electricity sector by 2035; (d) procure clean and zero-emission vehicles for federal, state, local and tribal government fleets; and (e) identify and eliminate federal fossil fuel subsidies. Additionally, an increasing number of states, local municipalities and other groups have made claims in federal and state courts against oil and natural gas companies, including Ovintiv, alleging that GHG emissions from oil and natural gas produced by such companies has contributed, and continues to contribute, to climate change. These allegations have included claims of public and private nuisance, trespass, negligence, strict liability and civil conspiracy. Some in the investment community (including, among others, shareholders, bondholders, institutional lenders, investment advisors, pension and sovereign wealth funds and endowments) have also become increasing concerned with the causes of climate change and the role oil and natural gas companies play in any of its purported effects. This has led some in the investment community to shift all or part of their investment or funding allocations away from the oil and natural gas industry and others to modify the terms upon which funding is made available to the oil and natural gas industry. In other instances, it has led shareholders to initiate lawsuits against the directors and management of oil and natural gas companies and/or bring shareholder proposals demanding that oil and natural gas companies increase climate disclosure; change business practices or operations; or appoint new board representation.
If initiatives and actions brought by private parties or additional governmental regulations with respect to climate change intensify, we could experience (a) a reduction in demand for the oil and natural gas we produce and sell; (b) a material increase in our cost of compliance and other operating costs; (c) difficulty in developing our oil and natural gas assets, reducing (i) the amount of oil, NGLs and natural gas we are ultimately able to produce from our reserves and (ii) our overall quantity of oil, NGLs and natural gas reserves; (d) limitations on our ability to access capital markets and raise capital on satisfactory terms, or at all; and (e) costly and time consuming litigation. While we are unable to accurately assess the probability and impact of potential climate change regulations, initiatives and actions, the occurrence of any one or more of the foregoing could have have a material adverse effect on our business, financial condition and results of operations.
Financial and Liquidity Risk
Downgrades in our credit ratings could increase our cost of capital and limit our access to capital, suppliers or counterparties.
Rating agencies regularly evaluate our credit, basing their credit ratings for our long-term and short-term debt securities on a variety of factors, including factors over which we have some control (e.g., our financial strength), as well as factors not entirely within our control (e.g., general macroeconomic trends and conditions affecting the oil and natural gas industry generally). While we currently hold investment grade credit ratings from three of the four major rating agencies, there is no assurance that our credit ratings will not be downgraded in the future, including below investment grade.
Our borrowing costs and ability to raise funds are directly impacted by our credit ratings. A credit rating downgrade may increase the cost of borrowing under our existing credit facilities, limit access to our current commercial paper programs, limit our access to private and public markets to raise short-term and long-term debt capital, and negatively impact our overall cost of capital. Credit ratings may also be important to suppliers or counterparties when they seek to engage in certain transactions. If we experience downgrades in one or more of our credit ratings, we may be required to post collateral, letters of credit, cash or other forms of security as financial assurance for our
performance under certain contractual arrangements with various counterparties including marketing, midstream (including gathering, processing and transportation providers), over-the-counter derivative, and construction counterparties. Additionally, certain of these arrangements contain financial assurance language that may, under certain circumstances, permit our counterparties to request additional collateral or require that we terminate transactions based on our credit rating. The occurrence of any of the foregoing could adversely affect our ability to execute portions of our business strategy, including hedging, and could have a material adverse effect on our liquidity and capital position.
Our level of indebtedness may limit our financial flexibility.
As of December 31, 2021, we had outstanding long-term unsecured senior notes of $4,741 million. The terms of our various financing arrangements, including but not limited to the indentures relating to our outstanding senior notes and the credit agreements relating to our revolving credit facilities, impose restrictions on our ability to take a number of actions that we may otherwise desire to take, including incurring additional debt (including guarantees of indebtedness) and selling or creating liens on certain assets.
Our level of indebtedness could affect our operations by:
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requiring us to dedicate a portion of our cash flows from operations to service indebtedness, thereby reducing the availability of cash flow for other purposes;
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reducing our competitiveness compared to similar oil and natural gas companies that have less debt;
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limiting our ability to obtain additional financing for working capital, capital investments and acquisitions;
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limiting our flexibility in planning for, or reacting to, changes in our business and industry; and
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increasing our vulnerability to general adverse economic and industry conditions.
Our ability to meet and service our debt obligations depends on our future operational performance. General economic conditions; oil, NGLs or natural gas prices; and financial, business and other factors may affect our operational performance. Many of these factors are beyond our control. If we are unable to satisfy our debt obligations with cash on hand, we may attempt to refinance or repay portions of our indebtedness, including with proceeds from a public securities offering or the sale of certain assets. No assurance can be given that we will be able to generate sufficient cash flows to pay the interest on our debt, or that funds from future borrowings, equity financings or asset sales will be available to pay or refinance our debt on terms that we consider favorable. Further, if we incur additional debt to finance asset or business acquisitions, we may decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance such acquisitions, and such acquisitions could result in a significant increase in our interest expense or financial leverage. The occurrence of any of the foregoing could adversely affect our ability to execute portions of our business strategy and could have a material adverse effect on our liquidity and capital position.
Our risk management activities may prevent us from fully benefiting from an increase in oil, NGLs and natural gas prices and expose us to certain other risks.
We are exposed to, among other things, fluctuations in oil, NGLs and natural gas prices and foreign currency exchange rates. We actively monitor such exposures and, where we deem appropriate, utilize 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 our reported net earnings.
The terms of our various risk management agreements and the amount of estimated production hedged may limit the benefits we receive from an increase in oil, NGLs and natural gas prices. We may also suffer financial loss if (a) we fail to produce anticipated volumes of oil, NGLs and natural gas, particularly during periods of increasing commodity prices; or (b) counterparties to our risk management agreements fail to fulfill their obligations under the agreements, particularly during periods of declining commodity prices. The occurrence of any of the foregoing could adversely affect our ability to execute portions of our business strategy and could have a material adverse effect on our liquidity and capital position.
The decision to return capital to shareholders, whether through cash dividends, share buybacks or otherwise, and the amount and timing of such capital returns is subject to the discretion of the Board of Directors and will vary from time to time.
Although we currently intend to return capital to shareholders in the form of (a) a base quarterly cash dividend; (b) variable cash dividends; and/or (c) repurchases of our outstanding common stock (commonly known as share buybacks), the amount and timing of these returns of capital to shareholders may vary from time to time. The decision whether to return capital to shareholders, as well as the timing and amount of any return of capital to shareholders, is subject to the discretion of the Board of Directors, which regularly evaluates our proposed capital returns to shareholders and the requirements, if any, under Delaware General Corporation Law (“DGCL”). Additionally, in the case of share buybacks, we may be limited in our ability to repurchase shares of our common stock by various governmental laws, rules and regulations which prevent us from purchasing our common stock during periods when we are in possession of material non-public information. The level of dividends per share of common stock will also 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.
The amount of cash available to return to shareholders, if any, can vary significantly from period to period for a number of reasons, including, among other things: our 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; our ability to access capital markets; foreign currency exchange rates and interest rates; any agreements relating to our indebtedness that restrict our ability to return capital to shareholders and the other risks set forth in Item 1A. Risk Factors of this Annual Report on Form 10-K. The trading price of our securities, including our common stock, may deteriorate if we are unable to meet investor expectations with respect to the timing and amount of capital returns to shareholders, and such deterioration may be material.
Regulation and Litigation Risk
We are subject to extensive federal, state, provincial and local government laws, rules and regulations that can adversely affect the cost, manner and feasibility of our business, and increased regulation in the future could increase costs, impose additional operating restrictions and cause delays.
All of our operations are subject to extensive federal, state, provincial, local and other laws, rules and regulations, including with respect to drilling operations; completion operations, including the use of hydraulic fracturing; the production of oil, NGLs and natural gas; the disposal of produced water and other hazardous waste; the gathering and transportation of oil, NGLs and natural gas; the imposition of taxes; royalty payments; environmental matters, including air and water emissions or discharges; free trade agreements; worker health and safety; and conservation policies, including policies related to environmentally sensitive areas and protected species. These laws, rules and regulations may impose substantial liabilities for our failure to comply, including the assessment of administrative, civil and criminal penalties and the issuance of injunctions restricting or prohibiting some or all of our activities in a particular area.
In the normal course of our business, we may be required to make large expenditures to comply with applicable governmental laws, rules, regulations, permits or orders. While we cannot predict the actions that future laws, rules and regulations may require or prohibit, our business could be subject to increased operating and other compliance costs and our operations may be delayed if existing laws, rules and regulations are revised or reinterpreted, or if new laws, rules and regulations become applicable to our operations. Any such increases or delays could have a material and adverse effect on our business, financial condition and results of operations.
We currently are, and from time to time in the future may be, subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in our favor.
We currently are, and from time to time in the future 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 our favor. If we are unable to resolve such matters favorably, we or our directors, officers or employees may become involved in legal proceedings that could result in an onerous or unfavorable 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 away from our operations. We may also be subject to adverse publicity associated with such matters, regardless of whether such allegations are valid or whether we are ultimately found liable. As a result, such matters could have a material adverse effect on our business, reputation, financial condition, results of operations or liquidity. See Item 3 of this Annual Report on Form 10-K.
The ability of Canadian and other non-resident shareholders to effect service of process or enforce remedies against Ovintiv, its directors, officers, experts, and assets may be limited.
We are incorporated in the State of Delaware and our principal place of business is in the United States. Most of our directors and officers are residents of the United States and many of the experts who provide us with services are residents of the United States. Additionally, most of our oil and natural gas assets and production are located in the United States. It may be difficult for our shareholders in Canada or other non-U.S. jurisdictions (each a "Foreign Jurisdiction") to (a) effect service of process within such Foreign Jurisdiction upon Ovintiv or certain of our directors, officers and representatives of experts who are not residents of the Foreign Jurisdiction (together, “Non-Residents”) and (b) enforce the judgments of courts in an applicable Foreign Jurisdiction against Ovintiv and other Non-Residents based upon liability under the laws of such Foreign Jurisdiction, including the securities laws of any province within Canada.
Tax Risks
U.S. and Canadian tax laws and regulations may change over time, and such changes may result in increased taxes on our business.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. and Canadian tax laws and regulations, including those specifically applicable to the oil and natural gas industry (such as the intangible drilling and development costs deduction under U.S. federal income tax law). While we are unable to predict the timing, scope and effect of any proposed or enacted tax law changes, elimination of certain tax deductions, as well as any other changes to, or the imposition of new, federal, state or local U.S. or Canadian taxes (including the imposition of, or increases in, production, severance or similar taxes), could materially and adversely affect our business, financial condition and results of operations. We will continue to monitor and assess any proposed or enacted tax law changes to determine the impact on our business, financial condition and results of operations and take appropriate actions, where necessary.
Additionally, U.S. and Canadian tax authorities could detrimentally change their administrative practices or may disagree with the way we calculate our tax liabilities or structure our arrangements and there are certain tax matters under governmental review for which the timing of resolution is uncertain. While we believe that our current provision for income taxes is adequate, certain tax authorities may reassess our taxes and such reassessments may be material.
Our corporate reorganization in January of 2020 may result in material Canadian and/or U.S. federal income taxes.
On January 24, 2020, Encana completed a corporate reorganization (the “Reorganization”), which included among other things, (a) a consolidation of Encana common stock on the basis of one post-consolidation share for each five pre-consolidation shares; (b) our acquisition of all of the issued and outstanding shares of Encana common stock in exchange for shares of Ovintiv common stock on a one-for-one basis and becoming the parent company of Encana and its subsidiaries and (c) our subsequent migration from Canada to the United States, becoming a Delaware corporation (the “U.S. Domestication”). We continue to carry on the business previously conducted by Encana and its subsidiaries prior to the completion of the Reorganization. The Reorganization and U.S. Domestication involved multiple complex U.S. and Canadian tax issues, including numerous assumptions and estimates of fair market value. While we believe that our analysis and application of both U.S. and Canadian tax laws to the Reorganization was correct, certain tax authorities may challenge our positions which could materially and adversely affect our business, financial condition and results of operations.
General Risks
The oil and natural gas industry is highly competitive and many of our competitors have available resources in excess of our own.
The oil and natural gas industry is highly competitive, and many competitors, including major integrated and independent oil and natural gas companies, as well as national oil companies, are larger and have substantially greater resources at their disposal than we do. We compete with these companies for the acquisition of oil and natural gas leases and other properties. Such competition can significantly increase costs and affect the availability of resources, which could provide our larger competitors a competitive advantage when acquiring equipment, leases and other properties.
We also compete with these companies for the personnel, including petroleum engineers, geologists, geophysicists and other key personnel, required to both (a) find, acquire, develop and operate our properties and (b) market our oil, NGLs and natural gas production. The experience, knowledge and contributions of our existing management team and directors to our immediate and near-term operations is of central importance for the foreseeable future. As such, the unexpected loss of services from, or retirement of any, of our key operations or management personnel could have a material adverse effect on our business and results of operation. In addition, the competition for qualified personnel in the oil and natural gas industry means there can be no assurance that we will be able to attract and retain key personnel with the required specialized skills necessary for our business.
We could be adversely affected by security threats, including cyber-security threats and related disruptions.
We have become increasingly dependent upon information technology systems to conduct our daily operations. We depend on a variety of information technology systems to estimate oil, NGLs and natural gas 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 a greater sensitivity to cyber-attacks and information systems breaches. Unauthorized access to information systems by employees or third parties could corrupt or expose confidential, fiduciary, or proprietary information; interrupt our communications or operations; disrupt our business activities; or interfere with our competitive position. In addition, our vendors, suppliers and other business partners may separately suffer disruptions as a result of such security breaches which may directly or indirectly affect our business activities or our competitive position.
To protect our information assets and systems, we apply technical and process controls, which are reviewed by the appropriate members of senior management with oversight from our Board of Directors. These controls are in line with industry standards and are reviewed annually with peer companies to guide our focus on information security initiatives. However, these controls may not adequately prevent cyber-security breaches and we may not adopt all controls utilized by our peers. As cyber-attacks continue to evolve, we may be required to expend additional resources to investigate, mitigate and remediate any potential vulnerabilities. We may also be subject to regulatory investigations or litigation relating to cyber-security issues.
Although we have not suffered any material losses related to a cyber-security breach to date, there is no assurance that we will not suffer material losses associated with cyber-security breaches in the future. If a cyber-attack were to successfully breach our information or operating systems, we could incur substantial remediation costs and suffer other negative consequences, including exposure to significant litigation risks. The potential for such occurrences subjects our operations to increased risks that could have a material adverse effect on our business, financial condition and results of operations.

---

ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
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 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. See Item 1A. Risk Factors of this Annual Report on Form 10-K, “We currently are, and from time to time in the future may be, subject to claims, litigation, administrative proceedings and regulatory actions that may not be resolved in the Company’s favor”.
In July 2020, the Company received a Notice of Violation (“NOV”) from the U.S. Environmental Protection Agency (“EPA”) and the Utah Department of Environmental Quality, Division of Air Quality (“UDAQ”). The NOV alleges violations under the federal Clean Air Act, the State of Utah’s State Implementation Plan, and the State of Utah’s air quality regulations for the oil and natural gas industry, at certain of the Company facilities located in the Uinta Basin. The Company has exchanged information with the EPA and UDAQ and is engaged in discussions aimed at resolving the allegations. The Company is unable to predict the financial impact of the NOV or the timing of its resolution at this time. Resolution of the matter may result in monetary sanctions of more than $300,000.
For additional information, see Note 27 to Ovintiv’s audited Consolidated Financial Statements under Item 8 of this Annual Report on Form 10-K.

---

ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
Market Information
Ovintiv’s shares of common stock are listed and posted for trading on the NYSE and TSX under the symbol “OVV”.
Shareholders
The Company is authorized to issue up to 775,000,000 shares of stock consisting of: (a) 750,000,000 shares of common stock, par value $0.01 per share, and (b) 25,000,000 shares of preferred stock, par value $0.01 per share. As at February 18, 2022, there were 256,769,168 shares of common stock outstanding held by 5,230 shareholders of record, and no shares of preferred stock outstanding.
Capital Return Information
In 2021, the Company paid a quarterly dividend of $0.09375 per share for each of the first two quarters and $0.14 per share for the third and fourth quarters (2020: $0.09375 per share each quarter) and $0.4675 per share annually (2020: $0.375 per share annually). On February 24, 2022 the Board of Directors declared a dividend of $0.20 per share of Ovintiv common stock payable on March 31, 2022 to common shareholders of record as of March 15, 2022. The Company currently pays dividends quarterly to shareholders 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.
On September 9, 2021 the Company announced a new capital allocation framework commencing in the fourth quarter of 2021, where the Company is committed to return 25 percent of Non-GAAP Cash Flow in excess of capital expenditures and base dividends in the form of share buybacks and/or variable dividends at the discretion of the Board. During the fourth quarter of 2021, the Company elected share buybacks under the capital allocation framework.
Although we currently intend to return capital to shareholders in the form of (a) a base quarterly cash dividend; (b) variable cash dividends; and/or (c) repurchases of our outstanding common stock (commonly known as share buybacks), the amount and timing of these returns of capital to shareholders may vary from time to time. The decision whether to return capital to shareholders, as well as the timing and amount of any return of capital to shareholders, is subject to the discretion of the Board of Directors, which regularly evaluates our proposed capital returns to shareholders and the requirements, if any, under DGCL. See Item 1A. Risk Factors of this Annual Report on Form 10-K, “The decision to return capital to shareholders, whether through cash dividends, share buybacks or otherwise, and the amount and timing of such capital returns is subject to the discretion of the Board of Directors and will vary from time to time”.
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 2022 annual meeting of shareholders, which is incorporated herein by reference.
PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PERSONS
On September 28, 2021, Ovintiv announced it had received regulatory approval to purchase, for cancellation, up to 26 million shares of common stock pursuant to a NCIB over a 12-month period from October 1, 2021 to September 30, 2022. The number of shares of common stock authorized for purchase represents 10 percent of Ovintiv's public float as of September 20, 2021.
During the three months ended December 31, 2021, the Company purchased approximately 3 million shares of common stock for total consideration of approximately $111 million at a weighted average price of $36.18 per share. The following table presents the shares of common stock purchased during the three months ended December 31, 2021.
Period
Total Number of Shares Purchased
Average
Price Paid
per Share (1)
Total Number of Shares
Purchased as Part of Publicly
Announced Plans or Programs
Maximum Number of Shares
That May Yet be Purchased
Under the Plans or Programs
October 1 to October 31, 2021
791,392
$
37.91
791,392
25,256,869
November 1 to November 30, 2021
1,786,135
35.94
1,786,135
23,470,734
December 1 to December 31, 2021
490,766
34.23
490,766
22,979,968
Total
3,068,293
$
36.18
3,068,293
22,979,968
(1)
Includes commissions.
RECENT SALES OF UNREGISTERED EQUITY SECURITIES
None.
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 shareholders of the Company’s common stock relative to the cumulative total returns of the S&P 400 and the SPDR Oil & Gas Exploration & Production ETF (“XOP U.S. Equity”). The graph was prepared assuming $100 was invested on December 31, 2016 in the Company’s common stock, the S&P 400 and the XOP U.S. Equity, 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 performance.
Comparison of 5-Year Cumulative Total Return Among
Ovintiv, the S&P 400 and XOP U.S. Equity
(US$100 Invested in Base Period)
Fiscal Year Ended December 31
Ovintiv
$ 100.00
$ 114.19
$ 49.82
$ 41.03
$ 26.75
$ 63.76
S&P 400
100.00
116.23
103.33
130.37
148.16
184.81
XOP US Equity
100.00
90.53
65.10
58.95
37.54
62.61

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [Reserved]
Not Applicable.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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 which includes an overview of Ovintiv’s consolidated 2021 results and year-over-year comparisons between 2021 and 2020 results. This MD&A should be read in conjunction with the audited Consolidated Financial Statements and accompanying notes for the year ended December 31, 2021 (“Consolidated Financial Statements”), which are included in Item 8 of this Annual Report on Form 10-K. Discussion and analysis of 2019 results and year-over-year comparisons between 2020 and 2019 results that are not included in this Form 10-K, and can be found in Item 7 of the 2020 Annual Report on Form 10-K.
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
Ovintiv is a leading North American energy producer that is focused on developing its multi-basin portfolio of oil, NGLs and natural gas producing plays as part of its strategy outlined in Items 1 and 2 of this Annual Report on Form 10-K. Ovintiv is committed to growing long-term shareholder value by delivering on its strategic priorities through execution excellence, disciplined capital allocation, commercial acumen and risk management, while driving environmental, social and governance progress. The Company’s strategy is founded on its multi-basin portfolio of top tier assets, financial strength, as well as its core and foundational values.
In support of the Company’s commitment to growing shareholder value, Ovintiv implemented a capital allocation framework in 2021 that outlines increasing returns to shareholders as well as continuing the Company’s progress on debt reduction.
Ovintiv is delivering results in a socially and environmentally responsible manner. Thoughtfully developed best practices are deployed across its assets, allowing the Company to capitalize on operational efficiencies and decrease emissions intensity. The Company’s sustainability reporting, which outlines its key metrics and progress achieved relating to ESG practices can be found on the Company’s website.
Ovintiv continually reviews and evaluates its strategy and changing market conditions in order to maximize cash flow generation from its Core Assets located in some of the best plays in North America. As at December 31, 2021, the Core Assets comprised Permian and Anadarko in the U.S., and Montney in Canada. These Core Assets form a multi-basin portfolio of oil, NGLs and natural gas producing plays enabling flexible and efficient investment of capital that support the Company’s strategy.
Underpinning Ovintiv’s strategy are core values of one, agile, innovative and driven, which guide the organization to be collaborative, responsive, flexible 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. For additional information on the segmented results, refer to Note 2 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, Net Debt 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.
Highlights
During 2021, the Company focused on executing its 2021 capital plan aimed at maximizing profitability through operational and capital efficiencies, delivering cash from operating activities and using excess cash flows to reduce total long-term debt. Higher upstream product revenues in 2021 compared to 2020 resulted from higher average realized prices, excluding the impact of risk management activities. Increases in average realized natural gas and liquids prices of 91 percent and 90 percent, respectively, were primarily due to higher benchmark prices. Ovintiv continues to focus on optimizing realized prices from the diversification of the Company’s downstream markets.
The Company continued to deliver significant cash from operating activities while reducing its total long-term debt balance. Cash from operating activities of $3,129 million included a net realized loss of $1,362 million on the settlement of commodity and foreign exchange risk management positions and a current income tax recovery of $156 million primarily due to the resolution of prior years’ tax items. The Company used excess cash flows to reduce its total long-term debt balance by $2.1 billion in 2021.
Significant Developments
•
On April 28, 2021, the Company closed the sale of its previously announced Duvernay assets and received proceeds of approximately $238 million, after closing and other adjustments. The transaction had an effective date of January 1, 2021.
•
On May 19, 2021, the Company closed the sale of its previously announced Eagle Ford assets and received proceeds of approximately $764 million, after closing and other adjustments. The transaction had an effective date of January 1, 2021.
•
On May 19, 2021, the Company announced its intention to redeem the Company’s $600 million, 5.75 percent senior notes due January 30, 2022, and its $518 million, 3.90 percent senior notes due November 15, 2021. The senior notes were redeemed on June 18, 2021 and August 16, 2021, respectively. The combined debt redemptions will result in annualized interest savings of over $50 million.
•
On July 27, 2021, Ovintiv announced an increase of about 50 percent to its quarterly dividend payment representing an annualized dividend of $0.56 per share of common stock as part of the Company’s commitment to returning capital to shareholders.
•
On September 9, 2021, Ovintiv announced a new capital allocation framework to support the Company’s strategy of increasing shareholder returns as well as reducing Net Debt.
•
On September 28, 2021, in conjunction with the new capital allocation framework, Ovintiv announced it received regulatory approval to commence a NCIB that enables the Company to purchase, for cancellation, up to approximately 26 million shares of common stock over a 12-month period from October 1, 2021 to September 30, 2022. During 2021, Ovintiv purchased for cancellation, approximately 3.1 million shares of common stock at an average price of $36.18 per share, for total consideration of approximately $111 million.
•
On October 6, 2021, Ovintiv launched its sustainability website, which highlights the Company’s progress on its key ESG metrics and initiatives, and announced several sustainability milestones related to emission reductions, social responsibility, and corporate governance. As of December 31, 2021, the Company exceeded its 33 percent methane emissions intensity reduction target, four years ahead of schedule and reduced its GHG emissions intensity by greater than 20 percent compared to 2019 levels. On February 24, 2022, the Company announced a further GHG emissions intensity reduction target of 50 percent compared to 2019 levels, to be achieved by 2030.
•
On February 24, 2022, Ovintiv announced an increase of about 43 percent to its quarterly dividend payment representing an annualized dividend of $0.80 per share of common stock as part of the Company’s commitment to returning capital to shareholders.
Financial Results
•
Reported net earnings of $1,416 million, including net losses on risk management in revenues of $1,883 million, before tax and a current income tax recovery of $156 million.
•
Generated cash from operating activities of $3,129 million, Non-GAAP Cash Flow of $3,209 million and Non-GAAP Cash Flow Margin of $16.46 per BOE. Cash from operating activities exceeded capital expenditures by $1,610 million.
•
Paid dividends of $0.4675 per share of common stock totaling $122 million.
•
Had $4.5 billion in total liquidity as at December 31, 2021, which included available credit facilities of $4.0 billion, available uncommitted demand lines of $300 million, and cash and cash equivalents of $195 million.
•
Reduced total long-term debt by $2.1 billion.
•
Reported Net Debt to Adjusted EBITDA of 1.4 times.
Capital Investment
•
Reported total capital spending of $1,519 million, which was in line with the full year 2021 investment plan of $1.5 billion.
•
Directed $1,362 million, or 90 percent, of total capital spending to the Core Assets.
•
Focused on highly efficient capital activity and short-cycle high margin projects providing flexibility to respond to fluctuations in commodity prices.
Production
•
Produced average liquids volumes of 274.5 Mbbls/d which accounted for 51 percent of total production volumes. Average oil and plant condensate volumes of 191.2 Mbbls/d, or 70 percent of total liquids production volumes, was in line with full year 2021 updated guidance of 191.0 Mbbls/d to 194.0 Mbbls/d.
•
Produced average natural gas volumes of 1,556 MMcf/d which accounted for 49 percent of total production volumes and was in line with full year 2021 updated guidance of 1,555 MMcf/d to 1,570 MMcf/d.
Operating Expenses
•
Incurred Total Costs in 2021 of $2,613 million, or $13.42 per BOE, an increase of $300 million or $1.82 per BOE compared to 2020. Total Costs is defined in the Non-GAAP Measures section of this MD&A. Significant items in 2021 compared to 2020 impacting Total Costs include:
o
Higher upstream transportation and processing expenses of $162 million, primarily due to higher production volumes in Montney ($95 million) and a higher U.S./Canadian dollar exchange rate ($55 million); and
o
Higher production, mineral and other taxes of $120 million, primarily due to higher commodity prices.
•
Total Operating Expenses in 2021 of $7,139 million decreased by $4,345 million primarily due to the non-cash ceiling test impairments of $5,580 million recognized in 2020.
Additional information on Total Costs items and Total Operating Expenses above can be found in the Results of Operations section of this MD&A.
2022 Outlook
Industry Outlook
Oil Markets
The oil and gas industry is cyclical and commodity prices are inherently volatile. Oil prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment.
In 2021, OPEC+ production cuts and increased global demand for oil resulted in upward pressures on oil prices and the tightening of global oil inventories. Oil prices during 2022 will continue to be impacted by the global containment of the coronavirus (“COVID-19”), pace of economic recovery, OPEC+ production levels, and the potential for higher U.S. production.
COVID-19 vaccine rollout/uptake continues to drive optimism, however, emerging COVID-19 variants may impact economic progress while the gradual easing of OPEC+ oil production cuts, the potential for higher U.S. oil production, and macroeconomic risks could contribute to commodity market uncertainty. Since the second quarter of 2021, OPEC+ has gradually increased production in response to increases in oil demand. OPEC+ continues to meet regularly to review the state of global oil supply, demand and inventory levels, and is expected to continue with its planned production increases in 2022.
Natural Gas Markets
Natural gas prices are primarily affected by structural changes in supply and demand as well as deviations from seasonally normal weather. In 2021, supportive weather conditions, limited supply growth from U.S. producers and increased electricity usage contributed to increased drawdowns of natural gas inventory and higher natural gas prices. Natural gas prices in 2022 are expected to be impacted by the interplay between gas production and associated gas from oil production, as well as changes in demand from the power generation sector, changes in export levels of liquified natural gas and impacts from seasonal weather.
Company Outlook
The Company continues to exercise discretion and discipline to optimize capital allocation throughout 2022 as oil demand recovers and the commodity price environment evolves. Ovintiv pursues innovative ways to reduce upstream operating and administrative expenses and expects to benefit from durable cost savings and efficiencies to maximize cash flows.
Markets for crude oil and natural gas are exposed to different price risks and are inherently volatile. 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. To mitigate price volatility and help sustain revenues, particularly during periods of low commodity prices, the Company enters into derivative financial instruments. As at December 31, 2021, the Company has hedged approximately 80.0 Mbbls/d of expected oil and condensate production and 1,293 MMcf/d of expected natural gas production for 2022. In addition, Ovintiv proactively utilizes transportation contracts to diversify the Company’s sales markets, thereby reducing significant exposure to any given market and regional pricing.
Additional information on Ovintiv’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.
Capital Investment
The Company plans to spend approximately $1.5 billion on its 2022 capital investment program. The majority of this capital program is expected to be allocated to the Core Assets with a focus on maximizing returns from high margin liquids. In 2022, 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. Initiatives such as applying Simul-Frac techniques, a process of fracking pairs of wells at the same time instead of a single well, increases operational efficiencies and contributes to well cost savings. Ovintiv's large-scale cube development
model utilizes multi-well pads and advanced completion designs to maximize returns and resource recovery from its reservoirs. Ovintiv’s disciplined capital program and continuous innovation create flexibility to allocate capital in changing commodity markets and to maximize cash flows while preserving the long-term value of the Company’s multi-basin portfolio.
Production
Ovintiv is strategically positioned in the current economic environment to maintain a flat liquids production profile while generating cash flows in excess of capital expenditures.
In 2022, the Company expects average oil and plant condensate production volumes of approximately 180.0 Mbbls/d to 190.0 Mbbls/d, other NGLs production volumes of approximately 78.0 Mbbls/d to 82.0 Mbbls/d and natural gas production volumes of approximately 1,450 MMcf/d to 1,500 MMcf/d.
Operating Expenses
The Company continues to benefit from cost savings measures implemented in 2020 which included workforce reductions and operating efficiencies. With rising activity in the oil and gas industry and the recovery of commodity prices, service and supply costs are expected to increase. Ovintiv continues to pursue innovative ways to reduce upstream operating and administrative expenses, and strives to minimize any inflationary pressures with efficiency improvements and effective supply chain management.
Total Costs per BOE is expected to increase for 2022 primarily due to higher production taxes resulting from expected strengthening of commodity prices and higher transportation and processing costs. For 2022, Ovintiv expects Total Costs of approximately $14.75 per BOE to $15.25 per BOE. Total Costs is defined in the Non-GAAP Measures section of this MD&A.
Long-Term Debt Reduction
Ovintiv remains focused on strengthening its balance sheet. Since the second quarter of 2020, the Company has allocated $2,580 million in excess cash flows to reduce its total long-term debt balance, which included proceeds from the Duvernay and Eagle Ford asset divestitures. The Company expects to achieve its Net Debt balance of $3.0 billion in the second half of 2022, assuming commodity prices of $85.00 per barrel for WTI oil and $4.50 per MMBtu for NYMEX natural gas.
In June 2021, the Company redeemed its $600 million, 5.75 percent senior notes due January 30, 2022, and in August 2021, redeemed its $518 million, 3.90 percent senior notes due November 15, 2021. The combined debt redemptions will result in annualized interest savings of over $50 million.
As at December 31, 2021, the Company had no outstanding balances under its revolving credit facilities and U.S. dollar commercial paper programs.
Additional information on Ovintiv’s long-term debt and liquidity position can be found in Note 15 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K and the Liquidity and Capital Resources section of this MD&A, respectively.
Additional information on Ovintiv’s 2022 Corporate Guidance can be accessed on the Company’s website at www.ovintiv.com.
Environmental, Social and Governance
Ovintiv recognizes the importance of reducing its environmental footprint and voluntarily participates in emission reduction programs. The Company has adopted a range of strategies to help reduce emissions from its operations. These strategies include incorporating new and proven technologies and optimizing processes in its drilling and completions operations, and working closely with third-party providers to develop best practices. The Company continues to look for innovative techniques and efficiencies to help maintain its commitment to emission reductions.
As of September 1, 2021, the Company is in alignment with the World Bank Zero Routine Flaring initiative, nine years ahead of the World Bank’s target date of 2030. Ovintiv does not engage in routine flaring by ensuring natural gas gathering infrastructure is in place for all of its producing wells.
As of December 31, 2021, the Company exceeded its targeted 33 percent reduction in methane emissions intensity four years ahead of schedule and achieved a greater than 20 percent reduction in Scope 1 and 2 GHG emissions intensity compared to 2019 levels. In 2022, the Company announced a further GHG emissions intensity reduction target of 50 percent compared to 2019 levels, to be achieved by 2030. This new emissions reduction target is also tied to its annual compensation program for all employees.
Ovintiv is committed to diversity, equity and inclusion. In 2021, the Company developed a new social commitment framework, which is rooted in the Company’s foundational values of integrity, safety, sustainability, trust and respect. The framework focuses on respecting stakeholders, strengthening communities and fostering a culture of inclusion.
Ovintiv remains committed to protecting the health and safety of its workforce. Safety is a foundational value at Ovintiv and plays a critical role in the Company’s belief that a safe workplace is a strong indicator of a well-managed business. This safety-oriented mindset enables the Company to quickly respond to emergencies and minimize any impacts to employees and business continuity. From the onset of the COVID-19 pandemic, Ovintiv established a Pandemic Response Team to continually assess the impact of COVID-19 and develop protocols and procedures to maintain a safe working environment for its staff. Despite the challenges presented by COVID-19, the Company reported its eighth consecutive safest year in 2021.
Additional information on Ovintiv’s ESG practices are outlined in Items 1 and 2 of this Annual Report on Form 10-K, and on the Company’s sustainability website at https://sustainability.ovintiv.com.
Results of Operations
Selected Financial Information
($ millions)
Product and Service Revenues
Upstream product revenues
$
7,420
$
4,044
Market optimization
3,043
1,459
Service revenues (1)
Total Product and Service Revenues
10,468
5,509
Gains (Losses) on Risk Management, Net
(1,883
)
Sublease Revenues
Total Revenues
8,658
6,087
Total Operating Expenses (2)
7,139
11,484
Operating Income (Loss)
1,519
(5,397
)
Total Other (Income) Expenses
Net Earnings (Loss) Before Income Tax
1,239
(5,730
)
Income Tax Expense (Recovery)
(177
)
Net Earnings (Loss)
$
1,416
$
(6,097
)
(1)
Service revenues include amounts related to the USA and Canadian Operations.
(2)
Total Operating Expenses include non-cash items such as DD&A, impairments, accretion of asset retirement obligations and long-term incentive costs.
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)
Oil & NGLs
WTI ($/bbl)
$
67.91
$
39.40
Houston ($/bbl)
68.85
41.05
Edmonton Condensate (C$/bbl)
85.48
49.45
Natural Gas
NYMEX ($/MMBtu)
$
3.84
$
2.08
AECO (C$/Mcf)
3.56
2.24
Dawn (C$/MMBtu)
4.60
2.50
Production Volumes and Realized Prices
Production Volumes (1)
Realized Prices (2)
Oil (Mbbls/d, $/bbl)
USA Operations
140.0
150.9
$
65.69
$
36.84
Canadian Operations
0.3
0.6
56.71
32.58
Total
140.3
151.5
65.67
36.83
NGLs - Plant Condensate (Mbbls/d, $/bbl)
USA Operations
10.5
11.1
60.18
26.68
Canadian Operations
40.4
41.0
67.11
35.87
Total
50.9
52.1
65.68
33.92
NGLs - Other (Mbbls/d, $/bbl)
USA Operations
67.5
70.3
25.66
9.52
Canadian Operations
15.8
15.0
29.45
11.53
Total
83.3
85.3
26.38
9.87
Total Oil & NGLs (Mbbls/d, $/bbl)
USA Operations
218.0
232.3
53.04
28.09
Canadian Operations
56.5
56.6
56.48
29.40
Total
274.5
288.9
53.75
28.34
Natural Gas (MMcf/d, $/Mcf)
USA Operations
3.71
1.60
Canadian Operations
1,066
1,000
3.52
2.01
Total
1,556
1,529
3.58
1.87
Total Production (MBOE/d, $/BOE)
USA Operations
299.7
320.5
44.65
23.00
Canadian Operations
234.2
223.3
29.66
16.42
Total
533.9
543.8
38.08
20.30
Production Mix (%)
Oil & Plant Condensate
NGLs - Other
Total Oil & NGLs
Natural Gas
Production Change - Year Over Year (%) (3)
Total Oil & NGLs
(5
)
(4
)
Natural Gas
(3
)
Total Production
(2
)
(4
)
Core Assets Production
Oil (Mbbls/d)
108.1
106.3
NGLs - Plant Condensate (Mbbls/d)
48.8
46.3
NGLs - Other (Mbbls/d)
76.2
75.8
Total Oil & NGLs (Mbbls/d)
233.1
228.4
Natural Gas (MMcf/d)
1,453
1,373
Total Production (MBOE/d)
475.2
457.2
% of Total Production
(1)
Average daily.
(2)
Average per-unit prices, excluding the impact of risk management activities.
(3)
Includes production impacts of acquisitions and divestitures.
Upstream Product Revenues
($ millions)
Oil
NGLs - Plant Condensate
NGLs - Other
Natural
Gas
Total
2020 Upstream Product Revenues
$
2,042
$
$
$
1,047
$
4,044
Increase (decrease) due to:
Sales prices
1,477
3,532
Production volumes
(155
)
(17
)
(7
)
(160
)
2021 Upstream Product Revenues (1)
$
3,364
$
1,218
$
$
2,032
$
7,416
(1)
Revenues for 2021 exclude certain other revenue and royalty adjustments with no associated production volumes of $4 million.
Oil Revenues
2021 versus 2020
Oil revenues increased $1,322 million compared to 2020 primarily due to:
•
Higher average realized oil prices of $28.84 per bbl, or 78 percent, increased revenues by $1,477 million. The increase reflected higher WTI and Houston benchmark prices which were up 72 percent and 68 percent, respectively, and the strengthening of regional pricing relative to the WTI benchmark price in the USA Operations; and
•
Lower average oil production volumes of 11.2 Mbbls/d decreased revenues by $155 million. Lower volumes were primarily due to natural declines surpassing incremental production in Eagle Ford, Anadarko and Bakken (11.3 Mbbls/d) and the sale of the Eagle Ford assets in the second quarter of 2021 (8.5 Mbbls/d), partially offset by successful drilling in Permian (5.4 Mbbls/d) and production shut-ins due to the economic downturn in 2020 (2.9 Mbbls/d).
NGL Revenues
2021 versus 2020
NGL revenues increased $1,065 million compared to 2020 primarily due to:
•
Higher average realized plant condensate prices of $31.76 per bbl, or 94 percent, increased revenues by $588 million. The increase reflected higher Edmonton Condensate and WTI benchmark prices which were up 73 percent and 72 percent, respectively, as well as higher regional pricing relative to the WTI benchmark price;
•
Higher average realized other NGL prices of $16.51 per bbl, or 167 percent, increased revenues by $501 million reflecting higher other NGL benchmark prices and higher regional pricing;
•
Lower average plant condensate production volumes of 1.2 Mbbls/d decreased revenues by $17 million. Lower volumes were primarily due to the sales of the Duvernay and Eagle Ford assets in the second quarter of 2021 (2.3 Mbbls/d) and natural declines in Duvernay and Anadarko (2.0 Mbbls/d), partially offset by successful drilling in Montney and Permian (3.0 Mbbls/d); and
•
Lower average other NGL production volumes of 2.0 Mbbls/d decreased revenues by $7 million. Lower volumes were primarily due to natural declines in Anadarko and Eagle Ford (4.3 Mbbls/d) and the sale of the Eagle Ford assets in the second quarter of 2021 (2.2 Mbbls/d), partially offset by successful drilling in Montney and Permian (4.0 Mbbls/d).
Natural Gas Revenues
2021 versus 2020
Natural gas revenues increased $985 million compared to 2020 primarily due to:
•
Higher average realized natural gas prices of $1.71 per Mcf, or 91 percent, increased revenues by $966 million. The increase reflected higher NYMEX, Dawn and AECO benchmark prices which were up 85 percent, 84 percent and 59 percent, respectively, and higher regional pricing; and
•
Higher average natural gas production volumes of 27 MMcf/d increased revenues by $19 million primarily due to successful drilling in Montney (119 MMcf/d), partially offset by natural declines in Anadarko and Duvernay (43 MMcf/d), the sales of the Duvernay and Eagle Ford assets in the second quarter of 2021 (36 MMcf/d) and increased third-party plant down-time in Montney (10 MMcf/d).
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, NGLs 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, 2021 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
Realized Gains (Losses) on Risk Management
Commodity Price (1)
Oil ($/bbl)
$
(737
)
$
$
(14.39
)
$
7.85
NGLs - Plant Condensate ($/bbl)
(155
)
$
(8.35
)
$
6.97
NGLs - Other ($/bbl)
(131
)
(14
)
$
(4.31
)
$
(0.46
)
Natural Gas ($/Mcf)
(373
)
$
(0.66
)
$
0.26
Other (2)
$
-
$
-
Total ($/BOE)
(1,395
)
$
(7.17
)
$
3.52
Unrealized Gains (Losses) on Risk Management
(488
)
(204
)
Total Gains (Losses) on Risk Management, Net
$
(1,883
)
$
(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. Additional information on fair value changes can be found in Note 24 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
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. Ovintiv also purchases and sells third-party volumes under marketing arrangements associated with the Company’s previous divestitures.
($ millions)
Market Optimization
$
3,043
$
1,459
2021 versus 2020
Market Optimization product revenues increased $1,584 million compared to 2020 primarily due to:
•
Higher oil and natural gas benchmark prices ($1,490 million) and higher sales of third-party purchased liquids volumes primarily relating to price optimization activities in the USA Operations ($555 million);
partially offset by:
•
Lower sales of third-party purchased natural gas volumes primarily relating to marketing arrangements for assets divested in prior years ($461 million).
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
USA Operations
$
$
$
2.54
$
1.34
Canadian Operations
$
0.18
$
0.18
Total
$
$
$
1.51
$
0.87
2021 versus 2020
Production, mineral and other taxes increased $120 million compared to 2020 primarily due to:
•
Higher production tax in USA Operations due to higher commodity prices ($144 million), partially offset by the sale of the Eagle Ford assets in the second quarter of 2021 ($15 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.
$ millions
$/BOE
USA Operations
$
$
$
4.64
$
3.86
Canadian Operations
$
10.97
$
10.12
Upstream Transportation and Processing
1,444
1,282
$
7.42
$
6.44
Market Optimization
Total
$
1,616
$
1,502
2021 versus 2020
Transportation and processing expense increased $114 million compared to 2020 primarily due to:
•
Higher volumes in Montney ($95 million), a higher U.S./Canadian dollar exchange rate ($57 million), higher variable rates in Permian and Anadarko due to higher natural gas prices ($57 million) and higher costs relating to the diversification of the Company’s downstream markets ($18 million);
partially offset by:
•
The expiration of certain transportation contracts in the USA Operations as well as expired contracts relating to previously divested assets ($51 million), the sales of the Eagle Ford and Duvernay assets in the second quarter of 2021 ($40 million), the decommissioning of Deep Panuke ($24 million), lower natural gas volumes in Anadarko ($16 million) and recoveries of amounts related to certain transportation contracts ($7 million).
Operating
Operating expense includes costs paid by the Company, net of amounts capitalized, on 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, electricity and workovers.
$ millions
$/BOE
USA Operations
$
$
$
4.48
$
4.12
Canadian Operations
$
1.27
$
1.21
Upstream Operating Expense (1)
$
3.07
$
2.92
Market Optimization
Corporate & Other
(1
)
(2
)
Total
$
$
(1)
Upstream Operating Expense per BOE for 2021 includes long-term incentive costs of $0.13/BOE (2020 - long-term incentive costs of $0.04/BOE).
2021 versus 2020
Operating expense increased $20 million compared to 2020 primarily due to:
•
Increased activity resulting from higher production in Permian and improved commodity prices ($32 million), lower capitalization of directly attributable internal costs ($26 million), higher long-term incentive costs resulting from an increase in the Company’s share price in 2021 compared to a decrease in 2020 ($21 million) and a higher U.S./Canadian dollar exchange rate ($7 million);
partially offset by:
•
The sales of the Eagle Ford and Duvernay assets in the second quarter of 2021 ($43 million) and lower salaries and benefits due to decreased headcount resulting from workforce reductions in the second quarter of 2020 ($23 million).
Additional information on the Company’s long-term incentive costs can be found in Note 22 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Purchased Product
Purchased product expense includes purchases of oil, NGLs and natural gas from third parties that are used to provide operational flexibility and cost mitigation for transportation commitments, product type, delivery points and customer diversification. The Company also purchases and sells third-party volumes under marketing arrangements associated with the Company’s previous divestitures.
($ millions)
Market Optimization
$
2,951
$
1,366
2021 versus 2020
Purchased product expense increased $1,585 million compared to 2020 primarily due to:
•
Higher oil and natural gas benchmark prices ($1,451 million) and higher third-party purchased liquids volumes primarily relating to price optimization activities in the USA Operations ($556 million);
partially offset by:
•
Lower third-party purchased natural gas volumes primarily relating to marketing arrangements for assets divested in prior years ($422 million).
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.
Additional information can be found under Upstream Assets and Reserve Estimates in the Critical Accounting Estimates section of this MD&A.
$ millions
$/BOE
USA Operations
$
$
1,378
$
7.65
$
11.75
Canadian Operations
$
3.89
$
5.21
Upstream DD&A
1,169
1,805
$
6.00
$
9.06
Corporate & Other
Total
$
1,190
$
1,834
2021 versus 2020
DD&A decreased $644 million compared to 2020 primarily due to:
•
Lower depletion rates in the USA and Canadian Operations ($448 million and $144 million, respectively) and lower production volumes in USA Operations ($93 million), partially offset by higher U.S./Canadian dollar exchange rate ($32 million) and higher production volumes in the Canadian Operations ($19 million).
The depletion rate in the USA Operations decreased $4.10 per BOE compared to 2020 primarily due to the ceiling test impairments recognized in 2020 and the sale of the Eagle Ford assets in the second quarter of 2021. The depletion rate in the Canadian Operations decreased $1.32 per BOE compared to 2020 primarily due to the sale of the Duvernay assets in the second quarter of 2021.
Impairments
Under full cost accounting, the carrying amount of Ovintiv’s oil and natural gas properties within each country cost centre is subject to a ceiling test performed quarterly. Ceiling test impairments are recognized when the capitalized costs, net of accumulated depletion and the related deferred income taxes, exceed the sum of the estimated after-tax future net cash flows from proved reserves as calculated under SEC requirements using the 12-month average trailing prices and discounted at 10 percent. 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.
In 2021, the Company did not recognize ceiling test impairments (2020 - $5,580 million before tax, in the USA Operations). The non-cash ceiling test impairments in 2020 primarily resulted from the decline in the 12-month average trailing prices, which reduced proved reserves.
The 12-month average trailing prices used in the ceiling test calculations were based on the benchmark prices below. The benchmark prices were adjusted for basis differentials to determine local reference prices, transportation costs and tariffs, heat content and quality.
Oil & NGLs
Natural Gas
WTI
($/bbl)
Edmonton
Condensate
(C$/bbl)
Henry Hub
($/MMBtu)
AECO
(C$/MMBtu)
12-Month Average Trailing Reserves Pricing (1)
66.56
83.69
3.60
3.26
39.62
49.77
1.98
2.13
(1)
All prices were held constant in all future years when estimating net revenues and reserves.
The Company 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. The discounted after-tax future net cash flows do not consider the fair market value of unamortized unproved properties, or probable or possible liquids and natural gas reserves. In addition, there is no consideration given to the effect of future changes in commodity prices. Ovintiv manages its business using estimates of reserves and resources based on forecast prices and costs. Additional information on the ceiling test calculation can be found in Note 10 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Administrative
Administrative expense represents costs associated with corporate functions provided by Ovintiv staff. Costs primarily include salaries and benefits, operating lease, office, information technology, restructuring and long-term incentive costs.
$ millions
$/BOE
Administrative, excluding Long-Term Incentive Costs,
Restructuring and Legal Costs, and Current
Expected Credit Losses (1)
$
$
$
1.55
$
1.41
Long-term incentive costs
0.55
0.12
Restructuring and legal costs
0.17
0.45
Current expected credit losses
-
-
Total Administrative (2)
$
$
$
2.27
$
1.98
(1)
Includes costs related to The Bow office lease of $117 million (2020 - $110 million), half of which is recovered from sublease revenues.
(2)
Total Administrative costs for 2021 reflects a higher U.S./Canadian dollar exchange rate of $13 million.
2021 versus 2020
Administrative expense increased $47 million compared to 2020 primarily due to:
•
Higher long-term incentive costs resulting from an increase in the Company’s share price in 2021 compared to a decrease in 2020 ($84 million) and higher legal and consulting costs ($28 million);
partially offset by:
•
A decrease in restructuring costs related to workforce reductions in 2020 ($76 million).
During 2020, the Company completed workforce reductions as part of a company-wide reorganization in response to the low commodity price environment resulting from the global pandemic and the Company’s planned reductions in capital spending. Additional information on restructuring charges and long-term incentive costs can be found in Notes 21 and 22, respectively, to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Other (Income) Expenses
($ millions)
Interest
$
$
Foreign exchange (gain) loss, net
(23
)
Other (gains) losses, net
(37
)
(55
)
Total Other (Income) Expenses
$
$
Interest
Interest expense primarily includes interest on Ovintiv’s long-term debt. 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.
2021 versus 2020
Interest expense decreased $31 million compared to 2020 primarily due to:
•
The redemption of the Company’s 2021 and 2022 senior notes ($25 million), and open market repurchases of long-term debt completed in 2020 and decreased amounts drawn from the Company’s credit facilities ($21 million);
partially offset by:
•
A one-time make-whole interest payment of $19 million resulting from the June 2021 early redemption of the Company’s $600 million, 5.75 percent senior notes due January 30, 2022.
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 Item 7A of this Annual Report on Form 10-K.
Following the completion of the corporate reorganization and U.S. domestication in the first quarter of 2020, 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, no longer attract foreign exchange translation gains or losses.
2021 versus 2020
Net foreign exchange gain was $23 million compared to a loss of $17 million in 2020 primarily due to:
•
Lower unrealized foreign exchange losses on the translation of U.S. dollar financing debt issued from Canada compared to 2020 ($50 million), realized foreign exchange gains on the settlement of U.S. dollar risk management contracts and financing debt issued from Canada compared to losses in 2020 ($34 million and $9 million, respectively) and realized foreign exchange gains on the settlement of intercompany notes compared to losses in 2020 ($8 million);
partially offset by:
•
Unrealized foreign exchange losses on the translation of U.S. dollar risk management contracts issued from Canada compared to gains in 2020 ($33 million) and lower unrealized foreign exchange gains on the translation of intercompany notes ($27 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, gains on debt repurchases, government stimulus programs and adjustments related to other assets.
Other gains in 2021 includes interest income of $14 million primarily associated with the resolution of prior years’ tax items.
Other gains in 2020 primarily included gains of $30 million relating to the repurchase of the Company’s fixed long-term debt on the open market and interest income of $5 million.
Income Tax
($ millions)
Current Income Tax Expense (Recovery)
$
(156
)
$
(14
)
Deferred Income Tax Expense (Recovery)
(21
)
Income Tax Expense (Recovery)
$
(177
)
$
Effective Tax Rate
(14.3%
)
(6.4%
)
Income Tax Expense (Recovery)
2021 versus 2020
In 2021, Ovintiv recorded an income tax recovery of $177 million compared to an income tax expense of $367 million in 2020, primarily due to the resolution of prior years’ tax items and the change in valuation allowances.
Deferred income tax assets are routinely assessed for realizability. During the year ended December 31, 2020, the Company determined, after weighing both positive and negative evidence, that a valuation allowance should be recorded to reduce the associated deferred tax assets in the U.S. and in Canada. Accordingly, a valuation allowance of $568 million was recognized in Canada related to prior years’ deferred tax assets during the year ended December 31, 2020. As at December 31, 2021, the Company continues to be in a cumulative three-year loss position in both the U.S. and Canada and as such, continues to recognize the valuation allowance against net deferred tax assets. The cumulative three-year losses and uncertainty in the timing as to when the realization of deferred tax assets will occur, is significant negative evidence to overcome, and consequently, it is more likely than not that the deferred tax assets will not be realizable. However, if market conditions continue to improve, it is possible that a portion of the valuation allowance in Canada may be reversed within the next 12 months.
Effective Tax Rate
The Company’s annual effective income tax rate is primarily impacted by earnings, changes in valuation allowances, amounts in respect of prior periods, state taxes, income tax related to foreign operations, the effect of legislative changes, and tax differences on divestitures and transactions.
The Company’s effective tax rate was (14.3) percent for 2021, which is lower than the U.S. federal statutory tax rate of 21 percent primarily due to the resolution of prior years’ tax items and the change in valuation allowances.
The Company’s effective tax rate was (6.4) percent for 2020, which is lower than the U.S. federal statutory tax rate of 21 percent primarily due to valuation allowances recorded relating to net losses arising from ceiling test impairments and an increase in the valuation allowance of $568 million in Canada related to prior years’ deferred tax assets.
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 tax 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.
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.
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. Ovintiv 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, 2021, $188 million in cash and cash equivalents was held by Canadian subsidiaries. The cash held by Canadian subsidiaries is accessible and may be subject to additional U.S. income taxes and Canadian withholding taxes if repatriated.
The Company’s capital structure consists of total shareholders’ equity plus long-term debt, including any current portion. The Company’s objectives when managing its capital structure are to maintain financial flexibility to preserve Ovintiv’s access to capital markets and its ability to meet financial obligations and finance internally generated growth, as well as potential acquisitions. Ovintiv has a practice of maintaining capital discipline and strategically managing its capital structure by adjusting capital spending, adjusting dividends paid to shareholders, issuing new shares of common stock, purchasing shares of common stock for cancellation, issuing new debt and repaying or repurchasing existing debt.
($ millions, except as indicated)
Cash and Cash Equivalents
$
$
Available Credit Facilities (1)
4,000
3,402
Available Uncommitted Demand Lines (2)
Issuance of U.S. Commercial Paper
-
(352
)
Total Liquidity
$
4,495
$
3,329
Long-Term Debt, including current portion
$
4,786
$
6,885
Total Shareholders’ Equity (3)
$
5,074
$
3,837
Debt to Capitalization (%) (4)
Debt to Adjusted Capitalization (%) (5)
(1)
Includes available credit facilities of $2.5 billion (2020 - $2.1 billion) in the U.S. and $1.5 billion (2020 - $1.3 billion) in Canada as at December 31, 2021 (collectively, the “Credit Facilities”).
(2)
Includes three uncommitted demand lines totaling $336 million, net of $36 million in related undrawn letters of credit (2020 - $336 million and $67 million, respectively).
(3)
Shareholders’ Equity reflects the shares of common stock purchased, for cancellation, under the Company’s 2021 NCIB program.
(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.
The Company has access to two 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, both maturing in July 2024. The Credit Facilities provide financial flexibility and allow the Company to fund its operations or capital program. At December 31, 2021, there were no outstanding amounts under the revolving Credit Facilities and the Company continues to have full access to its Credit Facilities.
During the fourth quarter of 2021, Ovintiv’s credit rating was upgraded to investment grade by one of its credit rating agencies driven by Ovintiv’s significant debt reductions and improved commodity price assumptions used by the rating agency. As a result of the upgrade, most of Ovintiv’s credit ratings are investment grade.
Depending on the Company’s credit rating and market demand, the Company may issue from its two U.S. CP programs, which include a $1.5 billion program for Ovintiv Inc. and a $1.0 billion program for a Canadian subsidiary. As at December 31, 2021, the Company had no commercial paper outstanding under its U.S. CP programs and continues to have full access to its U.S. CP programs.
The Credit Facilities, uncommitted demand lines, and cash and cash equivalents provide Ovintiv with total liquidity of approximately $4.5 billion. At December 31, 2021, Ovintiv also had approximately $36 million in undrawn
letters of credit issued in the normal course of business primarily as collateral security, related to transportation arrangements and to support future abandonment liabilities.
Ovintiv has a U.S. shelf registration statement and a Canadian shelf prospectus, under which the Company may issue from time to time, debt securities, common stock, preferred stock, warrants, units, share purchase contracts and share purchase units in the U.S. and/or Canada. At December 31, 2021, $6.0 billion remained accessible under the Canadian shelf prospectus. The ability to issue securities under the U.S. shelf registration statement or Canadian shelf prospectus is dependent upon market conditions and securities law requirements.
Ovintiv is currently in compliance with, and expects that it will continue to be in compliance with, all financial covenants under the Credit Facilities. Management monitors Debt to Adjusted Capitalization, which is a non-GAAP measure defined in the Non-GAAP Measures section of this MD&A, as a proxy for Ovintiv’s financial covenant under the Credit Facilities, which requires Debt to Adjusted capitalization to be less than 60 percent. As at December 31, 2021, the Company’s Debt to Adjusted Capitalization was 27 percent. The definitions used in the covenant under the Credit Facilities adjust capitalization for cumulative historical ceiling test impairments recorded in conjunction with the Company’s January 1, 2012 adoption of U.S. GAAP. Ovintiv does not expect the current COVID-19 pandemic to impact the Company’s ability to remain in compliance with its financial covenants under the Credit Facilities. Additional information on financial covenants can be found in Note 15 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Sources and Uses of Cash
During 2021, the Company primarily generated cash through operating activities and divestitures. The following table summarizes the sources and uses of the Company’s cash and cash equivalents.
($ millions)
Activity Type
Sources of Cash, Cash Equivalents and Restricted Cash
Cash from operating activities
Operating
$
3,129
$
1,895
Proceeds from divestitures
Investing
1,025
Net issuance of revolving long-term debt
Financing
-
4,154
2,236
Uses of Cash and Cash Equivalents
Capital expenditures
Investing
1,519
1,736
Acquisitions
Investing
Net repayment of revolving long-term debt
Financing
-
Repayment of long-term debt (1)
Financing
1,137
Purchase of shares of common stock
Financing
-
Dividends on shares of common stock
Financing
Other
Financing/Investing
3,969
2,411
Foreign Exchange Gain (Loss) on Cash, Cash Equivalents
and Restricted Cash Held in Foreign Currency
-
(5
)
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash
$
$
(180
)
(1)
Includes open market repurchases in 2020.
Operating Activities
Net cash from operating activities in 2021 was $3,129 million and was primarily a reflection of the impacts from higher average realized commodity prices, partially offset by the effects of the Company’s commodity price mitigation program and changes in non-cash working capital.
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 2021 was $3,209 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.
2021 versus 2020
Net cash from operating activities increased $1,234 million compared to 2020 primarily due to:
•
Higher realized commodity prices ($3,532 million), a current income tax recovery mainly due to the resolution of prior years’ tax items ($156 million), lower decommissioning payments primarily related to Deep Panuke ($123 million), lower administrative expenses, excluding non-cash long-term incentive costs and current expected credit losses ($25 million) and higher interest income ($9 million);
partially offset by:
•
Realized losses on risk management in revenues compared to gains in 2020 ($2,106 million), changes in non-cash working capital ($180 million), lower production volumes ($160 million), higher production, mineral and other taxes ($120 million) and higher transportation and processing expense ($114 million).
Investing Activities
The Company’s primary investing activities are capital expenditures, divestitures and acquisitions, and are summarized in Notes 2 and 9 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
2021 and 2020
Net cash used in investing activities in 2021 was $525 million primarily due to capital expenditures, partially offset by proceeds from divestitures. Capital expenditures decreased $217 million compared to 2020 due to the Company’s reduced capital program in response to the volatile market conditions that commenced at the end of the first quarter of 2020 as well as the Company’s drive to maintain capital discipline while maximizing efficiency gains.
Acquisitions in 2021 were $11 million (2020 - $19 million), which primarily included property purchases with oil and liquids rich potential.
Divestitures in 2021 were $1,025 million, which primarily included the sale of the Eagle Ford assets in south Texas and Duvernay assets in west central Alberta, totaling approximately $1.0 billion, after closing and other adjustments, as well as certain properties that did not complement Ovintiv’s existing portfolio of assets. Divestitures in 2020 were $89 million, which primarily included the sale of certain properties that did not complement Ovintiv’s existing portfolio of assets.
Financing Activities
Net cash used in financing activities has been impacted by the Company’s strategy to enhance liquidity, strengthen its balance sheet by repaying or repurchasing existing debt, and returning value to shareholders through the purchase of shares of common stock and paying dividends.
2021 versus 2020
Net cash used in financing activities in 2021 increased $2,213 million compared to 2020. The increase was primarily due to a net repayment of revolving long-term debt in 2021 of $950 million compared to a net issuance in 2020 of $252 million, higher repayment of long-term debt associated with the early redemption of the Company’s senior notes ($865 million) and shares of common stock purchased under the 2021 NCIB ($111 million) as discussed below.
From time to time, Ovintiv may seek to retire or purchase the Company’s outstanding debt through cash purchases and/or exchanges for other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, the Company’s liquidity requirements, contractual restrictions and other factors.
The Company’s long-term debt totaled $4,786 million at December 31, 2021. There was no current portion of long-term debt outstanding at December 31, 2021. The Company’s long-term debt at December 31, 2020 totaled $6,885 million, which included the current portion of $518 million. In June 2021, the Company redeemed its $600 million, 5.75 percent senior notes due January 30, 2022, and in August 2021, redeemed its $518 million, 3.90 percent senior notes due November 15, 2021. The combined debt redemptions will result in annualized interest savings of over $50 million. As at December 31, 2021, the Company has no fixed rate long-term debt due until 2024 and beyond.
Since the second quarter of 2020, the Company has allocated $2,580 million in excess cash flows to reduce its total long-term debt balance, which includes proceeds from the Duvernay and Eagle Ford asset divestitures. The Company expects to achieve its Net Debt balance of $3.0 billion in the second half of 2022, assuming commodity prices of $85.00 per barrel for WTI oil and $4.50 per MMBtu for NYMEX natural gas.
In support of the Company’s commitment to growing shareholder value, Ovintiv announced a new capital allocation framework in the third quarter that outlines increasing returns to shareholders as well as continuing the Company’s progress on debt reduction.
For additional information on long-term debt, refer to Note 15 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Dividends
The Company pays quarterly dividends to common shareholders at the discretion of the Board of Directors.
($ millions, except as indicated)
Dividend Payments
$
$
Dividend Payments ($/share)
$
0.4675
$
0.375
On February 24, 2022, the Board of Directors declared a dividend of $0.20 per share of common stock payable on March 31, 2022 to common shareholders of record as of March 15, 2022. This represents an increase of about 43 percent to the annualized dividend payment.
Normal Course Issuer Bid
On September 28, 2021, Ovintiv announced it received regulatory approval to commence a NCIB that enables the Company to purchase, for cancellation, up to approximately 26 million shares of common stock over a 12-month period from October 1, 2021 to September 30, 2022. The number of shares authorized for purchase represent approximately 10 percent of Ovintiv’s issued and outstanding shares of common stock as at September 20, 2021. The Company is funding the NCIB through its new capital allocation framework as discussed above. In 2021, the Company purchased for cancellation, approximately 3.1 million shares of common stock for total consideration of approximately $111 million.
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.
Material Cash Requirements
Ovintiv’s material cash requirements include various contractual obligations arising from long-term debt, operating leases, risk management liabilities and asset retirement obligations which are recognized on the Company’s Consolidated Balance Sheet. The Company expects to fund long term material cash requirements primarily with cash from operating activities.
Interest payments include scheduled cash payments on long-term debt, finance leases and other 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, office and buildings, certain land easements and various equipment utilized in the development and production of oil, NGLs and natural gas, as well as The Bow building. The Company has subleased approximately 50 percent of The Bow office space under the lease agreement. Additional information on leases 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 represent Ovintiv’s net liability positions with counterparties. The majority of the Company’s risk management positions are expected to be settled by the end of 2022. 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.
Contractual commitments relating to transportation and processing commitments, and drilling and field services can be found in Notes 14 and 27 to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
Further to the commitments discussed above, Ovintiv also has various obligations that become payable if certain future events occur relating to take or pay arrangements 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, the Company has obligations to fund its defined benefit pension and other post-employment benefit plans, as well as obligations to fund the disposal of long-lived assets upon their abandonment as described in Notes 23 and 17, respectively, to the Consolidated Financial Statements included in Item 8 of this Annual Report on Form 10-K.
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.
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.
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, NGLs 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 natural 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.
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 impairment, the carrying amount of each reporting unit is determined and compared to the fair value of each respective reporting unit. Any excess of the carrying value of the reporting unit, including goodwill, over its fair value is recognized as an impairment and charged to net earnings. The impairment charge measured is limited to the total amount of goodwill allocated to that reporting unit. Subsequent measurement of goodwill is at cost less any accumulated impairments.
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.
Description
Judgments and Uncertainties
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, processing plants, and restoring land at the end of oil and natural 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. These inputs may also be observable and corroborated by market data or unobservable and sourced from limited market activity, internally generated estimates or corroborated by third parties. Changes in these estimates and assumptions can impact net earnings, revenues and 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.
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, legislation and potential Treasury Department 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.
Description
Judgments and Uncertainties
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, changes in valuation allowances, state taxes, income tax related to foreign operations, the effect of legislative changes, and tax differences on divestitures and transactions.
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.
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, Net Debt 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)
Cash From (Used in) Operating Activities
$
3,129
$
1,895
(Add back) deduct:
Net change in other assets and liabilities
(39
)
(173
)
Net change in non-cash working capital
(41
)
Current tax on sale of assets
-
-
Non-GAAP Cash Flow (1)
$
3,209
$
1,929
Divided by:
Production Volumes (MMBOE)
194.9
199.0
Non-GAAP Cash Flow Margin ($/BOE)
$
16.46
$
9.69
(1)
2021 includes restructuring costs of $14 million (2020 - $90 million).
Total Costs
Total Costs is a non-GAAP measure which includes the summation of production, mineral and other taxes, upstream transportation and processing expense, upstream operating expense and administrative expense, excluding the impact of long-term incentive, restructuring and legal costs, and current expected credit losses. It is calculated as total operating expenses excluding non-upstream operating costs and non-cash items which include operating expenses from the Market Optimization and Corporate and Other segments, depreciation, depletion and amortization, impairments, accretion of asset retirement obligation, long-term incentive, restructuring and legal costs, and current expected credit losses. When presented on a per BOE basis, Total Costs is divided by production volumes. Management believes this measure is useful to the Company and its investors as a measure of operational efficiency across periods.
($ millions, except as indicated)
Total Operating Expenses
$
7,139
$
11,484
Deduct (add back):
Market optimization operating expenses
3,148
1,608
Corporate & other operating expenses
(1
)
(2
)
Depreciation, depletion and amortization
1,190
1,834
Impairments
-
5,580
Accretion of asset retirement obligation
Long-term incentive costs
Restructuring and legal costs
Current expected credit losses
Total Costs
$
2,613
$
2,313
Divided by:
Production Volumes (MMBOE)
194.9
199.0
Total Costs ($/BOE) (1)
$
13.42
$
11.60
(1)
Calculated using whole dollars and volumes.
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, 2021
December 31, 2020
Long-Term Debt, including current portion
$
4,786
$
6,885
Total Shareholders’ Equity
5,074
3,837
Equity Adjustment for Impairments at December 31, 2011
7,746
7,746
Adjusted Capitalization
$
17,606
$
18,468
Debt to Adjusted Capitalization
27%
37%
Net Debt and Net Debt to Adjusted EBITDA
Net Debt and Net Debt to Adjusted EBITDA are non-GAAP measures 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, depreciation, depletion and amortization, 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 these measures are 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. These measures are 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, 2021
December 31, 2020
Long-Term Debt, including current portion
$
4,786
$
6,885
Less:
Cash and cash equivalents
Net Debt
4,591
6,875
Net Earnings (Loss)
1,416
(6,097
)
Add back (deduct):
Depreciation, depletion and amortization
1,190
1,834
Impairments
-
5,580
Accretion of asset retirement obligation
Interest
Unrealized (gains) losses on risk management
Foreign exchange (gain) loss, net
(23
)
(Gain) loss on divestitures, net
-
-
Other (gains) losses, net
(37
)
(55
)
Income tax expense (recovery)
(177
)
Adjusted EBITDA
$
3,219
$
2,250
Net Debt to Adjusted EBITDA (times)
1.4
3.1

---

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 Ovintiv’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, NGLs 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, 2021
10% Price
10% Price
(US$ millions)
Increase
Decrease
Crude oil price
$
(160
)
$
Natural gas price
(164
)
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. The following table presents the foreign exchange rates for the respective years ended December 31.
Foreign Exchange Rates (C$ per US$1)
Average
1.254
1.342
Period End
1.268
1.273
As Ovintiv operates primarily 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. The table below summarizes selected foreign exchange impacts on Ovintiv’s financial results when compared to the same periods in the prior years.
$ millions
$/BOE
$ millions
$/BOE
Increase (Decrease) in:
Capital Investment
$
$
(6
)
Transportation and Processing Expense (1)
$
0.28
(7
)
$
(0.04
)
Operating Expense (1)
0.03
(1
)
(0.01
)
Administrative Expense
0.07
(3
)
(0.02
)
Depreciation, Depletion and Amortization (1)
0.15
(4
)
(0.02
)
(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, 2021, Ovintiv has entered into $400 million notional U.S. dollar denominated currency swaps at an average exchange rate of C$1.2848 to US$1, which mature monthly throughout 2022.
As at December 31, 2021, Ovintiv did not have any U.S. dollar denominated financing debt issued from Canada or foreign denominated intercompany loans that were subject to foreign exchange exposure.
The table below summarizes the sensitivity to foreign exchange rate fluctuations, with all other variables held constant. The Company has used a 10 percent variability to assess the potential impact from Canadian to U.S. foreign currency exchange rate changes. Fluctuations in foreign currency exchange rates could have resulted in unrealized gains (losses) impacting pre-tax net earnings as follows:
December 31, 2021
(US$ millions)
10% Rate
Increase
10% Rate
Decrease
Foreign currency exchange
$
(32
)
$
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, 2021, Ovintiv had no floating rate debt and there were no interest rate derivatives outstanding.

---

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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 United States and Canadian 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, 2021. 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 registered public accounting firm, 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, 2021, as stated in their Auditor’s Report. PricewaterhouseCoopers LLP has provided such opinions.
/s/ Brendan M. McCracken
Brendan M. McCracken
President & Chief Executive Officer
February 25, 2022
/s/ Corey D. Code
Corey D. Code
Executive Vice-President &
Chief Financial Officer
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. and its subsidiaries (together, the “Company”) as of December 31, 2021 and 2020, 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, 2021, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 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, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
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.
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 matter communicated below is a matter arising from the current period audit of the Consolidated Financial Statements that was communicated or required to be communicated to the audit committee and that (i) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
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 a net oil and natural gas proved properties balance of $6,607 million as of December 31, 2021 and depreciation, depletion, and amortization (“DD&A”) expense of $1,190 million for the year ended December 31, 2021. 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 (i) 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 and (ii) 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 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 calculation of the full
cost ceiling test and the calculation of DD&A expense. These procedures also included, among others, evaluating management’s ceiling test impairment calculation and testing the unit-of-production depletion 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 were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ 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.
/s/ PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Canada
February 25, 2022
We have served as the Company’s or its predecessors’ auditor since 1958.
Consolidated Statement of Earnings
For the years ended December 31 (US$ millions, except per share amounts)
Revenues
(Note 2)
Product and service revenues
(Note 3)
$
10,468
$
5,509
$
7,013
Gains (losses) on risk management, net
(Note 25)
(1,883
)
(361
)
Sublease revenues
(Note 14)
Total Revenues
8,658
6,087
6,726
Operating Expenses
(Note 2)
Production, mineral and other taxes
Transportation and processing
1,616
1,502
1,558
Operating
(Notes 14, 22, 23)
Purchased product
2,951
1,366
1,043
Depreciation, depletion and amortization
1,190
1,834
2,015
Impairments
(Note 10)
-
5,580
-
Accretion of asset retirement obligation
(Note 17)
Administrative
(Notes 14, 21, 22, 23)
Total Operating Expenses
7,139
11,484
6,128
Operating Income (Loss)
1,519
(5,397
)
Other (Income) Expenses
Interest
(Notes 4, 15)
Foreign exchange (gain) loss, net
(Notes 5, 25)
(23
)
(119
)
(Gain) loss on divestitures, net
-
-
(3
)
Other (gains) losses, net
(Notes 6, 8, 15, 23)
(37
)
(55
)
Total Other (Income) Expenses
Net Earnings (Loss) Before Income Tax
1,239
(5,730
)
Income tax expense (recovery)
(Note 6)
(177
)
Net Earnings (Loss)
$
1,416
$
(6,097
)
$
Net Earnings (Loss) per Share of Common Stock
(Note 18)
Basic
$
5.44
$
(23.47
)
$
0.90
Diluted
5.32
(23.47
)
0.90
Weighted Average Shares of Common Stock Outstanding (millions)
(Note 18)
Basic
260.4
259.8
261.2
Diluted
266.4
259.8
261.2
Consolidated Statement of Comprehensive Income
For the years ended December 31 (US$ millions)
Net Earnings (Loss)
$
1,416
$
(6,097
)
$
Other Comprehensive Income (Loss), Net of Tax
Foreign currency translation adjustment
(Note 19)
Pension and other post-employment benefit plans
(Notes 19, 23)
(8
)
Other Comprehensive Income (Loss)
Comprehensive Income (Loss)
$
1,432
$
(6,067
)
$
See accompanying Notes to Consolidated Financial Statements
Consolidated Balance Sheet
As at December 31 (US$ millions)
Assets
Current Assets
Cash and cash equivalents
$
$
Accounts receivable and accrued revenues (net of allowances
of $5 million (2020: $4 million))
(Notes 3, 7)
1,294
Risk management
(Notes 24, 25)
Income tax receivable
(Note 6)
1,587
1,247
Property, Plant and Equipment, at cost:
(Note 10)
Oil and natural gas properties, based on full cost accounting
Proved properties
55,475
53,883
Unproved properties
1,944
2,962
Other
Property, plant and equipment
58,322
57,756
Less: Accumulated depreciation, depletion and amortization
(49,561
)
(48,306
)
Property, plant and equipment, net
(Note 2)
8,761
9,450
Other Assets
(Notes 11, 14)
1,079
1,143
Risk Management
(Notes 24, 25)
-
Goodwill
(Notes 2, 8, 12)
2,628
2,625
(Note 2)
$
14,055
$
14,469
Liabilities and Shareholders’ Equity
Current Liabilities
Accounts payable and accrued liabilities
(Note 13)
$
1,979
$
1,704
Current portion of operating lease liabilities
(Note 14)
Income tax payable
Risk management
(Notes 24, 25)
Current portion of long-term debt
(Note 15)
-
2,748
2,423
Long-Term Debt
(Note 15)
4,786
6,367
Operating Lease Liabilities
(Note 14)
Other Liabilities and Provisions
(Notes 14, 16)
Risk Management
(Notes 24, 25)
Asset Retirement Obligation
(Note 17)
Deferred Income Taxes
(Note 6)
8,981
10,632
Commitments and Contingencies
(Note 27)
Shareholders’ Equity
Share capital - authorized 775 million shares of stock
2021 issued and outstanding: 258.0 million shares (2020: 259.8 million shares)
(Note 18)
Paid in surplus
(Note 18)
8,458
8,531
Retained earnings (Accumulated deficit)
(4,479
)
(5,773
)
Accumulated other comprehensive income
(Note 19)
1,092
1,076
Total Shareholders’ Equity
5,074
3,837
$
14,055
$
14,469
See accompanying Notes to Consolidated Financial Statements
Approved by the Board of Directors
/s/ Peter A. Dea
/s/ Bruce G. Waterman
Peter A. Dea
Bruce G. Waterman
Director
Director
Consolidated Statement of Changes in Shareholders’ Equity
Retained
Accumulated
Earnings
Other
Total
Share
Paid in
(Accumulated
Comprehensive
Shareholders’
For the year ended December 31, 2021 (US$ millions)
Capital
Surplus
Deficit)
Income
Equity
Balance, December 31, 2020
$
$
8,531
$
(5,773
)
$
1,076
$
3,837
Net Earnings (Loss)
-
-
1,416
-
1,416
Dividends on Shares of Common Stock ($0.4675 per share)
(Note 18)
-
-
(122
)
-
(122
)
Shares of Common Stock Purchased under Normal
Course Issuer Bid
(Note 18)
-
(111
)
-
-
(111
)
Equity-Settled Compensation Costs
-
-
-
Other Comprehensive Income (Loss)
(Note 19)
-
-
-
Balance, December 31, 2021
$
$
8,458
$
(4,479
)
$
1,092
$
5,074
Retained
Accumulated
Earnings
Other
Total
Share
Paid in
(Accumulated
Comprehensive
Shareholders’
For the year ended December 31, 2020 (US$ millions)
Capital
Surplus
Deficit)
Income
Equity
Balance, December 31, 2019
$
7,061
$
1,402
$
$
1,046
$
9,930
Net Earnings (Loss)
-
-
(6,097
)
-
(6,097
)
Dividends on Shares of Common Stock ($0.375 per share)
(Note 18)
-
-
(97
)
-
(97
)
Equity-Settled Compensation Costs
-
-
-
Other Comprehensive Income (Loss)
(Note 19)
-
-
-
Reclassification of Share Capital due to the Reorganization
(Note 18)
(7,058
)
7,058
-
-
-
Balance, December 31, 2020
$
$
8,531
$
(5,773
)
$
1,076
$
3,837
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
$
$
$
7,447
Net Earnings (Loss)
-
-
-
Dividends on Common Shares ($0.375 per share)
(Note 18)
-
-
(102
)
-
(102
)
Common Shares Purchased under Substantial Issuer Bid
(Note 18)
(257
)
-
-
(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)
-
-
-
Impact of Adoption of Topic 842, Leases
-
-
-
Balance, December 31, 2019
$
7,061
$
1,402
$
$
1,046
$
9,930
See accompanying Notes to Consolidated Financial Statements
Consolidated Statement of Cash Flows
For the years ended December 31 (US$ millions)
Operating Activities
Net earnings (loss)
$
1,416
$
(6,097
)
$
Depreciation, depletion and amortization
1,190
1,834
2,015
Impairments
(Note 10)
-
5,580
-
Accretion of asset retirement obligation
(Note 17)
Deferred income taxes
(Note 6)
(21
)
Unrealized (gain) loss on risk management
(Note 25)
Unrealized foreign exchange (gain) loss
(Note 5)
(23
)
Foreign exchange on settlements
(Note 5)
(11
)
(96
)
(Gain) loss on divestitures, net
-
-
(3
)
Other
(19
)
(57
)
Net change in other assets and liabilities
(39
)
(173
)
(97
)
Net change in non-cash working capital
(Note 26)
(41
)
Cash From (Used in) Operating Activities
3,129
1,895
2,921
Investing Activities
Capital expenditures
(Note 2)
(1,519
)
(1,736
)
(2,626
)
Acquisitions
(Note 9)
(11
)
(19
)
(65
)
Corporate acquisition, net of cash and restricted cash acquired
(Note 8)
-
-
Proceeds from divestitures
(Note 9)
1,025
Net change in investments and other
(20
)
(198
)
(156
)
Cash From (Used in) Investing Activities
(525
)
(1,864
)
(2,556
)
Financing Activities
Net issuance (repayment) of revolving long-term debt
(Note 15)
(950
)
Repayment of long-term debt
(Note 15)
(1,137
)
(272
)
(500
)
Purchase of shares of common stock
(Note 18)
(111
)
-
(1,250
)
Dividends on shares of common stock
(Note 18)
(122
)
(97
)
(102
)
Finance lease payments and other
(Note 14)
(99
)
(89
)
(84
)
Cash From (Used in) Financing Activities
(2,419
)
(206
)
(1,238
)
Foreign Exchange Gain (Loss) on Cash, Cash Equivalents
and Restricted Cash Held in Foreign Currency
-
(5
)
Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash
(180
)
(868
)
Cash, Cash Equivalents and Restricted Cash, Beginning of Year
1,058
Cash, Cash Equivalents and Restricted Cash, End of Year
$
$
$
Cash, End of Year
$
$
$
Cash Equivalents, End of Year
Restricted Cash, End of Year
-
-
-
Cash, Cash Equivalents and Restricted Cash, End of Year
$
$
$
Supplementary Cash Flow Information
(Note 26)
See accompanying Notes to Consolidated Financial Statements
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.
B)
BASIS OF PRESENTATION
The Consolidated Financial Statements include the accounts of Ovintiv 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. Following the U.S. Domestication on January 24, 2020, the functional currency of Ovintiv Inc. became U.S. dollars, and accordingly, the financial results herein are consolidated and reported in U.S. dollars. All references to US$ or to $ are to United States dollars and references to C$ are to Canadian dollars.
The Arrangement, as described above, was accounted for as a reorganization of entities under common control. Accordingly, the resulting transactions were recognized using historical carrying amounts. On January 24, 2020, Ovintiv became the reporting entity upon completion of the Reorganization.
In accordance with the Share Consolidation, all shares of common stock and per-share amounts disclosed herein reflect the post-Share Consolidation shares unless otherwise specified. References to shares of common stock refer to the shares of common stock of Ovintiv Inc. for any periods after the completion of the Arrangement, and to the common shares of Encana Corporation for any periods before January 24, 2020.
C)
PRINCIPLES OF CONSOLIDATION
The Consolidated Financial Statements include the accounts of Ovintiv 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 Ovintiv 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 Ovintiv’s accumulated translation gains and losses into net earnings occurs upon complete or substantially complete liquidation of the Company’s investment in the foreign operation.
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 Ovintiv’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 Ovintiv acts as agent are recorded on a net basis.
G)
PRODUCTION, MINERAL AND OTHER TAXES
Costs paid by Ovintiv for taxes based on production or revenues from oil, NGLs and natural gas are recognized when the product is produced. Costs paid by Ovintiv for taxes on the valuation of upstream assets and reserves are recognized when incurred.
H)
TRANSPORTATION AND PROCESSING
Costs paid by Ovintiv 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 Ovintiv, 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. Ovintiv 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
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. 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. 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. The assumptions used in determining expected future taxable earnings are consistent with those used in the goodwill impairment assessment.
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. Interest related to unrecognized tax benefits is recognized in interest expense.
L)
EARNINGS PER SHARE AMOUNTS
Basic net earnings per share of common stock is computed by dividing the net earnings by the weighted average number of shares of common stock outstanding during the period. Diluted net earnings per share of common stock is calculated giving effect to the potential dilution that would occur if stock options were exercised or other contracts to issue shares of common stock were exercised, fully vested, or converted to shares of common stock. 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 shares of common stock 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
Ovintiv 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 Ovintiv’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.
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 Ovintiv’s country cost centers. To assess impairment, the carrying amount of each reporting unit is determined and compared to the fair value of each respective reporting unit. Any excess of the carrying value of the reporting unit, including goodwill, over its fair value is recognized as an impairment and charged to net earnings. The impairment charge measured is limited to the total amount of goodwill allocated to that reporting unit. 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. Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cashflows that are largely independent of the cashflows of other groups of assets. 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, processing plants, and restoring land 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.
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. Ovintiv 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 Ovintiv’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 drilling 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.
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. The adoption of Topic 842 did not have a material impact on the Company’s Consolidated Statements of Earnings or Cash Flows. The effect of the January 1, 2019 adoption of Topic 842 on the Company’s Consolidated Balance Sheet can be found in Note 1 to the Company’s Consolidated Financial Statements included in Part II, Item 8 of Ovintiv’s 2019 Annual Report on Form 10-K.
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.
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 Ovintiv 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 presented in revenues as the contracts are settled. Realized gains or losses from foreign currency exchange swaps are presented in foreign exchange (gain) loss as the contracts are settled. Realized gains or losses recognized from other derivative contracts are presented in revenues as the obligations are settled.
Unrealized gains and losses are recognized based on the changes in fair value of the contracts and are presented in revenues and foreign exchange (gain) loss.
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.
2.
Segmented Information
Ovintiv’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 production of oil and other related activities within the China cost center. Effective July 31, 2019, the production sharing contract with China National Offshore Oil Corporation (“CNOOC”) was terminated and the Company exited its China Operations.
•
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.
Results of Operations
Segment Information
USA Operations
Canadian Operations
China Operations (1)
For the years ended December 31
Revenues
Product and service revenues
$
4,883
$
2,701
$
4,163
$
2,542
$
1,349
$
1,654
$
-
$
-
$
Gains (losses) on risk management, net
(982
)
(413
)
-
-
-
Sublease revenues
-
-
-
-
-
-
-
-
-
Total Revenues
3,901
3,198
4,321
2,129
1,556
1,865
-
-
Operating Expenses
Production, mineral and other taxes
-
-
-
Transportation and processing
-
-
-
Operating
-
-
Depreciation, depletion and amortization
1,378
1,593
-
-
-
Impairments
-
5,580
-
-
-
-
-
-
-
Total Operating Expenses
2,112
8,054
2,863
1,395
1,371
1,383
-
-
Operating Income (Loss)
$
1,789
$
(4,856
)
$
1,458
$
$
$
$
-
$
-
$
Market Optimization
Corporate & Other
Consolidated
Revenues
Product and service revenues
$
3,043
$
1,459
$
1,159
$
-
$
-
$
-
$
10,468
$
5,509
$
7,013
Gains (losses) on risk management, net
-
-
(488
)
(204
)
(730
)
(1,883
)
(361
)
Sublease revenues
-
-
-
Total Revenues
3,043
1,466
1,159
(415
)
(133
)
(656
)
8,658
6,087
6,726
Operating Expenses
Production, mineral and other taxes
-
-
-
-
-
-
Transportation and processing
-
-
-
1,616
1,502
1,558
Operating
(1
)
(2
)
(3
)
Purchased product
2,951
1,366
1,043
-
-
-
2,951
1,366
1,043
Depreciation, depletion and amortization
-
-
-
1,190
1,834
2,015
Impairments
-
-
-
-
-
-
-
5,580
-
Accretion of asset retirement obligation
-
-
-
Administrative
-
-
-
Total Operating Expenses
3,148
1,608
1,304
7,139
11,484
6,128
Operating Income (Loss)
$
(105
)
$
(142
)
$
(145
)
$
(899
)
$
(584
)
$
(1,218
)
1,519
(5,397
)
Other (Income) Expenses
Interest
Foreign exchange (gain) loss, net
(23
)
(119
)
(Gain) loss on divestitures, net
-
-
(3
)
Other (gains) losses, net
(37
)
(55
)
Total Other (Income) Expenses
Net Earnings (Loss) Before Income Tax
1,239
(5,730
)
Income tax expense (recovery)
(177
)
Net Earnings (Loss)
$
1,416
$
(6,097
)
$
(1)
Effective July 31, 2019, the production sharing contract with CNOOC was terminated and the Company exited its China Operations.
Intersegment Information
Market Optimization
Marketing Sales
Upstream Eliminations
Total
For the years ended December 31
Revenues
$
10,630
$
6,108
$
7,489
$
(7,587
)
$
(4,642
)
$
(6,330
)
$
3,043
$
1,466
$
1,159
Operating Expenses
Transportation and processing
(399
)
(396
)
(402
)
Operating
-
-
-
Purchased product
10,140
5,612
6,973
(7,189
)
(4,246
)
(5,930
)
2,951
1,366
1,043
Operating Income (Loss)
$
(106
)
$
(142
)
$
(147
)
$
$
-
$
$
(105
)
$
(142
)
$
(145
)
Revenues by Geographic Region
United States
Canada
For the years ended December 31
Revenues
Product revenues (1)
Oil
$
3,357
$
2,035
$
3,329
$
$
$
NGLs
1,158
Natural gas
1,368
Other revenues (2)
2,771
1,296
Gains (losses) on risk management, net
(1,160
)
(142
)
(723
)
(219
)
Total Revenues
$
6,494
$
4,400
$
4,985
$
2,164
$
1,687
$
1,704
China (3)
Total
Revenues
Product revenues (1)
Oil
$
-
$
-
$
$
3,364
$
2,042
$
3,376
NGLs
-
-
-
2,020
1,322
Natural gas
-
-
-
2,032
1,047
1,136
Other revenues (2)
-
-
-
3,125
1,536
1,253
Gains (losses) on risk management, net
-
-
-
(1,883
)
(361
)
Total Revenues
$
-
$
-
$
$
8,658
$
6,087
$
6,726
(1)
Includes intercompany marketing fees transacted between the Company’s operating segments.
(2)
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.
(3)
Effective July 31, 2019, the production sharing contract with CNOOC was terminated and the Company exited its China Operations.
Major Customers
In connection with the marketing and sale of Ovintiv’s own and purchased oil, NGLs and natural gas for the year ended December 31, 2021, the Company had one customer which individually accounted for more than 10 percent of Ovintiv’s product revenues. Sales to this customer, secured by a financial institution with an investment grade credit rating, totaled approximately $1,573 million which comprised $1,565 million in the United States and $8 million in Canada (2020 - one customer with sales of approximately $834 million; 2019 - one customer with sales of approximately $866 million).
Capital Expenditures by Segment
For the years ended December 31
USA Operations
$
1,125
$
1,353
$
2,134
Canadian Operations
Market Optimization
-
-
Corporate & Other
$
1,519
$
1,736
$
2,626
Goodwill, Property, Plant and Equipment and Total Assets by Segment
Goodwill
Property, Plant and Equipment
Total Assets
As at December 31
USA Operations
$
1,938
$
1,938
$
7,623
$
8,103
$
10,345
$
10,646
Canadian Operations
1,142
1,932
2,031
Market Optimization
-
-
-
Corporate & Other
-
-
1,478
1,559
$
2,628
$
2,625
$
8,761
$
9,450
$
14,055
$
14,469
Goodwill, Property, Plant and Equipment and Total Assets by Geographic Region
Goodwill
Property, Plant and Equipment
Total Assets
As at December 31
United States
$
1,938
$
1,938
$
7,673
$
8,159
$
10,715
$
10,925
Canada
1,088
1,291
3,337
3,540
Other Countries
-
-
-
-
$
2,628
$
2,625
$
8,761
$
9,450
$
14,055
$
14,469
3.
Revenues from Contracts with Customers
The following table summarizes Ovintiv’s revenues from contracts with customers.
Revenues
USA Operations
Canadian Operations
China Operations (1)
For the years ended December 31
Revenues from Customers
Product revenues (2)
Oil
$
3,369
$
2,045
$
3,341
$
$
$
$
-
$
-
$
NGLs
1,163
-
-
-
Natural gas
1,377
-
-
-
Service revenues
Gathering and processing
-
-
-
-
Product and Service Revenues
$
4,897
$
2,711
$
4,176
$
2,552
$
1,359
$
1,667
$
-
$
-
$
Market Optimization
Corporate & Other
Consolidated
Revenues from Customers
Product revenues (2)
Oil
$
2,268
$
$
$
-
$
-
$
-
$
5,644
$
2,668
$
3,637
NGLs
-
-
-
2,069
1,339
Natural gas
-
-
-
2,745
1,865
2,030
Service revenues
Gathering and processing
-
-
-
-
-
Product and Service Revenues
$
3,019
$
1,439
$
1,133
$
-
$
-
$
-
$
10,468
$
5,509
$
7,013
(1)
Effective July 31, 2019, the production sharing contract with CNOOC was terminated and the Company exited its China Operations.
(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. Ovintiv had no contract asset or liability balances during the periods presented. As at December 31, 2021, receivables and accrued revenues from contracts with customers were $1,070 million (2020 - $724 million).
Ovintiv’s 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, 2021.
As at December 31, 2021, 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 Ovintiv receives payments is generally 30 to 60 days, there is no financing element associated with customer contracts. In addition, Ovintiv does not disclose unsatisfied performance obligations for customer contracts with terms less than 12 months or for variable consideration related to unsatisfied performance obligations.
4.
Interest
For the years ended December 31
Interest Expense on:
Debt
$
$
$
Finance leases (See Note 14)
Other
$
$
$
Interest expense on debt for the year ended December 31, 2021 includes a one-time make-whole interest payment of $19 million resulting from the June 2021 early redemption of the Company’s $600 million, 5.75 percent senior notes due January 30, 2022 as discussed in Note 15.
5.
Foreign Exchange (Gain) Loss, Net
For the years ended December 31
Unrealized Foreign Exchange (Gain) Loss on:
Translation of U.S. dollar financing debt issued from Canada
$
$
$
(207
)
Translation of U.S. dollar risk management contracts issued from Canada
(13
)
(12
)
Translation of intercompany notes
-
(27
)
(23
)
Foreign Exchange (Gain) Loss on Settlements of:
U.S. dollar financing debt issued from Canada
(8
)
(25
)
U.S. dollar risk management contracts issued from Canada
(33
)
(3
)
Intercompany notes
(3
)
(71
)
Other Monetary Revaluations
-
(1
)
$
(23
)
$
$
(119
)
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, no longer attract foreign exchange translation gains or losses.
6.
Income Taxes
The provision for income taxes is as follows:
For the years ended December 31
Current Tax
United States
$
-
$
(12
)
$
Canada
(156
)
(2
)
(16
)
Total Current Tax Expense (Recovery)
(156
)
(14
)
(13
)
Deferred Tax
United States
(187
)
Canada
(22
)
(53
)
Total Deferred Tax Expense (Recovery)
(21
)
Income Tax Expense (Recovery)
$
(177
)
$
$
During the year ended December 31, 2021, the current income tax recovery was primarily due to the resolution of prior years’ tax items. The resolution, along with other items, resulted in a $222 million reduction of unrecognized tax benefits, offset by a $66 million reduction in valuation allowance. The Company also recognized related interest income of $12 million in other (gains) losses, net. During the year ended December 31, 2020, the current income tax recovery was primarily due to certain current year losses being carried back to prior years. During the year ended December 31, 2019, the current income tax recovery was primarily due to the resolution of prior year tax items.
Deferred income tax assets are routinely assessed for realizability. During the year ended December 31, 2020, the Company determined, after weighing both positive and negative evidence, that a valuation allowance should be recorded to reduce the associated deferred tax assets in the U.S. and in Canada. Accordingly, a valuation allowance of $568 million was recognized in Canada related to prior years’ deferred tax assets during the year ended December 31, 2020. As at December 31, 2021, the Company continues to be in a cumulative three-year loss position in both the U.S. and Canada and as such, continues to recognize the valuation allowance against net deferred tax assets. The cumulative three-year losses and uncertainty in the timing as to when the realization of deferred tax assets will occur, is significant negative evidence to overcome, and consequently, it is more likely than not that the deferred tax assets will not be realizable.
On June 28, 2019, Alberta Bill 3, the Job Creation Tax Cut (Alberta Corporate Tax Amendment) Act, was signed into law resulting in a phased in reduction of the Alberta corporate tax rate from 12 percent to eight percent over a period of four years. During the year ended December 31, 2019, the deferred tax expense of $94 million included 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.
The following table reconciles income taxes calculated at the applicable statutory rate with the actual income taxes:
For the years ended December 31
Net Earnings (Loss) Before Income Tax
$
1,239
$
(5,730
)
$
United States Federal Statutory Rate
21.0
%
21.0
%
21.0
%
Expected Income Tax Expense (Recovery)
(1,203
)
Effect on Taxes Resulting From:
State tax difference
(147
)
Income tax related to foreign operations
(2
)
(7
)
Effect of legislative changes
-
Non-taxable capital (gains) losses
-
(11
)
Realized capital loss resulting from U.S. Domestication
-
(1,238
)
-
Partnership tax allocations in excess of funding
-
-
(20
)
Amounts in respect of prior periods
(23
)
Change in valuation allowance
(558
)
2,900
(7
)
Other
$
(177
)
$
$
Effective Tax Rate
(14.3
%)
(6.4
%)
25.7
%
As part of the U.S. Domestication, in the first quarter of 2020 Ovintiv recognized a capital loss and recorded a deferred income tax benefit in the amount of $1.2 billion for Canadian income tax purposes. Ovintiv assessed the realizability of these capital losses against capital gains and concluded that it is more likely than not that the deferred tax asset will not be realizable. Therefore, Ovintiv recorded a corresponding valuation allowance against the deferred tax asset. If it is determined the capital loss can be utilized at a future date, a reduction in the valuation allowance will be recorded.
The effective tax rate of (14.3) percent for the year ended December 31, 2021 is lower than the U.S. federal statutory tax rate of 21 percent primarily due to the resolution of prior years’ tax items and the change in valuation allowances.
For the year ended December 31, 2020, the effective tax rate of (6.4) percent was lower than the U.S. federal statutory tax rate of 21 percent primarily due to valuation allowances recorded due to net losses arising from ceiling test impairments and an increase in the valuation allowance of $568 million in Canada related to prior years’ deferred tax assets. See Note 10 for further discussion related to the ceiling test impairments. For the year ended December 31, 2019, the effective tax rate of 25.7 percent was higher than the U.S. federal statutory tax rate of 21 percent primarily due to state taxes and the re-measurement of the Company’s deferred tax position resulting from the Alberta corporate tax rate reduction discussed above, partially offset by partnership tax allocations in excess of funding in Canada as well as the resolution of prior year tax items.
The net deferred income tax asset (liability) consists of:
As at December 31
Deferred Income Tax Assets
Property, plant and equipment
$
$
Risk management
Compensation plans
Interest and other deferred deductions
Net operating and net capital losses carried forward
2,727
2,917
Foreign tax credits
Other
Less: valuation allowance
(2,733
)
(3,273
)
Deferred Income Tax Liabilities
Property, plant and equipment
(381
)
(24
)
Unrealized foreign exchange gains
-
(21
)
Other
(36
)
(23
)
Net Deferred Income Tax Asset (Liability)
$
(4
)
$
(20
)
As at December 31, 2021, Ovintiv has recorded a valuation allowance against U.S. federal and state losses, U.S. foreign tax credits and U.S. charitable donations in the amount of $1,044 million (2020 - $1,310 million) and Canadian net operating losses, net capital losses and other tax basis in the amount of $1,689 million (2020 - $1,963 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 net deferred income tax asset (liability) for the following jurisdictions is reflected in the Consolidated Balance Sheet as follows:
As at December 31
Deferred Income Tax Assets
United States
$
-
$
-
Canada
-
-
-
-
Deferred Income Tax Liabilities
United States
(4
)
-
Canada
-
(20
)
(4
)
(20
)
Net Deferred Income Tax Asset (Liability)
$
(4
)
$
(20
)
Tax basis, loss carryforwards, charitable donations and tax credits available are as follows:
As at December 31
Expiration Date
United States
Tax basis
$
5,676
Indefinite
Net operating losses (Federal)
5,340
2022 - 2038 (1)
Foreign tax credits
2022 - 2024
Charitable donations
2022 - 2024
Canada
Tax basis
$
1,035
Indefinite
Net capital losses
5,716
Indefinite
Net operating losses
2027 - 2041
Charitable donations
(1)
Includes net operating losses of $1,339 million which have an indefinite expiration date.
As at December 31, 2021, approximately $468 million (2020 - nil) of Ovintiv’s unremitted earnings from its foreign subsidiaries were considered to be permanently reinvested and, accordingly, Ovintiv has not recognized a deferred income tax liability in respect of such earnings. If such earnings were to be remitted, Ovintiv 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.
The following table presents changes in the balance of Ovintiv’s unrecognized tax benefits excluding interest:
For the years ended December 31
Balance, Beginning of Year
$
(232
)
$
(222
)
Additions for tax positions taken in the current year
(2
)
(4
)
Additions for tax positions of prior years
(29
)
(1
)
Settlements
-
Foreign currency translation
(4
)
(5
)
Balance, End of Year
$
(10
)
$
(232
)
The unrecognized tax benefit is reflected in the Consolidated Balance Sheet as follows:
As at December 31
Income Tax Receivable
$
(1
)
$
-
Other Liabilities and Provisions (See Note 16)
-
(158
)
Deferred Income Tax Asset (1)
(9
)
(74
)
Balance, End of Year
$
(10
)
$
(232
)
(1)
As at December 31, 2021 and 2020, the unrealized tax benefit was offset against the valuation allowance recognized in Canada.
If recognized, all of Ovintiv’s unrecognized tax benefits as at December 31, 2021 would affect Ovintiv’s effective income tax rate. The nature of the unrecognized tax benefits is highly uncertain. As at December 31, 2021, Ovintiv does not anticipate that the amount of unrecognized tax benefits will significantly change during the next 12 months.
Ovintiv may recognize interest accrued in respect of unrecognized tax benefits in interest expense. During 2021, Ovintiv recognized an expense of nil (2020 - nil; 2019 - nil) in interest expense. As at December 31, 2021, Ovintiv had a liability of nil (2020 - $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
2018 - 2021
United States - State
2017 - 2021
Canada - Federal
2015 - 2021
Canada - Provincial
2015 - 2021
Other
Ovintiv 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.
7.
Accounts Receivable and Accrued Revenues
As at December 31
Trade Receivables and Accrued Revenues
Production accruals
$
$
Market optimization
Joint interest and trade receivables
Derivative financial instruments
Corporate and other
Total Trade Receivables and Accrued Revenues
1,204
Prepaids
Deposits and Other
1,299
Expected Credit Loss Allowance
(5
)
(4
)
$
1,294
$
Ovintiv’s trade receivables and accrued revenues primarily consist of production sales of oil, NGLs and natural gas, product optimization from marketing and recoveries from joint working interest partners. The Company’s receivables are short dated with payments generally due within 30 to 60 days, with no financing element.
Trade receivables and accrued revenues are subject to credit risk which is the risk of loss from the potential of a counterparty failing to meet its obligation in accordance with agreed terms. Ovintiv’s credit exposure related to product sales and derivative financial instruments are mitigated through the use of credit policies approved by the Board of Directors which govern credit practices that limit transactions according to counterparties’ credit quality, and regular monitoring and review of counterparties’ credit worthiness. The Company may also request collateral support, including standby letters of credit, from customers that purchase production. Receivables due from joint
working interest partners include numerous counterparties ranging from large public companies to small private companies within the oil and gas industry. In the event of non-payment, Ovintiv may be able to mitigate losses through requiring prepayment of future costs and netting outstanding receivables against associated revenue payables to the interest owner. The Company monitors ongoing credit exposure through active review of counterparty balances against contract terms and due dates, timely dispute resolution, payment confirmation, consideration of the customers’ financial condition and general industry market conditions.
Ovintiv’s estimated credit loss allowance is estimated using historical loss information, current industry conditions and payment practices, as well as reasonable and supportable forecasts of future economic conditions. Credit risk is assessed based on days outstanding and utilizes both internal credit assessments and publicly available credit information. As at December 31, 2021, the current period expected credit loss allowance was $5 million (2020 - $4 million). See Note 25 for more information on credit risk exposures.
8.
Business Combination
Newfield Exploration Company Acquisition
On February 13, 2019, the business combination with Newfield Exploration Company, a Delaware corporation (“Newfield”) was completed pursuant to an Agreement and Plan of Merger with Newfield (the “Merger”). As a result of the Merger, Newfield shareholders 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 were outstanding. For the year ended December 31, 2019, 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 results of Newfield’s operations have been included in the Company’s Consolidated Financial Statements as of February 14, 2019.
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)
Total Consideration
$
3,483
Assets Acquired:
Cash and cash equivalents
$
Accounts receivable and accrued revenues
Other current assets
Proved properties
5,903
Unproved properties
Other property, plant and equipment
Restricted cash
Other assets
Goodwill
Liabilities Assumed:
Accounts payable and accrued liabilities (3)
(795
)
Long-term debt
(2,603
)
Operating lease liabilities
(76
)
Other long-term liabilities
(65
)
Asset retirement obligation
(184
)
Deferred income taxes
(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)
In conjunction with the acquisition, various legal claims and actions arising in the normal course of Newfield’s operations were assumed by Ovintiv. 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”), and agreed to settle arbitration claims in the amount of $22.5 million arising from Sapura’s purchase of Newfield’s Malaysian business in February 2014. The settlement amount including legal fees was included in the purchase price allocation as part of the current liabilities assumed at the acquisition date. Although the outcome of any remaining legal claims and actions assumed following the acquisition of Newfield 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.
The income approach valuation technique was used 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.
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, 2019. 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 transaction-related costs incurred of approximately $71 million and severance payments made to employees which totaled $138 million for the year ended December 31, 2019. The pro forma financial information does not include any cost savings or other synergies from the Merger or any estimated costs that have been incurred to integrate the assets. Ovintiv’s consolidated results for the years ended December 31, 2021 and 2020 include the results from Newfield.
For the year ended December 31 (US$ millions, except per share amounts)
Revenues
$
7,005
Net Earnings (Loss)
$
Net Earnings (Loss) per Share
Basic & Diluted
$
1.44
9.
Acquisitions and Divestitures
For the years ended December 31
Acquisitions
USA Operations
$
$
$
Total Acquisitions
Divestitures
USA Operations
(772
)
(78
)
(196
)
Canadian Operations
(253
)
(11
)
(1
)
Total Divestitures
(1,025
)
(89
)
(197
)
Net Acquisitions & (Divestitures)
$
(1,014
)
$
(70
)
$
(132
)
ACQUISITIONS
Acquisitions in the USA Operations in 2021 and 2020 primarily included property purchases with oil and liquids rich potential. Acquisitions in 2019 in the USA Operations primarily included seismic purchases, water rights and property purchases with oil and liquids rich potential
DIVESTITURES
In 2021, amounts received from the sale of assets were $1,025 million (2020 - $89 million; 2019 - $197 million).
Amounts received from the Company’s divestiture transactions have been deducted from the respective U.S. and Canadian full cost pools.
USA Operations
In 2021, divestitures in the USA Operations primarily included the sale of the Eagle Ford assets located in south Texas for proceeds of approximately $764 million, after closing and other adjustments.
In 2020, divestitures in the USA Operations primarily included the sale of certain properties that did not complement Ovintiv’s existing portfolio of assets.
In 2019, divestitures in the USA Operations primarily included the sale of the Arkoma natural gas assets located in Oklahoma.
Canadian Operations
In 2021, divestitures in the Canadian Operations primarily included the sale of the Duvernay assets located in west central Alberta for proceeds of approximately $238 million, after closing and other adjustments.
As part of the Duvernay asset divestiture, the Company agreed to a contingent consideration arrangement, which is payable to Ovintiv in the amount of C$5 million at the end of 2021 and an additional C$10 million at the end of 2022, if the annual average of the WTI reference price for each calendar year is greater than $56 per barrel and $62 per barrel, respectively. The contingent consideration was determined to be an embedded derivative and accordingly, the Company recorded the contingent consideration at its fair value of $6 million on the closing date. Subsequent changes in the fair value of the contingent consideration are recognized as a gain or loss and presented in gains (losses) on risk management, net in the Consolidated Statement of Earnings. The fair value is presented in accounts receivable and accrued revenues in the Consolidated Balance Sheet. See Notes 24 and 25 for further information on the contingent consideration.
In 2020, divestitures in the Canadian Operations primarily included the sale of certain properties that did not complement Ovintiv’s existing portfolio of assets.
10.
Property, Plant and Equipment, Net
As at December 31
Cost
Accumulated
DD&A
Net
Cost
Accumulated
DD&A
Net
USA Operations
Proved properties
$
39,145
$
(33,418
)
$
5,727
$
37,875
$
(32,581
)
$
5,294
Unproved properties
1,884
-
1,884
2,785
-
2,785
Other
-
-
41,041
(33,418
)
7,623
40,684
(32,581
)
8,103
Canadian Operations
Proved properties
16,330
(15,450
)
16,008
(15,056
)
Unproved properties
-
-
Other
-
-
16,401
(15,450
)
16,198
(15,056
)
1,142
Market Optimization
(7
)
-
(7
)
Corporate & Other
(686
)
(662
)
$
58,322
$
(49,561
)
$
8,761
$
57,756
$
(48,306
)
$
9,450
USA and Canadian Operations’ property, plant and equipment include internal costs directly related to exploration, development and construction activities of $172 million, which have been capitalized during the year ended December 31, 2021 (2020 - $180 million).
For the year ended December 31, 2021, Ovintiv did not recognize ceiling test impairments in the USA Operations (2020 - $5,580 million; 2019 - nil) or in the Canadian Operations (2020 - nil; 2019 - nil). The non-cash ceiling test impairments recognized in the USA Operations in 2020 are included with accumulated DD&A in the table above and primarily resulted from the decline in the 12-month average trailing prices, which reduced proved reserves.
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 28.
11.
Other Assets
As at December 31
Operating Lease ROU Assets (See Note 14)
$
$
Long-Term Investments
Long-Term Receivables
Deferred Charges
Other
$
1,079
$
1,143
12.
Goodwill
As at December 31
United States
Balance, beginning and end of year
$
1,938
$
1,938
Canada
Balance, beginning of year
Foreign currency translation adjustment
Balance, end of year
Total Goodwill
$
2,628
$
2,625
The Company had no additions or dispositions relating to goodwill during 2021 or 2020. The change in the Canada goodwill balance reflects movement due to foreign currency translation.
Goodwill was assessed for impairment as at December 31, 2021 and December 31, 2020. 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.
13.
Accounts Payable and Accrued Liabilities
As at December 31
Trade Payables
$
$
Capital Accruals
Royalty and Production Accruals
Market Optimization Accruals
Outstanding Disbursements
Payroll & Other Accruals
Interest Payable
Current Portion of Long-Term Incentive Costs (See Note 22)
Current Portion of Finance Lease Obligations (See Note 14)
Current Portion of Asset Retirement Obligation (See Note 17)
$
1,979
$
1,704
Payables and accruals are non-interest bearing. Interest payable represents amounts accrued related to Ovintiv’s unsecured notes as disclosed in Note 15.
14.
Leases
Operating leases include drilling rigs, compressors, office and buildings, certain land easements and various equipment utilized in the development and production of oil, NGLs and natural gas. The Company has an office building that is accounted for as a finance lease. Subleases relate to office and building leases.
The tables below summarize Ovintiv’s operating and finance lease costs and include ROU assets and lease liabilities, amounts recognized in net earnings (loss) during the year and other lease information.
As at December 31 (US$ millions, unless otherwise specified)
Consolidated Balance Sheet (1):
Operating Lease ROU Assets, in Other Assets
$
$
Finance Lease ROU Assets, in Other Property Plant and Equipment
Operating Lease Liabilities:
Current
Long-term
Finance Lease Liabilities:
Current, in accounts payable and accrued liabilities
Long-term, in other liabilities and provisions
Weighted Average Discount Rate
Operating leases
5.44%
5.44%
Finance leases
6.11%
6.00%
Weighted Average Remaining Lease Term
Operating leases
15.3 years
15.9 years
Finance leases
5.5 years
3.0 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.
For the years ended December 31
Lease Costs (1):
Operating Lease Costs, Excluding Short-Term Leases
$
$
Finance Lease Costs:
Amortization of ROU assets
Interest on lease liabilities
Total Finance Lease Costs
Short-Term Lease Costs
Variable Lease Costs
Sublease Income:
Operating lease income
Variable lease income
Other Information (2):
Cash Paid for Amounts Included in the Measurement of Lease Liabilities:
Operating cash outflows from operating leases
Investing cash outflows from operating leases
Operating cash outflows from finance leases
Financing cash outflows from finance leases
Supplemental Non-Cash Information:
New ROU operating lease assets and liabilities
(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 years ended December 31
Operating Lease Expense
Transportation and processing
$
$
Operating
Administrative
Total Operating Lease Expense
$
$
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, 2021:
Thereafter
Total
Operating Leases (1)
Expected Future Lease Payments
$
$
$
$
$
$
$
1,426
Less: Discounting
Present Value of Future Operating
Lease Payments
$
Sublease Income (undiscounted)
$
(40
)
$
(39
)
$
(39
)
$
(39
)
$
(39
)
$
(474
)
$
(670
)
Finance Leases
Expected Future Lease Payments
$
$
$
$
$
$
$
Less: Discounting
Present Value of Future Finance
Lease Payments
$
Sublease Income (undiscounted) (2)
$
(8
)
$
(8
)
$
(7
)
$
(7
)
$
(7
)
$
(3
)
$
(40
)
(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 material commitments for leases with terms greater than one year that have not yet commenced at December 31, 2021.
15.
Long-Term Debt
As at December 31
Note
U.S. Dollar Denominated Debt
Revolving credit and term loan borrowings
A
$
-
$
U.S. Unsecured Notes:
B
3.90% due November 15, 2021
-
5.75% due January 30, 2022
-
5.625% due July 1, 2024
1,000
1,000
5.375% due January 1, 2026
8.125% due September 15, 2030
7.20% due November 1, 2031
7.375% due November 1, 2031
6.50% due August 15, 2034
6.625% due August 15, 2037
6.50% due February 1, 2038
5.15% due November 15, 2041
Total Principal
F
4,741
6,809
Increase in Value of Debt Acquired
C
Unamortized Debt Discounts and Issuance Costs
D
(32
)
(35
)
Total Long-Term Debt
$
4,786
$
6,885
Current Portion
E
$
-
$
Long-Term Portion
4,786
6,367
$
4,786
$
6,885
A)
REVOLVING CREDIT AND TERM LOAN BORROWINGS
At December 31, 2021, Ovintiv 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 Ovintiv Inc. and $1.5 billion on a revolving bank credit facility for a Canadian 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 Ovintiv. The facilities mature in July 2024, and are fully revolving up to maturity.
The Ovintiv Inc. facility, which remained unused as at December 31, 2021, is unsecured and bears interest at either the lenders’ U.S. base rate or LIBOR, plus applicable margins. The Canadian subsidiary facility, which remained unused as at December 31, 2021, bears interest at the lenders’ rates for Canadian prime, U.S. base rate, Bankers’ Acceptances or LIBOR, plus applicable margins.
Ovintiv 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, 2021, the Company is in compliance with all financial covenants.
Standby fees paid in 2021 relating to revolving credit and term loan agreements were approximately $10 million (2020 - $8 million; 2019 - $11 million) and were included in interest expense in the Consolidated Statement of Earnings.
B)
UNSECURED NOTES
Shelf Prospectuses
In the first quarter of 2020, Ovintiv filed a U.S. shelf registration statement and a Canadian shelf prospectus, under which the Company may issue from time to time, debt securities, common stock, preferred stock, warrants, units, share purchase contracts and share purchase units in the U.S. and/or Canada. At December 31, 2021, $6.0 billion was accessible under the Canadian shelf prospectus. The ability to issue securities under the U.S. shelf registration statement or Canadian shelf prospectus is dependent upon market conditions and security law requirements.
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.
On June 18, 2021, the Company completed the redemption of its $600 million, 5.75 percent senior notes due January 30, 2022. Ovintiv paid approximately $632 million in cash including accrued and unpaid interest of $13 million and a one-time make-whole payment of $19 million, which is included in interest expense as discussed in Note 4.
On August 16, 2021, the Company completed the redemption of its $518 million, 3.90 percent senior notes due November 15, 2021. The Company redeemed the notes at par and paid approximately $523 million in cash including accrued and unpaid interest of $5 million.
The Company used the net proceeds from its Eagle Ford and Duvernay asset sales, as discussed in Note 9, and cash on hand to complete the senior note redemptions.
During the year ended December 31, 2020, Ovintiv repurchased approximately $302 million in principal amount of its senior notes in the open market. The aggregate cash payments related to the note repurchases were $272 million, plus accrued interest, and a net gain of approximately $30 million was recognized in other (gains) losses, net in the Consolidated Statement of Earnings.
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 five 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 2021, no debt premiums or discounts were capitalized. During 2020, $4 million in issuance costs were capitalized related to the renewal of the Company’s credit facilities. Issuance costs are amortized over the term of the related debt.
E)
CURRENT PORTION OF LONG-TERM DEBT
As at December 31, 2021, the current portion of long-term debt was nil (2020 - $518 million).
F)
MANDATORY DEBT PAYMENTS
Principal
Interest
As at December 31
Amount
Amount
$
-
$
-
1,000
-
Thereafter
3,053
1,657
Total
$
4,741
$
3,032
As at December 31, 2021, total long-term debt had a carrying value of $4,786 million and a fair value of $5,804 million (2020 - carrying value of $6,885 million and a fair value of $7,379 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
Finance Lease Obligations (See Note 14)
$
$
Unrecognized Tax Benefits (See Note 6)
-
Pensions and Other Post-Employment Benefits (See Note 23)
Long-Term Incentive Costs (See Note 22)
Other Derivative Contracts (See Notes 24, 25)
Other
$
$
17.
Asset Retirement Obligation
As at December 31
Asset Retirement Obligation, Beginning of Year
$
$
Liabilities Incurred and Acquired
Liabilities Settled and Divested
(91
)
(160
)
Change in Estimated Future Cash Outflows
(49
)
Accretion Expense
Foreign Currency Translation
(1
)
Asset Retirement Obligation, End of Year
$
$
Current Portion (See Note 13)
$
$
Long-Term Portion
$
$
18.
Share Capital
AUTHORIZED
Subsequent to the Reorganization as described in Note 1 and as at December 31, 2021, Ovintiv is authorized to issue 750 million shares of common stock, par value $0.01 per share, and 25 million shares of preferred stock, par value $0.01 per share. No shares of preferred stock are outstanding.
ISSUED AND OUTSTANDING
As at December 31
Number
(millions)
Amount
Number
(millions)
Amount
Number
(millions)
Amount
Shares of Common Stock Outstanding, Beginning of Year
259.8
$
259.8
$
7,061
190.5
$
4,656
Shares of Common Stock Purchased
(3.1
)
-
-
-
(39.4
)
(1,073
)
Shares of Common Stock Issued
1.3
-
-
-
108.7
3,478
Reclassification of Share Capital due to the
Reorganization (See Note 1)
-
-
-
(7,058
)
-
-
Shares of Common Stock Outstanding, End of Year
258.0
$
259.8
$
259.8
$
7,061
In conjunction with the Reorganization, the amount recognized in share capital in excess of Ovintiv’s established par value of $0.01 per share was reclassified to paid in surplus. Accordingly, approximately $7,058 million was reclassified.
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.
NORMAL COURSE ISSUER BID
On September 28, 2021, Ovintiv announced it received regulatory approval to commence a NCIB that enables the Company to purchase, for cancellation, up to approximately 26 million shares of common stock over a 12-month period from October 1, 2021 to September 30, 2022.
During the year ended December 31, 2021, the Company purchased approximately 3.1 million shares under the current NCIB for total consideration of approximately $111 million. Of the amount paid, $28 thousand was charged to share capital and $111 million was charged to paid in surplus.
All purchases were made in accordance with the 2021 NCIB at prevailing market prices plus brokerage fees, with consideration allocated to share capital up to the par value of the shares, with any excess allocated to paid in surplus.
For the year ended December 31, 2019, the Company purchased the equivalent of approximately 29.9 million post-Share Consolidation shares under the previous NCIB which was in place from March 4, 2019 to March 3, 2020 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 2019 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.
SUBSTANTIAL ISSUER BID
On June 10, 2019, the Company announced its intention to purchase, for cancellation, up to $213 million of its common shares through a substantial issuer bid (“SIB”) which commenced on July 8, 2019. On August 29, 2019, the Company purchased the equivalent of approximately 9.5 million post-Share Consolidation shares at a converted price of $22.50 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.
DIVIDENDS
During the year ended December 31, 2021, the Company declared and paid dividends of $0.4675 per share of common stock, totaling $122 million (2020 - $0.375 per share of common stock, totaling $97 million; 2019 - $0.375 per common share on a post-Share Consolidation basis, totaling $102 million).
Ovintiv’s quarterly dividend payment in 2021 was $0.09375 per share of common stock for each of the first two quarters and $0.14 per share of common stock for the third and fourth quarters. The quarterly dividend payment in 2020 was $0.09375 per share of common stock. On a post-Share Consolidation basis, the Company’s quarterly dividend payment was $0.09375 per common share in 2019.
On February 24, 2022, the Board of Directors declared a dividend of $0.20 per share of common stock payable on March 31, 2022 to common shareholders of record as of March 15, 2022.
EARNINGS PER SHARE OF COMMON STOCK
The following table presents the computation of net earnings (loss) per share of common stock:
For the years ended December 31 (US$ millions, except per share amounts)
Net Earnings (Loss)
$
1,416
$
(6,097
)
$
Number of Shares of Common Stock:
Weighted average shares of common stock outstanding - Basic
260.4
259.8
261.2
Effect of dilutive securities (1) (2)
6.0
-
-
Weighted Average Shares of Common Stock Outstanding - Diluted
266.4
259.8
261.2
Net Earnings (Loss) per Share of Common Stock
Basic
$
5.44
$
(23.47
)
$
0.90
Diluted (1) (2)
5.32
(23.47
)
0.90
(1)
During the fourth quarter of 2020, Ovintiv’s Board of Directors resolved to settle certain Performance Share Units (“PSUs”) and Restricted Share Units (“RSUs”) with the issuance of the Company’s common stock. As a result, the stock-based compensation awards were modified and reclassified as equity-settled awards. See Note 22 for further information.
(2)
As at December 31, 2020, all of Ovintiv’s equity-settled awards were determined to be antidilutive and therefore are excluded from the calculation of fully diluted net earnings (loss) per share of common stock. See Note 22 for further information.
STOCK-BASED COMPENSATION PLANS
Ovintiv’s PSU and RSU stock-based compensation plans allow the Company to settle the awards either in cash or in the Company’s common stock. The PSUs and RSUs are classified as equity-settled if the Company has sufficient common stock held in reserve for issuance. These awards are included in the computation of diluted net earnings (loss) per share of common stock if dilutive.
Ovintiv’s stock options with associated Tandem Stock Appreciation Rights (“TSARs”) give the employee the right to purchase shares of common stock of the Company or receive cash. Historically, most holders of options have elected to exercise their TSARs in exchange for a cash payment. As a result, outstanding options are not considered potentially dilutive securities.
An aggregate of 7.4 million shares of common stock is authorized and held in reserve for issuance. At December 31, 2021, 5.2 million shares of common stock remained available for issuance under the Company’s stock-based compensation plans. Shares issued as a result of awards granted from stock-based compensation plans are generally funded out of the common stock authorized for issuance as approved by the Company’s shareholders.
See Note 22 for further information on Ovintiv’s outstanding and exercisable TSARs, PSUs and RSUs.
19.
Accumulated Other Comprehensive Income
For the years ended December 31
Foreign Currency Translation Adjustment
Balance, Beginning of Year
$
1,042
$
1,004
$
Change in Foreign Currency Translation Adjustment
Balance, End of Year
$
1,044
$
1,042
$
1,004
Pension and Other Post-Employment Benefit Plans
Balance, Beginning of Year
$
$
$
Other Comprehensive Income Before Reclassifications:
Net actuarial gains and (losses) (See Note 23)
(10
)
Income taxes
(4
)
(12
)
Net prior service costs from plan amendment (See Note 23)
-
(31
)
Income taxes
(2
)
-
Amounts Reclassified from Other Comprehensive Income:
Reclassification of net actuarial (gains) and losses to
net earnings (See Note 23)
(8
)
(9
)
(2
)
Income taxes
-
Reclassification of net prior service costs to net earnings (See Note 23)
Income taxes
-
-
-
Curtailment in net defined periodic benefit cost (See Note 23)
-
-
Income taxes
-
(1
)
-
Settlement in net defined periodic benefit cost (See Note 23)
-
-
Income taxes
-
(1
)
-
Balance, End of Year
$
$
$
Total Accumulated Other Comprehensive Income
$
1,092
$
1,076
$
1,046
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, 2021, VMLP provides approximately 1,169 MMcf/d of natural gas gathering and compression and 925 MMcf/d of natural gas processing under long-term service agreements with remaining terms ranging from 10 to 24 years and have various renewal terms providing up to a potential maximum of 10 years.
Ovintiv has determined that VMLP is a variable interest entity and that Ovintiv holds variable interests in VMLP. Ovintiv 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. Ovintiv is not required to provide any financial support or guarantees to VMLP.
As a result of Ovintiv’s involvement with VMLP, the maximum total exposure to loss related to the commitments under the agreements is estimated to be $1,738 million as at December 31, 2021. The estimate comprises the take or pay volume commitments and the 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, 2021, accounts payable and accrued liabilities included $0.2 million 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 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.
In June 2020, Ovintiv undertook a plan to reduce its workforce by approximately 25 percent as part of a company-wide reorganization in response to the low commodity price environment resulting from the global pandemic and the Company’s planned reductions in capital spending. During 2021, the Company incurred total restructuring charges of $14 million (2020 - $90 million), before tax, primarily related to severance costs. Of the $104 million in restructuring charges incurred, $3 million remains accrued as at December 31, 2021. The remaining amounts accrued are expected to be paid in 2022.
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
Severance and Benefits
$
$
$
Outplacement, Moving and Other Expenses
-
Restructuring Expenses
$
$
$
As at December 31
Outstanding Restructuring Accrual, Beginning of Year
$
$
$
-
Restructuring Expenses Incurred
Restructuring Costs Paid
(25
)
(84
)
(130
)
Outstanding Restructuring Accrual, End of Year (1)
$
$
$
(1)
Included in accounts payable and accrued liabilities in the Consolidated Balance Sheet.
22.
Compensation Plans
Ovintiv 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, Stock Appreciation Rights (“SARs”), PSUs, Deferred Share Units (“DSUs”) and RSUs.
Ovintiv accounts for PSUs and RSUs as equity-settled stock-based payment transactions provided there is sufficient common stock held in reserve for issuance. TSARs, SARs and DSUs are accounted for as cash-settled stock-based payment transactions. The Company accrues compensation costs over the vesting period based on the fair value of the rights determined using the Black-Scholes-Merton or other appropriate fair value models.
During the fourth quarter of 2020, Ovintiv’s Board of Directors resolved to settle certain PSU awards and RSU awards with the issuance of the Company’s common stock. Historically, the Company settled PSU and RSU awards in cash. As a result, the respective awards were modified and reclassified as equity-settled share-based payment transactions at the modification date. The modified awards accrue compensation expense using the modification date fair value of the awards over the remaining vesting period. The modification impacted all employees and there was no incremental compensation cost recognized at the modification date.
The Company has recognized the following share-based compensation costs:
For the years ended December 31
Total Compensation Costs of Transactions Classified as Cash-Settled
$
$
$
Total Compensation Costs of Transactions Classified as Equity-Settled
-
Less: Total Share-Based Compensation Costs Capitalized
(27
)
(12
)
(20
)
Total Share-Based Compensation Expense (Recovery)
$
$
$
Recognized in the Consolidated Statement of Earnings in:
Operating
$
$
$
Administrative
$
$
$
As at December 31, 2021, the liability for cash-settled share-based payment transactions totaled $114 million (2020 - $34 million), of which $78 million (2020 - $25 million) is recognized in accounts payable and accrued liabilities and $36 million (2020 - $9 million) is recognized in other liabilities and provisions in the Consolidated Balance Sheet.
The following sections outline certain information related to Ovintiv’s compensation plans as at December 31, 2021.
A)
TANDEM STOCK APPRECIATION RIGHTS
All options to purchase shares of common stock issued to eligible Canadian-based employees under Ovintiv’s Stock Option Plan have associated TSARs attached. In lieu of exercising the option, the associated TSARs give the option holder the right to purchase shares of common stock of the Company or receive a cash payment equal to the excess of the market price of Ovintiv’s shares of common stock at the time of exercise over the original grant price. TSARs granted vest and are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire seven years after the date granted. TSARs are classified as a liability and remeasured at the end of each reporting period.
The following tables summarize information related to the TSARs:
As at December 31
(thousands of units)
Outstanding
TSARs
Weighted
Average
Exercise
Price (C$)
Weighted
Average
Remaining
Contractual
Life (Years)
Outstanding
TSARs
Weighted
Average
Exercise
Price (C$)
Weighted
Average
Remaining
Contractual
Life (Years)
Outstanding, Beginning of Year
1,586
48.28
2.8
1,606
48.65
Granted
-
-
-
-
Exercised - SARs (1)
(136
)
28.01
-
-
Exercised - Options (1)
-
-
-
-
Forfeited
(717
)
46.11
-
-
Expired
-
-
(20
)
78.47
Outstanding, End of Year (2)
54.17
2.2
1,586
48.28
2.8
Vested and Exercisable, End of Year (3)
55.38
1.9
1,348
47.71
2.4
Expected to Vest (4)
45.64
4.3
51.52
5.0
(1)
The intrinsic value of option awards exercised and cash-settled during 2021 was $2 million (2020 - nil; 2019 - nil).
(2)
The intrinsic value of option awards outstanding during 2021 was $10 million (2020 - $6 million).
(3)
The intrinsic value of option awards vested and exercisable during 2021 was $9 million (2020 - $6 million).
(4)
The intrinsic value of option awards expected to vest during 2021 was $1 million (2020 - nil).
The following weighted average assumptions were used to determine the fair value of TSARs outstanding:
C$ Share Units
As at December 31
Risk Free Interest Rate
0.94%
0.20%
1.69%
Dividend Yield
1.65%
2.75%
1.64%
Expected Volatility Rate (1)
104.80%
103.64%
43.61%
Expected Term
1.4 yrs
1.8 yrs
2.4 yrs
Market Share Price
C$42.56
C$18.29
C$30.40
Weighted Average Grant Date Fair Value
C$54.17
C$48.28
C$48.65
(1)
Volatility was estimated using historical rates.
As at December 31, 2021, there was approximately $0.1 million of unrecognized compensation costs (2020 - $0.1 million) related to unvested TSARs. The costs are expected to be recognized over a weighted average period of 0.2 years.
B)
STOCK APPRECIATION RIGHTS
U.S. dollar denominated SARs are granted to eligible U.S.-based employees, which entitle the employee to receive a cash payment equal to the excess of the market price of Ovintiv’s shares of common stock at the time of exercise over the original grant price of the right. SARs granted vest and are exercisable at 30 percent of the number granted after one year, an additional 30 percent of the number granted after two years, are fully exercisable after three years and expire seven years after the date granted. SARs are classified as a liability and remeasured at the end of each reporting period.
The following tables summarize information related to the U.S. dollar denominated SARs:
As at December 31
(thousands of units)
Outstanding
SARs
Weighted
Average
Exercise
Price (US$)
Weighted
Average
Remaining
Contractual
Life (Years)
Outstanding
SARs
Weighted
Average
Exercise
Price (US$)
Weighted
Average
Remaining
Contractual
Life (Years)
Outstanding, Beginning of Year
38.03
3.7
39.84
Granted
35.11
-
-
Exercised (1)
(177
)
20.50
-
-
Forfeited
(15
)
45.35
(86
)
38.89
Expired
-
-
(43
)
69.35
Outstanding, End of Year (2)
1,150
38.89
2.2
38.03
3.7
Vested and Exercisable, End of Year (3)
1,021
39.54
1.9
39.22
2.9
Expected to Vest (4)
33.77
4.3
35.89
5.2
(1)
The intrinsic value of option awards exercised and cash-settled during 2021 was $2 million (2020 - nil; 2019 - nil).
(2)
The intrinsic value of option awards outstanding during 2021 was $15 million (2020 - $3 million).
(3)
The intrinsic value of option awards vested and exercisable during 2021 was $14 million (2020 - $3 million).
(4)
The intrinsic value of option awards expected to vest during 2021 was $1 million (2020 - nil).
The following weighted average assumptions were used to determine the fair value of SARs outstanding:
US$ Share Units
As at December 31
Risk Free Interest Rate
0.94%
0.20%
1.69%
Dividend Yield
1.66%
2.61%
1.60%
Expected Volatility Rate (1)
106.20%
104.53%
44.98%
Expected Term
1.4 yrs
2.3 yrs
2.8 yrs
Market Share Price
US$33.70
US$14.36
US$23.45
Weighted Average Grant Date Fair Value
US$38.89
US$38.03
US$39.84
(1)
Volatility was estimated using historical rates.
As at December 31, 2021, there was approximately $0.2 million of unrecognized compensation costs (2020 - $0.2 million) related to unvested SARs. The costs are expected to be recognized over a weighted average period of 0.3 years.
C)
PERFORMANCE SHARE UNITS
PSUs are granted to eligible employees, which entitle the employee to receive, upon vesting, one share of Ovintiv common stock for each PSU held or a cash equivalent, at the discretion of the Company. PSUs vest three years from the date granted, provided the employee remains actively employed with Ovintiv on the vesting date. Based on the performance assessment, up to a maximum of two times the original PSU grant may be eligible to vest in respect of the year being measured.
The ultimate value of the PSUs will depend upon Ovintiv’s performance relative to predetermined strategic milestones as well as the performance of a specified peer group over a three-year period.
The following tables summarize information related to the PSUs:
As at December 31
2020 (1)
U.S. Dollar Denominated Outstanding PSUs
Units
(thousands)
Weighted Average
Grant Date
Fair Value (US$)
Units
(thousands)
Weighted Average
Grant Date
Fair Value (US$)
Unvested and Outstanding, Beginning of Year
1,886
21.80
42.66
Granted
25.80
1,317
13.66
Vested and Released (2)
(177
)
54.65
(155
)
58.75
Units, in Lieu of Dividends
20.04
21.80
Forfeited
(152
)
32.96
(174
)
20.05
Unvested and Outstanding, End of Year
2,427
20.04
1,886
21.80
As at December 31
2020 (1)
Canadian Dollar Denominated Outstanding PSUs
Units
(thousands)
Weighted Average
Grant Date
Fair Value (C$)
Units
(thousands)
Weighted Average
Grant Date
Fair Value (C$)
Unvested and Outstanding, Beginning of Year
1,308
34.43
62.62
Granted
29.34
21.08
Vested and Released (2)
(137
)
68.80
(291
)
77.08
Units, in Lieu of Dividends
26.66
34.62
Forfeited
(261
)
46.13
(91
)
32.40
Unvested and Outstanding, End of Year
1,223
26.75
1,308
34.43
(1)
During the fourth quarter of 2020, Ovintiv’s Board of Directors resolved to settle the PSUs with the issuance of the Company’s common stock. As a result, the awards were modified and reclassified as equity-settled awards. The weighted average modification date fair value of the awards was US$14.85 per share and C$18.83 per share for the U.S. dollar denominated and Canadian dollar denominated PSUs, respectively.
(2)
During the year ended December 31, 2021, performance shares that vested and were cash-settled resulted in payments of $3 million (2020 - $6 million; 2019 - $64 million).
As at December 31, 2021, there was approximately $42 million of unrecognized compensation costs (2020 - $27 million) related to unvested PSUs. The costs are expected to be recognized over a weighted average period of 1.1 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 share of Ovintiv common stock and are settled in cash. DSUs are classified as a liability and remeasured at the end of each reporting period based on the change in fair value of the Company’s common stock.
Under the DSU Plan, employees have the option to convert either 25 or 50 percent of their annual bonus award into DSUs. The number of DSUs converted is based on the value of the award divided by the closing value of Ovintiv’s share price at the end of the performance period of the bonus award.
For both Directors and employees, DSUs can only be redeemed following departure from Ovintiv in accordance with the terms of the respective DSU Plan and must be redeemed prior to December 15th of the year following the departure from Ovintiv.
The following table summarizes information related to the DSUs:
(thousands of units)
U.S. Dollar Denominated
Outstanding DSUs
Canadian Dollar Denominated
Outstanding DSUs
As at December 31
Vested and Outstanding, Beginning of Year
-
-
Granted
-
Converted from bonus awards
-
-
-
-
Units, in Lieu of Dividends
-
-
Redeemed
-
-
(17
)
(72
)
Vested and Outstanding, End of Year
-
E)
RESTRICTED SHARE UNITS
RSUs are granted to eligible employees and Directors. An RSU is a conditional grant to receive a share of Ovintiv common stock or a cash equivalent at the Company’s discretion upon vesting of the RSUs and in accordance with the terms and conditions of the RSU Plans and grant agreements.
RSUs issued to employees before February 2020 vest three years from the date granted, provided the employee remains actively employed with Ovintiv on the vesting date. Beginning with the RSUs issued in February 2020, all RSU awards issued to employees will vest over their three-year service period. 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 Ovintiv, whichever is earlier.
The following table summarizes information related to the RSUs:
As at December 31
2021 (1)
2020 (2)
U.S. Dollar Denominated Outstanding RSUs
Units
(thousands)
Weighted Average
Grant Date
Fair Value (US$)
Units
(thousands)
Weighted Average
Grant Date
Fair Value (US$)
Unvested and Outstanding, Beginning of Year
5,486
21.26
2,270
43.44
Granted
1,952
23.57
4,165
12.72
Units, in Lieu of Dividends
20.93
21.48
Vested and Released (3)
(1,720
)
24.74
(449
)
54.68
Forfeited
(400
)
21.99
(884
)
21.11
Unvested and Outstanding, End of Year
5,401
20.92
5,486
21.26
As at December 31
2021 (1)
2020 (2)
Canadian Dollar Denominated Outstanding RSUs
Units
(thousands)
Weighted Average
Grant Date
Fair Value (C$)
Units
(thousands)
Weighted Average
Grant Date
Fair Value (C$)
Unvested and Outstanding, Beginning of Year
2,912
31.76
1,669
61.35
Granted
29.30
2,029
17.06
Units, in Lieu of Dividends
28.11
32.01
Vested and Released (3)
(1,035
)
37.63
(433
)
76.82
Forfeited
(250
)
34.43
(559
)
32.00
Unvested and Outstanding, End of Year
2,621
28.23
2,912
31.76
(1)
During the third quarter of 2021, the 2021 annual awards were modified and reclassified as equity-settled awards. The weighted average modification date fair value of the awards was US$25.66 per share and C$32.07 per share for the U.S. dollar denominated and Canadian dollar denominated RSUs, respectively.
(2)
During the fourth quarter of 2020, Ovintiv’s Board of Directors resolved to settle the RSUs with the issuance of the Company’s common stock. As a result, the awards were modified and reclassified as equity-settled awards. The weighted average modification date fair value of the awards was US$14.85 per share and C$18.83 per share for the U.S. dollar denominated and Canadian dollar denominated RSUs, respectively.
(3)
During the year ended December 31, 2021, restricted shares that vested and were cash-settled resulted in payments of $23 million (2020 - $10 million; 2019 - $85 million).
As at December 31, 2021, there was approximately $43 million of unrecognized compensation costs (2020 - $43 million) related to unvested RSUs. The costs are expected to be recognized over a weighted average period of 0.7 years.
23.
Pension and Other Post-Employment Benefits
Ovintiv 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 five 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 nine 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, 2019 and the next required filing is expected to be as at December 31, 2022.
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, 2021 and 2020, as well as the funded status of the plans and amounts recognized in the Consolidated Financial Statements as at December 31, 2021 and 2020.
Defined Benefits
OPEB
As at December 31
Change in Benefit Obligations
Projected Benefit Obligation, Beginning of Year
$
$
$
$
Service Cost
-
Interest Cost
Actuarial (Gains) Losses
(9
)
(8
)
Exchange Differences
-
Employee Contributions
-
-
Benefits Paid
(17
)
(17
)
(10
)
(9
)
Plan Amendment
-
-
(11
)
-
Settlement
-
(8
)
-
-
Curtailment
-
-
-
(1
)
Projected Benefit Obligation, End of Year
$
$
$
$
Change in Plan Assets
Fair Value of Plan Assets, Beginning of Year
$
$
$
-
$
-
Actual Return on Plan Assets
-
-
Exchange Differences
-
-
Employee Contributions
-
-
Employer Contributions
-
-
Benefits Paid
(17
)
(17
)
(10
)
(9
)
Transfers to Defined Contribution Plan
(4
)
(2
)
-
-
Settlement
-
(8
)
-
-
Fair Value of Plan Assets, End of Year
$
$
$
-
$
-
Funded Status of Plan Assets, End of Year
$
(15
)
$
(18
)
$
(67
)
$
(89
)
Total Recognized Amounts in the
Consolidated Balance Sheet Consist of:
Other Assets
$
$
$
-
$
-
Current Liabilities
-
-
(8
)
(10
)
Non-Current Liabilities
(25
)
(29
)
(59
)
(79
)
Total
$
(15
)
$
(18
)
$
(67
)
$
(89
)
Total Recognized Amounts in Accumulated
Other Comprehensive Income Consist of:
Net Actuarial (Gains) Losses
$
$
$
(82
)
$
(83
)
Net Prior Service Costs
(7
)
(7
)
Total Recognized in Accumulated Other Comprehensive
Income, Before Tax
$
$
$
(75
)
$
(64
)
The accumulated defined benefit obligation for all defined benefit plans was $258 million as at December 31, 2021 (2020 - $299 million).
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
Projected Benefit Obligation
$
(63
)
$
(69
)
$
(67
)
$
(89
)
Accumulated Benefit Obligation
(63
)
(69
)
(67
)
(89
)
Fair Value of Plan Assets (1)
-
-
(1)
The Company does not aggregate benefit plans.
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
Discount Rate
2.80%
2.25%
2.54%
2.09%
Rates of Increase in Compensation Levels
3.13%
3.11%
6.18%
6.28%
The following sets forth total benefit plans expense recognized by the Company:
Pension Benefits
OPEB
For the years ended December 31
Net Defined Periodic Benefit Cost
$
-
$
$
$
(3
)
$
$
Defined Contribution Plan Expense
-
-
-
Total Benefit Plans Expense
$
$
$
$
(3
)
$
$
Of the total benefit plans expense, $22 million (2020 - $27 million; 2019 - $31 million) was included in operating expense and $5 million (2020 - $6 million; 2019 - $9 million) was included in administrative expense. Excluding service costs, net defined periodic benefit gains of $6 million (2020 - nil; 2019 - costs of $7 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
Service Cost
$
-
$
$
$
$
$
Interest Cost
Expected Return on Plan Assets
(6
)
(7
)
(7
)
-
-
-
Amounts Reclassified from Accumulated
Other Comprehensive Income:
Amortization of net actuarial (gains) and losses
(9
)
(10
)
(3
)
Amortization of net prior service costs
-
-
-
Curtailment of net prior service costs
-
-
-
-
-
Settlement from net prior service costs
-
-
-
-
-
Curtailment
-
-
-
-
(1
)
Total Net Defined Periodic Benefit Cost (1)
$
-
$
$
$
(3
)
$
$
(1)
The components of total net defined periodic benefit cost, excluding the service cost component, are included in other (gains) losses, net.
Actuarial gains related to changes in the projected benefit obligations were due to an increase in the discount rate used to measure the obligations.
The amounts recognized in other comprehensive income are as follows:
Defined Benefits
OPEB
For the years ended December 31
Net Actuarial (Gains) Losses
$
(6
)
$
$
(6
)
$
(8
)
$
$
(52
)
Net Prior Service Costs from Plan Amendment
-
-
-
(11
)
-
Amortization of Net Actuarial Gains and (Losses)
(1
)
(1
)
(1
)
Amortization of Net Prior Service Costs
-
-
-
(1
)
(2
)
(1
)
Curtailment of Net Prior Service Costs
-
-
-
-
(5
)
-
Settlement from Net Prior Service Costs
-
(2
)
-
-
-
-
Total Amounts Recognized in Other Comprehensive
(Income) Loss, Before Tax
$
(7
)
$
$
(7
)
$
(11
)
$
$
(19
)
Total Amounts Recognized in Other Comprehensive
(Income) Loss, After Tax
$
(5
)
$
$
(5
)
$
(9
)
$
$
(15
)
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
Discount Rate
2.25
%
3.00
%
3.50
%
2.08
%
2.90
%
4.16
%
Long-Term Rate of Return on Plan Assets
3.00
%
3.75
%
4.00
%
-
-
-
Rates of Increase in Compensation Levels
3.13
%
3.12
%
3.12
%
6.33
%
5.92
%
6.53
%
The Company’s assumed health care cost trend rates are as follows:
For the years ended December 31
Health Care Cost Trend Rate for Next Year
6.15
%
6.42
%
6.61
%
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
The Company does not expect to contribute to its defined benefit pension plans in 2022. 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
$
$
2027 - 2031
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
Level 1
Level 2
Level 3
Total
Investments:
Cash and Cash Equivalents
$
$
$
-
$
Fixed Income
-
-
Equity
-
-
Fair Value of Plan Assets, End of Year
$
$
$
-
$
As at December 31
Level 1
Level 2
Level 3
Total
Investments:
Cash and Cash Equivalents
$
$
$
-
$
Fixed Income
-
-
Equity
-
-
Fair Value of Plan Assets, End of Year
$
$
$
-
$
Fixed Income investments consist of Canadian bonds issued by investment grade companies. Equity investments consist of international securities and securities held in the U.S. The fair values of these securities are based on dealer quotes, quoted market prices and net asset values.
Registered pension plan assets were invested by the Company in the following as at December 31, 2021: 67 percent Bonds (2020 - 69 percent), and 33 percent U.S. and Foreign Equity (2020 - 31 percent). The expected long-term rate of return is 3.50 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 $3 million (2020 - $17 million). 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.
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.
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, 2021
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
$
-
$
$
-
$
$
(10
)
$
-
Long-term assets
-
-
(1
)
-
Foreign Currency Derivatives:
Current assets
-
-
(4
)
Risk Management Liabilities
Commodity Derivatives:
Current liabilities
$
-
$
$
$
$
(10
)
$
Long-term liabilities
-
-
(1
)
Foreign Currency Derivatives:
Current liabilities
-
-
-
-
(4
)
(4
)
Other Derivative Contracts (2)
Current in accounts receivable and accrued revenues
$
-
$
-
$
$
$
-
$
Current in accounts payable and accrued liabilities
-
-
-
Long-term in other liabilities and provisions
-
-
-
As at December 31, 2020
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
$
-
$
$
-
$
$
(59
)
$
Long-term assets
-
-
(3
)
Foreign Currency Derivatives:
Current assets
-
-
-
Risk Management Liabilities
Commodity Derivatives:
Current liabilities
$
$
$
$
$
(59
)
$
Long-term liabilities
-
-
(3
)
Other Derivative Contracts (2)
Current in accounts payable and accrued liabilities
$
-
$
$
-
$
$
-
$
Long-term in other liabilities and provisions
-
-
-
(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.
(2)
Includes credit derivatives and contingent consideration associated with certain previous and current year divestitures, respectively.
The Company’s Level 1 and Level 2 risk management assets and liabilities consist of commodity fixed price contracts, 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 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, 2021, the Company’s Level 3 risk management assets and liabilities consist of WTI three-way options and contingent consideration derivative contracts tied to WTI with terms to 2022. The WTI three-way options are a combination of a sold call, bought put and a sold 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 partial downside price protection through the put options. The fair values of these contracts are determined using an option pricing model 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 for risk management positions is presented below:
Risk Management
Balance, Beginning of Year
$
(74
)
$
(52
)
Total Gains (Losses)
(708
)
Purchases, Sales, Issuances and Settlements:
Purchases, sales and issuances (1)
-
Settlements
(153
)
Transfers Out of Level 3
-
-
Balance, End of Year
$
(172
)
$
(74
)
Change in Unrealized Gains (Losses) During the
Year Included in Net Earnings (Loss)
$
(104
)
$
(22
)
(1)
Relates to the contingent consideration associated with the Duvernay divestiture discussed in Note 9.
Quantitative information about unobservable inputs used in Level 3 fair value measurements is presented below as at December 31, 2021:
Valuation Technique
Unobservable Input
Range
Weighted Average (1)
Risk Management - WTI Options
Option Model
Implied Volatility
40% - 67%
48%
(1)
Unobservable inputs were weighted by the relative fair value of the instruments.
A 10 percent increase or decrease in implied volatility for the WTI options would cause an approximate corresponding $15 million (2020 - $6 million) increase or decrease to net risk management assets and liabilities.
25.
Financial Instruments and Risk Management
A)
FINANCIAL INSTRUMENTS
Ovintiv’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
Ovintiv 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 (loss).
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.
Oil and NGLs - To partially mitigate oil and NGL commodity price risk, the Company uses WTI- and NGL-based contracts such as fixed price contracts and options. Ovintiv has also entered into basis swaps to manage against widening price differentials between various production areas, products and price points.
Natural Gas - To partially mitigate natural gas commodity price risk, the Company uses NYMEX-based contracts such as fixed price contracts, options and costless collars. Ovintiv 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, 2021, Ovintiv has entered into $400 million notional U.S. dollar denominated currency swaps at an average exchange rate of C$1.2848 to US$1, which mature monthly throughout 2022.
RISK MANAGEMENT POSITIONS AS AT DECEMBER 31, 2021
Notional Volumes
Term
Average Price
Fair Value
Oil and NGL Contracts
US$/bbl
Fixed Price Contracts
WTI Fixed Price
5.0 Mbbls/d
60.16
$
(22
)
WTI Three-Way Options
Sold call / bought put / sold put
75.0 Mbbls/d
70.79 / 60.82 / 49.33
(181
)
Basis Contracts (1)
-
Oil and NGLs Fair Value Position
(203
)
Natural Gas Contracts
US$/Mcf
Fixed Price Contracts
NYMEX Fixed Price
365 MMcf/d
2.60
(144
)
NYMEX Three-Way Options
Sold call / bought put / sold put
398 MMcf/d
3.02 / 2.75 / 2.00
(105
)
NYMEX Costless Collars
Sold call / bought put
200 MMcf/d
2.85 / 2.55
(64
)
NYMEX Call Options
Sold call
330 MMcf/d
2.38
(159
)
Basis Contracts (2)
(33
)
(13
)
2024 - 2025
(12
)
Other Financial Positions
Natural Gas Fair Value Position
(529
)
Other Derivative Contracts
Fair Value Position (3)
Foreign Currency Contracts
Fair Value Position (4)
Total Fair Value Position
$
(724
)
(1)
Ovintiv has entered into oil differential swaps associated with Canadian condensate and WTI.
(2)
Ovintiv has entered into natural gas basis swaps associated with AECO, Dawn, Malin, Waha, Houston Ship Channel and NYMEX.
(3)
Includes credit derivatives and contingent consideration associated with certain previous and current year divestitures, respectively.
(4)
Ovintiv has entered into U.S. dollar denominated fixed-for-floating average currency swaps to protect against fluctuations between the Canadian and U.S. dollars.
EARNINGS IMPACT OF REALIZED AND UNREALIZED GAINS (LOSSES) ON RISK MANAGEMENT POSITIONS
For the years ended December 31
Realized Gains (Losses) on Risk Management
Commodity and Other Derivatives:
Revenues (1)
$
(1,395
)
$
$
Foreign Currency Derivatives:
Foreign exchange
(1
)
$
(1,362
)
$
$
Unrealized Gains (Losses) on Risk Management
Commodity and Other Derivatives:
Revenues (2)
$
(488
)
$
(204
)
$
(730
)
Foreign Currency Derivatives:
Foreign exchange
(21
)
$
(509
)
$
(191
)
$
(696
)
Total Realized and Unrealized Gains (Losses) on Risk Management, net
Commodity and Other Derivatives:
Revenues (1) (2)
$
(1,883
)
$
$
(361
)
Foreign Currency Derivatives:
Foreign exchange
$
(1,871
)
$
$
(324
)
(1)
Includes a realized gain of $1 million for the year ended December 31, 2021 (2020 - gain of $2 million; 2019 - gain of $6 million) related to other derivative contracts.
(2)
Includes an unrealized gain of $4 million for the year ended December 31, 2021 (2020 - loss of $1 million; 2019 - loss of $1 million) related to other derivative contracts.
RECONCILIATION OF UNREALIZED RISK MANAGEMENT POSITIONS FROM JANUARY 1 TO DECEMBER 31
Fair Value
Total Unrealized Gain (Loss)
Total Unrealized Gain (Loss)
Total Unrealized Gain (Loss)
Fair Value of Contracts, Beginning of Year
$
(222
)
Change in Fair Value of Contracts in Place at Beginning of Year
and Contracts Entered into During the Year
(1,871
)
$
(1,871
)
$
$
(324
)
Settlement of Other Derivative Contracts
Fair Value of Other Derivative Contract Assets Entered into
During the Year (See Note 9)
Fair Value of Contracts Realized During the Year
1,362
1,362
(710
)
(372
)
Fair Value of Contracts Outstanding, End of Year
$
(724
)
$
(509
)
$
(191
)
$
(696
)
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.
UNREALIZED RISK MANAGEMENT POSITIONS
As at December 31
Risk Management Assets
Current
$
$
Long-term
-
Risk Management Liabilities
Current
Long-term
Other Derivative Contract Assets
Current in accounts receivable and accrued revenues
-
-
Other Derivative Contract Liabilities
Current in accounts payable and accrued liabilities
Long-term in other liabilities and provisions
Net Risk Management Assets (Liabilities) and Other Derivative Contracts
$
(724
)
$
(222
)
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 exchanges and clearing agencies, over-the-counter traded contracts expose Ovintiv to counterparty credit risk. Counterparties to the Company’s derivative financial instruments consist primarily of major financial institutions and companies within the energy industry. 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. Ovintiv actively evaluates the creditworthiness of its counterparties, assigns appropriate credit limits and monitors credit exposures against those assigned limits. As at December 31, 2021, Ovintiv’s maximum exposure of loss due to credit risk from derivative financial instrument assets on a gross and net fair value basis was $25 million and $10 million, respectively, as disclosed in Note 24. The Company had no significant credit derivatives in place and held no collateral at December 31, 2021.
As at December 31, 2021, cash equivalents include high-grade, short-term securities, placed primarily with financial institutions 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, 2021, approximately 90 percent (2020 - 89 percent) of Ovintiv’s accounts receivable and financial derivative credit exposures were with investment grade counterparties.
During 2015 and 2017, the Company entered into agreements resulting from divestitures, which may require Ovintiv to fulfill certain payment obligations on the take or pay volume commitments assumed by the purchasers. The circumstances that would require Ovintiv 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 expire in June 2024 with a fair value recognized of $6 million as at December 31, 2021 (2020 - $8 million). The maximum potential amount of undiscounted future payments is $57 million as at December 31, 2021, 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
Operating Activities
Accounts receivable and accrued revenues
$
(333
)
$
$
Accounts payable and accrued liabilities
(26
)
(44
)
Current portion of operating lease liabilities
(7
)
(11
)
Income tax receivable and payable
(27
)
$
(41
)
$
$
B)
NON-CASH ACTIVITIES
For the years ended December 31
Non-Cash Operating Activities
ROU operating lease assets and liabilities (See Note 14)
$
(23
)
$
(10
)
$
(20
)
Non-Cash Investing Activities
Asset retirement obligation incurred (See Note 17)
$
$
$
Asset retirement obligation change in estimated future cash outflows (See Note 17)
(49
)
Property, plant and equipment accruals
(9
)
(175
)
(78
)
Capitalized long-term incentives
(16
)
(27
)
Property additions/dispositions (swaps)
Contingent consideration (See Note 9)
-
-
Non-Cash Financing Activities
Common shares issued in conjunction with the Newfield business
combination (See Note 8)
$
-
$
-
$
(3,478
)
On September 1, 2020, Ovintiv closed an agreement with PetroChina Canada Ltd. (“PCC”) to terminate its joint venture with PCC and transfer the ownership and operation of certain Duvernay shale assets in west central Alberta. In connection with the closing, Ovintiv and PCC agreed to partition the Duvernay acreage and associated infrastructure. For the year ended December 31, 2020, property additions/dispositions (swaps) included a $203 million non-cash swap related to the Duvernay partition.
C)
SUPPLEMENTARY CASH FLOW INFORMATION
For the years ended December 31
Interest Paid
$
$
$
Income Taxes (Recovered), net of Amounts Paid
$
(176
)
$
(52
)
$
(22
)
27.
Commitments and Contingencies
COMMITMENTS
The following table outlines the Company’s commitments as at December 31, 2021:
Expected Future Payments
(undiscounted)
Thereafter
Total
Transportation and Processing
$
$
$
$
$
$
1,926
$
4,851
Drilling and Field Services
-
-
-
-
-
Building Leases
-
Total
$
$
$
$
$
$
1,926
$
4,975
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 Note 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
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. 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.
28.
Supplementary Oil and Gas Information (unaudited)
The unaudited supplementary information on oil and natural gas exploration and production activities for 2021, 2020 and 2019 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 Natural 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)
$
66.56
$
83.69
$
3.60
$
3.26
39.62
49.77
1.98
2.13
55.93
68.80
2.58
1.76
(1)
All prices were held constant in all future years when estimating net revenues and reserves.
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
Beginning of year
351.5
0.2
351.8
122.3
158.5
280.8
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
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
Beginning of year
722.4
1.3
723.7
409.4
179.1
588.5
2,441
2,818
5,259
2,188.8
Revisions and improved recovery (2)
(221.5
)
(0.5
)
(222.0
)
(29.1
)
(33.1
)
(62.2
)
(323
)
(161
)
(484
)
(364.9
)
Extensions and discoveries
144.3
0.1
144.4
78.1
27.7
105.8
377.5
Purchase of reserves in place
9.9
1.0
10.9
8.4
11.6
20.0
54.3
Sale of reserves in place
(9.3
)
-
(9.3
)
(7.9
)
(13.4
)
(21.4
)
(95
)
(106
)
(201
)
(64.1
)
Production
(55.2
)
(0.2
)
(55.4
)
(29.8
)
(20.5
)
(50.3
)
(194
)
(366
)
(560
)
(199.0
)
End of year
590.5
1.7
592.3
429.1
151.4
580.5
2,268
2,650
4,918
1,992.5
Developed
279.1
1.7
280.9
242.3
76.9
319.3
1,327
1,740
3,067
1,111.3
Undeveloped
311.4
-
311.4
186.7
74.5
261.2
1,851
881.1
Total
590.5
1.7
592.3
429.1
151.4
580.5
2,268
2,650
4,918
1,992.5
Beginning of year
590.5
1.7
592.3
429.1
151.4
580.5
2,268
2,650
4,918
1,992.5
Revisions and improved recovery (2)
(78.7
)
0.7
(78.0
)
(30.0
)
(20.3
)
(50.3
)
(67.8
)
Extensions and discoveries
121.2
0.3
121.5
75.1
66.9
142.0
1,538
1,966
591.2
Purchase of reserves in place
2.6
-
2.6
1.6
0.9
2.5
7.3
Sale of reserves in place
(27.0
)
(1.6
)
(28.6
)
(12.6
)
(8.4
)
(21.0
)
(50
)
(73
)
(123
)
(70.2
)
Production
(51.1
)
(0.1
)
(51.2
)
(28.5
)
(20.5
)
(49.0
)
(179
)
(389
)
(568
)
(194.9
)
End of year
557.5
1.1
558.6
434.7
170.0
604.7
2,536
4,033
6,570
2,258.2
Developed
291.0
0.7
291.7
264.3
84.5
348.8
1,621
2,490
4,111
1,325.7
Undeveloped
266.6
0.3
266.9
170.5
85.4
255.9
1,543
2,458
932.5
Total
557.5
1.1
558.6
434.7
170.0
604.7
2,536
4,033
6,570
2,258.2
(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.
Total Proved reserves increased 265.7 MMBOE including production of 194.9 MMBOE in 2021 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 396.1 MMBOE, partially offset by positive performance revisions of 160.6 MMBOE, higher 12-month average trailing prices of 144.5 MMBOE and 23.2 MMBOE from infill drilling locations.
•
Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 591.2 MMBOE due to successful drilling and technical delineation, as well as new proved undeveloped locations resulting from updated development plans in the Montney, Permian and Anadarko assets.
•
Purchases of 7.3 MMBOE were primarily in the Permian asset and a result of acreage trades.
•
Sale of reserves in place decreased proved developed reserves by 70.2 MMBOE primarily due to the divestitures of the Eagle Ford assets located in south Texas and the Duvernay assets located in west central Alberta.
Total Proved reserves decreased 196.3 MMBOE including production of 199.0 MMBOE in 2020 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 382.2 MMBOE and lower 12-month average trailing prices of 167.1 MMBOE, partially offset by positive revisions from well performance and development strategy changes of 182.0 MMBOE and from infill drilling locations of 2.4 MMBOE.
•
Extensions and discoveries of oil, NGLs and natural gas increased proved reserves by 377.5 MMBOE due to successful drilling and technical delineation, as well as new proved undeveloped locations resulting from development plan changes in the Permian, Montney, Anadarko and Uinta assets.
•
Purchases of 54.3 MMBOE were primarily in the Permian asset and a result of the partition of certain Duvernay shale assets between Ovintiv and PCC.
•
Sale of reserves in place decreased proved developed reserves by 64.1 MMBOE primarily due to divestitures in the Anadarko and Permian assets, and the partition of certain Duvernay shale assets between Ovintiv and PCC.
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.
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 Ovintiv’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.
Ovintiv 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 Ovintiv’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
Future Cash Inflows
$
51,473
$
26,093
$
46,076
$
18,312
$
7,156
$
10,404
Less Future:
Production costs
12,272
8,864
13,064
7,679
4,202
4,791
Development costs
5,767
6,187
10,795
2,061
1,859
3,024
Income taxes
5,480
2,262
1,695
-
-
Future Net Cash Flows
27,954
10,968
19,955
6,877
1,095
2,589
Less 10% annual discount for estimated
timing of cash flows
13,663
5,895
9,914
2,393
1,014
Discounted Future Net Cash Flows
$
14,291
$
5,073
$
10,041
$
4,484
$
$
1,575
Total
Future Cash Inflows
$
69,785
$
33,249
$
56,480
Less Future:
Production costs
19,951
13,066
17,855
Development costs
7,828
8,046
13,819
Income taxes
7,175
2,262
Future Net Cash Flows
34,831
12,063
22,544
Less 10% annual discount for estimated
timing of cash flows
16,056
6,141
10,928
Discounted Future Net Cash Flows
$
18,775
$
5,922
$
11,616
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
United States
Canada
Balance, Beginning of Year
$
5,073
$
10,041
$
6,950
$
$
1,575
$
2,654
Changes Resulting From:
Sales of oil and gas produced during the year
(3,608
)
(1,605
)
(2,893
)
(1,479
)
(405
)
(654
)
Discoveries and extensions, net of related costs
3,102
1,080
2,893
2,119
Purchases of proved reserves in place
5,581
-
Sales and transfers of proved reserves in place
(199
)
(255
)
(931
)
(38
)
(97
)
-
Net change in prices and production costs
10,702
(7,119
)
(2,629
)
3,266
(1,563
)
(1,219
)
Revisions to quantity estimates
(407
)
(2,346
)
(850
)
(188
)
(550
)
Accretion of discount
1,064
Development costs incurred during the year
1,139
1,341
2,115
Changes in estimated future development costs
(83
)
2,183
(885
)
(364
)
Other
-
-
-
(2
)
Net change in income taxes
(2,000
)
(59
)
(970
)
-
Balance, End of Year
$
14,291
$
5,073
$
10,041
$
4,484
$
$
1,575
Total
Balance, Beginning of Year
$
5,922
$
11,616
$
9,604
Changes Resulting From:
Sales of oil and gas produced during the year
(5,087
)
(2,010
)
(3,547
)
Discoveries and extensions, net of related costs
5,221
1,220
3,437
Purchases of proved reserves in place
5,581
Sales and transfers of proved reserves in place
(237
)
(352
)
(931
)
Net change in prices and production costs
13,968
(8,682
)
(3,848
)
Revisions to quantity estimates
(206
)
(2,534
)
(1,400
)
Accretion of discount
1,222
1,046
Development costs incurred during the year
1,536
1,876
2,660
Changes in estimated future development costs
(42
)
2,835
(1,249
)
Other
(2
)
Net change in income taxes
(2,970
)
Balance, End of Year
$
18,775
$
5,922
$
11,616
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
Oil, NGL and Natural Gas Revenues (1)
$
4,883
$
2,701
$
4,163
$
2,542
$
1,349
$
1,654
Less:
Production, mineral and other taxes
Transportation and processing
Operating
Depreciation, depletion and amortization
1,378
1,593
Impairments
-
5,580
-
-
-
-
Accretion of asset retirement obligation
Operating Income (Loss)
2,760
(5,366
)
1,285
1,136
(38
)
Income Taxes
(1,309
)
(9
)
Results of Operations
$
2,087
$
(4,057
)
$
$
$
(29
)
$
China (2)
Total
Oil, NGL and Natural Gas Revenues (1)
$
-
$
-
$
$
7,425
$
4,050
$
5,854
Less:
Production, mineral and other taxes
-
-
-
Transportation and processing
-
-
-
1,444
1,282
1,325
Operating
-
-
Depreciation, depletion and amortization
-
-
-
1,169
1,805
1,976
Impairments
-
-
-
-
5,580
-
Accretion of asset retirement obligation
-
-
Operating Income (Loss)
-
-
3,896
(5,404
)
1,555
Income Taxes
-
-
(1,318
)
Results of Operations
$
-
$
-
$
$
2,951
$
(4,086
)
$
1,178
(1)
Excludes gains (losses) on risk management.
(2)
Effective July 31, 2019, the production sharing contract with CNOOC was terminated and the Company exited its China Operations.
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 natural gas leaseholds where no proved reserves have been identified.
United States
Canada
Proved Oil and Gas Properties
$
39,145
$
37,875
$
35,870
$
16,330
$
16,008
$
15,284
Unproved Oil and Gas Properties
1,884
2,785
3,491
Total Capital Cost
41,029
40,660
39,361
16,390
16,185
15,507
Accumulated DD&A
33,418
32,581
25,623
15,450
15,056
14,320
Net Capitalized Costs
$
7,611
$
8,079
$
13,738
$
$
1,129
$
1,187
Other
Total
Proved Oil and Gas Properties
$
-
$
-
$
$
55,475
$
53,883
$
51,210
Unproved Oil and Gas Properties
-
-
-
1,944
2,962
3,714
Total Capital Cost
-
-
57,419
56,845
54,924
Accumulated DD&A
-
-
48,868
47,637
39,999
Net Capitalized Costs
$
-
$
-
$
-
$
8,551
$
9,208
$
14,925
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
Acquisition Costs
Unproved
$
$
$
$
-
$
-
$
-
Proved
5,963
-
-
-
Total Acquisition Costs
6,806
-
-
-
Exploration Costs
-
-
Development Costs
1,148
1,352
2,129
Total Costs Incurred
$
1,169
$
1,383
$
8,940
$
$
$
Total
Acquisition Costs
Unproved
$
$
$
Proved
5,963
Total Acquisition Costs
6,806
Exploration Costs
Development Costs
1,536
1,705
2,609
Total Costs Incurred
$
1,562
$
1,736
$
9,420
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
United States
$
1,884
$
2,785
Canada
$
1,944
$
2,962
The following is a summary of the costs related to Ovintiv’s unproved properties as at December 31, 2021:
Prior to 2019
Total
Acquisition Costs
$
$
$
$
$
1,788
Exploration Costs
$
$
$
$
1,089
$
1,944
Acquisition costs primarily include costs incurred to acquire or lease properties. Exploration costs primarily include costs related to geological and geophysical studies and unevaluated costs associated with 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.
The $1.9 billion of oil and natural gas properties not subject to depletion or amortization primarily includes leasehold and mineral costs related to the acquisition of Permian, Anadarko and Bakken. 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 two to three years. The remaining costs excluded from depletion are related to properties which are not individually significant.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
The financial statements for the fiscal years ended December 31, 2021, 2020, and 2019, 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.

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ITEM 9A. CONTROLS AND PROCEDURES
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, 2021.
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 2021 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.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 2022 annual meeting of shareholders, 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/policies-and-practices, and is available in print to any shareholder 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 17th 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/policies-and-practices.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information required by this Item 11 is set forth in the Proxy Statement relating to the Company’s 2022 annual meeting of shareholders, 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.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
The information required by this Item 12 is set forth in the Proxy Statement relating to the Company’s 2022 annual meeting of shareholders, which is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 2022 annual meeting of shareholders, which is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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 2022 annual meeting of shareholders, which is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
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
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).
4.3
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).
4.4
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).
4.5
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).
4.6
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).
4.7
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).
4.8
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).
4.9
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).
4.10
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).
4.11
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).
4.12
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).
4.13
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 filed on May 7, 2012, SEC File No. 333-181196).
4.14
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).
4.15
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).
4.16
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).
4.17
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).
4.18
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).
4.19
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).
4.20
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).
4.21
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).
4.22
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).
4.23
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).
4.24
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).
4.25
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).
4.26
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).
4.27
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).
4.28
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
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).
4.30
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).
4.31
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).
4.32
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).
4.33
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).
4.34
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).
4.35
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).
4.36
Second Supplemental Indenture, dated as of September 30, 2011, to Senior Indenture between 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 dated as of February 28, 2001 (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).
4.37
Third Supplemental Indenture, dated as of June 26, 2012, to Senior Indenture between 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 dated as of February 28, 2001 (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).
4.38
Fourth Supplemental Indenture, dated as of March 10, 2015, to Senior Indenture between 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 dated as of February 28, 2001 (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).
4.39
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 dated as of February 28, 2001 (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).
4.40
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 dated as of February 28, 2001 (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).
4.41
Seventh Supplemental Indenture, dated as of April 26, 2021, among Ovintiv Exploration Inc. (formerly Newfield Exploration Company), as Issuer, Ovintiv Inc., as Guarantor and Successor 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 dated as of February 28, 2001 (incorporated by reference to Exhibit 4.1 to Ovintiv’s Current Report on Form 8-K filed on April 28, 2021, SEC File No. 001-39191).
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
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).
10.6
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).
10.7*
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).
10.8*
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).
10.9*
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).
10.10*
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).
10.11*
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).
10.12*
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).
10.13*
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).
10.14*
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).
10.15*
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).
10.16*
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).
10.17*
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).
10.18*
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).
10.19*
Encana (USA) Deferred Compensation Plan (“U.S. 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).
10.20*
Change in Control Agreement between Ovintiv Inc. and Douglas J. Suttles effective January 24, 2020 (incorporated by reference to Exhibit 10.46 to Ovintiv’s Annual Report on Form 10-K filed on February 21, 2020, SEC File No. 001-39191).
10.21*
Change in Control Agreement between Ovintiv Inc. and Joanne L. Cox effective January 24, 2020 (incorporated by reference to Exhibit 10.47 to Ovintiv’s Annual Report on Form 10-K filed on February 21, 2020, SEC File No. 001-39191).
10.22*
Change in Control Agreement between Ovintiv Inc. and Corey D. Code effective January 24, 2020 (incorporated by reference to Exhibit 10.48 to Ovintiv’s Annual Report on Form 10-K filed on February 21, 2020, SEC File No. 001-39191).
10.23*
Change in Control Agreement between Ovintiv Inc. and Gregory D. Givens effective January 24, 2020 (incorporated by reference to Exhibit 10.49 to Ovintiv’s Annual Report on Form 10-K filed on February 21, 2020, SEC File No. 001-39191).
10.24*
Change in Control Agreement between Ovintiv Inc. and Brendan M. McCracken effective January 24, 2020 (incorporated by reference to Exhibit 10.52 to Ovintiv’s Annual Report on Form 10-K filed on February 21, 2020, SEC File No. 001-39191).
10.25*
Change in Control Agreement between Ovintiv Inc. and Renee E. Zemljak effective January 24, 2020 (incorporated by reference to Exhibit 10.54 to Ovintiv’s Annual Report on Form 10-K filed on February 21, 2020, SEC File No. 001-39191).
10.26*
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).
10.27*
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).
10.28*
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).
10.29*
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).
10.30*
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).
10.31*
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).
10.32*
First Amendment to U.S. Deferred Compensation Plan amended and restated effective April 1, 2018, dated effective January 24, 2020 (incorporated by reference to Exhibit 10.1 to Ovintiv’s Quarterly Report on Form 10-Q filed on May 8, 2020, SEC File No. 001-39191).
10.33*
Ovintiv U.S. Retirement Plan amended and restated effective January 27, 2020 (incorporated by reference to Exhibit 10.2 to Ovintiv’s Quarterly Report on Form 10-Q filed on May 8, 2020, SEC File No. 001-39191).
10.34*
Offer of employment dated June 10, 2013 (incorporated by reference to Exhibit 10.3 to Ovintiv’s Quarterly Report on Form 10-Q filed on May 8, 2020, SEC File No. 001-39191).
10.35*
Change in Control Agreement between Ovintiv Inc. and Rachel M. Moore effective June 30, 2020 (incorporated by reference to Exhibit 10.1 to Ovintiv’s Quarterly Report on Form 10-Q filed on July 31, 2020, SEC File No. 001-39191).
10.36*
Letter agreement between Ovintiv Inc. and David G. Hill (incorporated by reference to Exhibit 10.2 to Ovintiv’s Quarterly Report on Form 10-Q filed on July 31, 2020, SEC File No. 001-39191).
10.37*
Ovintiv Canadian Pension Plan amended and restated effective January 24, 2020 (incorporated by reference to Exhibit 10.49 to Ovintiv’s Annual Report on Form 10-K filed on February 18, 2021, SEC File No. 001-39191).
10.38*
Ovintiv Canadian Supplemental Pension Plan amended and restated effective January 24, 2020 (incorporated by reference to Exhibit 10.50 to Ovintiv’s Annual Report on Form 10-K filed on February 18, 2021, SEC File No. 001-39191).
10.39*
Ovintiv Canadian Investment Plan amended and restated effective January 24, 2020 (incorporated by reference to Exhibit 10.51 to Ovintiv’s Annual Report on Form 10-K filed on February 18, 2021, SEC File No. 001-39191).
10.40*
First Amendment to Ovintiv U.S. Retirement Plan amended and restated effective January 27, 2020, dated effective January 1, 2021 (incorporated by reference to Exhibit 10.52 to Ovintiv’s Annual Report on Form 10-K filed on February 18, 2021, SEC File No. 001-39191).
10.41*
Second Amendment to U.S. Deferred Compensation Plan amended and restated effective April 1, 2018, dated effective January 1, 2021 (incorporated by reference to Exhibit 10.53 to Ovintiv’s Annual Report on Form 10-K filed on February 18, 2021, SEC File No. 001-39191).
10.42*
Second Amending Agreement to Deferred Share Unit Plan for Employees of Ovintiv Inc. (incorporated by reference to Exhibit 10.54 to Ovintiv’s Annual Report on Form 10-K filed on February 18, 2021, SEC File No. 001-39191).
10.43*
Letter Agreement between Ovintiv Inc. and Brendan M. McCracken dated June 8, 2021 (incorporated by reference to Exhibit 10.1 to Ovintiv’s Current Report on Form 8-K filed on June 11, 2021, SEC File No. 001-39191).
10.44*
Change in Control Agreement between Ovintiv Inc. and Brendan McCracken effective August 1, 2021 (incorporated by reference to Exhibit 10.1 to Ovintiv’s Quarterly Report on Form 10-Q filed on November 4, 2021, SEC File No. 001-39191).
10.45*
First Amendment to Change in Control Agreement between Ovintiv Inc. and Corey D. Code effective November 1, 2021 (incorporated by reference to Exhibit 10.2 to Ovintiv’s Quarterly Report on Form 10-Q filed on November 4, 2021, SEC File No. 001-39191).
10.46*
First Amendment to Change in Control Agreement between Ovintiv Inc. and Gregory D. Givens effective November 1, 2021 (incorporated by reference to Exhibit 10.3 to Ovintiv’s Quarterly Report on Form 10-Q filed on November 4, 2021, SEC File No. 001-39191).
10.47*
First Amendment to Change in Control Agreement between Ovintiv Inc. and Joanne L. Cox effective November 1, 2021 (incorporated by reference to Exhibit 10.4 to Ovintiv’s Quarterly Report on Form 10-Q filed on November 4, 2021, SEC File No. 001-39191).
10.48*
First Amendment to Change in Control Agreement between Ovintiv Inc. and Rachel M. Moore effective November 1, 2021 (incorporated by reference to Exhibit 10.5 to Ovintiv’s Quarterly Report on Form 10-Q filed on November 4, 2021, SEC File No. 001-39191).
10.49*
First Amendment to Change in Control Agreement between Ovintiv Inc. and Renee E. Zemljak effective November 1, 2021 (incorporated by reference to Exhibit 10.6 to Ovintiv’s Quarterly Report on Form 10-Q filed on November 4, 2021, SEC File No. 001-39191).
14.1
Business Code of Conduct effective March 1, 2020 (incorporated by reference to Exhibit 14.1 to Ovintiv’s Annual Report on Form 10-K filed on February 18, 2021, SEC File No. 001-39191).
21.1
Significant Subsidiaries
23.1
Consent of PricewaterhouseCoopers LLP.
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.
The cover page from the Company’s Annual Report on Form 10-K for the year ended December 31, 2021, has been formatted in Inline XBRL.
* Management contract or compensatory arrangement.