Devon Energy Annual Report 2019

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FY2019 Annual Report · Devon Energy

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-K

(Mark One)
(cid:3) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

(cid:4) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number 001-32318

DEVON ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

Delaware
(State or other jurisdiction of incorporation or organization)

333 West Sheridan Avenue, Oklahoma City, Oklahoma
(Address of principal executive offices)

73-1567067
(I.R.S. Employer identification No.)

73102-5015
(Zip code)

Registrant’s telephone number, including area code: (405) 235-3611

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

Title of each class
Common stock, par value $0.10 per share

Trading Symbol
DVN

Name of each exchange on which registered
The New York Stock Exchange

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes (cid:3) No (cid:4)

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes (cid:4) No (cid:3)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes (cid:3) No (cid:4)

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant

to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was
required to submit such files). Yes (cid:3) No (cid:3)

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

Large accelerated filer
Smaller reporting company

(cid:5) Accelerated filer
(cid:4) Emerging growth company

(cid:4) Non-accelerated filer
(cid:4)

(cid:4)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for

complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. (cid:4)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes (cid:4) No (cid:3)

The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 28, 2019 was approximately

$11.6 billion, based upon the closing price of $28.52 per share as reported by the New York Stock Exchange on such date. On February 5, 2020,
382.9 million shares of common stock were outstanding.

Portions of Registrant’s definitive Proxy Statement relating to Registrant’s 2020 annual meeting of stockholders have been incorporated by
reference in Part III of this Annual Report on Form 10-K.

DOCUMENTS INCORPORATED BY REFERENCE

DEVON ENERGY CORPORATION
FORM 10-K
TABLE OF CONTENTS

Items 1 and 2. Business and Properties
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures

PART I

PART II

Item 5. Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity

Securities

Item 6. Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Item 8. Financial Statements and Supplementary Data
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information

PART III

Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder

Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services

Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10-K Summary
Signatures

PART IV

6
14
21
21
21

22
24
25
49
50
102
102
102

103

103
103

103
103
103

104

104
109
110

DEFINITIONS

Unless the context otherwise indicates, references to “us,” “we,” “our,” “ours,” “Devon,” the “Company” and

“Registrant” refer to Devon Energy Corporation and its consolidated subsidiaries. All monetary values, other than
per unit and per share amounts, are stated in millions of U.S. dollars unless otherwise specified. In addition, the
following are other abbreviations and definitions of certain terms used within this Annual Report on Form 10-K:

“2015 Plan” means the Devon Energy Corporation 2015 Long-Term Incentive Plan.

“2017 Plan” means the Devon Energy Corporation 2017 Long-Term Incentive Plan.

“ASC” means Accounting Standards Codification.

“ASR” means an accelerated share-repurchase transaction with a financial institution to repurchase Devon’s
common stock.

“ASU” means Accounting Standards Update.

“Bbl” or “Bbls” means barrel or barrels.

“Bcf” means billion cubic feet.

“BKV” means Banpu Kalnin Ventures.

“BLM” means the United States Bureau of Land Management.

“Boe” means barrel of oil equivalent. Gas proved reserves and production are converted to Boe, at the
pressure and temperature base standard of each respective state in which the gas is produced, at the rate of six
Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. Bitumen and
NGL proved reserves and production are converted to Boe on a one-to-one basis with oil.

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

“Canada” means the division of Devon encompassing oil and gas properties located in Canada. All dollar
amounts associated with Canada are in U.S. dollars, unless stated otherwise.

“CDM” means Cotton Draw Midstream, L.L.C.

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

“Devon Financing” means Devon Financing Company, L.L.C.

“Devon Plan” means Devon Energy Corporation Incentive Savings Plan.

“EnLink” means EnLink Midstream Partners, LP, a master limited partnership.

“EPA” means the United States Environmental Protection Agency.

“FASB” means Financial Accounting Standards Board.

“Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal
Reserve to other depository institutions overnight.

“G&A” means general and administrative expenses.

“GAAP” means U.S. generally accepted accounting principles.

“General Partner” means EnLink Midstream, LLC, the indirect general partner entity of EnLink, and, unless
the context otherwise indicates, EnLink Midstream Manager, LLC, the managing member of EnLink
Midstream, LLC.

“Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.

“LIBOR” means London Interbank Offered Rate.

“LOE” means lease operating expenses.

“MBbls” means thousand barrels.

“MBoe” means thousand Boe.

“Mcf” means thousand cubic feet.

“MMBbls” means million barrels.

“MMBoe” means million Boe.

“MMBtu” means million Btu.

“MMcf” means million cubic feet.

“N/M” means not meaningful.

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

“NYMEX” means New York Mercantile Exchange.

“NYSE” means New York Stock Exchange.

“OPEC” means Organization of the Petroleum Exporting Countries.

“OPIS” means Oil Price Information Service.

“SEC” means United States Securities and Exchange Commission.

“Senior Credit Facility” means Devon’s syndicated unsecured revolving line of credit, effective as of October
5, 2018.

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

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

“Tax Reform Legislation” means Tax Cuts and Jobs Act.

“TSR” means total shareholder return.

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

“VIE” means variable interest entity.

“WTI” means West Texas Intermediate.

“/Bbl” means per barrel.

“/d” means per day.

“/MMBtu” means per MMBtu.

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This report includes “forward-looking statements” as defined by the SEC. Such statements include those

concerning strategic plans, our expectations and objectives for future operations, as well as other future events or
conditions, and are often identified by use of the words and phrases “expects,” “believes,” “will,” “would,” “could,”
“continue,” “may,” “aims,” “likely to be,” “intends,” “forecasts,” “projections,” “estimates,” “plans,”
“expectations,” “targets,” “opportunities,” “potential,” “anticipates,” “outlook” and other similar terminology. All
statements, other than statements of historical facts, included in this report that address activities, events or
developments that Devon expects, believes or anticipates will or may occur in the future are forward-looking
statements. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are
beyond our control. Consequently, actual future results could differ materially from our expectations due to a
number of factors, including, but not limited to:

•

the volatility of oil, gas and NGL prices;

uncertainties inherent in estimating oil, gas and NGL reserves;

the extent to which we are successful in acquiring and discovering additional reserves;

the uncertainties, costs and risks involved in our operations, including as a result of employee
misconduct;

regulatory restrictions, compliance costs and other risks relating to governmental regulation, including
with respect to environmental matters;

risks related to regulatory, social and market efforts to address climate change;

risks related to our hedging activities;

counterparty credit risks;

risks relating to our indebtedness;

risks related to environmental regulations;

cyberattack risks;

our limited control over third parties who operate some of our oil and gas properties;

midstream capacity constraints and potential interruptions in production;

the extent to which insurance covers any losses we may experience;

competition for assets, materials, people and capital;

risks related to investors attempting to effect change;

our ability to successfully complete mergers, acquisitions and divestitures; and

any of the other risks and uncertainties discussed in this report.

All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its

behalf, are expressly qualified in their entirety by the cautionary statements above. We assume no duty to update or
revise our forward-looking statements based on new information, future events or otherwise.

Items 1 and 2. Business and Properties

General

PART I

A Delaware corporation formed in 1971 and publicly held since 1988, Devon (NYSE: DVN) is an

independent energy company engaged primarily in the exploration, development and production of oil, natural gas
and NGLs. Our operations are concentrated in various onshore areas in the U.S. In June 2019, we completed the sale
of substantially all of our oil and gas assets and operations in Canada. In December 2019, we announced the sale of
our Barnett Shale assets.

Our principal and administrative offices are located at 333 West Sheridan, Oklahoma City, OK 73102-5015
(telephone 405-235-3611). As of December 31, 2019, Devon and its consolidated subsidiaries had approximately
1,800 employees.

Devon files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on

Form 8-K, as well as any amendments to these reports, with the SEC. Through our website, www.devonenergy.com,
we make available electronic copies of the documents we file or furnish to the SEC, the charters of the committees
of our Board of Directors and other documents related to our corporate governance. The corporate governance
documents available on our website include our Code of Ethics for Chief Executive Officer, Chief Financial Officer
and Chief Accounting Officer, and any amendments to and waivers from any provision of that Code will also be
posted on our website. Access to these electronic filings is available free of charge as soon as reasonably practicable
after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents
and filings can be requested by writing to our corporate secretary at the address on the cover of this report. Reports
filed with the SEC are also made available on its website at www.sec.gov.

Our Strategy

Our business strategy is focused on delivering a consistently competitive shareholder return among our peer

group. Because the business of exploring for, developing and producing oil and natural gas is capital intensive,
delivering sustainable, capital efficient cash flow growth is a key tenant to our success. While our cash flow is
highly dependent on volatile and uncertain commodity prices, we pursue our strategy throughout all commodity
price cycles with four fundamental principles.

Proven and responsible operator – We operate our business with the interests of our stakeholders and our
environmental, social and governance progress in mind. With our vision to be a premier independent oil and natural
gas exploration and production company, the work our employees do every day contributes to the local, national and
global economies. We produce a valuable commodity that is fundamental to society, and we endeavor to do so in a
safe, environmentally responsible and ethical way, while striving to deliver strong returns to our shareholders. We
have an ongoing commitment to transparency in reporting our environmental, social and governance performance.
See our Sustainability Report published on our company website for performance highlights and additional
information. Information contained in our Sustainability Report is not incorporated by reference into, and does not
constitute a part of, this Annual Report on Form 10-K.

A premier, sustainable portfolio of assets – As discussed in the next section of this Annual Report, we own a
portfolio of assets located in the United States. We strive to own premier assets capable of generating cash flows in
excess of our capital and operating requirements, as well as competitive rates of return. We also desire to own a
portfolio of assets that can provide a production growth platform extending many years into the future. Due to the
strength of oil prices relative to natural gas, we have been positioning our portfolio to be more heavily weighted to
U.S. oil assets in recent years.

During 2019, we completed our transition to a U.S. oil company. We sold our Canadian business, generating
$2.6 billion in proceeds, and announced the sale of our Barnett Shale assets for approximately $770 million, before
purchase price adjustments. As a result of these divestitures, we expect our oil production growth, price realizations
and field-level margins will all improve, as we sharpen our focus on four U.S. oil plays located in the Delaware
Basin, STACK, Powder River Basin and Eagle Ford.

Superior execution – As we pursue cash flow growth, we continually work to optimize the efficiency of our

capital programs and production operations, with an underlying objective of reducing absolute and per unit costs and
enhancing our returns. We also strive to leverage our culture of health, safety and environmental stewardship in all
aspects of our business.

Throughout 2019, we continued to achieve efficiency gains in various aspects of our business. Our initial

production rates from new wells continued to improve in our four U.S. oil plays and have exceeded the average of
the top 40 U.S. producers since 2015 by more than 40%. We continued to improve cycle times, incorporate
production optimization strategies and other cost reduction initiatives, driving down breakeven costs across our
portfolio of assets.

As we focus on a more streamlined portfolio of U.S. oil assets, we are aggressively pursuing an improved cost

structure to further expand margins. We have realized annualized cost savings by reducing well costs, production
expense, financing costs and G&A costs.

Financial strength and flexibility – Commodity prices are uncertain and volatile, so we strive to maintain a
strong balance sheet, as well as adequate liquidity and financial flexibility, in order to operate competitively in all
commodity price cycles. Our capital allocation decisions are made with attention to these financial stewardship
principles, as well as the priorities of funding our core operations, protecting our investment-grade credit ratings,
and paying and growing our shareholder dividend.

During 2019, we reduced our consolidated debt by $1.7 billion, primarily from proceeds from our divestitures.

We also raised our quarterly dividend 12.5% and repurchased 69 million shares of common stock under our share
repurchase program.

Oil and Gas Properties

Canadian Business and Barnett Shale Assets – Discontinued Operations

As a result of our divestment of substantially all of our oil and gas assets and operations in Canada, as well as
the recently announced divestiture of our Barnett Shale assets, amounts associated with these assets are presented as
discontinued operations. Therefore, financial and operational data, such as reserves, production, wells and acreage,
provided in this document exclude amounts related to our Canadian and Barnett Shale assets unless otherwise noted.
Included within the amounts presented as discontinued operations associated with the Barnett Shale are properties
divested in previous reporting periods located primarily in Johnson and Wise counties, Texas. For additional
information, please see Note 2 in “Item 8. Financial Statements and Supplementary Data” of this report.

Property Profiles

Key summary data from each of our areas of operation as of and for the year ended December 31, 2019 are

detailed in the map below.

Powder River Basin

(cid:131) 23 MBoe/d (74% oil)

(cid:131) 7% of production

(cid:131) 49 MMBoe of proved reserves

(cid:131) 6% of proved reserves

(cid:131) 46 gross wells drilled

Delaware Basin

(cid:131) 127 MBoe/d (55% oil)

(cid:131) 39% of production

(cid:131) 257 MMBoe of proved reserves

(cid:131) 34% of proved reserves

(cid:131) 123 gross wells drilled

STACK

(cid:131) 119 MBoe/d (56% liquids)

(cid:131) 36% of production

(cid:131) 358 MMBoe of proved reserves

(cid:131) 47% of proved reserves

(cid:131) 75 gross wells drilled

Eagle Ford

(cid:131) 47 MBoe/d (49% oil)

(cid:131) 15% of production

(cid:131) 55 MMBoe of proved reserves

(cid:131) 7% of proved reserves

(cid:131) 12 gross wells drilled

Delaware Basin – The Delaware Basin is Devon’s most active program in the portfolio. Through capital-

efficient growth, it offers exploration and low-risk development opportunities from many geologic reservoirs and
play types, including the oil-rich Bone Spring, Wolfcamp and Leonard formations. With a significant inventory of
oil and liquids-rich drilling opportunities that have multi-zone development potential, Devon has a robust platform
to deliver high-margin growth for many years to come. At December 31, 2019, we had eight operated rigs
developing this asset. In 2020, we plan to invest approximately $1.0 billion of capital in the Delaware Basin, making
it the top-funded asset in the portfolio.

STACK – The STACK development, located primarily in Oklahoma’s Canadian, Kingfisher and Blaine
counties, provides long-term optionality through its significant inventory. Our STACK position is one of the largest
in the industry, providing visible long-term production. In December 2019, we announced an agreement with Dow
to jointly develop a portion of our STACK acreage. Dow will fund approximately 65% of the partnership capital
requirements through a drilling carry of $100 million over the next four years. In 2020, we plan approximately $75
million of capital investment.

Powder River Basin – This asset is focused on emerging oil opportunities in the Powder River Basin. Recent

drilling success in this basin has expanded our drilling inventory, and we expect further growth as we accelerate
activity and continue to de-risk this emerging light-oil opportunity. As of December 31, 2019, we had three operated
rigs targeting the Turner, Parkman, Teapot and Niobrara formations in northern Converse County, Wyoming of the
Powder River Basin. In 2020, we plan approximately $350 million of capital investment.

Eagle Ford – We acquired our position in the Eagle Ford in 2014. Since acquiring these assets, we have
delivered tremendous results driven by our development in DeWitt County, Texas located in the economic core of
the play. Our Eagle Ford production is leveraged to oil and has low-cost access to premium Gulf Coast pricing,
providing for solid operating margins. Our Eagle Ford assets generated substantial cash flow in 2019. In 2020, we
plan approximately $300 million of capital investment.

Proved Reserves

Proved oil and gas reserves are those quantities of oil, gas and NGLs which can be estimated with reasonable

certainty to be economically producible from known reservoirs under existing economic conditions, operating
methods and government regulations. To be considered proved, oil and gas reserves must be economically
producible before contracts providing the right to operate expire, unless evidence indicates that renewal is
reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be
reasonably certain that it will commence the project within a reasonable time. For estimates of our proved developed
and proved undeveloped reserves and the discussion of the contribution by each property, see Note 21 in “Item 8.
Financial Statements and Supplementary Data” of this report.

The process of estimating oil, gas and NGL reserves is complex and requires significant judgment, as
discussed in “Item 1A. Risk Factors” of this report. As a result, we have developed internal policies for estimating
and recording reserves in compliance with applicable SEC definitions and guidance. Our policies assign
responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the “Group”). The Group,
which is led by Devon’s Director of Reserves and Economics, is responsible for the internal review and certification
of reserves estimates. We ensure the Director and key members of the Group have appropriate technical
qualifications to oversee the preparation of reserves estimates and are independent of the operating groups. The
Director of the Group has over 30 years of industry experience, a degree in engineering and is a registered
professional engineer. The Group also oversees audits and reserves estimates performed by qualified third-party
petroleum consulting firms. During 2019, we engaged LaRoche Petroleum Consultants, Ltd. to audit approximately
85% of our proved reserves. Additionally, we have a Reserves Committee that provides additional oversight of our
reserves process. The committee consists of five independent members of our Board of Directors with education or
business backgrounds relevant to the reserves estimation process.

The following tables present production, price and cost information for each significant field.

Year Ended December 31,
2019

STACK
Delaware Basin
U.S.

2018

STACK
Delaware Basin
U.S.

2017

STACK
Delaware Basin
U.S.

Oil (MMBbls)

Gas (Bcf)

NGLs (MMBbls)

Total (MMBoe)

Production

114
65
219

121
42
206

107
37
189

13
10
28

14
6
26

11
4
21

43
46
119

45
30
108

38
23
95

11
26
55

12
16
47

9
12
42

Year Ended December 31,
2019 (1)

STACK
Delaware Basin
U.S.
2018 (1)

STACK
Delaware Basin
U.S.

2017

STACK
Delaware Basin
U.S.

$
$
$

Average Sales Price (1)

Oil (Per Bbl)

Gas (Per Mcf)

NGLs (Per Bbl)

Production Cost
(Per Boe) (1)(2)

55.13 $
54.01 $
54.73 $

63.81 $
57.24 $
61.96 $

48.43 $
48.38 $
49.41 $

1.97 $
0.99 $
1.79 $

2.29 $
1.80 $
2.34 $

2.40 $
2.43 $
2.57 $

15.90 $
13.54 $
15.21 $

25.53 $
24.05 $
25.47 $

17.78 $
16.44 $
16.74 $

7.36
6.43
7.75

7.16
8.15
8.22

4.72
8.19
6.49

(1) As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report,
starting in 2018 the presentation of certain processing arrangements changed from a net to a gross
presentation, which resulted in an increase to our upstream revenues and production expenses with no
impact to net earnings. These changes primarily related to our STACK properties.
(2) Represents production expense per Boe excluding production and property taxes.

Drilling Statistics

The following table summarizes our development and exploratory drilling results in the U.S.

Year Ended December 31,
2019
2018
2017

Development Wells (1) Exploratory Wells (1)
Productive Dry

Productive Dry

Total Wells (1)

Productive Dry

Total

161.7 —
154.9
3.1
145.8 —

27.2 —
69.4 —
44.0 —

188.9 — 188.9
224.3
3.1 227.4
189.8 — 189.8

(1) Well counts represent net wells completed during each year. Net wells are gross wells multiplied by our

fractional working interests.

As of December 31, 2019, there were 132 gross and 95.3 net wells that have been spud and are in the process

of drilling, completing or waiting on completion. Gross wells are the sum of all wells in which we own a working
interest. Net wells are gross wells multiplied by our fractional working interests in each well.

Productive Wells

The following table sets forth our producing wells as of December 31, 2019.

U.S.

Oil Wells

Natural Gas Wells

Total Wells

Gross (1)(3)

Net (2)

Gross (1)(3)

Net (2)

Gross (1)(3)

Net (2)

7,739

2,376

3,138

1,281

10,877

3,657

(1) Gross wells are the sum of all wells in which we own a working interest.
(2) Net wells are gross wells multiplied by our fractional working interests in each well.
(3)

Includes 63 and 85 gross oil and gas wells, respectively, which had multiple completions.

The day-to-day operations of oil and gas properties are the responsibility of an operator designated under

pooling or operating agreements. The operator supervises production, maintains production records, employs field
personnel and performs other functions. We are the operator of approximately 3,955 gross wells. As operator, we
receive reimbursement for direct expenses incurred to perform our duties, as well as monthly per-well producing,
drilling, and construction overhead reimbursement at rates customarily charged in the respective areas. In presenting
our financial data, we record the monthly overhead reimbursements as a reduction of G&A, which is a common
industry practice.

Acreage Statistics

The following table sets forth our developed and undeveloped lease and mineral acreage as of December 31,
2019. Of our 1.8 million net acres, approximately 1.1 million acres are held by production and approximately 20%
are located on federal lands. The acreage in the table includes approximately 0.1 million net acres subject to leases
that are scheduled to expire during 2020, 2021 and 2022. As of December 31, 2019, there were no proved
undeveloped reserves associated with our expiring acreage. Of the 0.1 million net acres set to expire by
December 31, 2022, we anticipate performing operational and administrative actions to continue the lease terms for
portions of the acreage that we intend to further assess. However, we do expect to allow a portion of the acreage to
expire in the normal course of business. In 2019, we allowed approximately 0.1 million acres to expire.

U.S.

1,055

576

2,956

1,272

4,011

1,848

Developed

Undeveloped

Total

Gross (1)

Net (2)

Gross (1)

Net (2)

Gross (1)

Net (2)

(Thousands)

(1) Gross acres are the sum of all acres in which we own a working interest.
(2) Net acres are gross acres multiplied by our fractional working interests in the acreage.

Title to Properties

Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for taxes

not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from
the value of properties or from the respective interests therein or materially interfere with their use in the operation
of the business.

As is customary in the industry, a preliminary title investigation, typically consisting of a review of local title

records, is made at the time of acquisitions of undeveloped properties. More thorough title investigations, which
generally include a review of title records and the preparation of title opinions by outside legal counsel, are made
prior to the consummation of an acquisition of producing properties and before commencement of drilling
operations on undeveloped properties.

Marketing Activities

Oil, Gas and NGL Marketing

The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As

detailed below, we sell our production under both long-term (one year or more) and short-term (less than one year)
agreements at prices negotiated with third parties. Regardless of the term of the contract, the vast majority of our
production is sold at variable, or market-sensitive, prices.

Additionally, we may enter into financial hedging arrangements or fixed-price contracts associated with a
portion of our oil, gas and NGL production. These activities are intended to support targeted price levels and to
manage our exposure to price fluctuations. See Note 3 in “Item 8. Financial Statements and Supplementary Data” of
this report for further information.

As of January 2020, our production was sold under the following contract terms.

Oil
Natural gas
NGLs

Delivery Commitments

Short-Term

Long-Term

Variable

Fixed

Variable

Fixed

64%
64%
38%

—
3%
28%

36%
33%
34%

—
—
—

A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed
and determinable quantity. As of December 31, 2019, we were committed to deliver the following fixed quantities
of production.

Natural gas (Bcf)
NGLs (MMBbls)
Total (MMBoe)

Total

Less Than 1 Year

1-3 Years

3-5 Years

273
8
53

128
8
29

94
—
16

More Than 5 Years
14
—
2

37
—
6

We expect to fulfill our delivery commitments primarily with production from our proved developed reserves.

Moreover, our proved reserves have generally been sufficient to satisfy our delivery commitments during the three
most recent years, and we expect such reserves will continue to be the primary means of fulfilling our future
commitments. However, where our proved reserves are not sufficient to satisfy our delivery commitments, we can
and may use spot market purchases to satisfy the commitments.

Customers

During 2019 and 2017, no purchaser accounted for over 10% of our consolidated sales revenue.

During 2018, we had one purchaser that accounted for approximately 11% of our consolidated sales revenue.

Competition

See “Item 1A. Risk Factors.”

Public Policy and Government Regulation

Our industry is subject to a wide range of regulations. Laws, rules, regulations, taxes, fees and other policy

implementation actions affecting our industry have been pervasive and are under constant review for amendment or
expansion. Numerous government agencies have issued extensive regulations which are binding on our industry and
its individual members, some of which carry substantial penalties for failure to comply. These laws and regulations
increase the cost of doing business and consequently affect profitability. Because public policy changes are
commonplace, and existing laws and regulations are frequently amended, we are unable to predict the future cost or
impact of compliance. However, we do not expect that any of these laws and regulations will affect our operations
materially differently than they would affect other companies with similar operations, size and financial strength.
The following are significant areas of government control and regulation affecting our operations.

Exploration and Production Regulation

Our operations are subject to federal, state and local laws and regulations. These laws and regulations relate to

matters that include:

•

acquisition of seismic data;

location, drilling and casing of wells;

•

well design;

hydraulic fracturing;

well production;

spill prevention plans;

emissions and discharge permitting;

use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;

surface usage and the restoration of properties upon which wells have been drilled;

calculation and disbursement of royalty payments and production taxes;

plugging and abandoning of wells;

transportation of production; and

endangered species and habitat.

Our operations also are subject to conservation regulations, including the regulation of the size of drilling and

spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable
from oil and gas wells; and the unitization or pooling of oil and gas properties. In the U.S., some states allow the
forced pooling or unitization of tracts to facilitate exploration, while other states rely on voluntary pooling of lands
and leases, which may make it more difficult to develop oil and gas properties. In addition, federal and state
conservation laws generally limit the venting or flaring of natural gas, and state conservation laws impose certain
requirements regarding the ratable purchase of production. These regulations limit the amounts of oil and gas we can
produce from our wells and the number of wells or the locations at which we can drill.

Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and
administered by the BLM or Bureau of Indian Affairs of the Department of the Interior. Such leases require
compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations
on lands covered by these leases and calculation and disbursement of royalty payments to the federal government,
tribes or tribal members. The federal government has, from time to time, evaluated and, in some cases, promulgated
new rules and regulations regarding competitive lease bidding, venting and flaring, oil and gas measurement and
royalty payment obligations for production from federal lands. In addition, permitting activities on federal lands can
sometimes be subject to delays.

Environmental, Pipeline Safety and Occupational Regulations

We strive to conduct our operations in a socially and environmentally responsible manner, which includes
compliance with applicable law. We are subject to many federal, state, and local laws and regulations concerning
occupational safety and health as well as the discharge of materials into, and the protection of, the environment and
natural resources. Environmental laws and regulations relate to:

•

the discharge of pollutants into federal 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 monitoring, abandonment, reclamation and remediation of well and other sites, including sites of
former operations;

•

the development of emergency response and spill contingency plans;

the monitoring, repair and design of pipelines used for the transportation of oil and natural gas;

the protection of threatened and endangered species; and

worker protection.

Failure to comply with these laws and regulations can lead to the imposition of remedial liabilities,

administrative, civil or criminal fines or penalties or injunctions limiting our operations in affected areas. Moreover,
multiple environmental laws provide for citizen suits, which can allow environmental organizations to sue operators
for alleged violations of environmental law. Environmental organizations also can assert legal and administrative
challenges to certain actions of oil and gas regulators, such as the BLM, for allegedly failing to comply with
environmental laws, which can result in delays in obtaining permits or other necessary authorizations.
Environmental protection and health and safety compliance are necessary, manageable parts of our business. We
have been able to plan for and comply with environmental, safety and health initiatives without materially altering
our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and
increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the
environment and safety and health compliance have increased over the years and may continue to increase.

Item 1A. Risk Factors

Our business and operations, and our industry in general, are subject to a variety of risks. The risks described
below may not be the only risks we face, as our business and operations may also be subject to risks that we do not
yet know of, or that we currently believe are immaterial. If any of the following risks should occur, our business,
financial condition, results of operations and liquidity could be materially and adversely impacted. As a result,
holders of our securities could lose part or all of their investment in Devon.

Volatile Oil, Gas and NGL Prices Significantly Impact Our Business

Our financial condition, results of operations and the value of our properties are highly dependent on the
general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of
these commodities. Historically, market prices and our realized prices have been volatile. For example, over the last
five years, NYMEX WTI oil and NYMEX Henry Hub prices ranged from highs of over $75 per Bbl and $4.80 per
MMBtu, respectively, to lows of under $27 per Bbl and $1.70 per MMBtu, respectively. Such volatility is likely to
continue in the future due to numerous factors beyond our control, including, but not limited to:

•

the domestic and worldwide supply of and demand for oil, gas and NGLs;

volatility and trading patterns in the commodity-futures markets;

conservation and environmental protection efforts;

production levels of members of OPEC, Russia, the U.S. or other producing countries;

geopolitical risks, including political and civil unrest in the Middle East, Africa and South America;

adverse weather conditions, natural disasters, public health crises and other catastrophic events, such as
tornadoes, earthquakes, hurricanes and epidemics of infectious diseases;

regional pricing differentials, including in the Delaware Basin and other areas of our operations;

differing quality of production, including NGL content of gas produced;

the level of imports and exports of oil, gas and NGLs and the level of global oil, gas and NGL
inventories;

the price and availability of alternative energy sources;

technological advances affecting energy consumption and production, including with respect to electric
vehicles;

•

stockholder activism or activities by non-governmental organizations to restrict the exploration and
production of oil and natural gas in order to reduce greenhouse gas emissions;

the overall economic environment;

changes in trade relations and policies, including the imposition of tariffs by the U.S. or China; and

other governmental regulations and taxes.

Estimates of Oil, Gas and NGL Reserves Are Uncertain and May Be Subject to Revision

The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the

evaluation of available geological, engineering and economic data for each reservoir, particularly for new
discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different
estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a
given reservoir may change substantially over time as a result of several factors, including additional development
and appraisal activity, the viability of production under varying economic conditions, including commodity price
declines, and variations in production levels and associated costs. Consequently, material revisions to existing
reserves estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could
have an adverse effect on our financial condition and the value of our properties, as well as the estimates of our
future net revenue and profitability. Our policies and internal controls related to estimating and recording reserves
are included in “Items 1 and 2. Business and Properties” of this report.

Discoveries or Acquisitions of Reserves Are Needed to Avoid a Material Decline in Reserves and Production

The production rates from oil and gas properties generally decline as reserves are depleted, while related per

unit production costs generally increase due to decreasing reservoir pressures and other factors. Moreover, our
current development activity is focused on unconventional oil and gas assets, which generally have significantly
higher decline rates as compared to conventional assets. Therefore, our estimated proved reserves and future oil, gas
and NGL production will decline materially as reserves are produced unless we conduct successful exploration and
development activities, such as identifying additional producing zones in existing wells, utilizing secondary or
tertiary recovery techniques or acquiring additional properties containing proved reserves. Consequently, our future
oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in
finding or acquiring additional reserves.

Our Operations Are Uncertain and Involve Substantial Costs and Risks

Our operating activities are subject to numerous costs and risks, including the risk that we will not encounter
commercially productive oil or gas reservoirs. Drilling for oil, gas and NGLs can be unprofitable, not only from dry
holes, but from productive wells that do not return a profit because of insufficient revenue from production or high
costs. Substantial costs are required to locate, acquire and develop oil and gas properties, and we are often uncertain
as to the amount and timing of those costs. Our cost of drilling, completing, equipping and operating wells is often
uncertain before drilling commences. Declines in commodity prices and overruns in budgeted expenditures are
common risks that can make a particular project uneconomic or less economic than forecasted. While both
exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of
dry holes or failure to find commercial quantities of hydrocarbons. In addition, our oil and gas properties can
become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may
increase as a result of a variety of factors, including, but not limited to:

•

unexpected drilling conditions, pressure conditions or irregularities in reservoir formations;

equipment failures or accidents;

fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground
migration of fluids and chemicals;

•

adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and
extreme temperatures;

issues with title or in receiving governmental permits or approvals;

restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or
constrained downstream markets;

environmental hazards or liabilities;

restrictions in access to, or disposal of, water used or produced in drilling and completion operations;
and

shortages or delays in the availability of services or delivery of equipment.

The occurrence of one or more of these factors could result in a partial or total loss of our investment in a
particular property, as well as significant liabilities. Moreover, certain of these events could result in environmental
pollution and impact to third parties, including persons living in proximity to our operations, our employees and
employees of our contractors, leading to possible injuries, death or significant damage to property and natural
resources. For example, we have from time to time experienced well-control events that have resulted in various
remediation and clean-up costs and certain of the other impacts described above.

In addition, we rely on our employees, consultants and sub-contractors to conduct our operations in
compliance with applicable laws and standards. Any violation of such laws or standards by these individuals,
whether through negligence, harassment, discrimination or other misconduct, could result in significant liability for
us and adversely affect our business. For example, negligent operations by employees could result in serious injury,
death or property damage, and sexual harassment or racial and gender discrimination could result in legal claims and
reputational harm.

We Are Subject to Extensive Governmental Regulation, Which Can Change and Could Adversely Impact
Our Business

Our operations are subject to extensive federal, state, local and other laws, rules and regulations, including

with respect to environmental matters, worker health and safety, wildlife conservation, the gathering and
transportation of oil, gas and NGLs, conservation policies, reporting obligations, royalty payments, unclaimed
property and the imposition of taxes. Such regulations include requirements for permits to drill and to conduct other
operations and for provision of financial assurances (such as bonds) covering drilling, completion and well
operations and decommissioning obligations. If permits are not issued, or if unfavorable restrictions or conditions
are imposed on our drilling or completion activities, we may not be able to conduct our operations as planned. In
addition, we may be required to make large expenditures to comply with applicable governmental laws, rules,
regulations, permits or orders. For example, certain regulations require the plugging and abandonment of wells and
removal of production facilities by current and former operators, including corporate successors of former operators.
These requirements may result in significant costs associated with the removal of tangible equipment and other
restorative actions.

In addition, changes in public policy have affected, and in the future could further affect, our operations.
Regulatory and public policy developments could, among other things, restrict production levels, impose price
controls, change environmental protection requirements and increase taxes, royalties and other amounts payable to
governments or governmental agencies. Our operating and other compliance costs could increase further if existing
laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our
operations. In addition, changes in public policy may indirectly impact our operations by, among other things,
increasing the cost of supplies and equipment and fostering general economic uncertainty. For example, changes in
U.S. trade relations, particularly the imposition of tariffs by the U.S. and China, may increase the cost of materials
we or our vendors use, thereby increasing our operating expense. Although we are unable to predict changes to
existing laws and regulations, such changes could significantly impact our profitability, financial condition and
liquidity, particularly changes related to hydraulic fracturing, environmental matters more generally, seismic activity
and income taxes, as discussed below.

Hydraulic Fracturing – In recent years, various federal agencies have asserted regulatory authority over

certain aspects of the hydraulic fracturing process. For example, the EPA has issued regulations under the federal
Clean Air Act establishing performance standards for oil and gas activities, including standards for the capture of air
emissions released during hydraulic fracturing, and it finalized in 2016 regulations that prohibit the discharge of
wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. The EPA also
released a report in 2016 finding that certain aspects of hydraulic fracturing, such as water withdrawals and
wastewater management practices, could result in impacts to water resources. The BLM previously finalized
regulations to regulate hydraulic fracturing on federal lands but subsequently issued a repeal of those regulations in
2017. Moreover, several states in which we operate have adopted, or stated intentions to adopt, laws or regulations
that mandate further restrictions on hydraulic fracturing, such as requiring disclosure of chemicals used in hydraulic
fracturing, imposing more stringent permitting, disclosure and well-construction requirements on hydraulic
fracturing operations and establishing standards for the capture of air emissions released during hydraulic fracturing.
In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general or
hydraulic fracturing in particular.

Beyond these regulatory efforts, various policy makers, regulatory agencies and political candidates at the

federal, state and local levels have proposed implementing even further restrictions on hydraulic fracturing,
including prohibiting the technology outright. For example, certain candidates running to be elected President of the
United States in 2020 have pledged to impose a ban on hydraulic fracturing. It is possible that any such restrictions
may particularly target industry activity on federal lands, which could adversely impact our operations in the
Delaware and Powder River Basins, as well as other areas where we operate under federal leases. As of
December 31, 2019, approximately 20% of our total leasehold resides on federal lands, and approximately 40% and
60% of our leasehold in the Delaware and Powder River Basins, respectively, resides on federal lands. Although it
is not possible at this time to predict the outcome of these or other proposals, any new restrictions on hydraulic
fracturing that may be imposed in areas in which we conduct business could potentially result in increased
compliance costs, delays or cessation in development or other restrictions on our operations.

Environmental Laws Generally – In addition to regulatory efforts focused on hydraulic fracturing, we are
subject to various other federal, state and local laws and regulations relating to discharge of materials into, and
protection of, the environment. These laws and regulations may, among other things, impose liability on us for the
cost of remediating pollution that results from our operations. Environmental laws may impose strict, joint and
several liability, and failure to comply with environmental laws and regulations can result in the imposition of
administrative, civil or criminal fines and penalties, as well as injunctions limiting operations in affected areas. Any
future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by
several factors, including future changes to regulatory requirements. Any such changes could have a significant
impact on our operations and profitability.

Seismic Activity – Earthquakes in northern and central Oklahoma and elsewhere have prompted concerns
about seismic activity and possible relationships with the oil and gas industry. Legislative and regulatory initiatives
intended to address these concerns may result in additional levels of regulation or other requirements that could lead
to operational delays, increase our operating and compliance costs or otherwise adversely affect our operations. In
addition, we are currently defending against certain third-party lawsuits and could be subject to additional claims,
seeking alleged property damages or other remedies as a result of alleged induced seismic activity in our areas of
operation.

Changes to Tax Laws – We are subject to U.S. federal income tax as well as income or capital taxes in various

state and foreign jurisdictions, and our operating cash flow is sensitive to the amount of income taxes we must pay.
In the jurisdictions in which we operate, income taxes are assessed on our earnings after consideration of all
allowable deductions and credits. Changes in the types of earnings that are subject to income tax, the types of costs
that are considered allowable deductions or the rates assessed on our taxable earnings would all impact our income
taxes and resulting operating cash flow.

Concerns About Climate Change and Related Regulatory, Social and Market Actions May Adversely Affect
Our Business

Continuing and increasing political and social attention to the issue of climate change has resulted in

legislative, regulatory and other initiatives, including international agreements, to reduce greenhouse gas emissions,
such as carbon dioxide and methane. Policy makers at both the U.S. federal and state levels have introduced
legislation and proposed new regulations designed to quantify and limit the emission of greenhouse gases. For
example, both the EPA and the BLM have issued regulations for the control of methane emissions, which also
include leak detection and repair requirements, for the oil and gas industry. Following the change in presidential
administrations, however, the agencies have attempted to revise or rescind their previously issued methane
standards. Litigation concerning these methane regulations and subsequent attempts to revise or rescind them is
ongoing. Nevertheless, several states where we operate, including Wyoming and New Mexico, have already
imposed, or stated intentions to impose, laws or regulations designed to reduce methane emissions from oil and gas
exploration and production activities. With respect to more comprehensive regulation, policy makers and political
candidates have made, or expressed support for, a variety of proposals, such as the development of cap-and-trade or
carbon tax programs, as well as the more sweeping “green new deal” resolutions introduced in Congress in early
2019. As generally proposed, a cap-and-trade program would cap overall greenhouse gas emissions on an economy-
wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender
emission allowances, while a carbon tax could impose taxes based on emissions from our operations and
downstream uses of our products. The “green new deal” resolutions call for a 10-year national mobilization effort
to, among other things, transition 100% of power demand in the U.S. to zero-emission sources and overhaul
transportation systems in the U.S. to remove greenhouse gas emissions as much as is technologically feasible.

In addition to regulatory risk, other market and social initiatives resulting from the changing perception of

climate change present risks for our business. For example, in an effort to promote a lower-carbon economy, there
are various public and private initiatives subsidizing the development and adoption of alternative energy sources and
technologies, including by mandating the use of specific fuels or technologies. These initiatives may reduce the
competitiveness of carbon-based fuels, such as oil and gas. Moreover, certain financial institutions, funds and other
sources of capital have begun restricting or eliminating their investment in oil and natural gas activities due to their
concern regarding climate change. Such restrictions in capital could decrease the value of our business and make it
more difficult to fund our operations. Finally, governmental entities and other plaintiffs have brought, and may
continue to bring, claims against us and other oil and gas companies for purported damages caused by the alleged
effects of climate change. These and the other regulatory, social and market risks relating to climate change
described above could result in unexpected costs, increase our operating expense and reduce the demand for our
products, which in turn could lower the value of our reserves and have an adverse effect on our profitability,
financial condition and liquidity.

Our Hedging Activities Limit Participation in Commodity Price Increases and Involve Other Risks

We enter into financial derivative instruments with respect to a portion of our production to manage our

exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to
protect ourselves from commodity price declines, we will be prevented from fully realizing the benefits of
commodity price increases above the prices established by our hedging contracts. In addition, our hedging
arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the
contract counterparties fail to perform under the contracts. Moreover, as a result of the Dodd-Frank Wall Street
Reform and Consumer Protection Act and other legislation and regulation, hedging transactions and many of our
contract counterparties have become subject to increased governmental oversight and regulations in recent
years. Although we cannot predict the ultimate impact of these laws and the related rulemaking, some of which is
ongoing, existing or future regulations may adversely affect the cost and availability of our hedging arrangements.

The Credit Risk of Our Counterparties Could Adversely Affect Us

We enter into a variety of transactions that expose us to counterparty credit risk. For example, we have
exposure to financial institutions and insurance companies through our hedging arrangements, our syndicated
revolving credit facility and our insurance policies. Disruptions in the financial markets or otherwise may impact
these counterparties and affect their ability to fulfill their existing obligations and their willingness to enter into
future transactions with us.

In addition, we are exposed to the risk of financial loss from trade, joint interest billing and other receivables.

We sell our oil, gas and NGLs to a variety of purchasers, and, as an operator, we pay expenses and bill our non-
operating partners for their respective share of costs. We also frequently look to buyers of oil and gas properties
from us or our predecessors to perform certain obligations associated with the disposed assets, including the removal
of production facilities and plugging and abandonment of wells. Certain of these counterparties or their successors
may experience insolvency, liquidity problems or other issues and may not be able to meet their obligations and
liabilities (including contingent liabilities) owed to, and assumed from, us, particularly during a depressed or volatile
commodity price environment. Any such default may result in us being forced to cover the costs of those obligations
and liabilities, which could adversely impact our financial results and condition.

Our Debt May Limit Our Liquidity and Financial Flexibility, and Any Downgrade of Our Credit Rating
Could Adversely Impact Us

As of December 31, 2019, we had total indebtedness of $4.3 billion. Our indebtedness and other financial

commitments have important consequences to our business, including, but not limited to:

•

requiring us to dedicate a portion of our cash flows from operations to debt service payments, thereby
limiting our ability to fund working capital, capital expenditures, investments or acquisitions and other
general corporate purposes;

increasing our vulnerability to general adverse economic and industry conditions, including low
commodity price environments; and

limiting our ability to obtain additional financing due to higher costs and more restrictive covenants.

In addition, we receive credit ratings from rating agencies in the U.S. with respect to our debt. Factors that

may impact our credit ratings include, among others, debt levels, planned asset sales and purchases, liquidity,
forecasted production growth and commodity prices. We are currently required to provide letters of credit or other
assurances under certain of our contractual arrangements. Any credit downgrades could adversely impact our ability
to access financing and trade credit, require us to provide additional letters of credit or other assurances under
contractual arrangements and increase our interest rate under any credit facility borrowing as well as the cost of any
other future debt.

Cyber Attacks May Adversely Impact Our Operations

Our business has become increasingly dependent on digital technologies, and we anticipate expanding the use

of technology in our operations, including through artificial intelligence, process automation and data analytics.
Concurrent with this growing dependence on technology is greater sensitivity to cyber attack related activities,
which have frequently targeted our industry. Cyber attackers often attempt to gain unauthorized access to digital
systems for purposes of misappropriating sensitive information, intellectual property or financial assets, corrupting
data or causing operational disruptions as well as to prevent users from accessing systems or information and
demand payment in order to regain access. These attacks may be perpetrated by third parties or insiders. Techniques
used in these attacks often range from highly sophisticated efforts to electronically circumvent network security to
more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain
access. Cyber attacks may also be performed in a manner that does not require gaining unauthorized access, such as
by causing denial-of-service attacks. In addition, our vendors, midstream providers and other business partners may
separately suffer disruptions or breaches from cyber attacks, which, in turn, could adversely impact our operations
and compromise our information. Although we have not suffered material losses related to cyber attacks to date, if
we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative
consequences, including litigation risks. Moreover, as the sophistication of cyber attacks continues to evolve, we
may be required to expend significant additional resources to further enhance our digital security or to remediate
vulnerabilities.

We Have Limited Control Over Properties Operated by Others

Certain of the properties in which we have an interest are operated by other companies and involve third-party

working interest owners. We have limited influence and control over the operation or future development of such
properties, including compliance with environmental, health and safety regulations or the amount and timing of
required future capital expenditures. These limitations and our dependence on the operator and other working
interest owners for these properties could result in unexpected future costs and delays, curtailments or cancellations
of operations or future development, which could adversely affect our financial condition and results of operations.

Midstream Capacity Constraints and Interruptions Impact Commodity Sales

We rely on midstream facilities and systems owned and operated by others to process our gas production and

to transport our oil, gas and NGL production to downstream markets. All or a portion of our production in one or
more regions may be interrupted or shut in from time to time due to losing access to plants, pipelines or gathering
systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions and
natural disasters, accidents, field labor issues or strikes. Additionally, the midstream operators may be subject to
constraints that limit their ability to construct, maintain or repair midstream facilities needed to process and transport
our production. Such interruptions or constraints could negatively impact our production and associated profitability.

Insurance Does Not Cover All Risks

As discussed above, our business is hazardous and is subject to all of the operating risks normally associated
with the exploration, development and production of oil, gas and NGLs. To mitigate financial losses resulting from
these operational hazards, we maintain comprehensive general liability insurance, as well as insurance coverage
against certain losses resulting from physical damages, loss of well control, business interruption and pollution
events that are considered sudden and accidental. We also maintain workers’ compensation and employer’s liability
insurance. However, our insurance coverage does not provide 100% reimbursement of potential losses resulting
from these operational hazards. Additionally, we have limited or no insurance coverage for a variety of other risks,
including pollution events that are considered gradual, war and political risks and fines or penalties assessed by
governmental authorities. The occurrence of a significant event against which we are not fully insured could have an
adverse effect on our profitability, financial condition and liquidity.

Competition for Assets, Materials, People and Capital Can Be Significant

Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and

independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the
equipment and personnel required to explore, develop and operate properties. Typically, during times of rising
commodity prices, drilling and operating costs will also increase. During these periods, there is often a shortage of
drilling rigs and other oilfield services, which could adversely affect our ability to execute our development plans on
a timely basis and within budget. Competition is also prevalent in the marketing of oil, gas and NGLs. Certain of our
competitors have financial and other resources substantially greater than ours and may have established superior
strategic long-term positions and relationships, including with respect to midstream take-away capacity. As a
consequence, we may be at a competitive disadvantage in bidding for assets or services and accessing capital and
downstream markets. In addition, many of our larger competitors may have a competitive advantage when
responding to factors that affect demand for oil and gas production, such as changing worldwide price and
production levels, the cost and availability of alternative energy sources and the application of government
regulations.

Our Business Could Be Adversely Impacted by Investors Attempting to Effect Change

Stockholder activism has been increasing in our industry, and investors may from time to time attempt to

effect changes to our business or governance, whether by stockholder proposals, public campaigns, proxy
solicitations or otherwise. Such actions could adversely impact our business by distracting our board of directors and
employees from core business operations, requiring us to incur increased advisory fees and related costs, interfering

with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty
about the future direction of our business. Such perceived uncertainty may, in turn, make it more difficult to retain
employees and could result in significant fluctuation in the market price of our common stock.

Our Acquisition and Divestiture Activities Involve Substantial Risks

Our business depends, in part, on making acquisitions that complement or expand our current business and

successfully integrating any acquired assets or businesses. If we are unable to make attractive acquisitions, our
future growth could be limited. Furthermore, even if we do make acquisitions, they may not result in an increase in
our cash flow from operations or otherwise result in the benefits anticipated due to various risks, including, but not
limited to:

•

mistaken estimates or assumptions about reserves, potential drilling locations, revenues and costs,
including synergies and the overall costs of equity or debt;

difficulties in integrating the operations, technologies, products and personnel of the acquired assets or
business; and

unknown and unforeseen liabilities or other issues related to any acquisition for which contractual
protections prove inadequate, including environmental liabilities and title defects.

In addition, from time to time, we may sell or otherwise dispose of certain of our properties or businesses as a
result of an evaluation of our asset portfolio and to help enhance our liquidity. These transactions also have inherent
risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets or
business and potential post-closing claims for indemnification. Moreover, volatility in commodity prices may result
in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a
transaction prior to closing.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 3. Legal Proceedings

We are involved in various legal proceedings incidental to our business. However, to our knowledge as of the
date of this report, there were no material pending legal proceedings to which we are a party or to which any of our
property is subject.

On April 4, 2019, Devon Energy Production Company, L.P., a wholly-owned subsidiary of the Company
(“DEPCO”), agreed to settle its previously disclosed negotiations with the EPA relating to certain alleged Clean Air
Act violations at its Beaver Creek Gas Plant located near Riverton, Wyoming by executing an agreed order with the
EPA. The order included a penalty of $150,000 and was approved by the regional EPA judicial officer on June 12,
2019. Moreover, in connection with the resolution of this matter with the EPA, DEPCO entered into a consent
decree on May 9, 2019 with respect to the same matter with the Wyoming Department of Environmental Quality,
which also included a separate penalty of $150,000.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

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

Our common stock is traded on the NYSE under the “DVN” ticker symbol. On February 5, 2020, there were

6,771 holders of record of our common stock. We began paying regular quarterly cash dividends in the second
quarter of 1993. The declaration of future dividends is a business decision made by our Board of Directors, and will
depend on Devon’s financial condition and other relevant factors. Additional information on our dividends can be
found in Note 17 in “Item 8. Financial Statements and Supplementary Data” of this report.

Performance Graph

The following graph compares the cumulative TSR over a five-year period on Devon’s common stock with

the cumulative total returns of the S&P 500 Index and a peer group of companies to which we compare our
performance. The peer group includes Apache Corporation, Chesapeake Energy Corporation, Concho Resources,
Inc., ConocoPhillips, Continental Resources, Inc., Encana Corporation, EOG Resources, Inc., Hess Corporation,
Marathon Oil Corporation, Murphy Oil Corporation, Noble Energy, Inc., Occidental Petroleum Corporation and
Pioneer Natural Resources Company. Anadarko Petroleum Corporation was a part of this peer group prior to being
acquired by Occidental Petroleum Corporation in 2019. The graph was prepared assuming $100 was invested on
December 31, 2014 in Devon’s common stock, the peer group and the S&P 500 Index, and dividends have been
reinvested subsequent to the initial investment. Commencing in 2020, Devon will use a recalibrated peer group for
performance and compensation purposes. This new peer group was selected to better align with Devon’s go-forward
size and operations in light of our strategic transformation in 2019.

Comparison of 5-Year Cumulative Total Return
Devon, Peer Group and S&P 500 Index

$200
$180
$160
$140
$120
$100
$80
$60
$40
$20
$-

Devon
Peer Group
S&P 500

2014
$100.00
$100.00
$100.00

2015
$53.40
$71.04
$101.38

2016
$77.29
$93.91
$113.51

2017
$70.53
$95.41
$138.29

2018
$38.73
$81.36
$132.23

2019
$45.24
$79.90
$173.86

The graph and related information should not be deemed “soliciting material” or to be “filed” with the SEC,
nor should such information be incorporated by reference into any future filing under the Securities Act of 1933, as
amended, or the Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate
such information by reference into such a filing. The graph and information is included for historical comparative
purposes only and should not be considered indicative of future stock performance.

Issuer Purchases of Equity Securities

The following table provides information regarding purchases of our common stock that were made by us

during the fourth quarter of 2019 (shares in thousands).

Period
October 1 - October 31
November 1 - November 30
December 1 - December 31

Total

Total Number of
Shares Purchased (1)
4,285 $
218 $
9 $
4,512 $

Average Price
Paid per Share
21.27
22.33
22.58
21.32

Total Number of Shares
Purchased As Part of Publicly
Announced Plans or
Programs (2)

Maximum Dollar Value of
Shares that May Yet Be
Purchased Under the Plans or
Programs (2)

4,244 $
192 $
— $
4,436

199
195
1,000

(1)

In addition to shares purchased under the share repurchase program described below, these amounts also
included approximately 76,000 shares received by us from employees for the payment of personal income
tax withholding on vesting transactions.

(2) On March 7, 2018, we announced a $1.0 billion share repurchase program. On June 6, 2018, we announced

the expansion of this program to $4.0 billion. On February 19, 2019, we announced a further expansion to
$5.0 billion with a December 31, 2019 expiration date. Of the $5.0 billion authorized amount, $4.8 billion
was repurchased when the program expired on December 31, 2019. On December 17, 2019, we announced a
new $1.0 billion share repurchase program with a December 31, 2020 expiration date. Under the new
program, $800 million of the $1.0 billion authorization is conditioned upon the closing of the pending
Barnett Shale divestiture. During 2019, we repurchased 68.6 million shares of common stock for $1.8 billion,
or $26.62 per share. Future purchases under the program will be made in the open market, private
transactions or through the use of ASR programs.

Under the Devon Plan, eligible employees previously had the option to purchase shares of our common stock

through an investment in the Devon Stock Fund, which is administered by an independent trustee. Eligible
employees purchased approximately 27,000 shares of our common stock in 2019, at then-prevailing stock prices,
that they held through their ownership in the Devon Stock Fund. We acquired the shares of our common stock sold
under this plan through open-market purchases.

Item 6. Selected Financial Data

The financial information below should be read in conjunction with “Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary
Data” of this report.

2019

2018

2017

2016

2015

Statement of Earnings data:
Upstream revenues (1)
$ 3,355 $ 4,542 $ 2,988 $ 2,325 $ 4,082
Total revenues (1)
$ 6,220 $ 8,896 $ 6,501 $ 5,054 $ 7,547
Net earnings (loss) from continuing operations (2)
(871) $ (7,989)
$
Net earnings (loss) from continuing operations per share:

714 $

(79) $

33 $

Basic (2)
Diluted (2)

Cash dividends per common share
Balance Sheet data:
Total assets (3)
Long-term debt (4)
Stockholders' equity
Common shares outstanding

$ (0.21) $
$ (0.21) $
0.35 $
$

1.43 $
1.42 $
0.30 $

0.06 $ (1.72) $ (19.66)
0.06 $ (1.72) $ (19.66)
0.96
0.24 $

0.42 $

$ 13,717 $ 19,566 $ 30,241 $ 28,675 $ 29,673
$ 4,294 $ 4,292 $ 5,258 $ 5,359 $ 7,488
$ 5,920 $ 9,186 $ 14,104 $ 12,722 $ 11,111
418

525

523

450

382

(1)

In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers using the modified
retrospective method and has applied the standard to all existing contracts. The impact of adoption is further
discussed in Note 1 of “Item 8. Financial Statements and Supplementary Data” of this report. Prior periods
have not been restated.

(2) Material asset impairments and acquisition and divestiture activity had significant impacts on operating results
and the carrying value of our oil and gas assets. Specifically, there were asset impairments of $0.3 billion,
$0.2 billion, $0.5 billion and $10.3 billion in 2018, 2017, 2016 and 2015, respectively. More discussion on
these items can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations” and in Note 2 and Note 5 of “Item 8. Financial Statements and Supplementary Data” of
this report.

(3) Amounts include assets related to our divested Canadian business and aggregate ownership interest in EnLink

and the General Partner as well as our recently announced Barnett Shale assets that will be divested in 2020.
For additional information, see Note 18 of “Item 8. Financial Statements and Supplementary Data” of this
report. These divestitures resulted in the reclassification of the respective assets to assets associated with
discontinued operations, which are included within this amount.

(4) Long-term debt balance excludes amounts that were classified as liabilities associated with discontinued

operations in the respective periods related to the sale of Devon’s Canadian business and ownership interests
in EnLink and the General Partner. See Note 18 of “Item 8. Financial Statements and Supplementary Data” of
this report for additional details.

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

Introduction

The following discussion and analysis presents management’s perspective of our business, financial condition

and overall performance. This information is intended to provide investors with an understanding of our past
performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8.
Financial Statements and Supplementary Data” of this report.

Overview of 2019 Results

During 2019, we completed our transformation to a U.S. oil growth company with our exit from Canada and

pending sale of the Barnett Shale. These transactions accelerate efforts to focus exclusively on our resource-rich
U.S. oil portfolio, which provides us with a strong foundation to grow returns, margin and profitability. By operating
under a disciplined returns-driven strategy focused on delivering strong operational results, financial strength and
value to our shareholders and continuing our commitment to environmental, social and governance excellence, we
completed our transformation to “New Devon” and made significant progress toward our cost reduction objectives
as evidenced by these 2019 highlights:

•

Closed on the sale of our Canadian business for $2.6 billion ($3.4 billion Canadian dollars) in June
2019.

Announced the sale of our Barnett Shale assets for $770 million (expected closing in the second quarter
of 2020).

Completed workforce reduction and other cost reduction initiatives, reaching approximately $240
million of annualized G&A savings.

Improved capital efficiency by reducing capital expenditures approximately 10% and increasing oil
production 21% compared to 2018.

Retired $1.7 billion of senior notes, reducing annualized financing costs by $60 million.

Repurchased $4.8 billion of our total $5.8 billion share repurchase authorizations, representing an
outstanding share count reduction of nearly 30% since the program’s inception.

Increased our quarterly common stock dividend 12.5% to $0.09 per share beginning in the second
quarter of 2019.

Increased Delaware Basin and Powder River Basin production over 60% in 2019 compared to 2018.

Reduced methane emissions by nearly 20% over the last three years and established a target to further
reduce methane intensity rates by 2025.

Exited 2019 with $1.8 billion of cash, inclusive of $380 million restricted for discontinued operations,
$3.0 billion of available credit under our Senior Credit Facility and have no debt maturities until 2025.

Average Benchmark Prices

$70

$60

$50

$40

$30

$20

$10

$3.20

$3.00

$2.80

$2.60

$2.40

$2.20

$2.00

f
c

r
e
p
s
a
G

l
a
r
u
t
a
N

As presented in the graph

at the left, our operating
achievements are subject to the
volatility of commodity prices.
Over the last four years,
NYMEX WTI oil and NYMEX
Henry Hub prices ranged from
average highs of $64.79 per Bbl
and $3.11 per MMBtu,
respectively, to average lows of
$43.36 per Bbl and $2.46 per
MMBtu, respectively.

l
b
B
r
e
p
L
G
N

/
l
i

2016

WTI (Oil)

2017

2018

2019

Opis Mont Belvieu (NGL)

Henry Hub (Natural Gas)

Trends of our annual earnings, operating cash flow, EBITDAX and capital expenditures are shown below.

The annual earnings chart presents amounts pertaining to both Devon’s continuing and discontinued operations. The
annual cash flow chart presents amounts pertaining to Devon’s continuing operations. “Core earnings” and
“EBITDAX” are financial measures not prepared in accordance with GAAP. For a description of these measures,
including reconciliations to the comparable GAAP measures, see “Non-GAAP Measures” in this Item 7.

Net(cid:3)earnings(cid:3)attributable(cid:3)to(cid:3)Devon(cid:3)(GAAP)

Core(cid:3)earnings(cid:3)(non(cid:882)GAAP)

Hedged(cid:3)price(cid:3)per(cid:3)BOE

Annual(cid:3)Earnings

s
n
o

i
l
l
i

m
n

(cid:3)

i
(cid:3)
s
g
n
n
r
a
E

(cid:3)$1,500
(cid:3)$1,300
(cid:3)$1,100
(cid:3)$900
(cid:3)$700
(cid:3)$500
(cid:3)$300
(cid:3)$100
(cid:3)$(100)
(cid:3)$(300)
(cid:3)$(500)

$898(cid:3)

$427(cid:3)

$3,064(cid:3)

$655(cid:3)

$570(cid:3)

$(355)

2017

2018

2019

(cid:3)$29.50
(cid:3)$29.00
(cid:3)$28.50
(cid:3)$28.00
(cid:3)$27.50
(cid:3)$27.00
(cid:3)$26.50
(cid:3)$26.00
(cid:3)$25.50
(cid:3)$25.00
(cid:3)$24.50

e
o
B
(cid:3)
r
e
p
e
c
i
r
P

(cid:3)

Our net earnings in recent years have been significantly impacted by divestiture transactions and temporary,

noncash adjustments to the value of our commodity hedges. Net earnings in 2017 included a $0.1 billion gain on
asset dispositions from continuing operations and a $0.2 billion hedge valuation gain, both net of taxes. Net earnings
in 2018 included a $2.2 billion gain on our EnLink disposition, a $0.5 billion hedge valuation gain and a $0.2 billion
gain on asset dispositions from continuing operations, all net of taxes. Net earnings in 2019 included a $0.4 billion
hedge valuation loss, $0.2 billion net gains and charges related to our Canadian disposition and a $0.6 billion asset
impairment related to our Barnett Shale disposition, all net of taxes. Excluding these amounts, our core earnings
have been more stable over recent years but continue to be heavily influenced by commodity prices.

Annual(cid:3)Cash(cid:3)Flow

Operating(cid:3)cash(cid:3)flow

Capital(cid:3)expenditures

EBITDAX(cid:3)(non(cid:882)GAAP)

(cid:3)$3,000

(cid:3)$2,500

(cid:3)$2,000

(cid:3)$1,500

(cid:3)$1,000

(cid:3)$500

(cid:3)$(cid:882)

$1,243(cid:3)

$1,614(cid:3)

$1,583(cid:3)

$2,116(cid:3)

$2,043(cid:3)

$1,910(cid:3)

2017

2018

2019

Like earnings, our operating cash flow is sensitive to volatile commodity prices. EBITDAX, which excludes
financial amounts related to discontinued operations, has been increasing over the past three years as a result of our
New Devon production growth and cost reductions. Regardless of cash flow fluctuations, we remain focused on
managing our capital investment to generate free cash flow. As operating cash flow has declined, we have adjusted
our capital development plans accordingly.

Business and Industry Outlook

Devon marked its 48th anniversary in the oil and gas business and its 31st year as a public company during
2019. As an established company with a strong leadership team, we have experience operating through periods of
volatile commodity prices. With our focused strategy and portfolio of quality assets, we are committed to navigating
the current environment while safeguarding our long-term financial strength.

Market prices for crude oil and natural gas are inherently volatile. In 2019, WTI oil prices averaged

approximately $57.02/Bbl versus $64.79/Bbl in 2018. Despite price support in the first half of 2019 driven by
supply tightness and geopolitical tensions, 2019 WTI oil prices overall were negatively impacted by trade concerns
and economic slowdown fears, even with strong supply and demand fundamentals. Looking ahead, crude oil has
experienced near term downward pressure as a result of softer demand from the growing impact of the coronavirus
related crisis. Positive factors that could reduce these recent negative factors and create more demand for crude oil
are the extension of OPEC cuts through 2020, as well as the International Maritime Organization 2020 regulations.

Henry Hub gas prices averaged approximately $2.63/MMBtu in 2019 versus $3.09/MMBtu in 2018. Mt.

Belvieu Blended Index NGL prices averaged approximately $19.22/Bbl in 2019 versus $28.31/Bbl in 2018. Natural
gas and NGL prices faced strong headwinds in 2019 due to U.S. supply growth far outpacing demand for both
commodities domestically and internationally. These factors continue to weigh on current natural gas and NGL
prices.

As discussed in our Critical Accounting Estimates, our STACK assets are susceptible to a material asset
impairment should prices decrease from current levels. While such an impairment would materially impact our
reported net earnings, it would not impact our operating cash flow or our current near-term drilling plans.

To mitigate our exposure to commodity price volatility and ensure our financial strength, we continue to

execute a disciplined, risk-management hedging program. Our hedging program incorporates both systematic
hedges added on a regular basis and discretionary hedges layered in on an opportunistic basis to take advantage of
favorable market conditions. We are adding 2020 positions at desirable prices, and we currently have approximately
40% of our anticipated oil volumes and 25% of our anticipated gas volumes hedged. Additionally, we are actively
adding attractive hedges for 2021. Further insulating our cash flow, we continue to examine and, when appropriate,
execute attractive regional basis swap hedges in an effort to protect price realizations across our portfolio.

Throughout 2019, our operational efficiencies continued to accelerate. Our improved cost structure
expanded margins, and we ended the year ahead of our multi-year cost savings initiative plan. As we carry our 2019
momentum into 2020, we will maintain our capital-efficiency focus and intensify our steadfast commitment to
capital discipline. Our returns-driven strategy will be underpinned by our continued efforts to improve our cost
structure and grow higher-margin oil production. As such, our 2020 capital program has been optimized for strong
returns, high single-digit oil growth, free cash flow and enhanced per-share cash flow growth.

To achieve our 2020 capital program objectives, our capital allocation priorities are four-fold: maintain base

production, fund dividends, invest in high-return growth projects and return excess cash to shareholders.
Accordingly, over half of the 2020 spend will be focused in on our highest margin U.S. oil play, the Delaware Basin.
As the most active program in Devon’s portfolio, capital activity in the Delaware Basin will be diversified across
five core areas. Also accretive to our 2020 returns-focused capital program is our 2020 Rockies activity, where
spend will be prioritized to our top-tier Powder River Basin development activity. In total, our 2020 operating plan
is expected to deliver U.S. oil growth of approximately 7.5% to 9.0% on a retained asset basis.

Results of Operations

The following graphs, discussion and analysis are intended to provide an understanding of our results of
operations and current financial condition. To facilitate the review, these numbers are being presented before
consideration of earnings attributable to noncontrolling interests. Analysis of the change in net earnings from
continuing operations is shown below and analysis of the change in net earnings from discontinued operations is
shown on page 33.

Continuing Operations

2019 vs. 2018

Our 2019 net loss from continuing operations was $79 million and decreased $793 million compared to 2018.

The graph below shows the change in net earnings from 2018 to 2019. The material changes are further discussed by
category on the following pages. To facilitate the review, these numbers are being presented before consideration of
earnings attributable to noncontrolling interests.

$410

($686)

$590

($44)

($269)

$714

$99

($1,153)

Net Earnings

$260

($79)

2018

Production
volumes

Field
prices

Hedge
settlements

Production
expenses

DD&A

G&A

Other
items

Income
taxes

2019

Production Volumes

Oil (MBbls/d)

Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other

New Devon
U.S. divest assets

Total

Gas (MMcf/d)

Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other
New Devon
U.S. divest assets

Total

2019

% of
Total

2018 Change

70
31
17
23
6
147
3
150

47%
20%
11%
16%
4%
98%
2%
100%

42 +67%
32
- 4%
14 +26%
- 17%
28
+4%
5
121 +21%
- 70%
130 +15%

2019

% of
Total

2018 Change

177
314
24
79
1
595
4
599

29%
53%
4%
13%
0%
99%
1%
100%

105 +68%
- 6%
334
16 +55%
- 0%
79
- 18%
1
535 +11%
- 87%
31
+6%
566

2019

% of
Total

2018 Change

NGLs (MBbls/d)

Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other

New Devon
U.S. divest assets

Total

27
36
2
11
1
77
—
77

36%
46%
3%
14%
1%
100%
0%
100%

16 +74%
- 5%
37
1 +53%
- 15%
1 +12%
68 +13%
3
71

N/M

+9%

Combined (MBoe/d)
Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other
New Devon
U.S. divest assets

Total

2019

% of
Total

2018 Change

127
119
23
47
7
323
4
327

39%
36%
7%
15%
2%
99%
1%
100%

125

75 +69%
- 5%
17 +34%
- 12%
54
+5%
7
278 +16%
18
- 80%
296 +11%

From 2018 to 2019, an 11% increase in production

volumes contributed to a $410 million increase in
earnings. Continued development in the Delaware
Basin and Powder River Basin drove a 16% production
increase for New Devon which was slightly offset by
decreased production associated with divested assets.

Field Prices

Oil (per Bbl)
WTI index
Realized price,
unhedged
Cash settlements
Realized price,
with hedges

2019 Realization 2018 Change

$57.02

$64.79

- 12%

$54.73
$ 1.71

96% $61.96
$ (8.01)

- 12%

$56.44

99% $53.95

+5%

2019 Realization 2018 Change

Gas (per Mcf)
Henry Hub index
$ 2.63
Realized price, unhedged $ 1.79
$ 0.14
Cash settlements
Realized price, with
hedges

$ 1.93

$ 3.09
68% $ 2.34
$ 0.02

- 15%
- 23%

73% $ 2.36

- 18%

NGLs (per Bbl)
Mont Belvieu blended
index (1)
Realized price,
unhedged
Cash settlements
Realized price, with
hedges

2019 Realization 2018 Change

$19.22

$28.31

- 32%

$15.21
$ 1.61

79% $25.47
$ (1.75)

- 40%

$16.82

88% $23.72

- 29%

(1)

Based upon composition of our NGL barrel.

Combined (per Boe)
Realized price, unhedged

2019

2018

Change

$ 31.93 $ 37.87

- 16%

Cash settlements
Realized price, with hedges

1.43 $

$
(3.89)
$ 33.36 $ 33.98

- 2%

From 2018 to 2019, field prices contributed to a
$686 million decrease in earnings. Unhedged realized
oil, gas and NGL prices decreased primarily due to
lower WTI, Henry Hub and Mont Belvieu index prices.
These decreases were partially offset by favorable
hedge cash settlements across each of our products.

Hedge Settlements

Oil
Natural gas
NGL

Total cash settlements

2019
$

2018

Change
(380) N/M
5 N/M
(45) N/M
(420) N/M

93 $
31
46
170 $

Cash settlements as presented in the tables above

represent realized gains or losses related to the
instruments described in Note 3 in “Item 8. Financial
Statements and Supplementary Data” of this report.

2019
$ 462

2018
$ 480

Change

- 4%

463
251
21
$1,197

407
248
18
$1,153

+14%
+1%
+17%
+4%

Production Expenses

LOE
Gathering, processing &
transportation
Production taxes
Property taxes

Total
Per Boe:
LOE
Gathering, processing &
transportation

Percent of oil, gas and
NGL sales:

Production taxes

Field-level cash
margin (non-GAAP)
Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other

New Devon
U.S. divest assets

Total

2019

$ per
BOE 2018

$ per
BOE

$ 1,157 $ 25.00 $
685 $ 15.81
246 $ 28.64
446 $ 25.80
65 $ 25.37

786 $ 28.65
992 $ 21.75
249 $ 38.50
717 $ 36.30
72 $ 28.59
2,599 $ 22.02 2,816 $ 27.67
116 $ 19.15
$ 2,612 $ 21.90 $ 2,932 $ 27.19

13 $ 11.01

Depreciation, Depletion and Amortization

Oil and gas per Boe

2019
$11.72 $10.51 +11%

2018 Change

Oil and gas
Other property and equipment

Total

$1,398 $1,134 +23%
+5%
1,228 +22%

99
$1,497

$ 3.87

$ 4.45

- 13%

$ 3.88

$ 3.77

+3%

Our oil and gas DD&A increased due to continued
development in the Delaware Basin and Powder River
Basin.

6.6%

6.1%

+8%

General and Administrative Expense

LOE per Boe decreased in 2019 compared to 2018

due to the impact of our cost reduction initiatives.
Gathering, processing and transportation increased
primarily due to increased activity in the Delaware
Basin.

Labor and benefits (net of
reimbursements)

Non-labor

Total Devon

2019 2018 Change

$ 307 $ 365

- 16%

168 209
$ 475 $ 574

- 20%
- 17%

From 2018 to 2019, G&A decreased $99 million
primarily as a result of the workforce reduction and
other cost-saving initiatives that occurred during 2019
as discussed in Note 6 in “Item 8. Financial Statements
and Supplementary Data” of this report.

Field-Level Cash Margin

The table below presents the field-level cash margin
for each of our operating areas. Field-level cash margin
is computed as oil, gas and NGL revenues less
production expenses and is not prepared in accordance
with GAAP. A reconciliation to the comparable GAAP
measures is found in “Non-GAAP Measures” in this
Item 7. The changes in production volumes, field prices
and production expenses, shown above, had the
following impacts on our field-level cash margins by
asset.

Other Items

Commodity hedge valuation
changes (1)
Marketing operations
Exploration expenses
Asset impairments
Asset dispositions
Net financing costs
Restructuring and transaction
costs
Other expenses

2019 2018

Change
in
earnings

$ (624) $ 877 $ (1,501)
20
70
156
(230)
330

53
33
58 128
— 156
(48) (278)
250 580

84
4

97
(7)

13
(11)
$ (1,153)

Asset impairments decreased due to recognizing

$109 million of proved asset impairments and $47
million of non-oil and gas asset impairments during
2018 as discussed in Note 5 in “Item 8. Financial
Statements and Supplementary Data” of this report.

Asset dispositions decreased primarily due to gains
recognized in conjunction with certain of our U.S. asset
dispositions in 2018. For additional information see
Note 2 in “Item 8. Financial Statements and
Supplementary Data” of this report.

Net financing costs decreased primarily due to $312
million of early retirement charges associated with our
debt retirement in 2018 as discussed in Note 13 in
“Item 8. Financial Statements and Supplementary Data”
of this report.

(1)

Included as a component of upstream revenues on the
consolidated statements of comprehensive earnings.

Income Taxes

We recognize fair value changes on our oil, gas and

NGL derivative instruments in each reporting period.
The changes in fair value resulted from new positions
and settlements that occurred during each period, as
well as the relationship between contract prices and the
associated forward curves.

Exploration expense decreased primarily due
to recognizing $95 million in unproved impairments
related to certain non-core acreage in the U.S during
2018 compared to $18 million in 2019.

Current benefit
Deferred expense (benefit)
Total expense (benefit)

2019

2018

(5)
(25)
(30)

(17)
247
230

Effective income tax rate

28%

24%

For discussion on income taxes, see Note 7 in “Item

8. Financial Statements and Supplementary Data” of
this report.

Results of Operations – 2018 vs. 2017

Our 2018 net earnings from continuing operations were $714 million and increased $681 million compared to

2017. The graph below shows the change in net earnings from 2017 to 2018. The material changes are further
discussed by category on the following pages. To facilitate the review, these numbers are being presented before
consideration of earnings attributable to noncontrolling interests.

$918

($535)

Net Earnings

($362)

$786

($223)

$714

$33

2017

$246

($220)

$71

Production
volumes

Field
prices (1)

Hedge
settlements

Production
expenses (1)

DD&A

G&A

Other
items

Income
taxes

2018

(1) As further discussed in Note 1 in “Item 8. Financial Statements and Supplementary Data” of this report, the presentation of certain

processing arrangements changed from a net to a gross presentation in 2018. The change resulted in an increase to our upstream
revenues and production expenses by $191 million during 2018 with no impact to net earnings.

Production Volumes

Oil (MBbls/d)

Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other

New Devon
U.S. divest assets

Total

Gas (MMcf/d)

Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other
New Devon
U.S. divest assets

Total

NGLs (MBbls/d)

Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other

New Devon
U.S. divest assets

Total

2018

% of
Total

2017 Change

42
32
14
28
5
121
9
130

32%
25%
10%
22%
4%
93%
7%
100%

29 +42%
25 +28%
10 +37%
- 17%
34
- 6%
6
104 +17%
11
- 24%
115 +13%

2018

% of
Total

2017 Change

105
334
16
79
1
535
31
566

19%
59%
3%
14%
0%
95%
5%
100%

86 +22%
294 +13%
8 +85%
- 17%
+6%
484 +10%
- 10%
35
+9%
519

95
1

2018

% of
Total

2017 Change

16
37
1
13
1
68
3
71

22%
53%
2%
18%
1%
96%
4%
100%

13
1

10 +53%
30 +24%
1 +75%
+2%
- 4%
55 +25%
3
- 10%
58 +23%

Combined (MBoe/d)
Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other

New Devon
U.S. divest assets

2018

% of
Total

2017 Change

75
125
17
54
7
278
18

26%
42%
6%
18%
2%
94%
6%

54 +39%
104 +20%
12 +43%
- 13%
62
- 3%
7
239 +16%
- 14%
21

Total

296

100%

260 +14%

From 2017 to 2018, an increase in production
volumes contributed to a $246 million increase in
earnings. Focused development activities in the
Delaware Basin, STACK and Powder River Basin
drove production increases for New Devon and were
partially offset by decreased activity in the Eagle Ford
and lower production volumes associated with our U.S.
divested assets.

Oil, Gas and NGL Prices

Oil (per Bbl)
WTI index
Realized price,
unhedged
Cash settlements
Realized price, with
hedges

2018 Realization 2017 Change

$64.79

$50.99 +27%

$61.96
$ (8.01)

96% $49.41 +25%
$ 1.98

$53.95

83% $51.39

+5%

Gas (per Mcf)
Henry Hub index
Realized price, unhedged
Cash settlements
Realized price, with
hedges

2018 Realization 2017 Change

$3.09
$2.34
$0.02

$3.11
76% $2.57
$0.18

- 1%
- 9%

$2.36

76% $2.75

- 14%

NGLs (per Bbl)
Mont Belvieu blended
index (1)
Realized price,
unhedged

Cash settlements
Realized price, with
hedges

2018 Realization 2017 Change

$28.31

$24.77 +14%

$25.47

90% $16.74 +52%

$ (1.75)

$ (0.16)

$23.72

84% $16.58 +43%

(1)

Based upon composition of average Devon NGL barrel.

Combined (per Boe)
Realized price, unhedged
Cash settlements
Realized price, with hedges

2018

2017

Change

$ 37.87 $ 30.80
$
1.21
$ 33.98 $ 32.01

(3.89) $

+23%

+6%

Upstream revenues increased $918 million as a
result of higher unhedged, realized prices for oil and
NGLs. The increase in oil sales primarily resulted from
higher average WTI crude index prices, which were
27% higher in 2018, resulting in an increase of
approximately $600 million.

NGL sales increased $282 million as a result of
14% higher NGL prices at the Mont Belvieu, Texas
hub, as well as improved realizations in our NGL price.
These increases were partially offset by unfavorable
hedge cash settlements for our oil and NGL hedges.

In 2018, the presentation of certain processing

arrangements changed from a net to a gross
presentation. The change resulted in an increase to our
upstream revenues and production expenses by
approximately $191 million with no impact to net
earnings.

Production taxes increased on an absolute dollar

basis primarily due to the increase in our upstream
revenues. Additionally, the increase in Oklahoma
severance tax rates that became effective during the
third quarter of 2018 also contributed to the increase on
an absolute dollar basis and as a percentage of oil, gas
and NGL sales.

Field-Level Cash Margin

The changes in production volumes, field prices and

production expenses, shown above, had the following
impact on our field-level cash margins by asset.

Field-level cash
margin (non-GAAP)
Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other

New Devon
U.S. divest assets

Total

2018

$ per
BOE 2017

$ per
BOE

786 $ 28.65 $
992 $ 21.75
249 $ 38.50
717 $ 36.30
72 $ 28.59

455 $ 23.04
683 $ 17.99
128 $ 28.67
667 $ 29.41
68 $ 26.21
2,816 $ 27.67 2,001 $ 22.88
129 $ 17.47
$ 2,932 $ 27.19 $ 2,130 $ 22.46

116 $ 19.15

Depreciation, Depletion and Amortization

Oil and gas per Boe

10.51 $

9.58

+10%

2018

2017

Change

Oil and gas
Other property and
equipment

Total

1,134 $

908

+25%

94
1,228 $

100
1,008

- 5%
+22%

Our oil and gas DD&A increased primarily due to
continued development in the STACK, Delaware Basin
and Powder River Basin properties.

General and Administrative Expense

Labor and benefits (net of
reimbursements)
Non-labor

Total Devon

2018 2017 Change

$ 365 $ 445
209 200
$ 574 $ 645

- 18%
+ 5%
- 11%

Hedge Settlements

Oil
Natural gas
NGL

Total cash settlements

Production Expenses

LOE
Gathering, processing &
transportation
Production taxes
Property taxes

Total
Per Boe:
LOE
Gathering, processing &
transportation

Percent of oil, gas and
NGL sales:

Production taxes

2018 2017 Change
83 N/M
$
35 N/M
(3) N/M
115 N/M

(380) $
5
(45)
(420) $

2018
$ 480

2017
$ 411

Change
+17%

407
248
18
$1,153

205
161
14
$ 791

+99%
+54%
+29%
+46%

$ 4.45

$4.33

+3%

$ 3.77

$2.16

+74%

6.1% 5.5% +10%

LOE increased $69 million primarily due to
continued focus on growing our liquids-rich assets
within the STACK and Delaware Basin, partially offset
by our U.S. non-core divestitures.

In 2018, the presentation of certain processing

From 2017 to 2018, G&A decreased $71 million
primarily as a result of the workforce reductions that
occurred during 2018 as discussed in Note 6 in “Item 8.
Financial Statements and Supplementary Data” of this
report.

Other Items

Commodity hedge valuation
changes (1)
Marketing operations
Exploration expenses
Asset impairments
Asset dispositions
Net financing costs
Restructuring and transaction
costs
Other expenses

2018 2017

Change
in
earnings

$ 877 $ (48) $
(46)
33
128
346
156 —
(219)
(278)
321
580

97 —
10
(7)
$

925
79
218
(156)
59
(259)

(97)
17
786

(1)

Included as a component of upstream revenues on the
consolidated statements of comprehensive earnings.

Marketing operations increased primarily due to

improved commodity prices, which were partially
offset by the impact of our downstream marketing
commitments.

Exploration expense decreased due to recognizing
$95 million in unproved impairments related to certain
non-core acreage in the U.S during 2018 compared to
$217 million in 2017. Additionally, geological and
geophysical costs decreased $86 million primarily in
the STACK and Delaware Basin.

Asset impairments increased due to recognizing
$109 million of proved asset impairments and $47
million of non-oil and gas asset impairments during
2018. For additional information, see Note 5 in “Item 8.
Financial Statements and Supplementary Data” of this
report.

Asset dispositions increased primarily due to gains
recognized in conjunction with certain of our U.S. asset
dispositions in 2018. For additional information, see
Note 2 in “Item 8. Financial Statements and
Supplementary Data” of this report.

Net financing costs increased primarily due to $312
million of early retirement charges associated with our
debt retirement in 2018 as discussed in Note 13 in
“Item 8. Financial Statements and Supplementary Data”
of this report.

Restructuring and transaction costs increased
primarily as a result of our workforce reductions in
2018. See Note 6 in “Item 8. Financial Statements and
Supplementary Data” of this report for additional
information.

Income Taxes

Current expense (benefit)
Deferred expense (benefit)

Total expense

Effective income tax rate

2018

2017

(17) $
247
230

$
24%

9
(2)
7
18%

For discussion on income taxes, see Note 7 in “Item

8. Financial Statements and Supplementary Data” of
this report.

Discontinued Operations

The table below presents key components from discontinued operations for the time periods presented.
Discontinued operations include our aggregate ownership interests in EnLink and the General Partner that Devon
divested in July 2018 and the Canadian business that Devon sold in June 2019. Discontinued operations also include
the Barnett Shale assets that Devon has contracted to sell and which is expected to close during the second quarter of
2020, as well as previously divested Barnett Shale properties located primarily in Johnson and Wise counties, Texas.
For additional information on discontinued operations, see Note 18 in “Part I. Financial Information – Item 1.
Financial Statements” of this report.

Upstream revenues
Production expenses
Marketing margin
Gain on sale of Canadian operations
Gain on sale of EnLink and General Partner interests
Asset impairments
Financing costs, net
Restructuring and transaction costs
Earnings (loss) from discontinued operations before
income taxes
Income tax expense (benefit)
Net earnings (loss) from discontinued operations, net of
tax

Production (MMBoe):
Barnett Shale
Canada

Total production

Realized price, unhedged (per Boe) - Barnett Shale
Realized price, unhedged (per Boe) - Canada

2019 vs 2018

2019

2018

2017

1,114 $
599 $
20 $
(223) $
— $
785 $
87 $
248 $

(632) $
(358) $

1,742 $
1,072 $
708 $
— $
(2,607) $
— $
112 $
17 $

2,839 $
329 $

2,319
1,031
958
—
—
17
177
—

856
(189)

(274) $

2,510 $

1,045

37
19
56
13.30 $
38.98 $

45
42
87
17.36 $
19.12 $

56
48
104
14.79
29.39

$
$
$
$
$
$
$
$

$
$

Net earnings from discontinued operations, net of tax decreased $2.8 billion as we recognized a $2.6 billion

($2.2 billion after-tax) gain on the sale of our aggregate ownership interests in EnLink and the General Partner
during 2018. Net earnings from discontinued operations also decreased due to a $748 million asset impairment to
our Barnett Shale assets in the fourth quarter of 2019.

2018 vs 2017

Net earnings from discontinued operations, net of tax increased $1.5 billion as we recognized a $2.6 billion

($2.2 billion after-tax) gain on the sale of our aggregate ownership interests in EnLink and the General Partner
during 2018. The gain was partially offset by a decrease in upstream revenues, which was primarily driven by
widening differentials for bitumen sales in Canada to the WTI index during the fourth quarter of 2018. Market
forces widened Canadian heavy oil differentials beyond historical norms and negatively impacted the price we
realized on our Canadian production. We had basis swaps for approximately half of our fourth quarter production to
mitigate the effect of the lower market price. To further mitigate the effects of the lower price, we reduced our
Jackfish production in November 2018 which impacted our fourth quarter production by approximately 8 MBbls/d.
For discussion on discontinued operations, see Note 18 in “Item 8. Financial Statements and Supplementary Data”
of this report.

Capital Resources, Uses and Liquidity

Sources and Uses of Cash

The following table presents the major changes in cash and cash equivalents for the time periods presented

below.

Operating cash flow from continuing operations
Divestitures of property and equipment
Capital expenditures
Acquisitions of property and equipment
Debt activity, net
Repurchases of common stock
Common stock dividends
Contributions from noncontrolling interests
Other
Net change in cash, cash equivalents and restricted cash
from discontinued operations
$
Net change in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at end of period $

Operating Cash Flow – Continuing Operations

2019

Year ended December 31,
2018

2017

2,043
390
(1,910)
(31)
(162)
(1,849)
(140)
116
(26)

1,583
500
(2,116)
(55)
(1,226)
(2,956)
(149)
—
(46)

967
(602) $
$
1,844

4,227
(238) $
$
2,446

1,243
425
(1,614)
(44)
—
—
(127)
—
(46)

888
725
2,684

Net cash provided by operating activities continued to be a significant source of capital and liquidity in 2019.
Our operating cash flow increased $460 million, or 29%, to $2.0 billion year over year. In 2019, our operating cash
flow nearly funded the entirety of our capital expenditures program and dividends, allowing us to use available cash
balances and net divestiture proceeds to fund other capital uses.

Our operating cash flow increased $340 million, or 27%, from 2017 to 2018. Our operating cash flow funded
approximately 70% of our capital expenditures program and dividends in 2018 and 2017, respectively. As a result,
we utilized available cash balances and divestiture proceeds to supplement our operating cash flows.

Divestitures of Property and Investments – Continuing Operations

During 2019, 2018 and 2017, as part of our announced divestiture programs, we sold non-core U.S. upstream
assets for $390 million, $500 million and $425 million, respectively. For further discussion, see Note 2 in “Item 8.
Financial Statements and Supplementary Data” of this report.

Capital Expenditures

The following table summarizes our capital expenditures and property acquisitions.

Delaware Basin
STACK
Powder River Basin
Eagle Ford
Other

Total oil and gas

Midstream
Other

Total capital expenditures

Acquisitions

Year ended December 31,

2019

2018

2017

$
$

912 $
396
308
194
36
1,846
42
22
1,910 $
31 $

768 $
827
157
215
110
2,077
16
23
2,116 $
55 $

394
742
121
115
155
1,527
50
37
1,614
44

Capital expenditures consist primarily of amounts related to our oil and gas exploration and development

operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition,
drilling and development of oil and gas properties. Our capital program is designed to operate within or near
operating cash flow and may fluctuate with changes to commodity prices and other factors impacting cash flow.
This is evidenced by our operating cash flow fully funding capital expenditures in 2019 and funding approximately
75% and 77% of capital expenditures in 2018 and 2017, respectively. Our capital expenditures are lower in 2019
primarily due to our decreased spending in the STACK, partially offset by increased capital investment in higher
margin assets in the Delaware and Powder River Basins.

Debt Activity, Net

During 2019, our debt decreased $162 million due to the repayment of our 6.30% senior notes at maturity.

During 2018, our debt decreased $922 million due to completed tender offers of certain long-term debt as well

as the maturity of certain senior notes. In conjunction with the tender offers, we recognized a $312 million loss on
the early retirement of debt, including $304 million of cash retirement costs and fees. For additional information, see
Note 13 in “Item 8. Financial Statements and Supplementary Data” of this report.

Repurchases of Common Stock and Shareholder Distributions

We repurchased 68.6 million shares of common stock for $1.8 billion in 2019 and 78.1 million shares of
common stock for $3.0 billion in 2018 under a share repurchase program authorized by our Board of Directors. For
additional information, see Note 17 in “Item 8. Financial Statements and Supplementary Data” in this report.

Devon paid common stock dividends of $140 million, $149 million and $127 million during 2019, 2018 and

2017, respectively. During the second quarter of 2018, we increased our quarterly dividend 33% from $0.06 to $0.08
per share as part of our focus on returning cash to shareholders. In February 2019, we further increased our quarterly
dividend 12.5% to $0.09 per share, beginning in the second quarter of 2019. For additional information, see Note 17
in “Item 8. Financial Statements and Supplementary Data” of this report.

Contributions from Noncontrolling Interests

During 2019, we received approximately $116 million in cash contributions from our partner in CDM.

Cash Flows from Discontinued Operations

All cash flows in the following table relate to activities from discontinued operations for the time periods

presented. Discontinued operations include our aggregate ownership interests in EnLink and the General Partner that
Devon divested in July 2018 and the Canadian business that Devon sold in June 2019. Discontinued operations also
include the Barnett Shale assets that Devon has contracted to sell and which is expected to close during the second
quarter of 2020, as well as previously divested Barnett Shale properties located primarily in Johnson and Wise
counties, Texas.

Settlements of intercompany foreign denominated
assets/liabilities
Other

Operating activities

Divestitures of property and equipment - Canadian operations
Divestitures of investments - EnLink and General Partner
Divestitures of property and equipment - Barnett Shale assets
Capital expenditures and other

Investing activities

Debt activity, net
Issuance of subsidiary units
Distributions to noncontrolling interests
Other

Financing activities

Settlements of intercompany foreign denominated
assets/liabilities
Other

Effect of exchange rate changes on cash

Net change in cash, cash equivalents and restricted cash of
discontinued operations

Year ended December 31,

2019

2018

2017

(32) $
60
28
2,608
—
—
(136)
2,472
(1,552)
—
—
(26)
(1,578)

32
13
45

(241) $
1,362
1,121
—
3,104
513
(891)
2,726
347
1
(217)
43
174

241
(35)
206

9
1,657
1,666
—
190
—
(1,156)
(966)
2
501
(354)
33
182

(9)
15
6

967 $

4,227 $

888

Operating cash flow in 2019 decreased $1.1 billion and $1.6 billion from 2018 and 2017, respectively, as a
result of the divestitures referenced above. Additionally, operating cash flow was negatively affected in the first
quarter of 2019 primarily due to realization impacts associated with the widening Canadian differentials in the
fourth quarter of 2018. Foreign currency denominated intercompany loan activity resulted in a realized loss of $32
million and $241 million in 2019 and 2018, respectively, as a result of the strengthening of the U.S. dollar in relation
to the Canadian dollar. Foreign currency denominated intercompany loan activity resulted in a realized gain of $9
million in 2017, as a result of the weakening of the U.S. dollar in relation to the Canadian dollar. There was an offset
in the effect of exchange rate changes on cash line in the above table, resulting in no impact to the net change in
cash, cash equivalents and restricted cash.

On June 27, 2019, Devon completed the sale of substantially all its oil and gas assets and operations in Canada

for proceeds of $2.6 billion. In the second and fourth quarter of 2018, Devon completed the sale of a portion of its
Barnett Shale assets, located primarily in Johnson and Wise counties, Texas for approximately $500 million in
combined proceeds. On July 18, 2018, Devon completed the sale of its aggregate ownership interests in EnLink and
the General Partner for $3.125 billion. During 2017, EnLink divested its ownership interest in Howard Energy
Partners for approximately $190 million.

Cash flows from financing activities includes the $1.5 billion of senior notes retired prior to maturity in July

2019 and common and preferred units EnLink issued and sold during 2017 generating net proceeds of $501 million.
Distributions to noncontrolling interests in the table above exclude the distributions EnLink and the General Partner
paid to Devon, which have been eliminated in consolidation. Distributions EnLink and the General Partner paid to
Devon were $134 million and $265 million during 2018 and 2017, respectively.

Liquidity

The business of exploring for, developing and producing oil and natural gas is capital intensive. Because oil,

natural gas and NGL reserves are a depleting resource, we, like all upstream operators, must continually make
capital investments to grow and even sustain production. Generally, our capital investments are focused on drilling
and completing new wells and maintaining production from existing wells. At opportunistic times, we also acquire
operations and properties from other operators or land owners to enhance our existing portfolio of assets.

Historically, our primary sources of capital funding and liquidity have been our operating cash flow, cash on

hand and asset divestiture proceeds. Additionally, we maintain a commercial paper program, supported by our
revolving line of credit, which can be accessed as needed to supplement operating cash flow and cash balances. If
needed, we can also issue debt and equity securities, including through transactions under our shelf registration
statement filed with the SEC. We estimate the combination of our sources of capital will continue to be adequate to
fund our planned capital requirements as discussed in this section.

Operating Cash Flow

Key inputs into determining our planned capital investment is the amount of cash we hold and operating cash
flow we expect to generate over the next one to three or more years. At the end of 2019, we held approximately $1.8
billion of cash, inclusive of $380 million of cash restricted for discontinued operations. Our operating cash flow
forecasts are sensitive to many variables and include a measure of uncertainty as these variables differ from our
expectations.

Commodity Prices – The most uncertain and volatile variables for our operating cash flow are the prices of the

oil, gas and NGLs we produce and sell. Prices are determined primarily by prevailing market conditions. Regional
and worldwide economic activity, weather and other substantially variable factors influence market conditions for
these products. These factors, which are difficult to predict, create volatility in prices and are beyond our control.

To mitigate some of the risk inherent in prices, we utilize various derivative financial instruments to protect a

portion of our production against downside price risk. We hedge our production in a manner that systematically
places hedges for several quarters in advance, allowing us to maintain a disciplined risk management program as it
relates to commodity price volatility. We supplement the systematic hedging program with discretionary hedges that
take advantage of favorable market conditions. The key terms to our oil, gas and NGL derivative financial
instruments as of December 31, 2019 are presented in Note 3 in “Item 8. Financial Statements and Supplementary
Data” of this report.

Further, when considering the current commodity price environment and our current hedge position, we
expect to achieve our capital investment priorities. Should WTI drop closer to $45/Bbl for an extended period, we
would shift our focus to preserving our financial strength and operational continuity. However, as WTI/Bbl rises
above $50, our free cash flow will accelerate, providing additional capital allocation opportunities.

Operating Expenses – Commodity prices can also affect our operating cash flow through an indirect effect on

operating expenses. Significant commodity price decreases can lead to a decrease in drilling and development
activities. As a result, the demand and cost for people, services, equipment and materials may also decrease, causing
a positive impact on our cash flow as the prices paid for services and equipment decline. However, the inverse is
also generally true during periods of rising commodity prices.

In 2019, we aggressively optimized our cost structure in conjunction with our Canadian and Barnett Shale

asset divestitures, as we focus on our remaining four U.S. oil plays, align our workforce with the retained business
and reduce outstanding debt. These optimizations include cost reductions and efficiencies related to our capital
programs, G&A, financing costs and production expenses.

Credit Losses – Our operating cash flow is also exposed to credit risk in a variety of ways. This includes the
credit risk related to customers who purchase our oil, gas and NGL production, the collection of receivables from
our joint interest partners for their proportionate share of expenditures made on projects we operate and
counterparties to our derivative financial contracts. We utilize a variety of mechanisms to limit our exposure to the
credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions,
requiring letters of credit, prepayments or collateral postings.

Divestitures of Property and Equipment

In December 2019, we announced the sale of our Barnett Shale assets for approximately $770 million. We

expect this transaction to close in the second quarter of 2020.

Credit Availability

We have $3.0 billion of available borrowing capacity under our Senior Credit Facility at December 31, 2019.

On December 13, 2019, we entered into an amendment and extension agreement to, among other things, (i) effect
the extension of the maturity date of the Senior Credit Facility from October 5, 2023 to October 5, 2024 with respect
to the consenting lenders and (ii) modify the maximum number of maturity extension requests during the term of the
Senior Credit Facility from two to three. As a result of this amendment, the Senior Credit Facility matures on
October 5, 2024, with the option to extend the maturity date by two additional one-year periods subject to lender
consent. Subsequent to October 5, 2023, the borrowing capacity decreases to $2.8 billion. The Senior Credit Facility
supports our $3.0 billion of short-term credit under our commercial paper program. As of December 31, 2019, there
were no borrowings under our commercial paper program. See Note 13 in “Item 8. Financial Statements and
Supplementary Data” of this report for further discussion.

The Senior Credit Facility contains only one material financial covenant. This covenant requires us to
maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%.
As of December 31, 2019, we were in compliance with this covenant with a 19.1% debt-to-capitalization ratio.

Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect”
clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation
of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and
adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the
borrower’s ability to make timely debt payments or the enforceability of material terms of the credit agreement.
While our credit facility includes covenants that require us to report a condition or event having a material adverse
effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse
effect.

As market conditions warrant and subject to our contractual restrictions, liquidity position and other factors,

we may from time to time seek to repurchase or retire our outstanding debt through cash purchases and/or exchanges
for other debt or equity securities in open market transactions, privately negotiated transactions, by tender offer or
otherwise. Any such cash repurchases by us may be funded by cash on hand or incurring new debt. The amounts
involved in any such transactions, individually or in the aggregate, may be material. Furthermore, any such
repurchases or exchanges may result in our acquiring and retiring a substantial amount of such indebtedness, which
would impact the trading liquidity of such indebtedness.

Debt Ratings

We receive debt ratings from the major ratings agencies in the U.S. In determining our debt ratings, the
agencies consider a number of qualitative and quantitative items including, but not limited to, commodity pricing
levels, our liquidity, asset quality, reserve mix, debt levels, cost structure, planned asset sales and production growth
opportunities. Our credit rating from Standard and Poor’s Financial Services is BBB- with a stable outlook. Our
credit rating from Fitch is BBB with a stable outlook. Our credit rating from Moody’s Investor Service is Ba1 with a
positive outlook. Any rating downgrades may result in additional letters of credit or cash collateral being posted
under certain contractual arrangements.

There are no “rating triggers” in any of our contractual debt obligations that would accelerate scheduled

maturities should our debt rating fall below a specified level. However, a downgrade could adversely impact our
interest rate on any credit facility borrowings and the ability to economically access debt markets in the future.

Share Repurchase Program

In December 2019, our Board of Directors approved a $1.0 billion share repurchase program that expires on

December 31, 2020. This repurchase program was approved in conjunction with the announced divestiture of
Devon’s assets in the Barnett Shale. Under this new program, $800 million of the $1.0 billion authorization is
conditioned upon the closing of the pending Barnett Shale divestiture.

Capital Expenditures

Our 2020 exploration and development budget is expected to be approximately $1.7 billion to $1.85 billion.

In December 2019, we announced a partnership under which we will monetize half our working interest

across 133 undrilled locations in the STACK for an approximate $100 million drilling carry spread over the next
four years. Drilling operations under this agreement are expected to commence in mid-2020.

Contractual Obligations

The following table presents a summary of our contractual obligations as of December 31, 2019.

Continuing Operations

Debt (1)
Interest expense (2)
Operational agreements (3)
Asset retirement obligations (4)
Drilling and facility obligations (5)
Lease obligations (6)
Other (7)
Total

Discontinued Operations

Barnett Shale obligations (8)
Canadian obligations (9)

Total

Total obligations

Payments Due by Period

Total

Less Than
1 Year

1-3 Years

3-5 Years

More Than
5 Years

4,349 $
4,513
1,468
398
262
426
223
11,639

271
347
618
12,257 $

— $
259
320
18
131
51
11
790

35
55
90
880 $

— $
518
431
13
61
53
75
1,151

63
69
132
1,283 $

— $
518
301
25
38
24
32
938

46
55
101
1,039 $

4,349
3,218
416
342
32
298
105
8,760

127
168
295
9,055

(1) Debt amounts represent scheduled maturities of debt obligations at December 31, 2019, excluding net

discounts and debt issue costs included in the carrying value of debt.
Interest expense represents the scheduled cash payments on long-term fixed-rate debt.

(2)
(3) Operational agreements represent commitments to transport or process certain volumes of oil, gas and NGLs
for a fixed fee. We have entered into these agreements to aid the movement of our production to downstream
markets.

(4) Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and
rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2019 balance sheet.

(5) Drilling and facility obligations represent gross contractual agreements with third-party service providers to
procure drilling rigs and other related services for developmental and exploratory drilling and facilities
construction.
Lease obligations consist primarily of non-cancelable leases for office space and equipment. For additional
information, see Note 14 in “Item 8. Financial Statements and Supplementary Data” of this report.

(6)

(7) Other obligations primarily relate to various tax obligations.
(8) Barnett Shale obligations primarily represent approximately $240 million of asset retirement obligations and

firm transportation agreements which will be transferred to BKV when the divestiture of those assets close.
The remainder of the Barnett Shale obligations relate to abandoned gas processing contracts which Devon
retained in connection with the 2018 Barnett Shale divestitures. For additional information, see Note 18 in
“Item 8. Financial Statements and Supplementary Data” of this report.

(9) Canadian obligations are related to a firm transportation agreement and office lease abandonments that were

retained after Devon’s sale of substantially all of its oil and gas assets and operations in Canada. For additional
information, see Note 18 in “Item 8. Financial Statements and Supplementary Data” of this report.

Contingencies and Legal Matters

For a detailed discussion of contingencies and legal matters, see Note 19 in “Item 8. Financial Statements and

Supplementary Data” of this report.

Critical Accounting Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the

U.S. requires us to make estimates, judgments and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates,
and changes in these estimates are recorded when known. We consider the following to be our most critical
accounting estimates that involve judgment and have reviewed these critical accounting estimates with the Audit
Committee of our Board of Directors.

Oil and Gas Assets Accounting, Classification, Reserves & Valuation

Successful Efforts Method of Accounting and Classification

We utilize the successful efforts method of accounting for our oil and natural gas exploration and development

activities which requires management’s assessment of the proper designation of wells and associated costs as
developmental or exploratory. This classification assessment is dependent on the determination and existence of
proved reserves, which is a critical estimate discussed in the section below. The classification of developmental and
exploratory costs has a direct impact on the amount of costs we initially recognize as exploration expense or
capitalize, then subject to DD&A calculations and impairment assessments and valuations.

Once a well is drilled, the determination that proved reserves have been discovered may take considerable

time and requires both judgment and application of industry experience. Development wells are always capitalized.
Costs associated with drilling an exploratory well are initially capitalized, or suspended, pending a determination as
to whether proved reserves have been found. At the end of each quarter, management reviews the status of all
suspended exploratory drilling costs to determine whether the costs should continue to remain capitalized or shall be
expensed. When making this determination, management considers current activities, near-term plans for additional
exploratory or appraisal drilling and the likelihood of reaching a development program. If management determines
future development activities and the determination of proved reserves are unlikely to occur, the associated
suspended exploratory well costs are recorded as dry hole expense and reported in exploration expense in the
consolidated statements of comprehensive earnings. Otherwise, the costs of exploratory wells remain capitalized. At
December 31, 2019, all suspended well costs have been suspended for less than one year.

Similar to the evaluation of suspended exploratory well costs, costs for undeveloped leasehold, for which
reserves have not been proven, must also be evaluated for continued capitalization or impairment. At the end of each
quarter, management assesses undeveloped leasehold costs for impairment by considering future drilling plans,
drilling activity results, commodity price outlooks, planned future sales or expiration of all or a portion of such
projects. At December 31, 2019, Devon had approximately $250 million of undeveloped leasehold. Of the
remaining undeveloped leasehold costs at December 31, 2019, approximately $6 million is scheduled to expire in
2020. The leasehold expiring in 2020 relates to areas in which Devon is actively drilling. If our drilling is not
successful, this leasehold could become partially or entirely impaired.

Reserves

Our estimates of proved and proved developed reserves are a major component of DD&A calculations.
Additionally, our proved reserves represent the element of these calculations that require the most subjective
judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and

the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial
judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may
make different estimates of reserve quantities based on the same data. Our engineers prepare our reserve estimates.
We then subject certain of our reserve estimates to audits performed by a third-party petroleum consulting firm. In
2019, 85% of our reserves were subjected to such audits.

The passage of time provides more qualitative information regarding estimates of reserves, when revisions are

made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our
reserve estimates, which have been both increases and decreases in individual years, have averaged less than 5% of
the previous year’s estimate. However, there can be no assurance that more significant revisions will not be
necessary in the future. The data for a given reservoir may also change substantially over time as a result of
numerous factors, including, but not limited to, additional development activity, evolving production history and
continual reassessment of the viability of production under varying economic conditions.

Valuation of Long-Lived Assets

Long-lived assets used in operations, including proved and unproved oil and gas properties, are depreciated

and assessed for impairment annually or whenever changes in facts and circumstances indicate a possible significant
deterioration in future cash flows is expected to be generated by an asset group. For DD&A calculations and
impairment assessments, management groups individual assets based on a judgmental assessment of the lowest level
(“common operating field”) for which there are identifiable cash flows that are largely independent of the cash flows
of other groups of assets. The determination of common operating fields is largely based on geological structural
features or stratigraphic condition, which requires judgment. Management also considers the nature of production,
common infrastructure, common sales points, common processing plants, common regulation and management
oversight to make common operating field determinations. These determinations impact the amount of DD&A
recognized each period and could impact the determination and measurement of a potential asset impairment.

Management evaluates assets for impairment through an established process in which changes to significant

assumptions such as prices, volumes and future development plans are reviewed. If, upon review, the sum of the
undiscounted pre-tax cash flows is less than the carrying value of the asset group, the carrying value is written down
to estimated fair value. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of
impaired assets is typically determined based on the present values of expected future cash flows using discount
rates believed to be consistent with those used by principal market participants. The expected future cash flows used
for impairment reviews and related fair value calculations are typically based on judgmental assessments of future
production volumes, commodity prices, operating costs and capital investment plans, considering all available
information at the date of review. The expected future cash flows used for impairment reviews include future
production volumes associated with proved producing and risk-adjusted proved undeveloped, probable and possible
reserves. Besides the estimates of reserves and future production volumes, future commodity prices are the largest
driver in the variability of undiscounted pre-tax cash flows. For our impairment determinations, we utilize the
forward strip prices for the first five years and apply internally generated price forecasts for subsequent years. We
estimate and escalate or de-escalate future capital and operating costs by using a method that correlates cost
movements to price movements similar to recent history. Changes to any of these assumptions could result in lower
undiscounted pre-tax cash flows and impact both the recognition and timing of impairments. Should management
materially reduce planned capital investment and commodity prices remain depressed, recognition of material asset
impairments could become more likely for certain of our assets.

As commodity prices decreased throughout 2019 and at year-end approximated the prices Devon used to
determine and compute material asset impairments in 2019, management conducted a robust review of its assets for
impairment as of December 31, 2019. Based on our recent impairment evaluations, our STACK asset’s sum of
undiscounted pre-tax cash flows exceeds the carrying value by less than 10%. This cushion has narrowed
significantly since the end of 2018 due primarily to approximately 30% and 5% declines in forward NGL and
natural gas pricing, respectively, and negative non-price reserve revisions of approximately 40 MMBoe as discussed
in Note 21 in “Item 8. Financial Statements and Supplementary Data” of this report. As of December 31, 2019, the
difference between the STACK’s undiscounted pre-tax cash flows, which is used to determine whether an
impairment exists, and the discounted pre-tax cash flows, which is used to measure an impairment, is approximately
$2.0 billion. Therefore, if commodity prices deteriorate or we materially reduce future development plans, causing
the capitalized costs to exceed the undiscounted pre-tax cash flows, our STACK asset would be subject to a material
impairment of capitalized costs.

Income Taxes

The amount of income taxes recorded requires interpretations of complex rules and regulations of federal,

state, provincial and foreign tax jurisdictions. We recognize current tax expense based on estimated taxable income
for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions
and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and
liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess our deferred
tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or
all of the deferred tax assets will not be realized. Within continuing operations, Devon maintains only a valuation
allowance against a portion of its deferred tax assets, including certain tax credits and state net operating losses.
Devon also has recorded a valuation allowance in discontinued operations against certain Canadian deferred tax
assets.

The accruals for deferred tax assets and liabilities are often based on assumptions that are subject to a
significant amount of judgment by management. These assumptions and judgments are reviewed and adjusted as
facts and circumstances change. Material changes to our income tax accruals may occur in the future based on the
progress of ongoing audits, changes in legislation or resolution of pending matters.

Non-GAAP Measures

Core Earnings

We make reference to “core earnings (loss) attributable to Devon” and “core earnings (loss) per share
attributable to Devon” in “Overview of 2019 Results” in this Item 7 that are not required by or presented in
accordance with GAAP. These non-GAAP measures are not alternatives to GAAP measures and should not be
considered in isolation or as a substitute for analysis of our results reported under GAAP. Core earnings (loss)
attributable to Devon, as well as the per share amount, represent net earnings excluding certain noncash and other
items that are typically excluded by securities analysts in their published estimates of our financial results. For more
information on the results of discontinued operations for our Barnett Shale assets, Canadian operations and for
EnLink and the General Partner, see Note 18 in “Item 8. Financial Statements and Supplementary Data” in this
report. Our non-GAAP measures are typically used as a quarterly performance measure. Amounts excluded for 2019
relate to asset dispositions, the gain on the sale of Canadian operations, noncash asset impairments (including
noncash Barnett Shale and unproved asset impairments), deferred tax asset valuation allowance, costs associated
with early retirement of debt, fair value changes in derivative financial instruments and foreign currency,
restructuring and transaction costs associated with the workforce reductions in 2019 and restructuring and
transaction costs associated with the divestment of our Canadian operations in 2019.

Amounts excluded for 2018 relate to asset dispositions, the gain on the sale of Devon’s aggregate ownership

interests in EnLink and the General Partner, noncash asset impairments (including noncash unproved asset
impairments), deferred tax asset valuation allowance, costs associated with early retirement of debt, fair value
changes in derivative financial instruments and foreign currency, restructuring and transaction costs associated with
the workforce reductions in 2018.

Amounts excluded for 2017 relate to asset dispositions, noncash asset impairments (including noncash

unproved asset impairments), U.S. tax reform changes, deferred tax asset valuation allowance, derivatives and
financial instrument fair value changes, legal entity restructuring and costs associated with early retirement of debt.

We believe these non-GAAP measures facilitate comparisons of our performance to earnings estimates
published by securities analysts. We also believe these non-GAAP measures can facilitate comparisons of our
performance between periods and to the performance of our peers.

Below are reconciliations of our core earnings and earnings per share to their comparable GAAP measures.

2019
Continuing Operations

Loss attributable to Devon (GAAP)
Adjustments:

Asset dispositions
Asset and exploration impairments
Fair value changes in financial instruments
Restructuring and transaction costs

Core earnings attributable to Devon (Non-GAAP)

Discontinued Operations

Loss attributable to Devon (GAAP)
Adjustments:

Gain on sale of Canadian operations
Asset and exploration impairments
Deferred tax asset valuation allowance
Early retirement of debt
Fair value changes in financial instruments and foreign currency
and other
Restructuring and transaction costs

Core earnings attributable to Devon (Non-GAAP)

Total

Loss attributable to Devon (GAAP)
Adjustments:

Continuing Operations
Discontinued Operations

Core earnings attributable to Devon (Non-GAAP)

2018
Continuing Operations

Earnings attributable to Devon (GAAP)
Adjustments:

Asset dispositions
Asset and exploration impairments
Deferred tax asset valuation allowance
Early retirement of debt
Fair value changes in financial instruments
Restructuring and transaction costs

Core earnings attributable to Devon (Non-GAAP)

Discontinued Operations

Earnings attributable to Devon (GAAP)
Adjustments:

Before tax

After tax

After
Noncontrolling
Interests

Per Diluted
Share

(109) $

(79) $

(81) $

(0.21)

(48)
20
623
84
570

(37)
15
480
64
443

(37)
15
480
64
441

(0.09)
0.04
1.19
0.15
1.08

(632) $

(274) $

(0.68)

(223)
785
—
58

(425)
613
24
45

(33)
248
203

(37)
183
129

(425)
613
24
45

(37)
183
129

(1.05)
1.52
0.06
0.11

(0.10)
0.45
0.31

(741) $

(353) $

(355) $

(0.89)

679
835
773

522
403
572

522
403
570

1.29
0.99
1.39

944 $

714 $

1.42

(278)
257
—
312
(938)
97
394

(214)
198

(4)

240
(723)
76
287

(214)
198

(4)

240
(723)
76
287

(0.42)
0.40
(0.01)
0.48
(1.45)
0.15
0.57

2,839 $

2,510 $

2,350 $

4.68

Asset dispositions
Fair value changes in financial instruments and foreign currency
Minimum volume commitment and restructuring and transaction costs
$

Core earnings attributable to Devon (Non-GAAP)

(2,593)
339
(31)
$
554

(2,250)
277
(27)
$
510

(2,250)
270

(2)
$

368

(4.49)
0.54
(0.00)
0.73

Total

Earnings attributable to Devon (GAAP)
Adjustments:

Continuing Operations
Discontinued Operations

Core earnings attributable to Devon (Non-GAAP)

3,783 $

3,224 $

3,064 $

6.10

(550)
(2,285)
$
948

(427)
(2,000)
$
797

(427)
(1,982)
$
655

(0.85)
(3.95)
1.30

2017
Continuing Operations

Earnings attributable to Devon (GAAP)
Adjustments:

Asset dispositions
Asset and exploration impairments
Deferred tax asset valuation allowance
Fair value changes in financial instruments

Core earnings attributable to Devon (Non-GAAP)

Discontinued Operations

Earnings attributable to Devon (GAAP)
Adjustments:

U.S. tax reform
Fair value changes in financial instruments and foreign currency
Asset dispositions, impairments and early retirement of debt
Legal entity restructuring and deferred tax asset valuation
allowance

Core earnings attributable to Devon (Non-GAAP)

Total

Earnings attributable to Devon (GAAP)
Adjustments:

Continuing Operations
Discontinued Operations

Before tax After tax

After
Noncontrolling
Interests

Per Diluted
Share

40 $

33 $

0.06

(219)
217
—
70
108

(140)
138

(4)
45
72

(140)
138

(4)
45
72

(0.27)
0.26
(0.01)
0.09
0.13

856 $ 1,045 $

865 $

1.64

—
(289)
11

(211)
(248)
9

(112)
(248)
7

(0.21)
(0.47)
0.01

—
578

(157)
$
438

(157)
$
355

(0.29)
0.68

896 $ 1,078 $

898 $

1.70

68
(278)

39
(607)

39
(510)

0.07
(0.96)

Core earnings attributable to Devon (Non-GAAP)

686

510

427

0.81

EBITDAX and Field-Level Cash Margin

To assess the performance of our assets, we use EBITDAX and Field-Level Cash Margin. We compute
EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration
expenses; DD&A; asset impairments; asset disposition gains and losses; non-cash share-based compensation; non-
cash valuation changes for derivatives and financial instruments; restructuring and transaction costs; accretion on
discounted liabilities; and other items not related to our normal operations. Field-Level Cash Margin is computed as
oil, gas and NGL revenues less production expenses. Production expenses consist of lease operating, gathering,
processing and transportation expenses, as well as production and property taxes.

We exclude financing costs from EBITDAX to assess our operating results without regard to our financing

methods or capital structure. Exploration expenses and asset disposition gains and losses are excluded from
EBITDAX because they generally are not indicators of operating efficiency for a given reporting period. DD&A and
impairments are excluded from EBITDAX because capital expenditures are evaluated at the time capital costs are
incurred. We exclude share-based compensation, valuation changes, restructuring and transaction costs, accretion on
discounted liabilities and other items from EBITDAX because they are not considered a measure of asset operating
performance.

We believe EBITDAX and Field-Level Cash Margin provide information useful in assessing our operating

and financial performance across periods. EBITDAX and Field-Level Cash Margin as defined by Devon may not be
comparable to similarly titled measures used by other companies and should be considered in conjunction with net
earnings from continuing operations.

Below are reconciliations of net earnings to EBITDAX and a further reconciliation to Field-Level Cash

Margin.

2019

2018

2017

Net earnings (loss) (GAAP)
Net (earnings) loss from discontinued operations, net of tax
Financing costs, net
Income tax expense (benefit)
Exploration expenses
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
Share-based compensation
Derivative and financial instrument non-cash valuation changes
Restructuring and transaction costs
Accretion on discounted liabilities and other
EBITDAX (non-GAAP)
Marketing revenues and expenses, net
Commodity derivative cash settlements
General and administration expenses, cash-based

(353)
274
250
(30)
58
1,497
—
(48)
83
623
84
5
2,443
(53)
(170)
392

3,224
(2,510)
580
230
128
1,228
156
(278)
104
(938)
97
54
2,075
(33)
420
470

Field-level cash margin (non-GAAP)

2,612

2,932

1,078
(1,045)
321
7
346
1,008
—
(219)
121
70
—
(12)
1,675
46
(115)
524

2,130

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 our potential exposure to market risks. The term “market risk” refers to our risk of loss arising
from adverse changes in oil, gas and NGL prices, interest rates and foreign currency exchange rates. The following
disclosures are not meant to be precise indicators of expected future losses but rather indicators of reasonably
possible losses. This forward-looking information provides indicators of how we view and manage our ongoing
market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than
speculative trading.

Commodity Price Risk

Our major market risk exposure is the pricing applicable to our oil, gas and NGL production. Realized pricing

is primarily driven by the prevailing worldwide price for crude oil and spot market prices applicable to our gas and
NGL production. Pricing for oil and gas production has been volatile and unpredictable as discussed in “Item 1A.
Risk Factors” of this report. Consequently, we systematically hedge a portion of our production through various
financial transactions. The key terms to our oil and gas derivative financial instruments as of December 31, 2019 are
presented in Note 3 in “Item 8. Financial Statements and Supplementary Data” of this report.

The fair values of our commodity derivatives are largely determined by estimates of the forward curves of the

relevant price indices. At December 31, 2019, a 10% change in the forward curves associated with our commodity
derivative instruments would have changed our net asset positions by approximately $115 million.

Interest Rate Risk

At December 31, 2019, we had total debt of $4.3 billion. All of our debt is based on fixed interest rates

averaging 6.0%.

Foreign Currency Risk

Devon has certain Canadian dollar obligations associated with its divested Canadian operations which are to

be paid with the cash restricted for discontinued operations. These balances are remeasured using the applicable
exchange rate as of the end of the reporting period. A 10% unfavorable change in the Canadian-to-U.S. dollar
exchange rate would not have materially impacted our December 31, 2019 balance sheet for these items. See Note
18 in “Item 8. Financial Statements and Supplementary Data” in this report for additional information.

Item 8. Financial Statements and Supplementary Data

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND CONSOLIDATED FINANCIAL STATEMENT SCHEDULES

Report of Independent Registered Public Accounting Firm

Consolidated Financial Statements

Consolidated Statements of Comprehensive Earnings
Consolidated Statements of Cash Flows
Consolidated Balance Sheets
Consolidated Statements of Equity
Notes to Consolidated Financial Statements

Note 1 – Summary of Significant Accounting Policies
Note 2 – Divestitures
Note 3 – Derivative Financial Instruments
Note 4 – Share-Based Compensation
Note 5 – Asset Impairments
Note 6 – Restructuring and Transaction Costs
Note 7 – Income Taxes
Note 8 – Net Earnings (Loss) Per Share From Continuing Operations
Note 9 – Other Comprehensive Earnings
Note 10 – Supplemental Information to Statements of Cash Flows
Note 11 – Accounts Receivable
Note 12 – Property, Plant and Equipment
Note 13 – Debt and Related Expenses
Note 14 – Leases
Note 15 – Asset Retirement Obligations
Note 16 – Retirement Plans
Note 17 – Stockholders’ Equity
Note 18 – Discontinued Operations and Assets Held For Sale
Note 19 – Commitments and Contingencies
Note 20 – Fair Value Measurements
Note 21 – Supplemental Information on Oil and Gas Operations (Unaudited)
Note 22 – Supplemental Quarterly Financial Information (Unaudited)

54
55
56
57
58
58
67
68
69
72
72
73
76
77
77
78
78
79
81
83
84
87
89
93
95
96
101

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.

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors
Devon Energy Corporation:

Opinions on the Consolidated Financial Statements and Internal Control Over Financial Reporting

We have audited the accompanying consolidated balance sheets of Devon Energy Corporation and subsidiaries (the
Company) as of December 31, 2019 and 2018, the related consolidated statements of comprehensive earnings,
equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes
(collectively, the consolidated financial statements). We also have audited the Company’s internal control over
financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated
Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the
financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash
flows for each of the years in the three-year period ended December 31, 2019, in conformity with U.S. generally
accepted accounting principles. Also in our opinion, the Company maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2019 based on criteria established in Internal Control –
Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Changes in Accounting Principles

As discussed in Note 14 to the consolidated financial statements, the Company has changed its method of
accounting for leases in 2019 due to the adoption of Accounting Standards Update 2016-02, Leases (Topic 842).

As discussed in Note 1 to the consolidated financial statements, the Company has changed its method of accounting
for revenue in 2018 due to the adoption of Accounting Standards Codification 606, Revenue from Contracts with
Customers (ASC 606).

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 Annual Report on Internal Control Over Financial
Reporting contained in “Item 9A. Controls and Procedures.” Our responsibility is to express an opinion on the
Company’s consolidated financial statements and an opinion 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 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 (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s
assets that could have a material effect on the financial statements.

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

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated
financial statements that were communicated or required to be communicated to the audit committee and that: (1)
relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our
especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter
in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by
communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the
accounts or disclosures to which they relate.

Evaluation of the estimate of proved and unproved oil and gas reserves used to assess the recoverability of the
carrying value of oil and gas properties in the STACK common operating field

As discussed in Notes 1, 5, and 12 to the consolidated financial statements, the Company performs
recoverability tests for the carrying value of its proved oil and gas properties subject to amortization. The
recoverability tests are performed on an annual basis or more often if events and circumstances indicate that the
carrying value of such properties may not be recoverable. The determination of the undiscounted cash flows is
driven by the underlying estimate of proved and unproved oil and gas reserves for oil and gas properties as
determined by the Company’s internal reservoir engineers. Estimating common operating fields’ future cash
flows requires the expertise of reservoir engineers who take into consideration the estimate of future production
quantities, future operating and capital cost assumptions, and projected oil and gas prices inclusive of market
differentials. The STACK common operating field had a carrying value of $3.7 billion as of December 31,
2019.

We identified the evaluation of the estimate of proved and unproved oil and gas reserves used to assess the
recoverability of the carrying value of the STACK common operating field’s oil and gas properties as a critical
audit matter. Based on current and forecasted commodity prices and costs, production volumes and drilling
plans, and the risk adjustment factors associated with the unproved reserve volumes, the STACK common
operating field required more judgment to evaluate the estimate of both proved and unproved oil and gas
reserves used in determining undiscounted future net cash flows for the asset group.

The primary procedures we performed to address this critical audit matter included the following. We tested
certain internal controls over the Company’s processes to develop and monitor the estimate of proved and
unproved oil and gas reserves used to determine future cash flows. We assessed compliance of the methodology
used by the Company’s internal reservoir engineers and external reservoir engineers to estimate proved and
unproved oil and gas reserves with industry and regulatory standards. To assess the Company’s ability to
accurately estimate future proved and unproved production quantities, we compared the future production
quantity assumptions used by the Company in prior periods to the actual production amounts in the current year
and the year-end forecasted future production quantities. We compared the estimated future proved and
unproved production quantities used by the Company in the current period to historical production trends and
investigated differences. In addition, we assessed the competence, objectivity, and capabilities of the

Company’s internal reservoir engineers and third-party reservoir engineers. We read and considered the report
of the Company’s external reservoir engineers in connection with our evaluation of the Company’s reserve
estimates. We also tested the processes and methodologies used by internal reservoir engineers to estimate
unproved future production quantities. We have compared the risk adjustment factors for unproved reserves
selected by the Company by prospect to the guideline risk adjustment factor ranges by reserve class in
published industry surveys. We have also evaluated the Company’s selected risk adjustment factors by
evaluation of the proximity of the unproved reserves to proved producing reserves. We evaluated the future
operating and capital cost assumptions used by the internal reservoir engineers to estimate future cash flows by
comparing them to historical costs. We also tested the projected oil and gas prices used by the internal reservoir
engineers to estimate future cash flows by comparing those prices to publicly available prices and tested the
relevant market differentials based on past results and any contractual changes in marketing and/or
transportation and processing agreements that would impact future cash flows to be received.

Assessment of the estimate of proved oil and gas reserves used in the depletion of proved oil and gas properties

As discussed in Notes 1 and 12 to the consolidated financial statements, the Company calculates depletion for
its proved oil and gas properties subject to amortization using a units-of-production method. The rates used to
deplete the balance of oil and gas properties subject to amortization are set using the estimate of proved oil and
gas reserves by common operating field. Under the units-of-production method, a rate is set annually using the
beginning of year balance of oil and gas properties subject to amortization and estimated proved oil and gas
reserves for each common operating field. That rate is then applied to production throughout the year to
determine the amount of depletion expense to be recorded by common operating field. The Company’s internal
reservoir engineers estimate proved oil and gas reserves, and the Company engages external reservoir engineers
to perform an independent evaluation of a portion of the estimates of proved oil and gas reserves. These
common operating fields had depletion expense of $1.4 billion for the year ended December 31, 2019.

We identified the assessment of the estimate of proved oil and gas reserves used in the depletion of proved oil
and gas properties as a critical audit matter. There was a high degree of subjectivity in evaluating the
Company’s estimate of the proved oil and gas reserves used as an input to determine depletion for each
common operating field.

The primary procedures we performed to address this critical audit matter including the following. We tested
certain internal controls over the Company’s depletion expense calculation process, including controls related to
the determination and monitoring of the estimate of proved oil and gas reserves. We analyzed the grouping of
costs and proved oil and gas reserves by common operating field. We analyzed and assessed the determination
of depletion expense for compliance with industry and regulatory standards. To assess the Company’s ability to
accurately estimate proved oil and gas reserves, we compared the estimated future production quantities
assumptions used by the Company in prior periods to the actual production amounts received and the year-end
future production quantities forecasted. We compared the estimated future production quantities used by the
Company in the current period to historical production trends and investigated differences. In addition, we
assessed the competence, objectivity, and capabilities of the Company’s internal reservoir engineers and the
Company’s external reservoir engineers. We read and considered the report of the Company’s third-party
reservoir engineers in connection with our evaluation of the Company’s reserve estimates.

/s/ KPMG LLP

We have served as the Company’s auditor since 1980.

Oklahoma City, Oklahoma
February 19, 2020

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE EARNINGS

Upstream revenues
Marketing and midstream revenues

Total revenues
Production expenses
Exploration expenses
Marketing and midstream expenses
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
General and administrative expenses
Financing costs, net
Restructuring and transaction costs
Other expenses

Total expenses

Earnings (loss) from continuing operations before income taxes

Income tax expense (benefit)

Net earnings (loss) from continuing operations
Net earnings (loss) from discontinued operations, net of income
taxes
Net earnings (loss)
Net earnings attributable to noncontrolling interests
Net earnings (loss) attributable to Devon
Basic net earnings (loss) per share:

Basic earnings (loss) from continuing operations per share
Basic earnings (loss) from discontinued operations per share
Basic net earnings (loss) per share
Diluted net earnings (loss) per share:

Diluted earnings (loss) from continuing operations per share
$
Diluted earnings (loss) from discontinued operations per share
$
Diluted net earnings (loss) per share

2019

2017

Year Ended December 31,
2018
(Millions, except per share amounts)
3,355 $
2,865
6,220
1,197
58
2,812
1,497
—
(48)
475
250
84
4
6,329
(109)
(30)
(79)

4,542 $
4,354
8,896
1,153
128
4,321
1,228
156
(278)
574
580
97
(7)
7,952
944
230
714

(274)
(353)
2
(355) $

(0.21) $
(0.68)
(0.89) $

2,510
3,224
160
3,064 $

1.43 $
4.71
6.14 $

1.42 $
4.68
6.10 $

2,988
3,513
6,501
791
346
3,559
1,008
—
(219)
645
321
—
10
6,461
40
7
33

1,045
1,078
180
898

0.06
1.65
1.71

0.06
1.64
1.70

Comprehensive earnings (loss):

Net earnings (loss)
Other comprehensive earnings (loss), net of tax:

(353) $

3,224 $

1,078

Foreign currency translation, discontinued operations
Release of Canadian cumulative translation adjustment,
discontinued operations
Pension and postretirement plans

Other comprehensive earnings (loss), net of tax
Comprehensive earnings (loss):
Comprehensive earnings attributable to noncontrolling interests
$
Comprehensive earnings (loss) attributable to Devon

(152)

(1,237)
13
(1,146)
(1,499)
2
(1,501) $

—
44
(108)
3,116
160
2,956 $

—
29
112
1,190
180
1,010

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

Year Ended December 31,
2018

2017

2019

Cash flows from operating activities:

Net earnings (loss)
Adjustments to reconcile net earnings (loss) to net cash from operating activities:

(353) $

3,224 $

1,078

Net (earnings) loss from discontinued operations, net of income taxes
Depreciation, depletion and amortization
Asset impairments
Leasehold impairments
Accretion on discounted liabilities
Total (gains) losses on commodity derivatives
Cash settlements on commodity derivatives
Gains on asset dispositions
Deferred income tax expense (benefit)
Share-based compensation
Early retirement of debt
Other
Changes in assets and liabilities, net

Net cash from operating activities - continuing operations

Cash flows from investing activities:

Capital expenditures
Acquisitions of property and equipment
Divestitures of property and equipment
Net cash from investing activities - continuing operations

Cash flows from financing activities:
Repayments of long-term debt
Early retirement of debt
Repurchases of common stock
Dividends paid on common stock
Contributions from noncontrolling interests
Shares exchanged for tax withholdings
Other
Net cash from financing activities - continuing operations

Net change in cash, cash equivalents and restricted cash of continuing operations
Cash flows from discontinued operations:

Operating activities
Investing activities
Financing activities
Effect of exchange rate changes on cash

Net change in cash, cash equivalents and restricted cash of discontinued operations
Net change in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period

Reconciliation of cash, cash equivalents and restricted cash:

Cash and cash equivalents
Cash restricted for discontinued operations
Restricted cash included in other current assets
Cash and cash equivalents included in current assets associated with
discontinued operations

Total cash, cash equivalents and restricted cash

274
1,497
—
18
33
454
166
(48)
(25)
115
—
(6)
(82)
2,043

(1,910)
(31)
390
(1,551)

(162)
—
(1,849)
(140)
116
(25)
(1)
(2,061)
(1,569)

28
2,472
(1,578)
45
967
(602)
2,446
1,844 $

(2,510)
1,228
156
94
27
(457)
(420)
(278)
247
137
312
(19)
(158)
1,583

(2,116)
(55)
500
(1,671)

(922)
(304)
(2,956)
(149)
—
(39)
(7)
(4,377)
(4,465)

1,121
2,726
174
206
4,227
(238)
2,684
2,446 $

1,464 $
380
—

2,414 $
—
32

—
1,844 $

—
2,446 $

(1,045)
1,008
—
219
27
(66)
115
(219)
(2)
126
—
(8)
10
1,243

(1,614)
(44)
425
(1,233)

—
—
—
(127)
—
(46)
—
(173)
(163)

1,666
(966)
182
6
888
725
1,959
2,684

2,642
—
11

31
2,684

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

December 31, 2019

December 31, 2018

Current assets:

ASSETS

Cash and cash equivalents
Cash restricted for discontinued operations
Accounts receivable
Current assets associated with discontinued operations
Other current assets

Total current assets

Oil and gas property and equipment, based on successful efforts
accounting, net
Other property and equipment, net ($80 million related to CDM in 2019)

Total property and equipment, net

Goodwill
Right-of-use assets
Other long-term assets
Long-term assets associated with discontinued operations
Total assets

LIABILITIES AND EQUITY

Current liabilities:

Accounts payable
Revenues and royalties payable
Short-term debt
Current liabilities associated with discontinued operations
Other current liabilities

Total current liabilities

Long-term debt
Lease liabilities
Asset retirement obligations
Other long-term liabilities
Long-term liabilities associated with discontinued operations
Deferred income taxes
Stockholders' equity:

Common stock, $0.10 par value. Authorized 1.0 billion shares; issued
382 million and 450 million shares in 2019 and 2018, respectively
Additional paid-in capital
Retained earnings
Accumulated other comprehensive earnings (loss)
Treasury stock, at cost, 1.0 million shares in 2018

Total stockholders’ equity attributable to Devon

Noncontrolling interests

Total equity
Total liabilities and equity

1,464 $
380
832
896
279
3,851

7,558
1,035
8,593
753
243
196
81
13,717 $

428 $
730
—
459
310
1,927
4,294
244
380
426
185
341

38
2,735
3,148
(119)
—
5,802
118
5,920
13,717 $

2,414
—
812
331
880
4,437

7,430
1,032
8,462
753
—
276
5,638
19,566

530
722
162
492
320
2,226
4,292
—
468
411
2,454
529

45
4,486
3,650
1,027
(22)
9,186
—
9,186
19,566

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF EQUITY

Retained
Additional Earnings
Common Stock Paid-In (Accumulated Earnings
Shares Amount Capital

Other
Comprehensive

Deficit)

(Loss)

523 $
—

52 $
—

7,237 $
—

(69) $
898

Treasury Noncontrolling Total
Stock
— $
—

Equity
4,448 $ 12,722
180 1,078

Interests

1,054 $
—

—

112

—

112

Balance as of December 31, 2016

Net earnings
Other comprehensive earnings,
net of tax
Restricted stock grants, net of
cancellations
Common stock repurchased
Common stock retired
Common stock dividends
Share-based compensation
Subsidiary equity transactions
Distributions to noncontrolling
interests

Balance as of December 31, 2017

Net earnings
Other comprehensive loss, net of tax
Restricted stock grants, net of
cancellations
Common stock repurchased
Common stock retired
Common stock dividends
Share-based compensation
Divestment of subsidiary equity
investment
Subsidiary equity transactions
Distributions to noncontrolling
interests
Other

Balance as of December 31, 2018

1
—
—
—
1
—

—
525 $

—
—

3
—
(79)
—
1

—
—

—
—
450 $

Effect of adoption of lease accounting —
—
Net earnings (loss)
Other comprehensive loss, net of tax
—
Restricted stock grants, net of
cancellations
Common stock repurchased
Common stock retired
Common stock dividends
Share-based compensation
Contributions from noncontrolling
interests

3
—
(71)
—
—

—

1
—
—
—
—
—

—
53 $

—
—

—
—
(8)
—
—

—
—

—
—
45 $

—
—
—

—
—
(7)
—
—

—

—
—
(44)
—
126
14

—
7,333 $

—
—

—
—
(2,987)
—
140

—
—

—
—
4,486 $

—
—
—

—
—
(1,867)
—
116

—
—
—
(127)
—
—

—
702 $

3,064
—

—
—
—
(149)
—

—
—

—
33
3,650 $

(7)
(355)
—

—
—
—
(140)
—

—

—
—
—
—
—
—

—
1,166 $

—
(108)

—
—
—
—
—

2
—

—
(33)
1,027 $

—
—
(1,146)

—
—
—
—
—

—

—
(44)
44
—
—
—

—
— $

—
—

—
(3,017)
2,995
—
—

—
—

—
—
(22) $

—
—
—

—
(1,852)
1,874
—
—

—
—
—
—
—
576

1
(44)
—
(127)
126
590

(354)
(354)
4,850 $ 14,104

160 3,224
(108)

—

—
—
— (3,017)
—
—
(149)
—
140
—

(4,863) (4,861)
72

(219)
(219)
—
—
— $ 9,186

(7)
—
2
(353)
— (1,146)

—
—
— (1,852)
—
—
(140)
—
116
—

—

— $

116

118 $ 5,920

Balance as of December 31, 2019

382 $

38 $

2,735 $

3,148 $

(119) $

See accompanying notes to consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Summary of Significant Accounting Policies

Devon is a leading independent energy company engaged primarily in the exploration, development and

production of oil, natural gas and NGLs. Devon’s operations are concentrated in various onshore areas in the U.S.

As further discussed in Note 18, Devon reached an agreement to sell its Barnett Shale assets in December
2019, sold its Canadian operations on June 27, 2019 and sold its ownership interests in EnLink and the General
Partner on July 18, 2018. Activity relating to Devon’s Barnett Shale assets, inclusive of properties divested as partial
sales of the Barnett Shale common operating field in previous reporting periods located primarily in Johnson and
Wise counties, Texas, Canadian operations and EnLink and the General Partner are classified as discontinued
operations within Devon’s consolidated statements of comprehensive earnings and consolidated statements of cash
flows. The associated assets and liabilities of Devon’s Barnett Shale assets and Canadian operations are presented as
assets and liabilities associated with discontinued operations on the consolidated balance sheets.

Accounting policies used by Devon and its subsidiaries conform to accounting principles generally accepted

in the U.S. and reflect industry practices. The more significant of such policies are discussed below.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Devon, entities in which it holds
a controlling interest and VIEs for which Devon is the primary beneficiary. All intercompany transactions have been
eliminated. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a
proportionate basis. Investments in non-controlled entities, over which Devon has the ability to exercise significant
influence over operating and financial policies, are accounted for using the equity method. In applying the equity
method of accounting, the investments are initially recognized at cost and subsequently adjusted for Devon’s
proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity
method and cost method are reported as a component of other long-term assets.

Devon entered into an agreement in the fourth quarter of 2019 to form Cotton Draw Midstream, L.L.C. or,

“CDM”, a partnership in the Delaware Basin with an affiliate of QL Capital Partners, LP (“QLCP”). As part of this
transaction, Devon contributed gathering system and compression assets in the Cotton Draw area to CDM in
exchange for a $100 million cash distribution funded by QLCP. Devon will continue to operate the assets pursuant
to the management services agreement. QLCP has also committed $40 million of expansion capital to CDM to fund
the build out of the assets over the next several years. Devon holds a controlling interest in CDM and the portions of
CDM’s net earnings and equity not attributable to Devon’s controlling interest are shown separately as
noncontrolling interests in the accompanying consolidated statements of comprehensive earnings and consolidated
balance sheets. CDM is considered a VIE to Devon.

Devon, through its controlling interest in CDM, has the power to direct the activities that significantly affect
the economic performance of CDM and the obligation to absorb losses or the right to receive benefits that could be
significant to CDM; therefore, Devon is considered the primary beneficiary and consolidates CDM. CDM maintains
its own capital structure that is separate from Devon.

The assets of CDM cannot be used by Devon for general corporate purposes and are included in and disclosed
parenthetically on Devon's consolidated balance sheets. The carrying amount of liabilities related to CDM for which
the creditors do not have recourse to Devon's assets are also included in and disclosed parenthetically on Devon's
consolidated balance sheets, if material.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Segment Information

Subsequent to the sale of Devon’s Canadian business in 2019 discussed in Note 18, Devon’s oil and gas

exploration and production activities are solely focused in the U.S. For financial reporting purposes, Devon
aggregates its U.S. operating segments into one reporting segment due to the similar nature of its business. With the
reclassification of Devon’s Canadian operations to discontinued operations and assets and liabilities associated with
discontinued operations, Devon now has one reporting segment, which is reflected in the consolidated financial
statements.

Use of Estimates

The preparation of financial statements requires management to make estimates and assumptions that affect

the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during the reporting period. Actual amounts
could differ from these estimates, and changes in these estimates are recorded when known. Significant items
subject to such estimates and assumptions include the following:

•

proved reserves and related present value of future net revenues;

evaluation of suspended well costs;

the carrying and fair values of oil and gas properties, other property and equipment and product and
equipment inventories;

derivative financial instruments;

the fair value of reporting units and related assessment of goodwill for impairment;

income taxes;

asset retirement obligations;

obligations related to employee pension and postretirement benefits;

legal and environmental risks and exposures; and

general credit risk associated with receivables and other assets.

Revenue Recognition

Impact of ASC 606 Adoption

In January 2018, Devon adopted ASC 606 – Revenue from Contracts with Customers (ASC 606) using the
modified retrospective method and applied the standard to all existing contracts at adoption. ASC 606 supersedes
previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict
the transfer of goods or services to customers in an amount that reflects the consideration in exchange for those
goods or services.

The changes to upstream revenues and production expenses were due to the conclusion that Devon represents

the principal and controls a promised product before transferring it to the ultimate third party customer in
accordance with the control model in ASC 606. This was a change from previous conclusions reached for these
agreements utilizing the principal versus agent indicators under ASC 605 where the assessment was focused on
Devon passing title and not control to the processing entity and Devon ultimately receiving a net price from the
third-party end customer. As a result, Devon changed the presentation of revenues and expenses for these
agreements. Revenues related to these agreements are presented on a gross basis for amounts expected to be
received from third-party customers through the marketing process. Gathering, processing and transportation
expenses related to these agreements, incurred prior to the transfer of control to the customer at the tailgate of the
natural gas processing facilities, are presented as production expenses. During 2018, these changes resulted in a
$191 million increase to upstream revenues and production expenses with no impact to net earnings. As a result of
the adoption of ASC 606, Devon’s marketing and midstream revenues and marketing and midstream expenses were
not impacted.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Upstream Revenues

Upstream revenues include the sale of oil, gas and NGL production. Oil, gas and NGL sales are recognized

when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has
transferred and collectability of the revenue is probable. Devon’s performance obligations are satisfied at a point in
time. This occurs when control is transferred to the purchaser upon delivery of contract specified production
volumes at a specified point. The transaction price used to recognize revenue is a function of the contract billing
terms. Revenue is invoiced, if required, by calendar month based on volumes at contractually based rates with
payment typically received within 30 days of the end of the production month. Taxes assessed by governmental
authorities on oil, gas and NGL sales are presented separately from such revenues in the accompanying consolidated
statements of comprehensive earnings.

Oil sales

Devon’s oil sales contracts are generally structured in one of two ways. First, production is sold at the

wellhead at an agreed-upon index price, net of pricing differentials. In this scenario, revenue is recognized when
control transfers to the purchaser at the wellhead at the net price received. Alternatively, production is delivered to
the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title and risk of
loss of the product. Under this arrangement, a third party is paid to transport the product and Devon receives a
specified index price from the purchaser with no transportation deduction. In this scenario, revenue is recognized
when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The
third-party costs are recorded as gathering, processing and transportation expense as a component of production
expenses in the consolidated statements of comprehensive earnings.

Natural gas and NGL sales

Under Devon’s natural gas processing contracts, natural gas is delivered to a midstream processing entity at
the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and
processes the natural gas and remits proceeds for the resulting sales of NGLs and residue gas. In these scenarios,
Devon evaluates whether it is the principal or the agent in the transaction. Devon has concluded it is the principal
under these contracts and the ultimate third party is the customer. Revenue is recognized on a gross basis, with
gathering, processing and transportation fees presented as a component of production expenses in the consolidated
statements of comprehensive earnings.

In certain natural gas processing agreements, Devon may elect to take residue gas and/or NGLs in-kind at the

tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing
process, the product is delivered to the ultimate third-party purchaser at a contractually agreed-upon delivery point,
and Devon receives a specified index price from the purchaser. In this scenario, revenue is recognized when control
transfers to the purchaser at the delivery point based on the index price received from the purchaser. The gathering,
processing and compression fees attributable to the gas processing contract, as well as any transportation fees
incurred to deliver the product to the purchaser, are presented as gathering, processing and transportation expense as
a component of production expenses in the consolidated statements of comprehensive earnings.

Marketing Revenues

Marketing revenues are generated primarily as a result of Devon selling commodities purchased from third

parties. Marketing revenues are recognized when performance obligations are satisfied. This occurs at the time
contract-specified products are sold to third parties at a contractually fixed or determinable price, delivery occurs at
a specified point or performance has occurred, control has transferred and collectability of the revenue is probable.
The transaction price used to recognize revenue and invoice customers is based on a contractually stated fee or on a
third party published index price plus or minus a known differential. Devon typically receives payment for invoiced
amounts within 30 days. Marketing revenues and expenses attributable to oil, gas and NGL purchases are reported
on a gross basis when Devon takes control of the products and has risks and rewards of ownership.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Satisfaction of Performance Obligations and Revenue Recognitions

Because Devon has a right to consideration from its customers in amounts that correspond directly to the

value that the customer receives from the performance completed on each contract, Devon recognizes revenue for
sales at the time the crude oil, natural gas or NGLs are delivered at a fixed or determinable price.

Transaction Price Allocated to Remaining Performance Obligations

Most of Devon’s contracts are short-term in nature with a contract term of one year or less. Devon applies the
practical expedient in ASC 606 exempting the disclosure of the transaction price allocated to remaining performance
obligations if the performance obligation is part of a contract that has an original expected duration of one year or
less. For contracts with terms greater than one year, Devon applies the practical expedient in ASC 606 exempting
the disclosure of the transaction price allocated to remaining performance obligations if the variable consideration is
allocated entirely to a wholly unsatisfied performance obligation. Under Devon’s contracts, each unit of product
typically represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and
disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

Cash received relating to future performance obligations is deferred and recognized when all revenue
recognition criteria are met. Contract liabilities generated from such deferred revenue are not considered material as
of December 31, 2019. Devon’s product sales and marketing contracts do not give rise to contract assets.

Disaggregation of Revenue

The following table presents revenue from contracts with customers that are disaggregated based on the type

of good.

Oil
Gas
NGL

Oil, gas and NGL revenues from
contracts with customers
Oil, gas and NGL derivatives

Upstream revenues

Oil
Gas
NGL

Total marketing revenues from
contracts with customers

Total revenues

Customers

Year Ended December 31,

2019

2018

2,988 $

391
430

3,809
(454)
3,355

1,534
645
686

2,865

6,220 $

2,941
482
662

4,085
457
4,542

2,745
738
871

4,354

8,896

During 2019 and 2017, no purchaser accounted for more than 10% of Devon’s consolidated sales revenue.

During 2018, Devon had one purchaser that accounted for approximately 11% of Devon’s consolidated sales

revenue.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Derivative Financial Instruments

Devon is exposed to certain risks relating to its ongoing business operations, including risks related to
commodity prices and interest rates. As discussed more fully below, Devon uses derivative instruments primarily to
manage commodity price risk and interest rate risk. Devon does not intend to issue or hold derivative financial
instruments for speculative trading purposes.

Devon enters into derivative financial instruments with respect to a portion of its oil, gas and NGL production

to hedge future prices received. These instruments are used to manage the inherent uncertainty of future revenues
resulting from commodity price volatility. Devon’s derivative financial instruments typically include financial price
swaps, basis swaps and costless price collars. Under the terms of the price swaps, Devon receives a fixed price for
its production and pays a variable market price to the contract counterparty. For the basis swaps, Devon receives a
fixed differential between two regional index prices and pays a variable differential on the same two index prices to
the contract counterparty. For price collars, Devon utilizes two-way price collars. The two-way price collars set a
floor and ceiling price for the hedged production. If the applicable monthly price indices are outside of the ranges set
by the floor and ceiling prices in the various collars, Devon will cash-settle the difference with the counterparty.

Devon periodically enters into interest rate swaps to manage its exposure to interest rate volatility. As of

December 31, 2019, Devon did not have any open interest rate swap contracts.

All derivative financial instruments are recognized at their current fair value as either assets or liabilities in the

balance sheet. Changes in the fair value of these derivative financial instruments are recorded in earnings unless
specific hedge accounting criteria are met. For derivative financial instruments held during the three-year period
ended December 31, 2019, Devon chose not to meet the necessary criteria to qualify its derivative financial
instruments for hedge accounting treatment. Cash settlements with counterparties on Devon’s derivative financial
instruments are also recorded in earnings.

By using derivative financial instruments to hedge exposures to changes in commodity prices and interest
rates, Devon is exposed to credit risk. Credit risk is the failure of the counterparty to perform under the terms of the
derivative contract. To mitigate this risk, the hedging instruments are placed with a number of counterparties whom
Devon believes are acceptable credit risks. It is Devon’s policy to enter into derivative contracts only with
investment-grade rated counterparties deemed by management to be competent and competitive market makers.
Additionally, Devon’s derivative contracts generally require cash collateral to be posted if either its or the
counterparty’s credit rating falls below certain credit rating levels. As of December 31, 2019, Devon held no cash
collateral of its counterparties nor posted collateral to its counterparties.

General and Administrative Expenses

G&A is reported net of amounts reimbursed by working interest owners of the oil and gas properties operated

by Devon.

Share-Based Compensation

Devon grants share-based awards to members of its Board of Directors, management and employees. All such

awards are measured at fair value on the date of grant and are generally recognized as a component of G&A in the
accompanying consolidated statements of comprehensive earnings over the applicable requisite service periods. As a
result of Devon’s restructuring activity discussed in Note 6, certain share-based awards were accelerated and
recognized as a component of restructuring and transaction costs in the accompanying consolidated statements of
comprehensive earnings.

Generally, Devon uses new shares from approved incentive programs to grant share-based awards and to issue

shares upon stock option exercises. Shares repurchased under approved programs are generally available to be
issued as part of Devon’s share-based awards. However, Devon has historically canceled these shares upon
repurchase.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Income Taxes

Devon is subject to current income taxes assessed by the federal and various state jurisdictions in the U.S. and

by other foreign jurisdictions. In addition, Devon accounts for deferred income taxes related to these jurisdictions
using the asset and liability method. Under this method, deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between the financial statement carrying amounts of assets and
liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary differences and carryforwards are
expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date.

Deferred tax assets are also recognized for the future tax benefits attributable to the expected utilization of

existing tax net operating loss carryforwards and other types of carryforwards. If the future utilization of some
portion of the deferred tax assets is determined to be unlikely, a valuation allowance is provided to reduce the
recorded tax benefits from such assets. Devon periodically weighs the positive and negative evidence to determine if
it is more likely than not that some or all of the deferred tax assets will be realized. Forming a conclusion that a
valuation allowance is not required is difficult when there is negative evidence, such as cumulative losses in recent
years. See Note 7 for further discussion.

Devon recognizes the financial statement effects of tax positions when it is more likely than not, based on the

technical merits, that the position will be sustained upon examination by a taxing authority. Recognized tax
positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of
being realized upon ultimate settlement with a taxing authority. Liabilities for unrecognized tax benefits related to
such tax positions are included in other long-term liabilities unless the tax position is expected to be settled within
the upcoming year, in which case the liabilities are included in other current liabilities. Interest and penalties related
to unrecognized tax benefits are included in current income tax expense.

Devon estimates its annual effective income tax rate in recording its provision for income taxes in the various
jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as
discrete items in the period in which they occur.

Net Earnings (Loss) Per Share Attributable to Devon

Devon’s basic earnings per share amounts have been computed based on the average number of shares of
common stock outstanding for the period. Basic earnings per share includes the effect of participating securities,
which primarily consist of Devon’s outstanding restricted stock awards, as well as performance-based restricted
stock awards that have met the requisite performance targets. Diluted earnings per share is calculated using the
treasury stock method to reflect the assumed issuance of common shares for all potentially dilutive securities. Such
securities primarily consist of unvested performance share units.

Cash and Cash Equivalents

Devon considers all highly liquid investments with original contractual maturities of three months or less to be

cash equivalents.

Cash Restricted for Discontinued Operations

In conjunction primarily with the sale of its Canadian operations in June 2019, approximately $380 million of
Devon’s cash balance is restricted for funding certain tax and other obligations related to the disposed assets. Other
obligations primarily relate to abandoned firm transportation and office lease agreements. This cash is not legally
restricted and can be used by Devon for other general corporate purposes. However, it has been designated to settle
retained obligations associated with discontinued operations.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Accounts Receivable

Devon’s accounts receivable balance primarily consists of oil and gas sales receivables, marketing and
midstream revenue receivables and joint interest receivables for which Devon does not require collateral security.
Devon has established an allowance for bad debts equal to the estimable portions of accounts receivable, including
joint interest receivables, for which failure to collect is considered probable. When a portion of the receivable is
deemed uncollectible, the write-off is made against the allowance.

Property and Equipment

Oil and Gas Property and Equipment

Devon follows the successful efforts method of accounting for its oil and gas properties. Exploration costs,
such as exploratory geological and geophysical costs, and costs associated with nonproductive exploratory wells,
delay rentals and exploration overhead are charged against earnings as incurred. Costs of drilling successful
exploratory wells along with acquisition costs and the costs of drilling development wells, including those that are
unsuccessful, are capitalized. Devon groups its oil and gas properties with a common geological structure or
stratigraphic condition (“common operating field”) for purposes of computing DD&A, assessing proved property
impairments and accounting for asset dispositions.

Exploratory drilling costs and exploratory-type stratigraphic test wells are initially capitalized, or suspended,

pending the determination of proved reserves. If proved reserves are found, drilling costs remain capitalized as
proved properties. Costs of unsuccessful wells are charged to exploration expense. For exploratory wells that find
reserves that cannot be classified as proved when drilling is completed, costs continue to be capitalized as suspended
exploratory well costs if there have been sufficient reserves found to justify completion as a producing well and
sufficient progress is being made in assessing the reserves and the economic and operating viability of the project. If
management determines that future appraisal drilling or development activities are unlikely to occur, associated
suspended exploratory well costs are expensed. In some instances, this determination may take longer than one year.
Devon reviews the status of all suspended exploratory drilling costs quarterly.

Capitalized costs of proved oil and gas properties are depleted by an equivalent unit-of-production method,

converting gas to oil at the ratio of six Mcf of gas to one Bbl of oil. Proved leasehold acquisition costs, less
accumulated amortization, are depleted over total proved reserves, which includes proved undeveloped reserves.
Capitalized costs of wells and related equipment and facilities, including estimated asset retirement costs, net of
estimated salvage values and less accumulated amortization are depreciated over proved developed reserves
associated with those capitalized costs. Depletion is calculated by applying the DD&A rate (amortizable base
divided by beginning of period proved reserves) to current period production.

Costs associated with unproved properties are excluded from the depletion calculation until it is determined

whether or not proved reserves can be assigned to such properties. Devon assesses its unproved properties for
impairment annually, or more frequently if events or changes in circumstances dictate that the carrying value of
those assets may not be recoverable. Significant unproved properties are assessed individually.

Proved properties are assessed for impairment annually, or more frequently if events or changes in

circumstances dictate that the carrying value of those assets may not be recoverable. Individual assets are grouped
for impairment purposes based on a common operating field. If there is an indication the carrying amount of an asset
may not be recovered, the asset is assessed for potential impairment by management through an established process.
If, upon review, the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset, the
carrying value is written down to estimated fair value. Because there is usually a lack of quoted market prices for
long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected
future cash flows using discount rates believed to be consistent with those used by principal market participants or
by comparable transactions. The expected future cash flows used for impairment reviews and related fair value
calculations are typically based on judgmental assessments of future production volumes, commodity prices,
operating costs, and capital investment plans, considering all available information at the date of review.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Gains or losses are recorded for sales or dispositions of oil and gas properties which constitute an entire

common operating field or which result in a significant alteration of the common operating field’s DD&A rate.
These gains and losses are classified as asset dispositions in the accompanying consolidated statements of earnings.
Partial common operating field sales or dispositions deemed not to significantly alter the DD&A rates are generally
accounted for as adjustments to capitalized costs with no gain or loss recognized.

Devon capitalizes interest costs incurred that are attributable to material unproved oil and gas properties and

major development projects of oil and gas properties.

Other Property and Equipment

Costs for midstream assets that are in use are depreciated over the assets’ estimated useful lives, using the

straight-line method. Depreciation and amortization of other property and equipment, including corporate and
leasehold improvements, are provided using the straight-line method based on estimated useful lives ranging from
three to 60 years. Interest costs incurred and attributable to major corporate construction projects are also
capitalized.

Asset Retirement Obligations

Devon recognizes liabilities for retirement obligations associated with tangible long-lived assets, such as

producing well sites when there is a legal obligation associated with the retirement of such assets and the amount
can be reasonably estimated. The initial measurement of an asset retirement obligation is recorded as a liability at its
fair value, with an offsetting asset retirement cost recorded as an increase to the associated property and equipment
on the consolidated balance sheet. When the assumptions used to estimate a recorded asset retirement obligation
change, a revision is recorded to both the asset retirement obligation and the asset retirement cost. Devon’s asset
retirement obligations also include estimated environmental remediation costs which arise from normal operations
and are associated with the retirement of such long-lived assets. The asset retirement cost is depreciated using a
systematic and rational method similar to that used for the associated property and equipment.

Goodwill

Goodwill represents the excess of the purchase price of business combinations over the fair value of the net

assets acquired and is tested for impairment annually, or more frequently if events or changes in circumstances
dictate that the carrying value of goodwill may not be recoverable. Such test includes a qualitative assessment to
determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If
the qualitative assessment determines that it is more likely than not that the fair value of a reporting unit is less than
its carrying amount, including goodwill, then a quantitative goodwill impairment test is performed. The quantitative
goodwill impairment test requires the fair value of each reporting unit be compared to the carrying value of the
reporting unit. If the fair value of the reporting unit is less than the carrying value, an impairment charge will be
recognized for the amount by which the carrying amount exceeds the fair value. Because quoted market prices are
not available for Devon’s reporting unit, the fair value of the reporting unit is estimated based upon several valuation
analyses, including comparable companies, comparable transactions and premiums paid.

Devon performed impairment tests of goodwill in the fourth quarters of 2019, 2018 and 2017. No impairment

was required as a result of the annual tests in these time periods.

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded
when it is probable that a liability has been incurred and the amount can be reasonably estimated. Liabilities for
environmental remediation or restoration claims resulting from allegations of improper operation of assets are
recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated.
Expenditures related to such environmental matters are expensed or capitalized in accordance with Devon’s
accounting policy for property and equipment.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Fair Value Measurements

Certain of Devon’s assets and liabilities are measured at fair value at each reporting date. Fair value represents

the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between
market participants. This price is commonly referred to as the “exit price.” Fair value measurements are classified
according to a hierarchy that prioritizes the inputs underlying the valuation techniques. This hierarchy consists of
three broad levels:

•

Level 1 – Inputs consist of unadjusted quoted prices in active markets for identical assets and liabilities
and have the highest priority. When available, Devon measures fair value using Level 1 inputs because
they generally provide the most reliable evidence of fair value.

Level 2 – Inputs consist of quoted prices that are generally observable for the asset or liability. Common
examples of Level 2 inputs include quoted prices for similar assets and liabilities in active markets or
quoted prices for identical assets and liabilities in markets not considered to be active.

Level 3 – Inputs are not observable from objective sources and have the lowest priority. The most
common Level 3 fair value measurement is an internally developed cash flow model.

Foreign Currency Translation Adjustments

The U.S. dollar is the functional currency for Devon’s consolidated operations. Devon’s recently divested
Canadian operations used the Canadian dollar as the functional currency. Assets and liabilities of the Canadian
operations were translated to U.S. dollars using the applicable exchange rate as of the end of a reporting period.
Revenues, expenses and cash flow were translated using an average exchange rate during the reporting period.

The disposition of substantially all of Devon’s Canadian oil and gas assets and operations resulted in Devon
releasing its historical cumulative foreign currency translation adjustment of $1.2 billion from accumulated other
comprehensive earnings to be included within the gain computation.

Noncontrolling Interests

Noncontrolling interests represent third-party ownership in the net assets of Devon’s consolidated subsidiaries

and are presented as a component of equity. Changes in Devon’s ownership interests in subsidiaries that do not
result in deconsolidation are recognized in equity.

Recently Adopted Accounting Standards

In January 2019, Devon adopted ASU 2016-02, Leases (Topic 842), using the modified retrospective method.

See Note 14 for further discussion regarding Devon’s adoption of the leases standard.

The SEC released Final Rule Release No. 33-10618, FAST Act Modernization and Simplification of
Regulation S-K, which amends Regulation S-K to modernize and simplify certain disclosure requirements in a
manner that reduces costs and burdens on registrants while continuing to provide all material information to
investors. The rule became effective May 2, 2019. The rule amended numerous SEC rules, items and forms covering
a diverse group of topics, primarily focusing on reducing or eliminating disclosures. Other than presentation, this
adoption did not have a material impact on Devon’s consolidated financial statements.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Divestitures

Discontinued Operations – Upstream Assets

In February 2019, Devon announced its intent to separate its Canadian business and Barnett Shale assets from
the Company, based on authorizations provided by its Board of Directors. On June 27, 2019, Devon completed the
sale of substantially all of its oil and gas assets and operations in Canada to Canadian Natural Resources Limited for
proceeds, net of purchase price adjustments, of $2.6 billion ($3.4 billion Canadian dollars), and recognized a pre-tax
gain of $223 million ($425 million, net of tax, primarily due to a significant deferred tax benefit). As a part of the
transaction, $436 million of asset retirement obligations were assumed by Canadian Natural Resources Limited. In
aggregate, the total estimated proved reserves associated with these assets were approximately 400 MMBoe, or 21%
of total proved reserves. In conjunction with the Canadian divestiture, Devon recognized approximately
$285 million of restructuring and asset impairment related charges. These costs relate to personnel, office lease
abandonment and a firm transportation agreement abandonment. Additional information on these discontinued
operations can be found in Note 18.

In December 2019, Devon announced the sale of its Barnett Shale assets to BKV for approximately $770
million, before purchase price adjustments. Estimated proved reserves associated with Devon’s Barnett Shale assets
are approximately 45% of total U.S. proved reserves. In connection with the announced sale of its Barnett Shale
assets, Devon recognized a $748 million asset impairment related to these assets, primarily due to the difference
between the net carrying value and the purchase price, net of estimated customary purchase price adjustments. This
transaction is expected to close in the second quarter of 2020. For additional information see Note 18.

During 2018, Devon received proceeds of approximately $500 million and recognized a $26 million net gain
on asset dispositions from the sales of non-core assets in the Barnett Shale, located primarily in Johnson and Wise
counties, Texas. In conjunction with these divestitures, Devon settled certain gas processing contracts and
recognized $40 million in settlement expense, which is included in asset dispositions within the discontinued
operations. For additional information, see Note 18.

Discontinued Operations – EnLink and General Partner

During the third quarter of 2018, Devon completed the sale of its aggregate ownership interests in EnLink and

the General Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax).
The proceeds from the sale were utilized to increase Devon’s share repurchase activities, which are discussed further
in Note 17. Additional information on these discontinued operations can be found in Note 18.

Continuing Operations

During 2019, Devon received proceeds of approximately $390 million and recognized a $48 million net gain

on asset dispositions, primarily from sales of non-core assets in the Permian Basin. In aggregate, the total estimated
proved reserves associated with these divested assets were approximately 54 MMBoe. As of December 31, 2018,
assets and liabilities associated with the Permian Basin divested assets were classified as held for sale in the
accompanying consolidated balance sheet.

During 2018, Devon received proceeds totaling approximately $500 million, primarily from the sales of non-

core assets in the Delaware Basin, and recognized a net gain on asset dispositions of $278 million. In aggregate, the
total estimated proved reserves associated with these divested assets were approximately 24 MMBoe.

During 2017, Devon received proceeds totaling approximately $425 million, and recognized a net gain on asset

dispositions of $219 million. Estimated proved reserves associated with these assets were less than 1% of total U.S.
proved reserves.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Derivative Financial Instruments

Commodity Derivatives

As of December 31, 2019, Devon had the following open oil derivative positions. The first table presents
Devon’s oil derivatives that settle against the average of the prompt month NYMEX WTI futures price. The second
table presents Devon’s oil derivatives that settle against the respective indices noted within the table.

Period
Q1-Q4 2020
Q1-Q4 2021

Price Swaps

Volume
(Bbls/d)

Weighted
Average
Price ($/Bbl)

Volume
(Bbls/d)

Price Collars

Weighted
Average Floor
Price ($/Bbl)

Weighted
Average
Ceiling Price
($/Bbl)

11,238 $
989 $

57.68
54.81

44,932 $
5,942 $

51.30 $
49.59 $

61.36
59.59

Period
Q1-Q4 2020
Q1-Q4 2020

Index
Argus MEH
NYMEX Roll

Oil Basis Swaps

Volume
(Bbls/d)

Weighted Average
Differential to WTI
($/Bbl)

10,000
50,000

$
$

3.38
0.36

As of December 31, 2019, Devon had the following open natural gas derivative positions. The first table
presents Devon’s natural gas derivatives that settle against the Inside FERC first of the month Henry Hub index. The
second table presents Devon’s natural gas derivatives that settle against the respective indices noted within the table.

Period
Q1-Q4 2020

Price Swaps

Volume
(MMBtu/d)

Weighted
Average Price
($/MMBtu)

Volume
(MMBtu/d)

81,409

2.77

42,557

Price Collars
Weighted
Average Floor
Price ($/MMBtu)
2.73

Weighted Average
Ceiling Price
($/MMBtu)

3.03

Natural Gas Basis Swaps

Period
Q1-Q4 2020
Q1-Q4 2020
Q1-Q4 2020

Index

Panhandle Eastern Pipe Line

El Paso Natural Gas
Houston Ship Channel

Volume
(MMBtu/d)
30,000
45,000
10,000

Weighted Average
Differential to
Henry Hub
($/MMBtu)

$
$
$

(0.47)
(0.70)
0.02

As of December 31, 2019, Devon had the following open NGL derivative positions. Devon’s NGL positions

settle against the average of the prompt month OPIS Mont Belvieu, Texas index.

Price Swaps

Period
Q1-Q4 2020
Q1-Q4 2020
Q1-Q4 2020

Product
Natural Gasoline
Normal Butane

Volume (Bbls/d)

Weighted Average
Price ($/Bbl)

1,000 $
1,500 $
4,500 $

44.84
23.56
25.18

Propane

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Financial Statement Presentation

The following table presents the net gains and losses by derivative financial instrument type followed by the

corresponding individual consolidated statements of comprehensive earnings caption.

Commodity derivatives:
Upstream revenues
Marketing and midstream revenues

Interest rate derivatives:
Other expenses

Net gains (losses) recognized

Year Ended December 31,

2019

2018

2017

(454) $
1

—
(453) $

457 $
(1)

65
521 $

67
3

(22)
48

The following table presents the derivative fair values by derivative financial instrument type followed by the

corresponding individual consolidated balance sheet caption.

Commodity derivative assets:

Other current assets
Other long-term assets

Total derivative assets

Commodity derivative liabilities:

Other current liabilities
Other long-term liabilities

Total derivative liabilities

Share-Based Compensation

December 31, 2019 December 31, 2018

49 $
1
50 $

30 $
1
31 $

634
40
674

32
1
33

In 2017, Devon’s stockholders approved the 2017 Plan. The 2017 Plan replaces the 2015 Plan. From the
effective date of the 2017 Plan, no further awards may be made under the 2015 Plan, and awards previously granted
will continue to be governed by the terms of the respective award documents. Subject to the terms of the 2017 Plan,
awards may be made for a total of 33.5 million shares of Devon common stock, plus the number of shares available
for issuance under the 2015 Plan (including shares subject to outstanding awards that were transferred to the 2017
Plan in accordance with its terms). The 2017 Plan authorizes the Compensation Committee, which consists of
independent, non-management members of Devon’s Board of Directors, to grant nonqualified and incentive stock
options, restricted stock awards or units, performance units and stock appreciation rights to eligible employees. The
2017 Plan also authorizes the grant of nonqualified stock options, restricted stock awards or units and stock
appreciation rights to non-employee directors. To calculate the number of shares that may be granted in awards
under the 2017 Plan, options and stock appreciation rights represent one share and other awards represent 2.3 shares.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The vesting for certain share-based awards was accelerated in 2019 and 2018 in conjunction with the
reduction of workforce activities described in Note 6 and is included in restructuring and transaction costs in the
accompanying consolidated statements of comprehensive earnings.

The table below presents the share-based compensation expense included in Devon’s accompanying

consolidated statements of comprehensive earnings.

G&A
Exploration expenses
Restructuring and transaction costs

Total

Related income tax benefit

2019

Year Ended December 31,
2018

2017

$
$

83 $
1
31
115 $
13 $

104 $
2
31
137 $
17 $

121
5
—
126
—

The following table presents a summary of Devon’s unvested restricted stock awards and units, performance-

based restricted stock awards and performance share units granted under the plans.

Restricted Stock
Awards and Units

Awards and
Units

Weighted
Average
Grant-Date
Fair Value

Performance-Based

Restricted Stock Awards
Weighted
Average
Grant-Date
Fair Value

Awards
(Thousands, except fair value data)
35.93
—
38.03
—
33.88

302 $
— $
(149) $
— $
153 $

Performance
Share Units

Weighted
Average
Grant-Date
Fair Value

Units

2,868 $
$
741
$
(145)
(1,309)
$
2,155 (1 ) $

30.14
28.97
37.23
11.91
40.35

Unvested at 12/31/18

Granted
Vested
Forfeited

Unvested at 12/31/19

5,963 $
4,430 $
(4,646) $
(763) $
4,984 $

35.47
25.47
33.48
27.50
29.65

(1) A maximum of 4.3 million common shares could be awarded based upon Devon’s final TSR ranking.

The following table presents the aggregate fair value of awards and units that vested during the indicated

period.

Restricted Stock Awards and Units
Performance-Based Restricted Stock Awards
Performance Share Units

2019

2018

2017

$
$
$

127 $
4 $
4 $

111 $
10 $
20 $

105
10
38

The following table presents the unrecognized compensation cost and the related weighted average

recognition period associated with unvested awards and units as of December 31, 2019.

Unrecognized compensation cost
Weighted average period for recognition (years)

Restricted Stock
Awards and Units
$

80 $
2.5

Performance-Based
Restricted Stock
Awards

Performance
Share Units

— $
1.4

12
1.5

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Restricted Stock Awards and Units

Restricted stock awards and units are subject to the terms, conditions, restrictions and limitations, if any, that

the Compensation Committee deems appropriate, including restrictions on continued employment. Generally, the
service requirement for vesting ranges from one to four years. During the vesting period, recipients of restricted
stock awards made under the 2015 Plan receive dividends that are not subject to restrictions or other limitations.
However, dividends declared during the vesting period with respect to restricted stock awards made under the 2017
Plan and all restricted stock units will not be paid until the underlying award vests. Devon estimates the fair values
of restricted stock awards and units as the closing price of Devon’s common stock on the grant date of the award or
unit, which is expensed over the applicable vesting period.

Performance-Based Restricted Stock Awards

Performance-based restricted stock awards were granted to certain members of Devon’s senior management.

Vesting of the awards is dependent on Devon meeting certain internal performance targets and the recipient meeting
certain service requirements. Generally, the service requirement for vesting ranges from one to four years. In order
for awards to vest, the performance target must be met in the first year. If the performance target is met, the recipient
is entitled to dividends under the same terms described above for nonperformance-based restricted stock. If the
performance target and service period requirements are not met, the award does not vest. Devon estimates the fair
values of the awards as the closing price of Devon’s common stock on the grant date of the award, which is
expensed over the applicable vesting period. No performance-based restricted stock awards were granted in 2019
and 2018.

Performance Share Units

Performance share units are granted to certain members of Devon’s management and employees. Each unit

that vests entitles the recipient to one share of Devon common stock. The vesting of these units is based on
comparing Devon’s TSR to the TSR of a predetermined group of fourteen peer companies over the specified three-
year performance period. The vesting of units may be between zero and 200% of the units granted depending on
Devon’s TSR as compared to the peer group on the vesting date.

At the end of the vesting period, recipients receive dividend equivalents with respect to the number of units

vested. The fair value of each performance share unit is estimated as of the date of grant using a Monte Carlo
simulation with the following assumptions used for all grants made under the plan: (i) a risk-free interest rate based
on U.S. Treasury rates as of the grant date; (ii) a volatility assumption based on the historical realized price volatility
of Devon and the designated peer group; and (iii) an estimated ranking of Devon among the designated peer group.
The fair value of the unit on the date of grant is expensed over the applicable vesting period. The following table
presents the assumptions related to performance share units granted.

Grant-date fair value
Risk-free interest rate
Volatility factor
Contractual term (years)

2019
28.43 — $29.53
2.48%
39.1%
2.89

2018
36.23 — $37.88
2.28%
45.8%
2.89

2017

51.05 — $

53.12

1.50%
45.8%
2.89

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Asset Impairments

The following table presents a summary of Devon’s asset impairments. Unproved impairments shown below

are included in exploration expenses in the consolidated statements of comprehensive earnings.

Proved oil and gas assets
Other assets

Total asset impairments

Unproved impairments

2019

Year Ended December 31,
2018

2017

— $
—
— $

18 $

109 $
47
156 $

95 $

—
—
—

217

Proved Oil and Gas and Other Asset Impairments

In 2018, Devon recognized $109 million of proved asset impairments relating to U.S. non-core assets no

longer in its development plans and approximately $47 million of non-oil and gas asset impairments.

Unproved Impairments

In 2019, 2018 and 2017, Devon allowed certain non-core acreage to expire without plans for development

resulting in unproved impairments.

Restructuring and Transaction Costs

2019 Workforce Reductions

During the first quarter of 2019, Devon announced workforce reductions and other initiatives designed to
enhance its operational focus and cost structure in conjunction with the portfolio transformation announcement
further discussed in Note 2. As a result, Devon recognized $84 million of restructuring expenses during 2019. Of
these expenses, $31 million resulted from accelerated vesting of share-based grants, which are noncash charges.
Additionally, $7 million resulted from settlements of defined retirement benefits.

Prior Years’ Restructurings

During 2018, Devon recognized $97 million in personnel related restructuring expenses related to workforce

reductions. Of these expenses, $31 million resulted from accelerated vesting of share-based grants, which are
noncash charges. Additionally, $14 million resulted from estimated settlements of defined retirement benefits.

The following table summarizes Devon’s restructuring liabilities presented in the accompanying consolidated

balance sheets.

Other
Current
Liabilities

Other
Long-term
Liabilities

Total

Balance as of December 31, 2017

Changes related to prior years' restructurings

Balance as of December 31, 2018

Changes due to 2019 workforce reductions
Changes related to prior years' restructurings

Balance as of December 31, 2019

17 $
22
39 $
18
(37)
20 $

17 $
(14)
3 $
—
(2)
1 $

34
8
42
18
(39)
21

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Income Taxes

Income Tax Expense (Benefit)

The following table presents Devon’s income tax components.

Current income tax expense (benefit):

U.S. federal
Various states

Total current income tax expense (benefit)

Deferred income tax expense (benefit):

U.S. federal
Various states

Total deferred income tax expense (benefit)

Total income tax expense (benefit)

Year Ended December 31,

2019

2018

2017

(3) $
(2)
(5)

8
(33)
(25)
(30) $

(14) $
(3)
(17)

184
63
247
230 $

8
1
9

(2)
—
(2)
7

Total income tax expense differed from the amounts computed by applying the U.S. federal income tax rate to

earnings (loss) from continuing operations before income taxes as a result of the following:

Earnings (loss) from continuing operations before income taxes

(109)

944

Year Ended December 31,

2019

2018

2017

U.S. statutory income tax rate
U.S. Tax Reform
State income taxes
Change in unrecognized tax benefits
Audit settlements
Other
Deferred tax asset valuation allowance

Effective income tax rate

21%
0%
24%
(13%)
15%
(19%)
0%
28%

21%
0%
5%
(2%)
(2%)
2%
0%
24%

35%
957%
(2%)
(15%)
0%
2%
(959%)
18%

Devon and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various
state and foreign jurisdictions. Devon’s tax reserves are related to tax years that may be subject to examinations by
the relevant taxing authority. Devon is under audit in the U.S. and various foreign jurisdictions as part of its normal
course of business.

Devon assesses the realizability of its deferred tax assets. If Devon concludes that it is more likely than not

that some portion or all of the deferred tax assets will not be realized, the asset is reduced by a valuation allowance.
Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors
such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.

2019

In December 2019, Devon announced the sale of its Barnett Shale assets. This transaction is expected to close

in the second quarter of 2020. Devon expects no incremental cash taxes associated with the divestiture of these
assets.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On June 27, 2019, Devon completed the sale of substantially all of its oil and gas assets and operations in
Canada. Devon’s foreign earnings have not been considered indefinitely reinvested since the announcement of the
plan to separate the assets in the first quarter of 2019. As the separation took the form of an asset sale and Devon has
retained certain non-operating obligations to be settled over time, Devon has not recorded a deferred tax asset or
corresponding valuation allowance related to its Canadian investment.

Devon has recorded materially all tax impacts related to the Barnett Shale and Canadian assets in discontinued

operations. Additional information on these discontinued operations can be found in Note 18.

During 2019, Devon recorded a tax expense of $14 million related to unrecognized tax benefits, due to a

change in tax positions taken in prior periods.

In the fourth quarter of 2019, Devon entered into an audit agreement with the Canada Revenue Agency. The
Canadian income tax expense resulting from this agreement is reflected in discontinued operations. However, the
agreement also resulted in a $16 million tax benefit to Devon’s U.S. continuing operations.

The “other” effect is composed of permanent differences, including stock compensation, for which the dollar

amounts do not increase or decrease in relation to the change in pre-tax earnings. Generally, permanent adjustments,
as well as the state income tax, have an insignificant impact on Devon’s effective income tax rate. However, these
items had a more noticeable impact to the rate in 2019 due to the low relative net loss in the period.

2018

Through the first six months of 2018, Devon maintained a 100% valuation allowance against its deferred tax

assets resulting from prior year cumulative financial losses, oil and gas impairments and significant net operating
losses for U.S. federal and state income tax. However, upon closing the EnLink divestiture in the third quarter of
2018, Devon realized a pre-tax gain of $2.6 billion. Based on its net deferred tax liability position, current period
projected net operating loss utilization, and projections of future taxable income, Devon reassessed its position and
determined that it was no longer in a full valuation allowance position, maintaining only valuation allowances
against certain deferred tax assets, including certain tax credits and state net operating losses. As part of its
reassessment, Devon determined that apart from the sale of EnLink and the General Partner, Devon would have
remained in a full valuation allowance position. Accordingly, the deferred tax benefit resulting from the release of
the valuation allowance that was generated in the first two quarters was allocated to continuing operations, while the
$259 million of the deferred tax benefit resulting from the release of the remainder of the full valuation allowance
position was allocated entirely to discontinued operations.

2017

The Tax Reform Legislation, enacted on December 22, 2017, contained several key tax provisions that
affected Devon, including a one-time mandatory transition tax on accumulated foreign earnings and a reduction of
the corporate income tax rate to 21% effective January 1, 2018. Devon was required to recognize the effect of the
tax law changes in the period of enactment, such as determining the transition tax, remeasuring deferred tax assets
and liabilities and reassessing the net realizability of deferred tax assets and liabilities. Devon recognized $167
million of deferred tax expense for the one-time mandatory transition tax on accumulated foreign earnings, and $205
million in deferred tax expense related to the reduction of the U.S. corporate income tax rate to 21%.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During 2017, Devon recorded a tax benefit of $6 million related to unrecognized tax benefits, primarily as a

result of a change in tax positions taken in prior periods.

Devon maintained a 100% valuation allowance against its deferred tax assets resulting from prior year
cumulative financial losses largely due to asset impairments and significant net operating losses for U.S. federal and
state income tax. Devon reduced its valuation allowance by $342 million in 2017 based primarily on the financial
income recorded during the period.

Deferred Tax Assets and Liabilities

The following table presents the tax effects of temporary differences that gave rise to Devon’s deferred tax

assets and liabilities.

Deferred tax assets:

Asset retirement obligations
Accrued liabilities
Net operating loss carryforwards
Pension benefit obligations
Tax credits and other

Total deferred tax assets before valuation allowance
Less: valuation allowance
Net deferred tax assets

Deferred tax liabilities:

Property and equipment
Other

Total deferred tax liabilities

Net deferred tax liability

December 31,

2019

2018

123 $
35
306
39
66
569
(106)
463

(800)
(4)
(804)
(341) $

146
45
126
44
77
438
(31)
407

(786)
(150)
(936)
(529)

At December 31, 2019, Devon has recognized $306 million of deferred tax assets related to various net
operating loss carryforwards available to offset future taxable income. Devon has $871 million of U.S. federal net
operating loss carryforwards ($466 million expiring in 2037 with the remainder having an indefinite life) and $2.5
billion of U.S. state net operating loss carryforwards expiring between 2021 and 2039. In the current environment,
Devon expects tax benefits from the U.S. federal and $377 million of U.S. state net operating loss carryforwards to
be utilized in 2022 and beyond. A valuation allowance is recorded against the remaining $2.1 billion of U.S. state
net operating loss carryforwards.

Unrecognized Tax Benefits

The following table presents changes in Devon’s unrecognized tax benefits.

Balance at beginning of year

Tax positions taken in prior periods

Balance at end of year

December 31,

2019

2018

51 $
14
65 $

71
(20)
51

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Devon recognized a net interest benefit of $5 million in 2019 and its unrecognized tax benefit balance
included no interest and penalties at December 31, 2019. Devon recognized no net interest or penalties in 2018 and
its unrecognized tax benefit balance included $5 million of interest and penalties at December 31, 2018. At
December 31, 2019 and December 31, 2018, there are $65 million and $51 million, respectively, of unrecognized
tax benefits that if recognized would affect the annual effective tax rate. Included below is a summary of the tax
years, by jurisdiction, that remain subject to examination by taxing authorities.

Jurisdiction
U.S. Federal
Various U.S. states

Tax Years Open
2016-2019
2015-2019

Certain statute of limitation expirations are scheduled to occur in the next twelve months. However, Devon is

currently in various stages of the administrative review process for certain open tax years. In addition, Devon is
currently subject to various income tax audits that have not reached the administrative review process.

Net Earnings (Loss) Per Share from Continuing Operations

The following table reconciles net earnings (loss) from continuing operations and weighted-average common

shares outstanding used in the calculations of basic and diluted net earnings (loss) per share from continuing
operations.

Net earnings (loss) from continuing operations:

Net earnings (loss) from continuing operations
Attributable to participating securities
Basic and diluted earnings (loss) from continuing
operations
Common shares:

Common shares outstanding - total
Attributable to participating securities
Common shares outstanding - basic
Dilutive effect of potential common shares issuable
Common shares outstanding - diluted

Net earnings (loss) per share from continuing operations:

Basic
Diluted

Antidilutive options (1)

$
$

2019

Year Ended December 31,
2018

2017

(81) $
(2)

(83) $

407
(6)
401
—
401

(0.21) $
(0.21) $
1

714 $
(8)

706 $

499
(5)
494
3
497

1.43 $
1.42 $
1

33
(1)

525
(5)
520
—
520

0.06
0.06
2

(1) Amounts represent options to purchase shares of Devon’s common stock that are excluded from the diluted

net earnings per share calculations because the options are antidilutive.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Other Comprehensive Earnings

Components of other comprehensive earnings consist of the following:

Foreign currency translation:

Beginning accumulated foreign currency translation and other
Change in cumulative translation adjustment
Release of Canadian cumulative translation adjustment (1)
Income tax benefit (expense)
Other
Ending accumulated foreign currency translation and other

Pension and postretirement benefit plans:

Beginning accumulated pension and postretirement benefits
Net actuarial loss (gain) and prior service cost arising in current year
Recognition of net actuarial loss and prior service cost in earnings (2)
Curtailment and settlement of pension benefits
Income tax expense
Other (3)
Ending accumulated pension and postretirement benefits
Accumulated other comprehensive earnings (loss), net of tax

Year Ended December 31,
2018

2017

2019

1,159 $
78
(1,237)
—
—
—

(132)
(10)
6
21
(4)
—
(119)
(119) $

1,309 $
(166)
—
14
2
1,159

(143)
(3)
12
47
(12)
(33)
(132)
1,027 $

1,226
113
—
(30)
—
1,309

(172)
10
19
—
—
—
(143)
1,166

(1)

(2)

In conjunction with the sale of substantially all of its oil and gas assets and operations in Canada, Devon
released the cumulative translation adjustment as part of its gain on the disposition of its Canadian business.
See Note 18 for additional details.
These accumulated other comprehensive earnings components are included in the computation of net periodic
benefit cost, which is a component of other expenses in the accompanying consolidated statements of
comprehensive earnings. See Note 16 for additional details.

(3) As a result of Devon’s early adoption of ASU 2018-02 in the fourth quarter of 2018, Devon reclassified $33
million from accumulated other comprehensive income to retained earnings in the December 31, 2018
consolidated balance sheet.

10.

Supplemental Information to Statements of Cash Flows

Changes in assets and liabilities, net:

Accounts receivable
Other current assets
Other long-term assets
Accounts payable
Revenues and royalties payable
Other current liabilities
Other long-term liabilities

Total
Supplementary cash flow data - total operations:
Interest paid (net of capitalized interest)
Income taxes paid

2019

Year Ended December 31,
2018

2017

(3) $
(7)
17
(54)
8
(66)
23
(82) $

308 $
6 $

(69) $
(152)
(7)
(3)
106
3
(36)
(158) $

385 $
40 $

(139)
15
(36)
91
102
(15)
(8)
10

481
78

$
$

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

11. Accounts Receivable

Components of accounts receivable include the following:

Oil, gas and NGL sales
Joint interest billings
Marketing and midstream revenues
Other

Gross accounts receivable
Allowance for doubtful accounts
Net accounts receivable

12.

Property, Plant and Equipment

Capitalized Costs

December 31, 2019 December 31, 2018
375
452 $
$
149
168
284
207
10
13
818
840
(6)
(8)
812
832 $

The following table reflects the aggregate capitalized costs related to Devon’s oil and gas and non-oil and gas

activities.

Property and equipment:

Proved
Unproved and properties under development

Total oil and gas
Less accumulated DD&A

Oil and gas property and equipment, net

Other property and equipment
Less accumulated DD&A

Other property and equipment, net (1)

Property and equipment, net

(1) $80 million related to CDM in 2019.

Suspended Exploratory Well Costs

December 31, 2019

December 31, 2018

27,668 $
583
28,251
(20,693)
7,558
1,725
(690)
1,035
8,593 $

25,901
830
26,731
(19,301)
7,430
1,680
(648)
1,032
8,462

The following summarizes the changes in suspended exploratory well costs for the three years ended

December 31, 2019.

Beginning balance

Additions pending determination of proved reserves
Reclassifications to proved properties

Ending balance

Year Ended December 31,
2018

2017

2019

98 $
278
(294)
82 $

100 $
658
(660)
98 $

75
491
(466)
100

Devon had no projects with suspended exploratory well costs capitalized for a period greater than one year

since the completion of drilling as of December 31, 2019, 2018 and 2017, respectively.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

13. Debt and Related Expenses

See below for a summary of debt instruments and balances. The notes and debentures are senior, unsecured

obligations of Devon.

6.30% due January 15, 2019
5.85% due December 15, 2025
7.50% due September 15, 2027 (1)
7.875% due September 30, 2031 (2) (3)
7.95% due April 15, 2032 (2)
5.60% due July 15, 2041
4.75% due May 15, 2042
5.00% due June 15, 2045
Net discount on debentures and notes
Debt issuance costs

Total debt
Less amount classified as short-term debt
Total long-term debt (4)

December 31, 2019 December 31, 2018

— $
485
73
675
366
1,250
750
750
(20)
(35)
4,294
—
4,294 $

162
485
73
675
366
1,250
750
750
(21)
(36)
4,454
162
4,292

(1)

(2)
(3)

(4)

This instrument was assumed by Devon in April 2003 in conjunction with the merger with Ocean Energy. The
fair value and effective rates of this note at the time assumed was $169 million and 6.5%. This instrument is
the unsecured and unsubordinated obligation of Devon OEI Operating, L.L.C. and is guaranteed by Devon
Energy Production Company, L.P. Each of these entities is a wholly-owned subsidiary of Devon.
These senior notes were included in 2018 tender offer repurchases discussed below.
These senior notes were originally issued by Devon Financing, a wholly-owned subsidiary of Devon, and
guaranteed by Devon. On June 19, 2019, Devon Financing assigned its obligations and rights with respect to
these senior notes to Devon pursuant to the terms of the related indenture. As a result of this transfer, Devon
Financing was relieved of its obligations under the senior notes and related indenture and Devon assumed all
such obligations.
The balance as of December 31, 2018 excludes the $1.5 billion of Senior Notes classified as liabilities held for
sale that were retired early in July 2019 utilizing a portion of the proceeds from the sale of Devon’s Canadian
business. See Note 18 for additional details.

As noted in the table above, as of December 31, 2019, Devon does not have any outstanding debt maturities

due within the next five years.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Credit Lines

Devon has a $3.0 billion Senior Credit Facility. As of December 31, 2019, Devon had $2 million in
outstanding letters of credit under the Senior Credit Facility. There were no borrowings under the Senior Credit
Facility as of December 31, 2019.

In connection with the closing of the sale of its Canadian business, Devon reallocated and terminated all

Canadian commitments under the Senior Credit Facility in accordance with the terms of the credit agreement
governing the Senior Credit Facility. The termination of the Canadian subfacility was effective as of June 27, 2019,
and such termination did not decrease the $3.0 billion in total revolving commitments under, or otherwise modify
the terms of, the Senior Credit Facility. Subsequent to Devon’s divestment of substantially all of its oil and gas
assets and operations in Canada, Devon entered into an amendment and extension agreement on December 13, 2019
to, among other things, (i) effect the extension of the maturity date of the Senior Credit Facility from October 5,
2023 to October 5, 2024 with respect to the consenting lenders, (ii) modify the maximum number of maturity
extension requests during the term of the Senior Credit Facility from two to three and (iii) eliminate various
references to the terminated Canadian subfacility. As a result of this amendment, Devon has the option to extend the
October 5, 2024 maturity date by two additional one-year periods subject to lender consent, and the maximum
borrowing capacity of the Senior Credit Facility becomes $2.8 billion after October 5, 2023. Amounts borrowed
under the Senior Credit Facility may, at the election of Devon, bear interest at various fixed rate options for periods
of up to twelve months. Such rates are generally less than the prime rate. However, Devon may elect to borrow at
the prime rate. The Senior Credit Facility currently provides for an annual facility fee of $6 million.

The Senior Credit Facility contains only one material financial covenant. This covenant requires Devon’s ratio

of total funded debt to total capitalization, as defined in the credit agreement, to be no greater than 65%. The credit
agreement contains definitions of total funded debt and total capitalization that include adjustments to the respective
amounts reported in the accompanying consolidated financial statements. For example, total capitalization is
adjusted to add back noncash financial write-downs such as asset impairments. As of December 31, 2019, Devon
was in compliance with this covenant with a debt-to-capitalization ratio of 19.1%.

Commercial Paper

Devon’s Senior Credit Facility supports its $3.0 billion of short-term credit under its commercial paper
program. Commercial paper debt generally has a maturity of between 1 and 90 days, although it can have a maturity
of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is generally
based on a standard index such as the Federal Funds Rate, LIBOR or the money market rate as found in the
commercial paper market. As of December 31, 2019, Devon had no outstanding commercial paper borrowings.

Retirement of Senior Notes

In January 2019, Devon repaid the $162 million of 6.30% senior notes at maturity.

During 2018, Devon completed tender offers to repurchase $807 million in aggregate principal amount of debt

using cash on hand. This included $384 million of the 7.875% senior notes due September 30, 2031 and $423
million of the 7.95% senior notes due April 15, 2032. Devon recognized a $312 million charge on early retirement
of debt, consisting of $304 million in cash retirement costs and $8 million of noncash charges. These costs, along
with other charges associated with retiring the debt, are included in net financing costs in the consolidated
statements of comprehensive earnings. During 2018, Devon repaid $115 million of senior notes at maturity.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Financing Costs, Net

The following schedule includes the components of net financing costs.

Interest based on debt outstanding
Early retirement of debt
Other

Total net financing costs

14. Leases

2019

Year Ended December 31,
2018

2017

260 $
—
(10)
250 $

287 $
312
(19)
580 $

337
—
(16)
321

Devon adopted ASU No. 2016-02, Leases (Topic 842), as of January 1, 2019, using the modified retrospective

transition approach. ASC 842 supersedes the previous lease accounting requirements in ASC 840 and requires
lessees to recognize leases on-balance sheet and disclose key information about leasing arrangements. ASC 842
establishes a right-of-use model that requires a lessee to recognize a right-of-use asset and lease liability on the
balance sheet for all leases with a term longer than 12 months. At adoption, using the modified retrospective
transition approach, Devon recorded right-of-use lease assets of $410 million and lease liabilities of $380 million.
Additionally, Devon recorded a $8 million before tax, $7 million net of tax, cumulative-effect adjustment to reduce
retained earnings. Comparative periods have been presented in accordance with ASC Topic 840 and do not include
any retrospective adjustments to reflect the adoption of Topic 842. Excluding land easements and rights-of-way, all
leases that existed at January 1, 2019 or were entered into or modified thereafter, are accounted for under Topic 842.
Devon elected the practical expedient provided in the standard that allows the new guidance to be applied
prospectively to all new or modified land easements and rights-of-way. Devon also elected a policy not to recognize
right-of-use assets and lease liabilities related to short-term leases with terms of 12 months or less. Additionally,
Devon elected to account for lease components separately from the nonlease components.

Devon made certain significant assumptions and judgments in determining its right-of-use asset and lease
liability balances. First is the determination of whether a contract contains a lease. Devon considered the presence of
an identified asset that is physically distinct, and for which the supplier does not have substantive substitution rights
and whether Devon has the right to control the underlying asset. Second, Devon assessed lease terms and considered
whether Devon is reasonably certain to extend leases or exercise purchase options. Certain of Devon’s leases include
one or more options to renew, with renewal terms that can extend the lease term for additional years. Certain leases
also include options to purchase the leased property. For options to renew or purchase that Devon is reasonably
certain to exercise, these costs are recognized as part of the right-of-use assets and lease liabilities. Third, significant
judgments have been made in determining discount rates. Devon estimates discount rates using market rates that
approximate collateralized borrowings over the remaining term of Devon’s lease payments.

Devon’s right-of-use operating lease assets are for certain leases related to real estate, drilling rigs and other

equipment related to the exploration, development and production of oil and gas. Devon’s right-of-use financing
lease assets are related to real estate. Certain of Devon’s lease agreements include variable payments based on usage
or rental payments adjusted periodically for inflation. Devon’s lease agreements do not contain any material residual
value guarantees or restrictive covenants.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents Devon’s right-of-use assets and lease liabilities as of December 31, 2019.

Right-of-use assets
Lease liabilities:

Current lease liabilities (1)
Long-term lease liabilities

Total lease liabilities

Finance

229

Operating
$

7
240
247

10
4
14

Total

243

17
244
261

(1) Current lease liabilities are included in other current liabilities on the consolidated balance sheets.

The following table presents Devon’s total lease cost.

Operating lease cost
Short-term lease cost (1)
Financing lease cost:

Amortization of right-of-use assets
Interest on lease liabilities

Variable lease cost
Lease income

Net lease cost

Property, plant and equipment; G&A
Property, plant and equipment; G&A

DD&A
Net financing costs
G&A
G&A

(1) Short-term lease cost excludes leases with terms of one month or less.

Year Ended
December 31, 2019

40
84

8
10
2
(5)
139

The following table presents Devon’s additional lease information for the year ended December 31, 2019.

Cash outflows for lease liabilities:

Operating cash flows
Investing cash flows

Right-of-use assets obtained in exchange for new
lease liabilities
Weighted average remaining lease term (years)
Weighted average discount rate

Year Ended December 31, 2019

Finance

Operating

$
$

7
—

$
$

—
8.0
4.2%

2
41

3
2.2
3.2%

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents Devon’s maturity analysis as of December 31, 2019 for leases expiring in each of

the next 5 years and thereafter.

Finance

Operating
$

2020
2021
2022
2023
2024
Thereafter

Total lease payments
Less: interest
Present value of lease liabilities

7
7
8
8
8
297
335
(88)
$
247

10
1
1
1
1
1
15
(1)
$
14

Total (1)

17
8
9
9
9
298
350
(89)
261

(1) Under previous lease accounting standard, ASC 840, Devon’s lease obligations as of December 31, 2018

expiring in each of the next 5 years and thereafter were $61 million for 2019, $48 million for 2020, $18 million
for 2021, $9 million for 2022, $8 million for 2023 and $33 million thereafter.

Devon rents or subleases certain real estate to third parties. The following table presents Devon’s expected

lease income as of December 31, 2019 for each of the next 5 years and thereafter.

2020
2021
2022
2023
2024
Thereafter
Total

Operating

Lease Income

15. Asset Retirement Obligations

The following table presents the changes in asset retirement obligations.

Asset retirement obligations as of beginning of period

Liabilities incurred
Liabilities settled and divested
Revision of estimated obligation
Accretion expense on discounted obligation
Asset retirement obligations as of end of period
Less current portion
Asset retirement obligations, long-term

Year Ended December 31,
2018
2019

484 $
20
(66)
(61)
21
398
18
380 $

6
6
6
7
7
44
76

492
30
(48)
(16)
26
484
16
468

During 2019, Devon reduced its asset retirement obligations by $61 million, primarily due to changes in the

future cost estimates and retirement dates for its oil and gas assets. During 2019, Devon also reduced its asset
retirement obligations by $42 million as a result of Devon’s 2019 divestitures. For additional information, see Note
2.

During 2018, Devon reduced its asset retirement obligations by $34 million as a result of Devon’s 2018

divestitures. For additional information, see Note 2.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

16. Retirement Plans

Defined Contribution Plans

Devon sponsors defined contribution plans covering its employees. Such plans include its 401(k) plan and

enhanced contribution plan. Contributions are primarily based upon percentages of annual compensation and years
of service. In addition, each plan is subject to regulatory limitations by the U.S. government. Devon contributed $34
million, $40 million and $42 million to these plans in 2019, 2018 and 2017, respectively.

Defined Benefit Plans

Devon has various non-contributory defined benefit pension plans, including qualified plans and nonqualified

plans covering eligible employees and former employees meeting certain age and service requirements. Benefits
under the defined benefit plans have been closed to new employees; however, eligible employees continue to accrue
benefits based upon years of service and compensation. Benefits are primarily funded from assets held in the plans’
trusts.

Devon’s investment objective for its plans’ assets is to achieve stability of the funded status while providing
long-term growth of invested capital and income to ensure benefit payments can be funded when required. Devon
has established certain investment strategies, including target allocation percentages and permitted and prohibited
investments, designed to mitigate risks inherent with investing. Devon’s target allocations for its plan assets are 70%
fixed income, 20% equity and 10% other. See the following discussion for Devon’s pension assets by asset class.

Fixed-income – Devon’s fixed-income securities consist of U.S. Treasury obligations, bonds issued by
investment-grade companies from diverse industries and asset-backed securities. These fixed-income securities are
actively traded securities that can be redeemed upon demand. The fair values of these Level 1 securities are based
upon quoted market prices and were $240 million and $193 million at December 31, 2019 and 2018, respectively.
Also included are commingled funds that primarily invest in long-term bonds and U.S. Treasury securities. These
fixed income securities can be redeemed on demand but are not actively traded. The fair values of these securities
are based upon the net asset values provided by the investment managers and were $233 million and $291 million at
December 31, 2019 and 2018, respectively.

Equity – Devon’s equity securities include commingled global equity funds that invest in large, mid and small

capitalization stocks across the world’s developed and emerging markets and international large cap equity
securities. These equity securities can be sold on demand but are not actively traded. The fair values of these
securities are based upon the net asset values provided by the investment managers and were $112 million and $77
million at December 31, 2019 and 2018, respectively.

Other – Devon’s other securities include short-term investment funds and a hedge fund that invest both long
and short term using a variety of investment strategies. The fair value of these securities is based upon the net asset
values provided by investment managers and were $109 million and $124 million at December 31, 2019 and 2018,
respectively.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Defined Postretirement Plans

Devon also has defined benefit postretirement plans that provide benefits for substantially all qualifying

retirees. Benefit obligations for such plans are estimated based on Devon’s future cost-sharing intentions. Devon’s
funding policy for the plans is to fund the benefits as they become payable with available cash and cash equivalents.

Benefit Obligations and Funded Status

The following table summarizes the benefit obligations, assets, funded status and balance sheet impacts

associated with its defined pension and postretirement plans. Devon’s benefit obligations and plan assets are
measured each year as of December 31. The accumulated benefit obligation for pension plans approximated the
projected benefit obligation at December 31, 2019 and 2018.

Pension Benefits

Postretirement Benefits

2019

2018

2019

2018

Change in benefit obligation:

Benefit obligation at beginning of year
Service cost
Interest cost
Actuarial loss (gain)
Plan amendments
Plan curtailments
Plan settlements
Participant contributions
Benefits paid
Benefit obligation at end of year

Change in plan assets:

Fair value of plan assets at beginning
of year
Actual return on plan assets
Employer contributions
Participant contributions
Plan settlements
Benefits paid
Fair value of plan assets at end of year

Funded status at end of year
Amounts recognized in balance sheet:

Other current liabilities
Other long-term liabilities
Net amount

Amounts recognized in accumulated other
comprehensive earnings:
Net actuarial loss (gain)
Prior service cost (credit)
Total

916 $
7
32
91
3
(3)
(75)
—
(47)
924

685
118
13
—
(75)
(47)
694
(230) $

(13) $
(217)
(230) $

1,247 $
9
38
(81)
—
2
(241)
—
(58)
916

1,007
(36)
13
—
(241)
(58)
685
(231) $

(13) $
(218)
(231) $

183 $
5
188 $

198 $
4
202 $

17 $
—
—
(3)
—
1
—
2
(3)
14

—
—
1
2
—
(3)
—
(14) $

(2) $
(12)
(14) $

(12) $
(1)
(13) $

19
—
—
(3)
—
2
—
2
(3)
17

—
—
1
2
—
(3)
—
(17)

(3)
(14)
(17)

(11)
(2)
(13)

During the third quarter of 2018, Devon entered into a group annuity contract, under which a third party has
permanently assumed certain of Devon’s defined benefit pension obligations. The purchase of this group annuity
contract reduced Devon’s pension assets and liabilities and is the primary component of the $241 million of plan
settlements within the preceding table. In connection with the group annuity contract transaction, Devon recorded a
settlement expense of approximately $33 million, which was reclassified from other comprehensive earnings to
other expense on the consolidated statements of comprehensive earnings in 2018.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Certain of Devon’s pension plans have a combined projected benefit obligation or accumulated benefit
obligation in excess of plan assets at December 31, 2019 and December 31, 2018, as presented in the table below.

Projected benefit obligation
Accumulated benefit obligation (1)
Fair value of plan assets

December 31,

2019

2018

$
$
$

924 $
223 $
694 $

916
900
685

(1)

The accumulated benefit obligation as of December 31, 2019 included a qualified pension plan that contained
$690 million of accumulated benefit obligation which was not in excess of plan assets.

The following table presents the components of net periodic benefit cost and other comprehensive earnings.

Pension Benefits
2018

2019

Postretirement Benefits

2017

2019

2018

2017

Net periodic benefit cost:

Service cost
Interest cost
Expected return on plan assets
Recognition of net actuarial loss (gain) (1)
Recognition of prior service cost (1)
Total net periodic benefit cost (2)
Other comprehensive loss (earnings):

Actuarial loss (gain) arising in current year
Prior service cost arising in current year
Recognition of net actuarial gain (loss), including
settlement expense, in net periodic benefit cost (3)
Recognition of prior service cost, including
curtailment, in net periodic benefit cost (3)
Total other comprehensive loss (earnings)

Total recognized

7 $
32
(38)
7
1
9

9 $
38
(48)
13
1
13

15 $ — $ — $ —
41 — — —
(54) — — —
(1)
19
(1)
2
(2)
23

(1)
(1)
(2)

7
(1)
3 — — — — —

(1)

(2)

(8)

(22)

(59)

(19)

(2)
(2)
(14)
(56)
(5) $ (43) $

1
(2)
(29) —
(2) $
(6) $

1
1
(1) $

1
1
(1)

(1)
(2)

(3)

These net periodic benefit costs were reclassified out of other comprehensive earnings in the current period.
The service cost component of net periodic benefit cost is included in G&A expense and the remaining
components of net periodic benefit costs are included in other expenses in the accompanying consolidated
statements of comprehensive earnings.
These amounts include restructuring costs that were reclassified out of other comprehensive earnings in 2019
and 2018. See Note 6 for further discussion.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Assumptions

Assumptions to determine benefit obligations:

Discount rate
Rate of compensation increase

Assumptions to determine net periodic benefit cost:

Discount rate - service cost
Discount rate - interest cost
Rate of compensation increase
Expected return on plan assets

Pension Benefits

Postretirement Benefits

2019

2018

2017

2019

2018

2017

3.14%
2.50%

4.09%
2.50%

3.51%
2.50%

2.81%
N/A

4.01%
N/A

3.25%
N/A

3.74%
3.36%
2.50%
5.75%

3.77%
3.14%
2.50%
5.75%

4.06%
2.91%
4.50%
5.75%

3.99%
3.21%
N/A
N/A

4.13%
2.67%
N/A
N/A

4.22%
2.39%
N/A
N/A

Discount Rate - Future pension and post-retirement obligations are discounted based on the rate at which

obligations could be effectively settled, considering the timing of expected future cash flows related to the plans.
This rate is based on high-quality bond yields, after allowing for call and default risk.

Expected return on plan assets – This was determined by evaluating input from external consultants and

economists, as well as long-term inflation assumptions and consideration of target allocation of investment types.

Mortality rate – Devon utilized the Society of Actuaries produced mortality tables.

Other assumptions – For measurement of the 2019 benefit obligation for the other postretirement medical
plans, a 7.1% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2020.
The rate was assumed to decrease annually to an ultimate rate of 5% in the year 2029 and remain at that level
thereafter.

Expected Cash Flows

Devon expects benefit plan payments to average approximately $56 million a year for the next five years and
$278 million total for the five years thereafter. Of these payments to be paid in 2020, $16 million is expected to be
funded from Devon’s available cash, cash equivalents and other assets.

17.

Stockholders’ Equity

The authorized capital stock of Devon consists of 1.0 billion shares of common stock, par value $0.10 per
share, and 4.5 million shares of preferred stock, par value $1.00 per share. The preferred stock may be issued in one
or more series, and the terms and rights of such stock will be determined by the Board of Directors.

Share Repurchase Program

On March 7, 2018, Devon announced a $1.0 billion share repurchase program. On June 6, 2018, Devon

announced the expansion of this program to $4.0 billion. On February 19, 2019, Devon announced a further
expansion to $5.0 billion with a December 31, 2019 expiration date. Of the $5.0 billion authorized amount, $4.8
billion was repurchased when the program expired on December 31, 2019. On December 17, 2019, Devon
announced a new $1.0 billion share repurchase program with a December 31, 2020 expiration date. Under the new
program, $800 million of the $1.0 billion authorization is conditioned upon the closing of the pending Barnett Shale
divestiture.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The table below provides information regarding purchases of Devon’s common stock that were made during

2018 and 2019 (shares in thousands).

Total Number of
Shares Purchased

Dollar Value of

Shares Purchased

Average Price Paid
per Share

First quarter 2018:
Open-Market

Second quarter 2018:

Open-Market

Third quarter 2018:

Open-Market
ASR

Total

Fourth quarter 2018:

Open-Market
First quarter 2019:
Open-Market

Second quarter 2019:

Open-Market

Third quarter 2019:

Open-Market

Fourth quarter 2019:

Open-Market

Total inception-to-date

Dividends

2,561

11,154

16,492
24,330
40,822

23,612

36,141

5,911

22,137

439

712
1,000
1,712

745

1,024

159

550

4,436
146,774

94
4,805

The table below summarizes the dividends Devon paid on its common stock.

Amounts

Rate Per Share

Year Ended 2019:
First quarter
Second quarter
Third quarter
Fourth quarter

Total year-to-date

Year Ended 2018:
First quarter
Second quarter
Third quarter
Fourth quarter

Total year-to-date

Year Ended 2017:
First quarter
Second quarter
Third quarter
Fourth quarter

Total year-to-date

34 $
37 $
35 $
34 $
140

32 $
42 $
38 $
37 $
149

32 $
33 $
30 $
32 $
127

32.19

39.35

43.13
41.10
41.92

31.57

28.33

27.01

24.80

21.32
32.74

0.08
0.09
0.09
0.09

0.06
0.08
0.08
0.08

0.06
0.06
0.06
0.06

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Devon raised its quarterly dividend by 12.5%, to $0.09 per share, beginning in the second quarter of 2019. In

the second quarter of 2018, Devon increased the quarterly dividend rate by 33% from $0.06 to $0.08 per share. In
February 2020, Devon announced a 22% increase to its quarterly dividend, to $0.11 per share, beginning in the
second quarter of 2020.

Noncontrolling Interests

As discussed in Note 1, the noncontrolling interests’ share of CDM’s net earnings and the contributions from

the noncontrolling interests are presented as components of equity for 2019. The noncontrolling interests’ equity
balances and activities for 2017 and 2018 are related to EnLink and the divestment of Devon’s aggregate ownership
interests in EnLink and the General Partner, as further discussed in Note 18.

18. Discontinued Operations and Assets Held For Sale

Barnett Shale

On December 17, 2019, Devon announced that it had entered into an agreement to sell its Barnett Shale assets

to BKV for approximately $770 million, before purchase price adjustments. Devon concluded that the transaction
was a strategic shift and met the requirements of assets held for sale and discontinued operations upon the
authorization to enter the agreement by Devon’s Board of Directors. As part of its assessment, Devon is effectively
exiting its last natural gas focused asset and the transaction resulted in a material reduction to total assets, revenues,
net earnings and total proved reserves. Estimated proved reserves associated with Devon’s Barnett Shale assets are
approximately 45% of total U.S. proved reserves. As a result, Devon has classified the results of operations and cash
flows related to its Barnett Shale assets, inclusive of Barnett properties divested in previous reporting periods
located primarily in Johnson and Wise counties, Texas, as discontinued operations on its consolidated financial
statements. In connection with the abandonment of certain gas processing contracts related to 2018 divestitures,
Devon has restricted approximately $25 million to fund these obligations. Cash payments for the abandonment
charges total approximately $2 million per quarter.

In connection with the announced sale of its Barnett Shale assets, Devon recognized a $748 million asset
impairment related to these assets, primarily due to the difference between the net carrying value and the purchase
price, net of estimated customary purchase price adjustments, and qualifies as a level 2 fair value measurement.
Approximately $88 million of the U.S. reporting unit goodwill was allocated to the Barnett Shale assets.
Additionally, Devon ceased depreciation for all plant, property and equipment classified as assets held for sale on
the date the sales agreement was approved by the Board of Directors. This transaction is expected to close in the
second quarter of 2020.

Canada

On May 29, 2019, Devon announced it had entered into an agreement to sell substantially all of its oil and gas
assets and operations in Canada to Canadian Natural Resources Limited. Devon concluded that the transaction was a
strategic shift and met the requirements of assets held for sale and discontinued operations upon the authorization to
enter the agreement by Devon’s Board of Directors. As part of its assessment, Devon considered the following: 1)
Devon is exiting its entire heavy oil and Canadian operations; 2) Devon’s Canadian operations is a separate
reportable segment and is a component of Devon’s business; and 3) the transaction resulted in a material reduction
in total assets, revenues, net earnings and total proved reserves. As a result, Devon has classified the results of
operations and cash flows related to its Canadian operations as discontinued operations on its consolidated financial
statements. Additionally, Devon ceased depreciation for all plant, property and equipment classified as assets held
for sale on the date the sales agreement was approved by the Board of Directors.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

On June 27, 2019, Devon completed the sale of its Canadian business for $2.6 billion ($3.4 billion Canadian

dollars), net of purchase price adjustments, and recognized a pre-tax gain of $223 million ($425 million net of
tax, primarily due to a significant deferred tax benefit). Included within this gain is a $55 million adjustment to the
gain in the fourth quarter of 2019 related to income taxes. Current (cash) income tax associated with the
sale was approximately $150 million and is expected to be paid in early 2020. The disposition of substantially all of
Devon’s Canadian oil and gas assets resulted in Devon releasing its historical cumulative foreign currency
translation adjustment of $1.2 billion from accumulated other comprehensive earnings to be included within the gain
computation. The historical cumulative foreign currency translation portion of the gain is not taxable. As of
December 31, 2019, $355 million of the Canadian cash balance is restricted for funding certain tax and other
obligations related to the Canadian business and is classified as cash restricted for discontinued operations on the
consolidated balance sheets.

In conjunction with the sale of Devon’s Canadian business, Devon recognized approximately $285 million of
restructuring and asset impairment related charges. Canadian Natural Resources Limited has reimbursed Devon for
approximately $50 million of these restructuring costs, under the terms of the disposition agreement. Along with
certain tax obligations, these costs will be funded with the restricted cash described above. These charges consist of
$154 million related to a firm transportation agreement abandonment and $57 million related to office lease
abandonment and associated asset impairment charges. Cash payments for the abandonment charges total
approximately $6 million per quarter. Additionally, there are $74 million of employee related costs, including
approximately $40 million of noncash accelerated vesting of employee stock awards. As mentioned above,
Canadian Natural Resources Limited reimbursed the Company for approximately $50 million of these costs
pursuant to the disposition agreement and Devon funded the remaining employee related costs.

Prior to the second quarter of 2019, Devon’s Canadian business maintained a valuation allowance against
certain capital loss carryforwards and net operating losses. As a result of the sale of substantially all of Devon’s
Canadian oil and gas assets and operations and the lack of future forecasted income, all but approximately $22
million of the Canadian deferred tax assets have been offset with a valuation allowance. In the fourth quarter of
2019, Devon entered into an audit agreement with the Canada Revenue Agency. As a result of this agreement,
income tax expense of $82 million is reflected in discontinued operations.

In July 2019, Devon utilized a portion of the sales proceeds to early retire $500 million of the 4.00% senior

notes due July 15, 2021 and $1.0 billion of the 3.25% senior notes due May 15, 2022. Devon recognized a charge on
the early retirement of these notes in the third quarter of 2019 consisting of $52 million in cash retirement costs and
$6 million of noncash charges.

EnLink

On June 6, 2018, Devon announced that it had entered into an agreement to sell its aggregate ownership

interests in EnLink and the General Partner for $3.125 billion. Upon entering into the agreement to sell its
ownership interest in June 2018, Devon concluded that the transaction was a strategic shift and met the requirements
of assets held for sale and discontinued operations. As a result, Devon classified the results of operations and cash
flows related to EnLink and the General Partner as discontinued operations on its consolidated financial statements.

On July 18, 2018, Devon completed the sale of its aggregate ownership interests in EnLink and the General

Partner for $3.125 billion and recognized a gain of approximately $2.6 billion ($2.2 billion after-tax). Current (cash)
income tax associated with the transaction was approximately $12 million. The vast majority of the tax effect relates
to deferred tax expense offset by the valuation allowance adjustment.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

As part of the sale agreement, Devon extended its fixed-fee gathering and processing contracts with respect
to the Bridgeport and Cana plants with EnLink through 2029. Although the agreements were extended to 2029, the
minimum volume commitments for the Bridgeport and Cana plants expired at the end of 2018. Devon has minimum
volume commitments for gathering and processing of 77-128 MMcf/d with EnLink at the Chisholm plant through
early 2021.

Prior to the divestment of Devon’s aggregate ownership of EnLink and the General Partner, certain activity
between Devon and EnLink were eliminated in consolidation. Subsequent to the divestment, all activity related to
EnLink represent third-party transactions and are no longer eliminated in consolidation.

During 2019 and from the period of July 19, 2018 through December 31, 2018, Devon had net outflows of
approximately $560 million and $380 million with EnLink, respectively, which primarily related to gathering and
processing expenses. These net outflows represent gross cash amounts and not net working interest amounts.

The following table presents the amounts reported in the consolidated statements of comprehensive earnings

as discontinued operations.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Year ended December 31,

Barnett Shale Canada

EnLink

Total

2019
Upstream revenues
Marketing and midstream revenues
Total revenues
Production expenses
Exploration expenses
Marketing and midstream expenses
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
General and administrative expenses
Financing costs, net
Restructuring and transaction costs
Other expenses
Total expenses
Earnings (loss) from discontinued operations before income taxes
Income tax benefit
Net earnings (loss) from discontinued operations, net of tax

2018
Upstream revenues
Marketing and midstream revenues
Total revenues
Production expenses
Exploration expenses
Marketing and midstream expenses
Depreciation, depletion and amortization
Asset dispositions
General and administrative expenses
Financing costs, net
Restructuring and transaction costs
Other expenses
Total expenses
Earnings (loss) from discontinued operations before income taxes
Income tax expense (benefit)
Net earnings (loss) from discontinued operations, net of tax
Net earnings attributable to noncontrolling interests
Net earnings (loss) from discontinued operations, attributable to Devon

2017
Upstream revenues
Marketing and midstream revenues
Total revenues
Production expenses
Exploration expenses
Marketing and midstream expenses
Depreciation, depletion and amortization
Asset impairments
Asset dispositions
General and administrative expenses
Financing costs, net
Other expenses
Total expenses
Earnings from discontinued operations before income taxes
Income tax expense (benefit)
Net earnings from discontinued operations, net of tax
Net earnings attributable to noncontrolling interests
Net earnings from discontinued operations, attributable to Devon

486 $
—
486
306
—
—
77
748
1
—
—
—
11
1,143
(657)
(142)
(515) $

777 $
—
777
467
—
—
100
14
—
—
—
(34)
547
230
50
180
—
180 $

825 $
—
825
440
—
—
141
—
1
—
—
12
594
231
—
231
—
231 $

628

$
38
666
293
13
18
128
37
(223)
34
87
248
6
641
25
(216)
$
241

965

$
95
1,060
605
48
42
330
—
76
14
17
182
1,314
(254)
(124)
(130)
—
(130) $

1,494

$
58
1,552
591
34
60
380
—
1
92
(4)
(104)
1,050
502
8
494
—
$

494

—
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— $

— $
3,567
3,567
—
—
2,912
244
(2,607)
65
98
—
(8)
704
2,863
403
2,460
160
2,300 $

— $
5,071
5,071
—
—
4,111
545
17
—
128
181
(34)
4,948
123
(197)
320
180
140 $

1,114
38
1,152
599
13
18
205
785
(222)
34
87
248
17
1,784
(632)
(358)
(274)

1,742
3,662
5,404
1,072
48
2,954
674
(2,593)
141
112
17
140
2,565
2,839
329
2,510
160
2,350

2,319
5,129
7,448
1,031
34
4,171
1,066
17
2
220
177
(126)
6,592
856
(189)
1,045
180
865

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

The following table presents the carrying amounts of the assets and liabilities associated with discontinued

operations on the consolidated balance sheets. The U.S. Other amounts in the table below relate to the divestiture of
non-core upstream Permian Basin assets which closed in January 2019 as further discussed in Note 2.

As of December 31, 2019

As of December 31, 2018

Barnett
Shale (1)

Canada

Total

Barnett
Shale

Canada

U.S.
Other

Total

Cash restricted for discontinued operations $

25 $

355 $

380 $

— $

Accounts receivable

Other current assets
Oil and gas property and equipment, based
on successful efforts accounting, net

Other property and equipment, net

Goodwill

Other long-term assets
Total assets associated with discontinued
operations

Accounts payable

Revenues and royalties payable

Other current liabilities

Long-term debt (2)

Asset retirement obligations

Deferred income taxes

Other long-term liabilities
Total liabilities associated with
discontinued operations

—

81
60

5,571
90
88
79

38 $

751

—

1 $

—

39 $

44 $

30 $

7 $

—

751

1,552

3,829

190

—

893 $

84 $

977 $

1,700 $

4,072 $

197 $

5,969

15 $

—

141

—

4 $

233

—

169

19 $

252

—

141

—

185

32 $

111

—

139

—

98 $

104

1,493

424

348

3 $

—

133
178
134
1,493
610
348
50

235 $

409 $

644 $

323 $

2,554 $

69 $

2,946

(1) Certain long-term assets and liabilities for the Barnett Shale were reclassified to respective current assets

and liabilities as of December 31, 2019 with the announced sale of the Barnett Shale assets expected to
close during the second quarter of 2020.

(2) Includes the $500 million 4.00% Senior Notes due July 15, 2021 and $1.0 billion 3.25% Senior Notes due
May 15, 2022 that were retired early in July 2019 utilizing a portion of the proceeds from the sale of
Devon’s Canadian business.

19. Commitments and Contingencies

Devon is party to various legal actions arising in connection with its business. Matters that are probable of

unfavorable outcome to Devon and which can be reasonably estimated are accrued. Such accruals are based on
information known about the matters, Devon’s estimates of the outcomes of such matters and its experience in
contesting, litigating and settling similar matters. None of the actions are believed by management to likely involve
future amounts that would be material to Devon’s financial position or results of operations after consideration of
recorded accruals. Actual amounts could differ materially from management’s estimates.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Royalty Matters

Numerous oil and natural gas producers and related parties, including Devon, have been named in various
lawsuits alleging royalty underpayments. Devon is currently named as a defendant in a number of such lawsuits,
including some lawsuits in which the plaintiffs seek to certify classes of similarly situated plaintiffs. Among the
allegations typically asserted in these suits are claims that Devon used below-market prices, made improper
deductions, used improper measurement techniques and entered into gas purchase and processing arrangements with
affiliates that resulted in underpayment of royalties in connection with oil, natural gas and NGLs produced and sold.
Devon is also involved in governmental agency proceedings and royalty audits and is subject to related contracts and
regulatory controls in the ordinary course of business, some that may lead to additional royalty claims. Devon does
not currently believe that it is subject to material exposure with respect to such royalty matters.

Environmental and Other Matters

Devon is subject to certain laws and regulations relating to environmental remediation activities associated
with past operations, such as the Comprehensive Environmental Response, Compensation, and Liability Act and
similar state statutes. In response to liabilities associated with these activities, loss accruals primarily consist of
estimated uninsured remediation costs. Devon’s monetary exposure for environmental matters is not expected to be
material.

Beginning in 2013, various parishes in Louisiana filed suit against more than 100 oil and gas companies,
including Devon, alleging that the companies’ operations and activities in certain fields violated the State and Local
Coastal Resource Management Act of 1978, as amended, and caused substantial environmental contamination,
subsidence and other environmental damages to land and water bodies located in the coastal zone of Louisiana. The
plaintiffs’ claims against Devon relate primarily to the operations of several of Devon’s corporate predecessors. The
plaintiffs seek, among other things, payment of the costs necessary to clear, re-vegetate and otherwise restore the
allegedly impacted areas. Although Devon cannot predict the ultimate outcome of these matters, Devon denies any
wrongdoing and is vigorously defending against these claims.

Various municipalities and other governmental and private parties in California have filed legal proceedings

against certain oil and gas companies, including Devon, seeking relief to abate alleged impacts of climate change.
These proceedings include far-reaching claims for monetary damages and injunctions against the production of all
fossil fuels. Although Devon cannot predict the ultimate outcome of these matters, Devon believes these claims to
be baseless and intends to vigorously defend against the proceedings.

Commitments

The following table presents Devon’s commitments that have initial or remaining noncancelable terms in

excess of one year as of December 31, 2019.

Year Ending December 31,

Drilling and Facility
Obligations

Operational
Agreements

Office and Equipment
Leases

2020
2021
2022
2023
2024
Thereafter
Total

131 $
31
30
22
16
32
262 $

320 $
223
208
162
139
416
1,468 $

51
41
12
12
12
298
426

Devon has certain drilling and facility obligations under contractual agreements with third-party service
providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities
construction. The value of the drilling obligations reported is based on gross contractual value.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Devon has certain operational agreements whereby Devon has committed to transport or process certain

volumes of oil, gas and NGLs for a fixed fee. Devon has entered into these agreements to aid the movement of its
production to downstream markets.

Devon leases certain office space and equipment under financing and operating lease arrangements.

20. Fair Value Measurements

The following table provides carrying value and fair value measurement information for certain of Devon’s

financial assets and liabilities. The carrying values of cash, cash restricted for discontinued operations, accounts
receivable, other current receivables, accounts payable, other current payables, accrued expenses and lease liabilities
included in the accompanying consolidated balance sheets approximated fair value at December 31, 2019 and
December 31, 2018, as applicable. Therefore, such financial assets and liabilities are not presented in the following
table.

December 31, 2019 assets (liabilities):

Cash equivalents
Commodity derivatives
Commodity derivatives
Debt

December 31, 2018 assets (liabilities):

Cash equivalents
Commodity derivatives
Commodity derivatives
Debt

$
$
$
$

Carrying
Amount

Total Fair
Value

Level 1
Inputs

Level 2
Inputs

Fair Value Measurements Using:

702 $
50 $
(31) $
(4,294) $

$
1,505
674
$
(33) $
(4,454) $

702 $
50 $
(31) $
(5,376) $

$
1,505
674
$
(33) $
(4,494) $

702 $
— $
— $
— $

1,405
—
—
—

$
$
$
$

—
50
(31)
(5,376)

100
674
(33)
(4,494)

The following methods and assumptions were used to estimate the fair values in the tables above.

Level 1 Fair Value Measurements

Cash equivalents – Amounts consist primarily of money market investments and the fair value approximates

the carrying value.

Level 2 Fair Value Measurements

Cash equivalents – Amounts primarily consist of Canadian agency and provincial securities investments. The

fair value approximates the carrying value.

Commodity derivatives – The fair value of commodity derivatives is estimated using internal discounted cash

flow calculations based upon forward curves and data obtained from independent third parties for contracts with
similar terms or data obtained from counterparties to the agreements.

Debt – Devon’s debt instruments do not actively trade in an established market. The fair values of its debt are

estimated based on rates available for debt with similar terms and maturity.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

21.

Supplemental Information on Oil and Gas Operations (Unaudited)

Supplemental unaudited information regarding Devon’s oil and gas activities is presented in this note. With

the sale of substantially all of its Canadian assets and operations, all of Devon’s reserves are located within the U.S.

The supplemental information in the tables below exclude amounts for all periods presented related to

Devon’s discontinued operations, which consist of Devon’s Canadian operations that were sold in 2019 and its
Barnett Shale assets, inclusive of properties divested in previous reporting periods located primarily in Johnson and
Wise counties, Texas, which is expected to close in 2020. 612 MMBoe of estimated proved reserves and $940
million of discounted future net cash flows were excluded for 2019, which all related to Devon’s Barnett Shale
assets. Amounts excluded for 2018 and 2017 consisted of 1,104 MMBoe and 1,365 MMBoe, respectively, of
estimated proved reserves and $3,042 million and $5,383 million, respectively, of discounted future net cash flows,
which related to both Devon’s Canadian operations and its Barnett Shale assets, inclusive of properties divested in
previous reporting periods located primarily in Johnson and Wise counties, Texas. 410 MMBoe and $1,426 million
of discounted future net cash flows related to Devon’s Canadian operations in 2018 were sold in the second quarter
of 2019. For additional information on these discontinued operations, see Note 18.

Costs Incurred

The following tables reflect the costs incurred in oil and gas property acquisition, exploration and

development activities.

Property acquisition costs:

Proved properties
Unproved properties

Exploration costs
Development costs
Costs incurred

Year Ended December 31,

2019

2018

2017

— $
35
312
1,499
1,846 $

2 $
70
679
1,505
2,256 $

1
50
591
1,046
1,688

Development costs in the tables above include additions and revisions to Devon’s asset retirement obligations.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Results of Operations

The following tables include revenues and expenses associated with Devon’s oil and gas producing activities.

They do not include any allocation of Devon’s interest costs or general corporate overhead and, therefore, are not
necessarily indicative of the contribution to net earnings of Devon’s oil and gas operations. Income tax expense has
been calculated by applying statutory income tax rates to oil, gas and NGL sales after deducting costs, including
DD&A and after giving effect to permanent differences.

Year Ended December 31,

2019

2018

2017

Oil, gas and NGL sales
Production expenses
Exploration expenses
Depreciation, depletion and amortization
Asset dispositions
Asset impairments
Accretion of asset retirement obligations
Income tax expense
Results of operations
Depreciation, depletion and amortization per Boe

$
$

3,809
$
(1,197)
(58)
(1,398)
37
—
(21)
(270)
902 $
11.72 $

4,085
$
(1,153)
(128)
(1,134)
276
(109)
(26)
(416)
1,395 $
10.51 $

2,921
(791)
(346)
(908)
212
—
(27)
—
1,061
9.58

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Proved Reserves

The following table presents Devon’s estimated proved reserves by product.

Oil (MMBbls)

Gas (Bcf)

NGL (MMBbls)

Combined
(MMBoe)

Proved developed and undeveloped reserves:
December 31, 2016

Revisions due to prices
Revisions other than price
Extensions and discoveries
Production
Sale of reserves
December 31, 2017

Revisions due to prices
Revisions other than price
Extensions and discoveries
Production
Sale of reserves
December 31, 2018

Revisions due to prices
Revisions other than price
Extensions and discoveries
Purchase of reserves
Production
Sale of reserves
December 31, 2019

Proved developed reserves:

December 31, 2016
December 31, 2017
December 31, 2018
December 31, 2019

Proved developed-producing reserves:

December 31, 2016
December 31, 2017
December 31, 2018
December 31, 2019

Proved undeveloped reserves:

December 31, 2016
December 31, 2017
December 31, 2018
December 31, 2019

191
12
6
90
(42)
(3)
254
12
(10)
93
(47)
(6)
296
(7)
(13)
76
3
(55)
(24)
276

157
175
196
198

141
163
188
191

34
79
100
78

1,613
55
(31)
371
(189)
(9)
1,810
7
(102)
358
(206)
(65)
1,802
(86)
(50)
269
7
(219)
(102)
1,621

1,359
1,455
1,427
1,344

1,267
1,384
1,394
1,327

254
355
375
277

200
5
(15)
63
(21)
(1)
231
2
(27)
54
(26)
(7)
227
(6)
(9)
39
1
(28)
(13)
211

161
168
166
167

148
160
162
165

39
63
61
44

660
27
(14)
215
(95)
(6)
787
15
(53)
206
(108)
(24)
823
(28)
(31)
160
6
(119)
(54)
757

545
585
600
589

500
554
582
578

115
202
223
168

(1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative
energy content of gas and oil. NGL reserves are converted to Boe on a one-to-one basis with oil. The
conversion rates are not necessarily indicative of the relationship of oil, natural gas and NGL prices.

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

Proved Undeveloped Reserves

The following table presents the changes in Devon’s total proved undeveloped reserves during 2019

(MMBoe).

Proved undeveloped reserves as of December 31, 2018

Extensions and discoveries
Revisions due to prices
Revisions other than price
Sale of reserves
Conversion to proved developed reserves

Proved undeveloped reserves as of December 31, 2019

U.S.

223
89
—
(20)
(17)
(107)
168

Total proved undeveloped reserves decreased 25% from 2018 to 2019 with the year-end 2019 balance

representing 22% of total proved reserves. Over 70% of the 89 MMBoe in extensions and discoveries were the result
of Devon’s focus on drilling and development activities in the STACK and Delaware Basin. This continued
development in the STACK, and Delaware Basin also led to the conversion of 107 MMBoe, or 48% of the 2018
U.S. proved undeveloped reserves to proved developed reserves. Costs incurred to develop and convert Devon’s
proved undeveloped reserves were approximately $918 million for 2019.

Price Revisions

Reserves decreased 28 MMBoe in 2019 primarily due to price decreases in the trailing 12 month averages for

oil, gas and NGLs.

Reserves increased 15 MMBoe and 27 MMBoe primarily due to price increases in the trailing 12 month

averages for oil, gas and NGLs in 2018 and 2017, respectively.

Revisions Other Than Price

Total revisions other than price in 2019 and 2018 primarily related to Devon’s development programs

evaluation of certain oil and dry gas regions, with the largest revisions being made in the STACK.

Extensions and Discoveries

2019 – Of the 160 MMBoe of additions from extensions and discoveries, 77 MMBoe were in the Delaware
Basin, 37 MMBoe were in the STACK, 28 MMBoe in the Powder River Basin and 18 MMBoe in Eagle Ford. In
2019, there were no additions related to infill drilling activities.

2018 – Approximately 85% of the additions were through focused efforts in the STACK (87 MMBoe) and the
Delaware Basin (88 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.

The 2018 extensions and discoveries included 21 MMBoe related to additions from Devon’s infill drilling

activities, primarily relating to the STACK.

2017 – Over 90% of the additions were through focused efforts in the STACK (120 MMBoe) and the

Delaware Basin (79 MMBoe). The remaining extensions were added throughout the remainder of Devon’s portfolio.

The 2017 extensions and discoveries included 61 MMBoe related to additions from Devon’s infill drilling

activities primarily related to the STACK.

Sale of Reserves

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

During 2019, 2018 and 2017, Devon had U.S. non-core asset divestitures. For additional information on these

divestitures, see Note 2.

Standardized Measure

The following tables reflect Devon’s standardized measure of discounted future net cash flows from its proved

reserves.

Future cash inflows
Future costs:

Development
Production
Future income tax expense

Future net cash flow
10% discount to reflect timing of cash flows
Standardized measure of discounted future net cash flows

Year Ended December 31,

2019

2018

2017

20,750

27,759

20,845

(2,093)
(9,174)
(1,037)
8,446
(3,048)
5,398 $

(2,957)
(10,991)
(2,036)
11,775
(4,625)
7,150 $

(2,687)
(7,782)
—
10,376
(4,422)
5,954

Future cash inflows, development costs and production costs were computed using the same assumptions for

prices and costs that were used to estimate Devon’s proved oil and gas reserves at the end of each year. For 2019
estimates, Devon’s future realized prices were assumed to be $53.58 per Bbl of oil, $1.69 per Mcf of gas and $15.26
per Bbl of NGLs. Of the $2.1 billion of future development costs as of the end of 2019, $0.8 billion, $0.5 billion and
$0.2 billion are estimated to be spent in 2020, 2021 and 2022, respectively.

Future development costs include not only development costs but also future asset retirement costs. Included

as part of the $2.1 billion of future development costs are $0.4 billion of future asset retirement costs. The future
income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax
credits under current laws.

The principal changes in Devon’s standardized measure of discounted future net cash flows are as follows:

Beginning balance
Net changes in prices and production costs
Oil, gas and NGL sales, net of production costs
Changes in estimated future development costs
Extensions and discoveries, net of future development costs
Purchase of reserves
Sales of reserves in place
Revisions of quantity estimates
Previously estimated development costs incurred during the period
Accretion of discount
Net change in income taxes and other
Ending balance

Year Ended December 31,

2019
7,150 $
(2,323)
(2,612)
303
1,690
43
(481)
(359)
857
506
624
5,398 $

2018

2017

5,954 $
1,533
(2,932)
(273)
2,944
—
(120)
(152)
787
648
(1,239)
7,150 $

3,292
1,784
(2,130)
(73)
2,398
2
(3)
(51)
322
445
(32)
5,954

100

DEVON ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

22.

Supplemental Quarterly Financial Information (Unaudited)

The following tables present a summary of Devon’s unaudited interim results of operations.

First
Quarter

Second
Quarter

2019
Third
Quarter

Fourth
Quarter

Total revenues (1)
Asset dispositions (2)
Earnings (loss) from continuing operations before income taxes
Net earnings (loss) from continuing operations
Net earnings (loss) from discontinued operations, net of income
tax expense (benefit) (4)
Net earnings (loss) attributable to Devon
Basic net earnings (loss) per share attributable to Devon
Diluted net earnings (loss) per share attributable to Devon

Total revenues (1)
Asset dispositions (2)
Earnings (loss) from continuing operations before income taxes (3)
Net earnings (loss) from continuing operations
Net earnings (loss) from discontinued operations, net of income
tax expense (benefit) (4)
Net earnings (loss) attributable to Devon
Basic net earnings (loss) per share attributable to Devon
Diluted net earnings (loss) per share attributable to Devon

$
$
$
$

1,079 $
(45) $
(497) $
(378) $

61 $
(317) $
(0.74) $
(0.74) $

1,806 $
(2) $
219 $
151 $

344 $
495 $
1.20 $
1.19 $

1,746 $
(1) $
190 $
136 $

Full Year
6,220
(48)
(109)
(79)

1,589 $
— $
(21) $
12 $

(27) $
109 $
0.27 $
0.27 $

(652) $
(642) $
(1.70) $
(1.70) $

(274)
(355)
(0.89)
(0.89)

First
Quarter

Second
Quarter

2018
Third
Quarter

Fourth
Quarter

1,665 $
(12) $
(264) $
(261) $

108 $
(197) $
(0.38) $
(0.38) $

1,727 $
(18) $
(486) $
(499) $

163 $
(425) $
(0.83) $
(0.83) $

1,974 $
(6) $
(105) $
96 $

2,469 $
2,537 $
5.17 $
5.14 $

Full Year
8,896
(278)
944
714

3,530 $
(242) $
1,799 $
1,378 $

(230) $
1,149 $
2.50 $
2.48 $

2,510
3,064
6.14
6.10

(1)

(2)
(3)

(4)

Includes noncash commodity hedge valuation changes of approximately $600 million loss in the first quarter of 2019 and approximately
$1.4 billion gain in the fourth quarter of 2018.
Additional discussion regarding asset dispositions can be found in Note 2.
Includes asset impairments of approximately $150 million in the second quarter of 2018. Additional discussion regarding asset
impairments can be found in Note 5.
2019 includes a $748 million asset impairment recognized in connection with the announced sale of Devon’s Barnett Shale assets in the
fourth quarter of 2019. In addition, 2019 includes a gain of $425 million (after-tax) on the sale of its Canadian business during 2019, and
2018 includes a gain on sale associated with the divestment of Devon’s aggregate ownership interests in EnLink and the General Partner
of approximately $2.2 billion (after-tax) in the third quarter of 2018. Additional discussion can be found in Note 18.

101

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

We have established disclosure controls and procedures to ensure that material information relating to Devon,

including its consolidated subsidiaries, is made known to the officers who certify Devon’s financial reports and to
other members of senior management and the Board of Directors.

Based on their evaluation, our principal executive and principal financial officers have concluded that our

disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act
of 1934) were effective as of December 31, 2019 to ensure that the information required to be disclosed by Devon in
the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized
and reported within the time periods specified in the SEC rules and forms.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial
reporting for Devon, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of
1934. Under the supervision and with the participation of Devon’s management, including our principal executive
and principal financial officers, we conducted an evaluation of the effectiveness of our internal control over financial
reporting based on the framework in Internal Control – Integrated Framework issued in 2013 by the Committee of
Sponsoring Organizations of the Treadway Commission (the “2013 COSO Framework”). Based on this evaluation
under the 2013 COSO Framework, which was completed on February 19, 2020, management concluded that its
internal control over financial reporting was effective as of December 31, 2019.

The effectiveness of our internal control over financial reporting as of December 31, 2019 has been audited by
KPMG LLP, an independent registered public accounting firm who audited our consolidated financial statements as
of and for the year ended December 31, 2019, as stated in their report, which is included under “Item 8. Financial
Statements and Supplementary Data” of this report.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the fourth quarter of 2019 that has

materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

On February 18, 2020, we entered into indemnification agreements with each of our directors. Subject to

various terms and conditions, the indemnification agreements provide for, among other things, (i) indemnification
rights for the directors with respect to certain claims and liabilities to the fullest extent permitted by Delaware law,
(ii) the right to advancement of expenses for the directors with respect to certain claims and liabilities,
(iii) clarification for the processes used to determine whether a director is entitled to indemnification and (iv) the
maintenance of directors and officers liability insurance coverage for the directors. The foregoing description of the
indemnification agreements is not complete and is subject to and qualified in its entirety by reference to a form of
the indemnification agreement, a copy of which is attached hereto as Exhibit 10.40 and the terms of which are
incorporated herein by reference.

102

Item 10. Directors, Executive Officers and Corporate Governance

PART III

The information called for by this Item 10 is incorporated herein by reference to the definitive Proxy
Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the
Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2019.

Item 11. Executive Compensation

The information called for by this Item 11 is incorporated herein by reference to the definitive Proxy
Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the
Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2019.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information called for by this Item 12 is incorporated herein by reference to the definitive Proxy
Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the
Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2019.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information called for by this Item 13 is incorporated herein by reference to the definitive Proxy
Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the
Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2019.

Item 14. Principal Accountant Fees and Services

The information called for by this Item 14 is incorporated herein by reference to the definitive Proxy
Statement to be filed by Devon pursuant to Regulation 14A of the General Rules and Regulations under the
Securities Exchange Act of 1934 no later than 120 days following the fiscal year ended December 31, 2019.

103

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) The following documents are included as part of this report:

1. Consolidated Financial Statements

Reference is made to the Index to Consolidated Financial Statements and Consolidated Financial Statement

Schedules appearing at “Item 8. Financial Statements and Supplementary Data” in this report.

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

Exhibit No.

2.1

2.2

2.3

3.1

3.2

4.1

4.2

4.3

4.4

Description

Purchase Agreement, dated June 5, 2018, by and among Devon Gas Services, L.P. and Southwestern
Gas Pipeline, L.L.C., as sellers, and Enlink Midstream Manager, LLC, Registrant, and GIP III Stetson
I, L.P. and GIP III Stetson II, L.P., as acquirors (incorporated by reference to Exhibit 2.1 to Registrant’s
Form 8-K filed June 7, 2018; File No. 001-32318).

Agreement of Purchase and Sale, dated as of May 28, 2019, among Devon Canada Corporation, Devon
Canada Crude Marketing Corporation and Canadian Natural Resources Limited (incorporated by
reference to Exhibit 2.1 to the Company’s Form 8-K filed May 31, 2019; File No. 001-32318).

Purchase and Sale Agreement, dated December 17, 2019, by and between Devon Energy Production
Company, L.P. and BKV Barnett, LLC (incorporated by reference to Exhibit 2.1 to the Company’s
Form 8-K filed December 18, 2019; File No. 001-32318).*

Registrant’s Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1 of
Registrant’s Form 10-K filed February 21, 2013; File No. 001-32318).

Registrant’s Bylaws (incorporated by reference to Exhibit 3.1 of Registrant’s Form 8-K filed
January 27, 2016; File No. 001-32318).

Indenture, dated as of July 12, 2011, between Registrant and UMB Bank, National Association, as
Trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed July 12, 2011; File No.
001-32318).

Supplemental Indenture No. 1, dated as of July 12, 2011, to Indenture dated as of July 12, 2011,
between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.60% Senior
Notes due 2041 (incorporated by reference to Exhibit 4.2 to Registrant’s Form 8-K filed July 12, 2011;
File No. 001-32318).

Supplemental Indenture No. 2, dated as of May 14, 2012, to Indenture dated as of July 12, 2011,
between Registrant and UMB Bank, National Association, as Trustee, relating to the 4.750% Senior
Notes due 2042 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed May 14, 2012;
File No. 001-32318).

Supplemental Indenture No. 4, dated as of June 16, 2015, to Indenture dated as of July 12, 2011,
between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.000% Senior
Notes due 2045 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed June 16, 2015;
File No. 001-32318).

104

Exhibit No.

4.5

4.6

4.7

4.8

4.9

4.10

4.11

4.12

4.13

4.14

Description

Supplemental Indenture No. 5, dated as of December 15, 2015, to Indenture dated as of July 12, 2011,
between Registrant and UMB Bank, National Association, as Trustee, relating to the 5.850% Senior
Notes due 2025 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K filed December 15,
2015; File No. 001-32318).

Indenture, dated as of March 1, 2002, between Registrant and The Bank of New York Mellon Trust
Company, N.A. (as successor to The Bank of New York), as Trustee (incorporated by reference to
Exhibit 4.1 of Registrant’s Form 8-K filed April 9, 2002; File No. 000-30176).

Supplemental Indenture No. 1, dated as of March 25, 2002, to Indenture dated as of March 1, 2002,
between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to
the 7.95% Senior Debentures due 2032 (incorporated by reference to Exhibit 4.2 to Registrant’s Form
8-K filed April 9, 2002; File No. 000-30176).

Supplemental Indenture No. 4, dated as of March 22, 2018, to Indenture dated as of March 1, 2002,
between Registrant and The Bank of New York Mellon Trust Company, N.A., as Trustee, relating to
the 7.95% Senior Notes due 2032 (incorporated by reference to Exhibit 4.1 to Registrant’s Form 8-K
filed March 22, 2018; File No. 000-32318).

Indenture, dated as of October 3, 2001, among Devon Financing Company, L.L.C. (f/k/a Devon
Financing Corporation, U.L.C.), as Issuer, Registrant, as Guarantor, and The Bank of New York Mellon
Trust Company, N.A., originally The Chase Manhattan Bank, as Trustee, relating to the 7.875%
Debentures due 2031 (incorporated by reference to Exhibit 4.7 to Registrant’s Registration Statement
on Form S-4 filed October 31, 2001; File No. 333-68694).

Assignment and Assumption Agreement, dated as of June 19, 2019, by and between Devon Financing
Company, L.L.C. and Registrant, relating to that certain Indenture, dated as of October 3, 2001, by and
among Devon Financing Company, L.L.C. (f/k/a Devon Financing Company, U.L.C.), as Issuer, Devon
Energy Corporation, as Guarantor, and The Bank of New York Mellon Trust Company, N.A., as
successor to The Chase Manhattan Bank, as Trustee, and the 7.875% Debentures due 2031 issued
thereunder (incorporated by reference to Exhibit 4.1 to the Company’s Form 10-Q filed August 7,
2019; File No. 001-32318).

Senior Indenture, dated as of September 1, 1997, between Devon OEI Operating, L.L.C. (as successor
to Seagull Energy Corporation) and The Bank of New York Mellon Trust Company, N.A. (as successor
to The Bank of New York), as Trustee, and related Specimen of 7.50% Senior Notes due 2027
(incorporated by reference to Exhibit 4.4 to Ocean Energy Inc.’s Form 10-K filed March 23, 1998; File
No. 001-08094).

First Supplemental Indenture, dated as of March 30, 1999, to Senior Indenture dated as of September 1,
1997, by and among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and The Bank of New
York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027
(incorporated by reference to Exhibit 4.10 to Ocean Energy, Inc.’s Form 10-Q filed May 17, 1999; File
No. 001-08094).

Second Supplemental Indenture, dated as of May 9, 2001, to Senior Indenture dated as of September 1,
1997, by and among Devon OEI Operating, L.L.C., its Subsidiary Guarantor, and The Bank of New
York Mellon Trust Company, N.A., as Trustee, relating to the 7.50% Senior Notes due 2027
(incorporated by reference to Exhibit 99.4 to Ocean Energy, Inc.’s Form 8-K filed May 14, 2001; File
No. 033-06444).

Third Supplemental Indenture, dated as of December 31, 2005, to Senior Indenture dated as of
September 1, 1997, by and among Devon OEI Operating, L.L.C., as Issuer, Devon Energy Production
Company, L.P., as Successor Guarantor, and The Bank of New York Mellon Trust Company, N.A., as
Trustee, relating to the 7.50% Senior Notes due 2027 (incorporated by reference to Exhibit 4.27 of
Registrant’s Form 10-K filed March 3, 2006; File No. 001-32318).

4.15

Description of Securities Registered under Section 12 of the Securities Exchange Act of 1934.

105

Exhibit No.

10.1

10.2

10.3

10.4

10.5

10.6

10.7

10.8

10.9

10.10

10.11

10.12

10.13

10.14

10.15

10.16

Description

Credit Agreement, dated as of October 5, 2018, among Registrant, as U.S. Borrower, Devon Canada
Corporation, as Canadian Borrower, Bank of America, N.A., as Administrative Agent, Swing Line
Lender and an L/C Issuer, and each Lender and L/C Issuer from time to time party thereto (incorporated
by reference to Exhibit 10.1 of Registrant’s Form 8-K filed October 9, 2018; File No. 001-32318).

First Amendment to Credit Agreement and Extension Agreement, dated as of December 13, 2019, by
and among Registrant, as U.S. Borrower, Devon Canada Corporation, as Canadian Borrower, Bank of
America, N.A., individually and as Administrative Agent, and the Lenders party thereto.

Devon Energy Corporation 2009 Long-Term Incentive Plan (as amended and restated effective June 6,
2012) (incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed June 8, 2012; File
No. 001-32318).**

Devon Energy Corporation 2015 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1
to Registrant’s Form S-8 filed June 3, 2015; File No. 333-204666).**

Devon Energy Corporation 2017 Long-Term Incentive Plan (incorporated by reference to Exhibit 99.1
to Registrant’s Form S-8 filed June 7, 2017; File No. 333-218561).**

2013 Amendment (effective as of March 6, 2013) to the Devon Energy Corporation 2009 Long-Term
Incentive Plan (as amended and restated effective June 6, 2012) (incorporated by reference to Exhibit
10.1 to Registrant’s Form 10-Q filed May 1, 2013; File No. 001-32318).**

Devon Energy Corporation Annual Incentive Compensation Plan (amended and restated effective as of
January 1, 2017) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed June 12,
2017; File No. 001-32318).**

Devon Energy Corporation Non-Qualified Deferred Compensation Plan (amended and restated
effective as of April 15, 2014) (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q
filed August 6, 2014; File No. 001-32318).**

Amendment 2014-2, executed May 9, 2014, to the Devon Energy Corporation Non-Qualified Deferred
Compensation Plan (amended and restated effective April 15, 2014) (incorporated by reference to
Exhibit 10.11 to Registrant’s Form 10-K filed February 20, 2015; File No. 001-32318).**

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Non-Qualified
Deferred Compensation Plan (amended and restated effective April 15, 2014) (incorporated by
reference to Exhibit 10.13 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**

Amendment 2018-1, executed August 21, 2018, to the Devon Energy Corporation Non-Qualified
Deferred Compensation Plan (amended and restated effective April 15, 2014) (incorporated by
reference to Exhibit 10.10 to Registrant’s Form 10-K filed February 20, 2019; File No. 001-32318).**

Devon Energy Corporation Benefit Restoration Plan (amended and restated effective January 1, 2012)
(incorporated by reference to Exhibit 10.15 to Registrant’s Form 10-K filed February 24, 2012; File No.
001-32318).**

Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Benefit Restoration
Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.6 to
Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).**

Amendment 2015-1, executed April 15, 2015, to the Devon Energy Corporation Benefit Restoration
Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.1 to
Registrant’s Form 10-Q filed May 6, 2015; File No. 001-32318).**

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Benefit Restoration
Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit 10.17 to
Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**

Devon Energy Corporation Defined Contribution Restoration Plan (amended and restated effective
January 1, 2012) (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed February
24, 2012; File No. 001-32318).**

106

Exhibit No.

10.17

10.18

10.19

10.20

10.21

10.22

10.23

10.24

10.25

10.26

10.27

10.28

10.29

10.30

10.31

Description

Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Defined Contribution
Restoration Plan (amended and restated effective January 1, 2012) (incorporated by reference to Exhibit
10.7 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).**

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Defined
Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by
reference to Exhibit 10.20 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**

Amendment 2018-1, executed August 21, 2018, to the Devon Energy Corporation Defined
Contribution Restoration Plan (amended and restated effective January 1, 2012) (incorporated by
reference to Exhibit 10.18 to Registrant’s Form 10-K filed February 20, 2019; File No. 001-32318).**

Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Defined Contribution
Restoration Plan (as amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.1 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).**

Devon Energy Corporation Supplemental Contribution Plan (amended and restated effective January 1,
2012) (incorporated by reference to Exhibit 10.17 to Registrant’s Form 10-K filed February 24, 2012;
File No. 001-32318).**

Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental
Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.8 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).**

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental
Contribution Plan (amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.23 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**

Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Supplemental
Contribution Plan (as amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.2 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).**

Devon Energy Corporation Supplemental Executive Retirement Plan (amended and restated effective
January 1, 2012) (incorporated by reference to Exhibit 10.18 to Registrant’s Form 10-K filed February
24, 2012; File No. 001-32318).**

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental
Executive Retirement Plan (amended and restated effective January 1, 2012) (incorporated by reference
to Exhibit 10.25 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**

Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Supplemental
Executive Retirement Plan (as amended and restated effective January 1, 2012) (incorporated by
reference to Exhibit 10.3 to Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).**

Devon Energy Corporation Supplemental Retirement Income Plan (amended and restated effective
January 1, 2012) (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February
24, 2012; File No. 001-32318).**

Amendment 2014-1, executed March 7, 2014, to the Devon Energy Corporation Supplemental
Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.9 to Registrant’s Form 10-Q filed May 9, 2014; File No. 001-32318).**

Amendment 2016-1, executed October 20, 2016, to the Devon Energy Corporation Supplemental
Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.28 to Registrant’s Form 10-K filed February 15, 2017; File No. 001-32318).**

Amendment 2019-1, effective September 10, 2019, to the Devon Energy Corporation Supplemental
Retirement Income Plan (amended and restated effective January 1, 2012) (incorporated by reference to
Exhibit 10.2 to Registrant’s Form 10-Q filed November 6, 2019; File No. 001-32318).**

107

Exhibit No.

10.32

Devon Energy Corporation Incentive Savings Plan (amended and restated effective January 1, 2018)
(incorporated by reference to Exhibit 10.28 to Registrant’s Form 10-K filed February 21, 2018; File No.
001-32318).**

Description

10.33 Amendment 2018-1, executed December 14, 2018, to the Devon Energy Corporation Incentive Savings

Plan (amended and restated effective January 1, 2018) (incorporated by reference to Exhibit 10.28 to
Registrant’s Form 10-K filed February 20, 2019; File No. 001-32318).**

10.34

10.35

10.36

10.37

10.38

10.39

10.40

10.41

10.42

10.43

10.44

10.45

10.46

Amendment 2019-1, executed June 19, 2019, to the Devon Energy Corporation Incentive Savings Plan
(as amended and restated effective January 1, 2018) (incorporated by reference to Exhibit 10.4 to
Registrant’s Form 10-Q filed August 7, 2019; File No. 001-32318).**

Amended and Restated Form of Employment Agreement between Registrant and certain executive
officers (incorporated by reference to Exhibit 10.19 to Registrant’s Form 10-K filed February 27, 2009;
File No. 001-32318).**

Form of Amendment No. 1 to the Amended and Restated Employment Agreement between Registrant
and certain executive officers (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed
April 25, 2011; File No. 001-32318).**

Form of Employment Agreement between Registrant and certain executive officers (incorporated by
reference to Exhibit 10.22 to Registrant’s Form 10-K filed February 28, 2014; File No. 001-32318).**

Employment Agreement, dated April 19, 2017, by and between Registrant and Mr. Jeffrey L. Ritenour
(incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K, filed on April 20, 2017; File No.
001-32318).**

Employment Agreement, dated effective September 13, 2019, by and between Registrant and Mr.
David G. Harris (incorporated by reference to Exhibit 10.1 to Registrant’s Form 8-K filed September
16, 2019; File No. 001-32318).**

Form of Indemnity Agreement between Registrant and non-management directors.**

Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015
Long-Term Incentive Plan between Registrant and David A. Hager for performance based restricted
stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed November 4,
2015; File No. 001-32318).**

Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the 2015
Long-Term Incentive Plan between Registrant and executive officers for performance based restricted
stock awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 4, 2016;
File No. 001-32318).**

2017 Form of Notice of Grant of Performance Restricted Stock Award and Award Agreement under the
2015 Long-Term Incentive Plan between Registrant and executive officers for performance based
restricted stock awarded (incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed
May 3, 2017; File No. 001-32318).**

2018 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-
Term Incentive Plan between Registrant and executive officers for restricted stock awarded
(incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed on May 2, 2018; File No.
001-32318).**

2019 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-
Term Incentive Plan between Registrant and executive officers for restricted stock awarded
(incorporated by reference to Exhibit 10.1 to Registrant’s Form 10-Q filed May 1, 2019; File No. 001-
32318).**

2017 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2015
Long-Term Incentive Plan between Registrant and executive officers for performance based restricted
share units awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 3,
2017; File No. 001-32318).**

108

Exhibit No.

10.47

10.48

10.49

10.50

23.1

23.2

31.1

31.2

32.1

32.2

Description

2018 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017
Long-Term Incentive Plan between Registrant and executive officers for performance based restricted
share units awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-Q filed May 2,
2018; File No. 001-32318).**

2019 Form of Notice of Grant of Performance Share Unit Award and Award Agreement under the 2017
Long-Term Incentive Plan between Devon Energy Corporation and executive officers for performance
based restricted share units awarded (incorporated by reference to Exhibit 10.2 to Registrant’s Form 10-
Q filed May 1, 2019; File No. 001-32318).**

Form of Notice of Grant of Nonqualified Stock Options and Award Agreement under the 2009 Long-
Term Incentive Plan between Registrant and certain employees and executive officers for nonqualified
stock options granted (incorporated by reference to Exhibit 10.16 to Registrant’s Form 10-K filed
February 25, 2011; File No. 001-32318).**

2019 Form of Notice of Grant of Restricted Stock Award and Award Agreement under the 2017 Long-
Term Incentive Plan between Registrant and all non-management directors for restricted stock
awarded.**

List of Subsidiaries.

Consent of KPMG LLP.

Consent of LaRoche Petroleum Consultants, Ltd.

Certification of principal executive officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Certification of principal financial officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Certification of principal executive officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Certification of principal financial officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Report of LaRoche Petroleum Consultants, Ltd.

101.INS

Inline XBRL Instance Document – the XBRL 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 Extension Schema Document.

101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB Inline XBRL Taxonomy Extension Labels Linkbase Document.

101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104

Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).

*
**

Portions of this exhibit have been omitted in accordance with Item 601(b)(2)(ii) of Regulation S-K.
Indicates management contract or compensatory plan or arrangement.

Item 16. Form 10-K Summary

Not applicable.

109

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has

duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

SIGNATURES

DEVON ENERGY CORPORATION

By:

/s/ JEFFREY L. RITENOUR
Jeffrey L. Ritenour
Executive Vice President and
Chief Financial Officer

February 19, 2020

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the

following persons on behalf of the Registrant and in the capacities and on the dates indicated.

/s/ DAVID A. HAGER
David A. Hager

/s/ JEFFREY L. RITENOUR
Jeffrey L. Ritenour

/s/ JEREMY D. HUMPHERS
Jeremy D. Humphers

/s/ DUANE C. RADTKE
Duane C. Radtke

/s/ BARBARA M. BAUMANN
Barbara M. Baumann

/s/ JOHN E. BETHANCOURT
John E. Bethancourt

/s/ ANN G. FOX
Ann G. Fox

/s/ ROBERT H. HENRY
Robert H. Henry

/s/ MICHAEL M. KANOVSKY
Michael M. Kanovsky

/s/ JOHN KRENICKI JR.
John Krenicki Jr.

/s/ ROBERT A. MOSBACHER, JR.
Robert A. Mosbacher, Jr.

/s/ KEITH O. RATTIE
Keith O. Rattie

/s/ MARY P. RICCIARDELLO
Mary P. Ricciardello

President, Chief Executive Officer and
Director (Principal executive officer)

February 19, 2020

Executive Vice President
and Chief Financial Officer
(Principal financial officer)

Senior Vice President
and Chief Accounting Officer
(Principal accounting officer)

February 19, 2020

Chairman of the Board

February 19, 2020

Director

110