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

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 19, 2019

DEVON ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)

 
					
DELAWARE	 	001-32318	 	73-1567067	
(State or Other Jurisdiction
of Incorporation)	 	(Commission
File Number)	 	(IRS Employer
Identification Number)	
		
333 W. SHERIDAN AVE., OKLAHOMA CITY,
OKLAHOMA	 	73102-5015	
(Address of Principal Executive Offices)	 	(Zip Code)	
Registrant’s telephone number, including area code: (405) 235-3611
Not Applicable
(Former Name or Former Address, if Changed Since Last Report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instructions A-2. Below):
 
 	☐	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)	
 
 	☐	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)	
 
 	☐	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))	
 
 	☐	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))	
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§ 230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§ 240.12b-2 of this chapter).
Emerging growth company  ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

 

Item 2.02	Results of Operations and Financial Condition.	
On February 19, 2019, Devon Energy Corporation (the “Company”) issued press releases announcing certain strategic initiatives and its financial and operational results for the quarter and year ended December 31, 2018. In connection with these releases, the Company also provided a strategic update and operations report for the fourth quarter of 2018, as well as certain supplemental financial information, which included guidance for 2019. Copies of these documents are furnished as Exhibits 99.1, 99.2, 99.3 and 99.4, respectively, to this report and will be available on the Company’s website at www.devonenergy.com.
The information contained in this report and the exhibits hereto shall not be deemed to be “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and shall not be incorporated by reference into any filings made by the Company under the Securities Act of 1933, as amended, or the Exchange Act, except as may be expressly set forth by specific reference in such filing.
 
Item 7.01	Regulation FD Disclosure.	
The information in Item 2.02 above is incorporated herein by reference.
 
Item 9.01	Financial Statements and Exhibits.	
(d)    Exhibits

Exhibit	
    No.    	  		Description of Exhibits	
			
99.1	  	Press release regarding strategic initiatives, dated February 19, 2019.		
			
99.2	  	Press release regarding results for the quarter and year ended December 31, 2018, dated February 19, 2019.		
			
99.3	  	Strategic update and fourth quarter 2018 operations report.		
			
99.4	  	Supplemental financial information.		

SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

DEVON ENERGY CORPORATION	
		
By:	 	/s/ Jeffrey L. Ritenour	
	 	Jeffrey L. Ritenour	
	 	Executive Vice President and Chief Financial Officer	
Date: February 19, 2019

Exhibit 99.1

NEWS RELEASE
Devon Energy Announces Final Step to Complete Transformation to U.S. Oil Growth Company
Highlights
 
 	•	 	Pursuing separation of its Canadian and Barnett Shale assets	
 
 	•	 	Expect to complete separation by end of 2019	
 
 	•	 	Share-repurchase authorization increased to $5 billion	
 
 	•	 	Quarterly dividend increased 13 percent	
 
 	•	 	Committed to at least $780 million in annual cost reductions	
OKLAHOMA CITY – Feb. 19, 2019 – Devon Energy Corp. (NYSE: DVN) today announced that the board of directors has authorized the company to pursue the separation of its Canadian and Barnett Shale assets to complete its transformation to a high-return U.S. oil growth business. Devon will evaluate multiple methods of separating the assets, including a potential sale or spin-off. The separation will allow the company to focus on its top-tier, high-return U.S. oil assets and is aligned with Devon’s previously announced long-term strategic plan.
“With our world-class U.S. oil resource plays rapidly building momentum and achieving operating scale, the final step in our multi-year transformation is an aggressive, transformational move that will accelerate value creation for our shareholders by further simplifying our resource-rich asset portfolio,” said Dave Hager, president and CEO. “New Devon will emerge with a highly focused U.S. asset portfolio and has the ability to substantially increase returns and profitability as we aggressively align our cost structure to expand margins with this top-tier oil business. The New Devon will be able to grow oil volumes at a mid-teens rate while generating free cash flow at pricing above $46 per barrel.”
The company expects to complete the separation of its Canadian and Barnett Shale assets by the end of 2019. Devon has hired advisors for each asset, and data rooms for Canada and the Barnett are expected to be open by the second quarter of 2019. The company anticipates using potential proceeds from the separation of these assets to maintain target debt levels of 1.0-to-1.5 times EBITDA and to continue Devon’s industry-leading share repurchase activity.
Share-Repurchase Program Increased to $5 Billion and Dividend Raised 13 Percent
Devon also announced today that its board of directors authorized a $1 billion increase to the company’s previously announced $4 billion share-repurchase program, bringing the total repurchase program to $5 billion. The authorization for the repurchase program expires on Dec. 31, 2019. As of Feb. 18, 2019, Devon had completed $3.4 billion of repurchases under the program, totaling approximately 90 million shares.
All purchases will be made in accordance with applicable laws from time to time in open-market or private transactions, depending on market conditions, and may be discontinued at any time. At the current share price, this program covers nearly 30 percent of the company’s outstanding common stock.
 
1

Additionally, the company’s board of directors approved a 13 percent increase in its quarterly common stock dividend beginning in the second quarter of 2019. The new quarterly dividend rate will be $0.09 per share, compared to the prior quarterly dividend of $0.08 per share.
Commitment to $780 Million in Annual Cost Reductions
With Devon’s new, narrowed focus as a U.S. oil business, the company is committed to aligning the cost structure by taking steps to deliver at least $780 million in sustainable annual cost savings by 2021. The cost-reduction plan includes a number of actions to achieve more efficient field-level operations and improvements in drilling and completion costs while better aligning personnel with the go-forward business. Approximately 70 percent of the estimated cost reductions are expected to be accomplished by year-end 2019, with the remaining savings realized in 2020 and 2021.
“Devon is taking aggressive, meaningful and decisive steps to improve our operational and corporate cost structure,” said Jeff Ritenour, executive vice president and chief financial officer. “The combination of selling higher-cost assets and bringing online new lower cost production, along with our commitment to at least $780 million in annual cost-reductions, is expected to drive down per-unit cash costs more than 20 percent by 2021.”
To underscore the commitment to achieving targeted results, the standing reserves committee of the board of directors will expand its scope of work to include oversight and measurement of progress toward the targets alongside management. The committee is composed of three independent board members, each with strong operational backgrounds.
Positioned for Significant Margin Expansion and Sustainable Long-Term Growth
New Devon’s business is characterized by core of the core positions with significant operating scale in four basins: the Delaware, STACK, Power River and Eagle Ford. In the fourth-quarter of 2018, these assets delivered light-oil production growth of 20 percent year over year, with total production averaging 296,000 oil-equivalent barrels (Boe) per day. New Devon has operating margins that are 57 percent above the total company average in 2018 and has demonstrated well productivity that has exceeded the industry average by approximately 40 percent over the past three years.
With the steps announced today, the company’s highly concentrated U.S. oil business is expected to generate 13 to 18 percent oil growth in 2019, with 10 percent less upstream capital than 2018, and is self-funded at $46 oil prices (assuming flat service and supply pricing relative to 2018). With this plan, New Devon is now positioned to deliver substantially higher price realizations, significantly improved per-unit costs, superior operating margins and sustainable long-term growth through its deep inventory of high-caliber oil growth opportunities.
Detailed 2019 Guidance and Three-Year Performance Targets
More detailed information regarding Devon’s retained U.S. oil assets is available within its fourth-quarter 2018 earnings materials available at www.devonenergy.com . Included within these documents are operating and financial metrics by key asset, detailed guidance for 2019 and updated three-year performance targets for the business.
 
2

Advisors
Devon has retained J.P. Morgan Securities LLC and Goldman Sachs to assist the company in exploring strategic alternatives for its Canadian business. Devon has retained Jefferies as financial advisor to assist the company in exploring strategic alternatives for the Barnett Shale.
Forward-Looking Statements
This release includes “forward-looking statements” as defined by the Securities and Exchange Commission (SEC). Such statements include those concerning strategic plans, expectations and objectives for future operations, 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 press release that address activities, events or developments that the company 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 the control of the company. Statements regarding our business and operations are subject to all of the risks and uncertainties normally incident to the exploration for and development and production of oil and gas. These risks include, but are not limited to: our ability to successfully complete the separation transactions in a timely manner or at all; the amount of proceeds received (if any) in such separation transactions, and the ultimate use of those proceeds; our ability to realize the anticipated cost savings and other benefits with respect to the retained business; changes in commodity prices, market conditions or other circumstances that could negatively impact the company’s ability to complete the stock repurchase program or maintain our quarterly dividend; and any of the other risks and uncertainties identified in our Form 10-K and our other filings with the SEC. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this release are made as of the date of this release, even if subsequently made available by Devon on its website or otherwise. Devon does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise.
About Devon Energy
Devon Energy is a leading independent energy company engaged in finding and producing oil and natural gas. Based in Oklahoma City and included in the S&P 500, Devon operates in several of the most prolific oil and natural gas plays in the U.S. and Canada with an emphasis on achieving strong returns and capital-efficient, cash-flow growth. For more information, please visit www.devonenergy.com .

Investor Contacts	  	Media Contact	
Scott Coody, 405-552-4735	  	John Porretto, 405-228-7506	
Chris Carr, 405-228-2496	  		
 
3

Exhibit 99.2

NEWS RELEASE
Devon Energy Reports Fourth-Quarter and Full-Year 2018 Results
OKLAHOMA CITY – Feb. 19, 2019 – Devon Energy Corp. (NYSE: DVN) today reported operational and financial results for the fourth quarter and full-year 2018. Also provided is the company’s guidance for the first quarter and full-year 2019. Supplemental financial tables for the fourth quarter, full-year 2018 and 2019 outlook are available on the company’s website at www.devonenergy.com .
Fourth-Quarter and Full-Year 2018 Highlights
 
 	•	 	Light-oil production advances 20 percent year over year in fourth quarter	
 
 	•	 	Prolific well productivity in Delaware Basin drives high-return U.S. oil growth	
 
 	•	 	U.S. oil reserves added at attractive finding cost	
 
 	•	 	Corporate cost structure improves 21 percent in fourth quarter	
 
 	•	 	Divestiture program approaches nearly $5 billion in proceeds	
 
 	•	 	Stock-repurchase program reaches $3.4 billion	
“2018 was a pivotal year for Devon as we took several significant steps toward achieving our long-term strategic goals,” said Dave Hager, president and CEO. “Operationally, we successfully transitioned our franchise U.S. oil business into full-field development, which resulted in high-return, light-oil production advancing 20 percent in the fourth quarter. In addition to this strong operating performance, we made substantial progress high-grading our asset portfolio, building per-share value through our industry-leading share-repurchase program and reducing our outstanding debt by more than 40 percent.”
Completing Transformation to High-Return U.S. Oil Growth Company
Additionally, in a separate press release issued today, Devon announced that its board of directors has authorized the company to pursue the separation of its Canadian and Barnett Shale assets to complete the transformation to a high-return U.S. oil growth business. The company will evaluate multiple methods of separating the assets, including a potential sale or spin-off. The separation will allow Devon to focus on its top-tier, high-return U.S. oil assets and is aligned with the company’s previously announced long-term strategic plan.
“With our world-class U.S. oil resource plays rapidly building momentum and achieving operating scale, the final step in our multi-year transformation is an aggressive, transformational move that will accelerate value creation for our shareholders by further simplifying our resource-rich asset portfolio,” said Hager. “New Devon will emerge with a highly focused U.S. oil portfolio and has the ability to substantially increase returns and profitability as we aggressively align our cost structure to expand margins with this top-tier oil business. The New Devon will be able to grow oil volumes at a mid-teens rate while generating free cash flow at pricing above $46 per barrel.”
Share-Repurchase Program Increased to $5 Billion and Dividend Raised 13 Percent
Devon also announced today that its board of directors authorized a $1 billion increase to the company’s previously announced $4 billion share-repurchase program, bringing the total repurchase program to $5 billion. The authorization for the repurchase program expires on Dec. 31, 2019. As of Feb. 18, 2019, Devon had completed $3.4 billion of repurchases under the program, totaling approximately 90 million shares.

All purchases will be made in accordance with applicable laws from time to time in open-market or private transactions, depending on market conditions, and may be discontinued at any time. At the current share price, this program covers nearly 30 percent of the company’s outstanding common stock.
Additionally, the company’s board of directors approved a 13 percent increase in its quarterly common stock dividend beginning in the second quarter of 2019. The new quarterly dividend rate will be $0.09 per share, compared to the prior quarterly dividend of $0.08 per share. The adjusted dividend is payable on June 28, 2019, to stockholders of record at the close of business on June 14, 2019.
Delaware Basin Drives U.S. Oil Production 20 Percent Higher
Fourth-quarter production was highlighted by Devon’s U.S. oil business, which is attaining the highest margins and returns in the company’s portfolio. In the quarter, light-oil production from the company’s retained assets in the U.S. averaged 126,000 barrels per day, a 20 percent increase compared to the fourth quarter of 2017. This strong performance in the U.S. was driven by growth in the company’s four key oil assets: the Delaware Basin, STACK, Powder River Basin and Eagle Ford.
The strongest asset-level performance in the quarter was achieved by the Delaware Basin operations in southeast New Mexico. Oil production from this world-class asset increased 49 percent year over year, driving volumes to 84,000 oil-equivalent barrels (Boe) per day. In early 2019, production growth has accelerated, with January rates averaging 96,000 Boe per day, a 14 percent increase compared to the fourth quarter of 2018.
In Canada, net oil production averaged 120,000 barrels per day in the fourth quarter. Production was reduced by approximately 17,000 barrels per day in the quarter due to the company’s decision to curtail volumes in response to market conditions. These curtailments were partially offset by royalty adjustments related to the lower commodity price environment.
Overall, Devon’s reported net production averaged 532,000 Boe per day during the fourth quarter of 2018, exceeding midpoint guidance by 3,000 Boe per day. Of this total, oil production accounted for the largest component of the product mix at 47 percent of total volumes.
Light-Oil Reserves Added at Attractive Finding Costs
Devon’s estimated proved reserves were 1.9 billion Boe on Dec. 31, 2018, with proved developed reserves accounting for 77 percent of the total. The company’s reserve additions in 2018 came primarily from its retained U.S. assets, where proved oil reserves increased 16 percent year over year.
In 2018, Devon’s oil-driven capital programs in the U.S. added 232 million Boe of reserves (extensions and discoveries). This represents a reserve replacement rate in the U.S. of approximately 150 percent. Excluding property acquisition costs, these reserves were added at an attractive finding cost of less than $10 per Boe.
Premium Gulf Coast Pricing Drives Upstream Revenue Higher in 2018
Devon’s upstream revenue, excluding commodity derivatives, totaled $5.7 billion in 2018, a 10 percent increase compared to 2017. Contributing factors to revenue growth were higher commodity price realizations and growth in higher-margin U.S. oil production.

Also contributing to higher revenues in 2018 were firm transport and marketing agreements that provide the majority of Devon’s U.S. oil production direct access to advantaged Gulf Coast pricing. Combined with price protection provided by regional basis swaps, oil realizations in the U.S. averaged nearly 100 percent of the West Texas Intermediate (WTI) benchmark.
In the fourth quarter, the company’s upstream revenue, excluding commodity derivatives, totaled $1.1 billion, an 18 percent decline compared to the year-ago quarter. Revenue in the fourth quarter was impacted by historically wide differentials in Canada, which negatively impacted the realized price on heavy oil production. Devon mitigated the weak pricing environment in Canada through its Western Canadian Select basis swap hedge position that generated $144 million of cash settlements in the quarter.
Cost Structure Continues to Improve in the Fourth Quarter
Devon’s production expense, which represents field-level operating costs, totaled $556 million in the fourth quarter. This result is a 2 percent improvement on a per-unit basis compared to the third quarter of 2018. The largest components of production expense are lease operating expense and transportation, which totaled $471 million, or $9.62 per Boe in the quarter. Production and property taxes also contributed $85 million to production expense during the fourth quarter.
General and administrative (G&A) expenses totaled $151 million in the fourth quarter, a 21 percent improvement from the fourth quarter of 2017. The lower overhead costs were driven by reduced personnel expenses.
The company also reduced financing costs in 2018. With the retirement of $1.1 billion of outstanding debt over the past year, net financing costs improved by 9 percent in the fourth quarter to $70 million compared to the fourth quarter of 2017.
Fourth-Quarter Earnings and Cash-Flow Results
The company reported net earnings attributable to Devon of $1.1 billion, or $2.48 per diluted share, in the fourth quarter. Adjusting for items securities analysts typically exclude from published estimates, the company’s core earnings totaled $46 million, or $0.10 per diluted share.
Devon’s operating cash flow from continuing operations totaled $542 million in the fourth quarter and $2.2 billion for the full-year 2018. The company also generated additional cash inflows through its ongoing divestiture activity. With the closing of the EnLink transaction, combined with other minor asset sales, total proceeds from Devon’s divestiture program have reached nearly $5 billion.
Debt Reduction Strengthens Investment-Grade Financial Position
Overall, Devon’s financial position remains exceptionally strong, with investment-grade credit ratings and excellent liquidity. The company exited the fourth quarter with $2.4 billion of cash on hand and an undrawn credit facility of $3 billion. At year end, Devon had an outstanding debt balance of $5.9 billion with no significant debt maturities until mid-2021.

Three-Year Performance Targets and Detailed 2019 Guidance
In conjunction with fourth-quarter results, Devon provided updated three-year performance targets and its detailed capital and production outlook for 2019. The company’s three-year performance targets are available within the company’s fourth-quarter 2018 operations report at www.devonenergy.com . Detailed guidance for the first quarter and full-year 2019 are provided within the supplemental financial tables that are available on the company’s website at www.devonenergy.com .
Conference Call Webcast and Supplemental Earnings Materials
Also provided with today’s release is the company’s detailed operations report that is available on the company’s website at www.devonenergy.com . The company’s fourth-quarter conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, Feb. 20, 2019, and will serve primarily as a forum for analyst and investor questions and answers.
Non-GAAP Disclosures
This release may include non-GAAP (generally accepted accounting principles) financial measures. Such non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. Reconciliations of these non-GAAP measures and other disclosures are provided within the supplemental financial tables that are available on the company’s website at www.devonenergy.com .
Forward-Looking Statements
This press release includes “forward-looking statements” as defined by the Securities and Exchange Commission (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 press release 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 oil and gas operations; 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; 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; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties discussed in our Form 10-K and other filings with the SEC. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this press release are made as of the date of this press release, even if subsequently made available by Devon on its website or otherwise. Devon does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise. The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. This release may contain certain terms, such as resource potential, potential locations, risked and unrisked locations, estimated ultimate

recovery (or EUR), exploration target size and other similar terms. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosure in our Form 10-K, available at www.devonenergy.com . You can also obtain this form from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov .
About Devon Energy
Devon Energy is a leading independent energy company engaged in finding and producing oil and natural gas. Based in Oklahoma City and included in the S&P 500, Devon operates in several of the most prolific oil and natural gas plays in the U.S. and Canada with an emphasis on achieving strong returns and capital-efficient, cash-flow growth. For more information, please visit www.devonenergy.com .

Investor Contacts	  	Media Contact	
Scott Coody, 405-552-4735	  	John Porretto, 405-228-7506	
Chris Carr, 405-228-2496	  		

Strategic Update & Q4 2018 Operations Report February 19, 2019 Exhibit 99.3

Completing Transformation to a U.S. Oil Growth Company Sharpens focus on world-class U.S. oil assets Delaware, STACK, Eagle Ford and Powder River High-margins and low cost of supply Multi-decade growth platform Pursuing strategic alternatives for Barnett Shale and Canadian assets Outright sale or spin-off Expect to complete by year end Targeting at least $780 million of cost savings with retained U.S. oil business (details on pg. 7) Board increases share-buyback program to $5 billion $3.4 billion repurchased to date (~90 million shares) Potential to reduce share count by nearly 30% Increased quarterly dividend 13% to $0.09 per share 18 MBOED (71% OIL) STACK 126 MBOED (55% LIQUIDS) POWDER RIVER EAGLE FORD 61 MBOED (50% OIL) 84 MBOED (54% OIL) DELAWARE Production: 296 MBOED (Q4 2018) Revenue: 84% oil & liquids Oil growth rate: 17% in 2018 Multi-decade growth platform (see pg.6) New Devon Overview

A Track Record of Execution Divestiture Assets New Devon Brazil Azerbaijan China Russia GoM Shelf GoM Deepwater San Juan East Texas Mississippian Granite Wash Uinta Washakie Conventional Canadian Assets Midland Assets DIVESTITURE PROCEEDS EnLink West Africa $30 Billion > Heavy Oil(1) Barnett Shale(1) (1) Pursuing strategic alternatives and expect to exit assets by YE 2019 U.S. oil business has achieved operating scale Positioned for mid-teens oil growth and FCF above $46 WTI High-quality, multi-decade drilling inventory Dramatically improves cost structure and margins Accelerates value realization for Canada & Barnett STRATEGIC RATIONALE FOR TODAY’S ANNOUNCEMENT STACK POWDER RIVER EAGLE FORD DELAWARE (over last decade) Rockies CO2 (marketing)

New Devon’s World-Class Oil Assets Visualized Portfolio positioned in top oil basins Well level breakeven (PV-10, WTI to HH @ 20:1) ($/bbl) Net Acres 40,000 Net Acres 280,000 Net Acres 280,000 Net Acres 330,000 DOMINANT POSITION IN 4 TOP OIL PLAYS Source: RS Energy Group, December 2018. Breakeven($/bbl@20:1 WTI:HH) Note: acreage denoted represents core acreage positions

Unleashing Potential of World-Class Oil Assets U.S. well productivity showcases asset quality Source: IHS/Devon. All wells drilled since 2015 and includes operators with more than 100 wells. Superior oil growth and pricing +17% (vs. 2017) +1% (vs. 2017) DECLINE 20% (FY 2018) Improved per-unit costs 2018 LOE & transportation expense ($/BOE) Higher field-level margins 2018 field-level cash margins ($/BOE) $17.68 $27.67 INCREASE 56% (FY 2018) $9.66 Avg. 90-Day IPs BOED, 20:1 PEER AVG. 96% (of WTI) 65% (of WTI) Reported New Devon Top 40 U.S. Producers $7.76 SUPERIOR WELL RESULTS +40% VS. PEER AVG.

Inventory Supports Sustainable Long-Term Growth STACK Delaware Basin Eagle Ford PRB 4,200 operated locations (Avg. lateral length: ~7,500’) ~280 operated wells online (Avg. lateral length: ~8,000’) 15 YEAR INVENTORY (AT CURRENT ACTIVITY PACE) WTD AVG. IRR: >50% 6,500 operated locations (Avg. lateral length: <7,500’) (1) High-Return Inventory Potential(1) Gross operated inventory locations High-return inventory represents locations generating >20% IRR. Returns based on all-in E&P capital investment, which includes drilling, completion and well-site facilities and flow back. Requires additional appraisal work, cost efficiencies, spacing optimization and operating cost improvements to compete for capital allocation with current high-return inventory opportunity set. >20 YEAR INVENTORY (AT CURRENT ACTIVITY PACE)

Next Steps to Optimize New Devon Cost Structure Aggressively pursuing improved cost structure New Devon expected cost savings by area vs. 2018 results ($MM) $780 ANNUAL COST SAVINGS BY 2021 MILLION Timing of annual cost savings Cumulative estimated annual cost savings ($MM) Interest G&A D&C(1) LOE G&A $300 MM Interest $130 MM Per-Unit Recurring LOE $50 MM D&C Efficiencies $300 MM Restructuring to unlock potential of New Devon One functional focus across entire organization Reduced complexity provides for further focus on competitive advantages in U.S. Refocused and streamlined leadership structure Realigning personnel with go-forward business Cost savings designed to be front-end weighted ~70% of targeted savings achieved by year-end 2019 Targeted G&A level: ~$2.50 per Boe Structural D&C efficiencies reflected in 2019 outlook PV10 of cost savings plan: ~$4.5 billion (over next 10 years) COMMITTED TO OPTIMIZING CAPITAL EFFICIENCY AND OPERATIONAL EXCELLENCE (1) D&C costs assume flat service cost environment versus 2018 (1)

Disciplined Returns-Focused Strategy KEY STRATEGIC OBJECTIVES Fund high-return projects Maintain financial strength Return cash to shareholders Generate free cash flow 1 2 3 4 (1) Price sensitivity also assumes $3 Henry Hub and current hedge position. $40 Free cash flow accelerates (no change to activity levels over 3-year plan) Key strategic objectives achieved (3-year plan delivers mid-teens oil growth within cash flow) Maintain financial strength and operational continuity (New Devon FCF breakeven below $40 in 2019 with hedging gains) WTI PRICE(1) $46 $46 GREATER THAN APPROACH TO THE CURRENT ENVIRONMENT

New Devon: 3-Year Performance Targets CUMULATIVE FREE CASH FLOW OIL GROWTH COST SAVINGS DEBT TARGET CAPITAL PROGRAM RETURN ON CAPITAL TARGET: >15%(1) (At $50 WTI & $3 HH) $1.6 At $55 WTI & $3 HH 12% – 17% CAGR (FY2018 – 2021) Total Light-Oil Production $780 MM By 2021 See pg. 7 for detail 1.0x to 1.5x Debt to EBITDA Funded Assumes $3 HH price At $46 WTI Improve financial strength and flexibility Sustainably pay and grow dividend Opportunistically repurchase shares Reinvest in high-return U.S. oil business Free Cash Flow Priorities (See page 10 for FCF sensitivities) Internal rate of return on capital investment after burdening for G&A and corporate costs. Metric further detailed in proxy and driver of management compensation. Assumes cost savings detailed on page 7 are fully realized at the beginning of 2019. BILLION (2)

New Devon: Free Cash Flow Yield to Investors ($50 WTI) ($55 WTI) Cumulative Free Cash Flow $2.3B Cumulative Free Cash Flow ($B) Cumulative Free Cash Flow $1.6B Free Cash Yield (Annual Avg.) Cumulative Free Cash Flow $0.8B Note: Free cash flow yield assumes market capitalization based on current share price multiplied by expected shares outstanding at year-end 2019 (~375 mm shares). Cumulative free cash flow represents the aggregate operating cash flow less total capital requirements before dividend. Assumes $3 HH price. Cumulative Free Cash Flow Free Cash Flow Yield (Annual Avg.) (1) Assumes cost savings detailed on page 7 are fully realized at the beginning of 2019. OIL CAGR: 12%-17% BREAKEVEN: $46 WTI (BREAKEVEN CALC INCLUSIVE OF ALL CAPEX) 3-YEAR CAPITAL PLAN (1) (1) (1)

Attractive Entry Point for World-Class Oil Business New Devon: trading at significant discount $ in Billions $15.7 $2.5 $16.8 Peer trading multiples 2019e EV/EBITDAX(1) Peer average 6.8x (1) Estimates were sourced from Credit Suisse and assumes $54 WTI and $3.05 HH. “EV” stands for enterprise value. (2) 2019e Adjusted EBITDAX assumes cost savings discussed on page 7 are realized at the first of the year and assumes Credit Suisse price deck of $54 WTI and $3.05 HH. (3) Represents estimated 2019 Adjusted EBITDAX multiplied by peer average multiple of 6.8x. (4) Assumes share count, debt and cash at 12/31/18 and current share price. (2) (3) (4) Discounted valuation with asset sale upside Note: Adjusted EBITDAX is non-GAAP measure and is reconciled to GAAP on a historic basis in our Form 10-K. Valuation Gap (6.8x * $2.5B) Peer Multiple * New DVN EBITDAX

Why Own New Devon? World-class U.S. oil company Unrivaled acreage position in top basins Multi-decade inventory to drive sustainable growth Accelerating value realization for Canada & Barnett Focused on operational excellence Aggressively reducing costs Shifting to higher-margin production Positioned for mid-teens oil growth and free cash flow generation above $46 WTI Delivering value to shareholders Committed to return of capital Capital-efficient per-share growth Strong value proposition with attractive valuation 18 MBOED (71% OIL) STACK 126 MBOED (55% LIQUIDS) POWDER RIVER EAGLE FORD 61 MBOED (50% OIL) 84 MBOED (54% OIL) DELAWARE Production: 296 MBOED (Q4 2018) Revenue: 84% oil & liquids Oil growth rate: 17% in 2018 Multi-decade growth platform (see pg.6) New Devon Overview

Q4 2018 Operations Report & 2019 Outlook

Q4 2018 - ASSET DETAIL DELAWARE STACK PRB EAGLE FORD PRODUCTION Oil (MBbl/d) 45 31 13 30 NGL (MBbl/d) 18 37 2 15 Gas (MMcf/d) 127 343 20 95 Total (MBoe/d) 84(1) 126 18(1) 61 ASSET MARGIN (per Boe) Realized price $37.84(2) $29.40 $46.27 $44.20 Lease operating expenses ($6.04) ($1.84) ($6.95) ($2.69) Gathering, processing & transportation ($2.06) ($4.62) ($1.95) ($5.72) Production & property taxes ($2.71) ($1.30) ($5.40) ($2.44) Cash margin $27.03 $21.64 $31.97 $33.35 CAPITAL ACTIVTY Upstream capital ($MM) $252 $195 $56 $32 Operated development rigs (avg.) 10 5 2 Operated frac crews (avg.) 2.5 2 0.5 Operated spuds 31 17 12 Operated wells tied-in 27 25 8 Average lateral length 8,800’ 8,400’ 9,500’ Q4 production was impacted by timing of completions. Delaware production has increased to 96 MBOED in January. PRB production has increased to 22 MBOED in January. Includes benefits of regional basis swaps and firm transport in the Delaware totaling $35 million. Q4 2018 - Key Modeling Stats

New Devon: Pro Forma Financials KEY METRICS (WTI / HH) Q4 2018 ($58.80 / $3.65) FY 2018 ($64.79 / $3.09) FY 2019 (ASSUMES PRO FORMA COSTS) ($50 / $3) Oil production (MBbls/d) 125 121 137 - 143 NGL production (MBbls/d) 73 69 70 - 74 Gas production (MMcf/d) 589 537 520 - 550 Total production (MBoe/d) 296 279 294 - 309 Oil realizations (% of WTI) 95% 96% 90% - 100% Gas realizations (% of Henry Hub) 78% 76% 66% - 72% LOE & GP&T ($/BOE) $7.71 $7.76 $7.30 - $7.50 Production & property taxes ($/BOE) $2.19 $2.40 $2.10 - $2.30 General & administrative ($MM) $151 $650 ~$350 Financing costs, net (includes capitalized interest) ($MM) $70 $323 ~$170 Upstream capital ($MM) $547 $2,056 $1,800 - $2,000 Adjusted field-level cash margins ($/BOE) $24.91 $27.67 $20.00 - $22.00 Adjusted EBITDAX ($MM) $548 $1,900 ~$2,400 Note: Adjusted field-level cash margins and Adjusted EBITDAX are non-GAAP measures and are reconciled to GAAP on a historic basis in our Form 10-K.

Executing on Disciplined Strategy in 2018 Shifted U.S. oil assets into development U.S. oil growth +17% in 2018 (vs. 2017) Divestiture program reached ~$5 billion Reduced consolidated debt by >40% Raised quarterly dividend 33% Repurchased 15% of stock in 2018 ü ü ü ü ü Share buyback $6.8 Billion Upstream capital Debt reduction Dividends $2.4B $3.0B $1.2B $0.2B >60% OF CASH ALLOCATED TO SHAREHOLDER-FRIENDLY INITIATIVES KEY ACCOMPLISHMENTS ü

Capital Efficiencies Accelerate in 2019 Focused on top-tier oil development opportunities 2019e E&P capital (New Devon) $1.8-$2.0 E&P CAPITAL 47% DELAWARE 21% STACK 16% POWDER RIVER 16% EAGLE FORD BILLION 2019 CAPITAL ACTIVITY E&P CAPITAL ($MM) NEW WELLS ONLINE (Operated) Delaware Basin $900 100-110 STACK $400 85-95 Powder River $300 35-40 Eagle Ford $300 40-50 New Devon Total $1,800 - $2,000 CAPITAL PROGRAM FUNDED AT $46 WTI Structural improvements drive capital efficiency: Outlook assumes flat service & supply costs vs. 2018 Facility cost savings up to 40% across U.S. by year end Wolfcamp costs and cycle times improving (20% vs 2018) STACK infill spacing design optimized (15% vs. 2018) Dedicated frac crew to lower PRB costs (17% vs. 2018) >15% more wells drilled for ~10% less capital (vs. 2018)

Disciplined Growth Benefits From Buyback Activity Focused on delivering sustainable, high-margin growth (funded at $46 WTI) Driven by U.S. oil growth (+13%-18% vs. 2018) U.S. oil exit rate: >20% vs. 2018 avg. Top-line production to advance (+8% vs. 2018) Eagle Ford timing to impact Q1 (see pg. 25) Margins to benefit from improved cost structure LOE rates to decline ~10% by Q4 2019 Additional cost saving initiatives underway (pg. 7) Board increased share-repurchase authorization to $5 billion Potential to reduce share count by ~30% $3.4 billion repurchased to date (~90 million shares) 13% - 18% OIL GROWTH >20% (2019 exit rate vs. FY 2018) 2018 vs 2019 Positioned for high-return growth in 2019 New Devon U.S oil production (MBOD) Repurchase program accelerates per-share growth Outstanding shares (MM) ~30% SHARE COUNT REDUCTION 527 ~375(1) 521 491 459 437 ((1) Assumes shares are repurchased at current share price.

Delaware Basin – Capital-Efficient Growth Engine DELAWARE BASIN OVERVIEW RATTLESNAKE Q4 2018 Key Wells Upcoming Projects THISTLE/GAUCHO POTATO BASIN TODD COTTON DRAW Seawolf (7 Wolfcamp wells) Avg. IP 30: 3,000 BOED/well 2,800 BOED 30-DAY IPs Fighting Okra Flowing Back New Mexico Texas 15 WELLS AVG. Eddy Lea Spud Muffin Drilling Lusitano (1 Bone Spring well) Avg. IP 30: 2,200 BOED Ko Lanta (2 Leonard wells) Avg. IP 30: 2,600 BOED/well North Thistle Completing Morab (2 Bone Spring wells) Avg. IP 30: 1,600 BOED/well High-rate wells drive Q4 growth Net production increased 49% vs. Q4 2017 January 2019 production: 96 MBOED (+14% vs. Q4) Wolfcamp program headlines Q4 performance Seawolf development reaches peak rates Strong appraisal results achieved in Todd area Fighting Okra project achieves 1st production Firm transport and basis swaps protect pricing Q4 oil realizations: 98% of WTI(1) Swaps & firm transport protect ~75% of 2019e oil Field-level cash flow expands 72% (vs. FY2017) Per-unit costs improve 15% year over year Capital requirements funded within cash flow Q4 2018 KEY WELLS Tomb Raider (3 Wolfcamp wells) Avg. IP 30: 3,500 BOED/well RECORD WELL PRODUCTIVITY ACHIEVED IN 2018 (see pg. 20) LEVERAGING INFRASTRUCTURE TO EXPAND MARGINS & RETURNS Cats (Offsets Boundary Raider) Completing (1) Includes benefits of basis swaps & firm transport Flagler (Phase 1) Completing

Step-Change in Delaware Basin Well Productivity Well productivity reaching record highs Average cumulative oil production per well (MBO) Months Online 2018 average 2015-2017 average Bone Spring Wolfcamp Leonard Significant growth platform at $50 WTI Gross operated inventory locations generating IRR >20%(1) 2,000 locations (Avg. lateral length: 7,500’) BOUNDARY RAIDER & WOLFCAMP FOCUS IN 2019 2018 Boundary Raider wells 16 YEAR INVENTORY (AT CURRENT ACTIVITY PACE) Weighted Avg. IRR: >50% (>90% improvement vs. 3-year avg.) (1) IRR on E&P capital investment (includes drilling, completion and well-site facilities and flow back). (targeting Bone Spring)

Focusing on Wolfcamp & Bone Spring Projects in 2019 Todd Area Bone Spring “Cats” Area (~20 wells online in 2019) Eddy Boundary Raider (2 wells) Avg. IP 24: 12 MBOED/well RATTLESNAKE DEVELOPMENT ACTIVITY Rattlesnake Area Lea ACCELERATING TODD DEVELOPMENT PROGRAM Flagler (Phase 1) Completing Lea Wolfcamp program: ~45% of 2019 drilling activity Six key projects underway in Rattlesnake area Seawolf delivers massive rates (IP30: ~40 MBOED) Fighting Okra flowing back (all wells online) Multi-phase Flagler project underway (~20 wells) Development of Bone Spring in Todd area underway Activity offsetting prolific Boundary Raider wells Initial wells had highest rates in Delaware history ~20 new wells to be brought online in 2019 (see map) Leonard & Wolfcamp appraisal success in Q4 Ko Lanta (2 wells) Avg. IP 30: 2,600 BOED/well Tomb Raider (3 wells) Avg. IP 30: 3,500 BOED/well Bone Spring Leonard Wolfcamp Fighting Okra Flowing back Peak rates: 1H 2019 Arena Roja 2H 2019 Spud Mean Green 2H 2019 Spud Jayhawk 1H 2019 Spud Seawolf 12 Wolfcamp wells Avg. IP 30: 3,300 BOED/well Wolfcamp

Delaware Basin – Focused Development Plan in 2019 Diversified state-line activity Percent of activity by formation Delivering high-margin growth Net production (MBOED) 2019 DRILLING ACTIVITY Wolfcamp (45%) Bone Spring (30%) Leonard (25%) Top-funded asset in portfolio (~$900 million) Low-risk development activity: ~95% of program Running 11 operated rigs (spud ~125 wells) Average lateral length increases to ~8,000’ High-margin oil growth (~40% vs. 2018) LOE rates to decline by >15% by year end Infrastructure drives sustainable savings and ESG benefits Operating costs to improve >60% vs. peak rates Concentrated acreage position & activity levels (~280k acres) Nearly all oil and water on pipe (avoids high-cost trucking) Operate ~50 disposal wells and 8 water reuse facilities >90% of water used in completions is recycled Note: 2016-2017 costs are pro forma for revenue recognition accounting rules recently implemented. >15% IMPROVEMENT (2019 EXIT VS. 2018) Operating scale drives costs lower LOE & GP&T expense ($/BOE)

Net production increases 11% vs. Q4 2017 Oil production increased 9% (vs. Q3 2018) Growth driven by infill development activity (see map) Highest Q4 rates from Chipmunk & Faith Marie activity Safari project design supports future infill spacing Spaced at 5 wells per unit (Avg. IP30: 1,400 BOED) Well placement targeted Upper Meramec interval D&C savings reach ~30% vs. legacy parent well Early results at Pony Express, Northwoods & Scott further confirms view on spacing Learnings from infill development activity to date Lighter-spaced pilots delivering improved returns Upper Meramec is the best performing interval Flowback approach designed to optimize oil recoveries STACK – Optimizing Infill Spacing Kingfisher Canadian Blaine Upcoming Developments STACK DEVELOPMENT ACTIVITY Developments Online Safari (5 wells/DSU) Avg. IP30: 1,400 BOED Chipmunk (3 wells) Avg. IP30: 4,400 BOED Geis (7 wells/DSU) Avg. IP120: 900 BOED(1) Faith Marie (2 wells) Avg. IP30: 3,100 BOED 4-6 wells UPCOMING ACTIVITY PER DSU Efficiencies accelerate at Safari development Feet drilled per day >90% Improvement 30% D&C INFILL COSTS BELOW PARENT WELL Scott (5 wells/DSU) Avg. IP10: 3,100 BOED(1) Pony Express (4 wells/DSU) Avg. IP30: 1,600 BOED(1) Northwoods (5 wells/DSU) Avg. IP30: 1,500 BOED (1) Normalized for 10,000’ laterals

STACK – 2019 Strategic Priorities Transitioning infill developments to 4-6 wells per unit Investment concentrated in volatile-oil window Wells primarily targeting Upper Meramec interval Strategic priorities for 2019 capital program Generate attractive infill development returns Prioritizing free cash flow over volume growth Retain operational flexibility to increase investment 2nd highest funded asset in portfolio Capital investment: ~$400 million (4-rig program) Expect stable production profile (vs. 2018) Timing of activity to impact Q1 production profile Significant growth inventory remaining 130,000 net acres in over-pressured oil window High-quality Woodford optionality Significant free cash flow contributor in 2019 Free cash flow ($MM)(2) ($55 WTI/$2.75HH) Type Curve (10K LATERAL) Well Spacing (per DSU) 4 – 6 wells 30-DAY IP (BOED) 1,300 – 1,600 EUR (MBOE) 1,200 – 1,400 D&C COST ~$7.5 MM LIQUIDS MIX (% OF EUR) 55% -65% Updated infill development type curve expectations Early results in line with type curve expectations (BOED) ~100% GROWTH (VS 2018 ASSUMING $50 WTI) 1,400 (30-day IP) 1,600(1) (30-day IP) 5 WELLS/DSU 5 WELLS/DSU 5 WELLS/DSU (1) Normalized for 10,000’ laterals 1,500 (30-day IP) 3,100(1) (10-day IP) 4 WELLS/DSU (2) Calculated as cash margin (see pg. 15) less capital expenditures

Eagle Ford Q4 production averaged 61 MBOED (50% oil) Net production 11% higher vs. Q4 2017 15 new wells: Avg. IP30 3,700 BOED High-rates driven by larger completion design Increasing activity to a 3 rig program in 2019 ~70 spuds planned (40-50 wells online by year-end) Targeting up to 25 horizontal refracs Initiating Austin Chalk appraisal program ~5 appraisal tests scheduled in 2019 Program to derisk >200 inventory locations 1st production at initial appraisal well in Q2 2019 Activity underway to stabilize volumes by year end Q1 outlook: 50-55 MBOED (~10 wells tied-in) Positioned to deliver volume growth in 2020 Q4 Results 15 Lower Eagle Ford Wells Avg. 30-Day IP: 3,700 BOED/Well EAGLE FORD OVERVIEW (in $MM) 2018 Revenue $926 Production Expenses $208 Cash Margin $718 Capital Expenditures $203 Free Cash Flow $515 Free cash flow generation Austin Chalk Appraisal Well Q1 2019 Spud Austin Chalk Appraisal Well 1st Production in Q2 2019 FREE CASH FLOW 515 $ MILLION IN 2018 700 High-return locations Strong inventory upside Potential locations High-Return Locations (With Upside) ~

Powder River Basin Net production increased 27% vs. Q4 2017 8 wells online in late December (Avg. IP30: 1,500 BOED) January 2019 production: 22 MBOED (+25% vs. Q4) Increasing activity to 4 rigs in 2019 Represents 2x increase in activity from 2018 Dedicated and decoupled stimulation services improve capital efficiency No permitting or infrastructure constraints Capital program focused in Super Mario area Prioritizing Turner development activity (~35 spuds) Advancing Niobrara delineation work (~10 spuds) Year-end exit-rates: >50% oil growth (vs. Q4’ 18) ~20% oil growth expected in Q1 (vs. Q4’ 18) Operating scale to drive ~10% LOE savings in 2019 KEY POWDER RIVER BASIN ACTIVITY 2019 Activity Q4 2018 Activity Super Mario Area RU JFW Fed 14-4 (Turner) Avg. 30-Day IP: 1,600 BOED (~80% oil) (9,500’ lateral) CWDU FED 31-3 (Parkman) Avg. 30-Day IP: 1,200 BOED (~95% oil) (9,500’ lateral) PRB Activity ~50 Spuds Downs Fed 02-1 (Teapot) Avg. 30-Day IP: 1,400 BOED (~95% oil) (9,000’ lateral) EMERGING OIL GROWTH OPPORTUNITY STACKED PAY POSITION IN OIL FAIRWAY (Planned for 2019) RU Fed 14-C (Turner) Avg. 30-Day IP: 2,000 BOED (~80% oil) (9,500’ lateral) RU JFW Fed 14-3 (Parkman) Avg. 30-Day IP: 1,100 BOED (~95% oil) (9,300’ lateral) CU Downs Fed 35-1 (Teapot) Avg. 30-Day IP: 1,500 BOED (~95% oil) (10,200’ lateral) CU Downs Fed 15-2 (Teapot) Avg. 30-Day IP: 1,800 BOED (~95% oil) (10,500’ lateral) Downs Fed 02-3 (Teapot) Avg. 30-Day IP: 1,400 BOED (~95% oil) (8,500’ lateral)

Barnett Shale Canada Dow JV efficiently maintaining base production Q4 production: 103 MBOED (~30% NGLs) Minimum volume commitments expired at year end Wise County divestiture package closed in October Stable production outlook expected in 2019 Capital investment: $65 million (~35 new wells online) GP&T expense ~$90 million lower due to MVC expiry BARNETT SHALE OVERVIEW Sale price: ~$50 million Production: ~4 MBOED Denton Wise Divest Details 2019e Dow JV Activity CLOSED Q4 2018 Q4 impacted by curtailments & royalties Reduced production due to market conditions (17 MBOD) Royalty adjustments increased Q4 volumes (due to ↓ pricing) WCS hedges deliver $144 million of cash settlements Q4 PRODUCTION GROSS NET Jackfish 1 (MBOD) 33.7 39.3 Jackfish 2 (MBOD) 31.3 30.7 Jackfish 3 (MBOD) 30.7 29.9 Lloydminster (MBOED) 19.7 21.5 Total Heavy Oil (MBOED) 115.4 121.4 Regional pricing improves due to industry curtailments Positioned to generate free cash flow above $50 WTI Hedging position mitigates WCS downside risk in 2019 Q1 net production expected to reach ~115 MBOED

Investor Contacts & Notices Investor Relations Contacts Scott CoodyChris Carr VP, Investor RelationsManager, Investor Relations 405-552-4735405-228-2496 Email: investor.relations@dvn.com Forward-Looking Statements This presentation includes “forward-looking statements” as defined by the Securities and Exchange Commission (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 presentation 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 Investor Notices reserves; the extent to which we are successful in acquiring and discovering additional reserves; the uncertainties, costs and risks involved in oil and gas operations; 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; 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; our ability to successfully complete mergers, acquisitions and divestitures; and any of the other risks and uncertainties discussed in our Form 10-K and other filings with the SEC. Investors are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements. The forward-looking statements in this presentation are made as of the date of this presentation, even if subsequently made available by Devon on its website or otherwise. Devon does not undertake any obligation to update the forward-looking statements as a result of new information, future events or otherwise. Use of Non-GAAP Information This presentation may include non-GAAP financial measures. Such non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. For additional disclosure regarding such non-GAAP measures, including reconciliations to their most directly comparable GAAP measure, please refer to Devon’s fourth-quarter 2018 earnings release at www.devonenergy.com. Cautionary Note to Investors The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. This presentation may contain certain terms, such as high-return inventory, potential locations, risked and unrisked locations, estimated ultimate recovery (EUR), exploration target size and other similar terms. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosure in our Form 10-K, available at www.devonenergy.com. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov.

Exhibit 99.4
DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
PRODUCTION NET OF ROYALTIES

 	  	Quarter Ended	 	  	Year Ended	 	
 	  	December 31,	 	  	December 31,	 	
 	  	2018	 	  	2017	 	  	2018	 	  	2017	 	
Oil and bitumen (MBbls/d)	  				  				  				  				
U. S.	  	 	126	 	  	 	104	 	  	 	122	 	  	 	104	 	
Heavy Oil	  	 	120	 	  	 	132	 	  	 	115	 	  	 	128	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	246	 	  	 	236	 	  	 	237	 	  	 	232	 	
Divested assets	  	 	7	 	  	 	10	 	  	 	9	 	  	 	12	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	253	 	  	 	246	 	  	 	246	 	  	 	244	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				
U. S.	  	 	103	 	  	 	95	 	  	 	98	 	  	 	86	 	
Divested assets	  	 	2	 	  	 	11	 	  	 	8	 	  	 	13	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	105	 	  	 	106	 	  	 	106	 	  	 	99	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				
U. S.	  	 	1,025	 	  	 	940	 	  	 	982	 	  	 	959	 	
Heavy Oil	  	 	6	 	  	 	15	 	  	 	10	 	  	 	17	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	1,031	 	  	 	955	 	  	 	992	 	  	 	976	 	
Divested assets	  	 	19	 	  	 	220	 	  	 	108	 	  	 	227	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	1,050	 	  	 	1,175	 	  	 	1,100	 	  	 	1,203	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				
U. S.	  	 	399	 	  	 	356	 	  	 	383	 	  	 	350	 	
Heavy Oil	  	 	121	 	  	 	134	 	  	 	117	 	  	 	131	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	520	 	  	 	490	 	  	 	500	 	  	 	481	 	
Divested assets	  	 	12	 	  	 	58	 	  	 	35	 	  	 	62	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	532	 	  	 	548	 	  	 	535	 	  	 	543	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
PRODUCTION TREND

 	  	2017	 	  	2018	 	
 	  	Quarter 4	 	  	Quarter 1	 	  	Quarter 2	 	  	Quarter 3	 	  	Quarter 4	 	
Oil and bitumen (MBbls/d)	  				  				  				  				  				
Delaware Basin	  	 	30	 	  	 	34	 	  	 	45	 	  	 	44	 	  	 	45	 	
STACK	  	 	29	 	  	 	34	 	  	 	34	 	  	 	29	 	  	 	31	 	
Powder River Basin	  	 	12	 	  	 	15	 	  	 	13	 	  	 	15	 	  	 	13	 	
Heavy Oil	  	 	132	 	  	 	129	 	  	 	109	 	  	 	102	 	  	 	120	 	
Eagle Ford	  	 	27	 	  	 	23	 	  	 	28	 	  	 	31	 	  	 	30	 	
Barnett Shale	  	 	—  	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	  	 	1	 	
Other	  	 	6	 	  	 	6	 	  	 	7	 	  	 	6	 	  	 	6	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	236	 	  	 	241	 	  	 	236	 	  	 	227	 	  	 	246	 	
Divested assets	  	 	10	 	  	 	10	 	  	 	9	 	  	 	8	 	  	 	7	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	246	 	  	 	251	 	  	 	245	 	  	 	235	 	  	 	253	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				  				
Delaware Basin	  	 	12	 	  	 	11	 	  	 	15	 	  	 	19	 	  	 	18	 	
STACK	  	 	34	 	  	 	35	 	  	 	37	 	  	 	40	 	  	 	37	 	
Powder River Basin	  	 	1	 	  	 	1	 	  	 	1	 	  	 	2	 	  	 	2	 	
Eagle Ford	  	 	13	 	  	 	8	 	  	 	13	 	  	 	15	 	  	 	15	 	
Barnett Shale	  	 	33	 	  	 	29	 	  	 	31	 	  	 	30	 	  	 	30	 	
Other	  	 	2	 	  	 	1	 	  	 	1	 	  	 	1	 	  	 	1	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	95	 	  	 	85	 	  	 	98	 	  	 	107	 	  	 	103	 	
Divested assets	  	 	11	 	  	 	12	 	  	 	11	 	  	 	6	 	  	 	2	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	106	 	  	 	97	 	  	 	109	 	  	 	113	 	  	 	105	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				  				
Delaware Basin	  	 	84	 	  	 	93	 	  	 	94	 	  	 	103	 	  	 	127	 	
STACK	  	 	307	 	  	 	324	 	  	 	329	 	  	 	337	 	  	 	343	 	
Powder River Basin	  	 	8	 	  	 	12	 	  	 	13	 	  	 	18	 	  	 	20	 	
Heavy Oil	  	 	15	 	  	 	12	 	  	 	12	 	  	 	11	 	  	 	6	 	
Eagle Ford	  	 	87	 	  	 	63	 	  	 	74	 	  	 	84	 	  	 	95	 	
Barnett Shale	  	 	453	 	  	 	458	 	  	 	447	 	  	 	447	 	  	 	439	 	
Other	  	 	1	 	  	 	1	 	  	 	1	 	  	 	1	 	  	 	1	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	955	 	  	 	963	 	  	 	970	 	  	 	1,001	 	  	 	1,031	 	
Divested assets	  	 	220	 	  	 	214	 	  	 	158	 	  	 	45	 	  	 	19	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	1,175	 	  	 	1,177	 	  	 	1,128	 	  	 	1,046	 	  	 	1,050	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				  				
Delaware Basin	  	 	57	 	  	 	61	 	  	 	76	 	  	 	79	 	  	 	84	 	
STACK	  	 	114	 	  	 	123	 	  	 	125	 	  	 	126	 	  	 	126	 	
Powder River Basin	  	 	14	 	  	 	18	 	  	 	16	 	  	 	19	 	  	 	18	 	
Heavy Oil	  	 	134	 	  	 	131	 	  	 	111	 	  	 	104	 	  	 	121	 	
Eagle Ford	  	 	55	 	  	 	41	 	  	 	54	 	  	 	60	 	  	 	61	 	
Barnett Shale	  	 	109	 	  	 	105	 	  	 	105	 	  	 	105	 	  	 	103	 	
Other	  	 	7	 	  	 	7	 	  	 	8	 	  	 	7	 	  	 	7	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Retained assets	  	 	490	 	  	 	486	 	  	 	495	 	  	 	500	 	  	 	520	 	
Divested assets	  	 	58	 	  	 	58	 	  	 	46	 	  	 	22	 	  	 	12	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	548	 	  	 	544	 	  	 	541	 	  	 	522	 	  	 	532	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
BENCHMARK PRICES
(average prices)

 	  	Quarter 4	 	 	Year Ended December 31,	 	
 	  	2018	 	 	2017	 	 	2018	 	 	2017	 	
Oil ($/Bbl) - West Texas Intermediate (Cushing)	  	$	58.80	 	 	$	55.49	 	 	$	64.79	 	 	$	50.99	 	
Natural Gas ($/Mcf) - Henry Hub	  	$	3.65	 	 	$	2.93	 	 	$	3.09	 	 	$	3.11	 	
					
REALIZED PRICES	  				 				 				 				
		
 	  	Quarter Ended December 31, 2018	 	
 	  	Oil /Bitumen	 	 	NGL	 	 	Gas	 	 	Total	 	
 	  	(Per Bbl)	 	 	(Per Bbl)	 	 	(Per Mcf)	 	 	(Per Boe)	 	
United States	  	$	55.78	 	 	$	22.15	 	 	$	2.88	 	 	$	30.94	 	
Canada	  	$	(2.49	) 	 	 	N/M	 	 	 	N/M	 	 	$	(2.46	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	$	27.99	 	 	$	22.15	 	 	$	2.88	 	 	$	23.32	 	
Cash settlements	  	$	6.59	 	 	$	0.18	 	 	$	(0.28	) 	 	$	2.61	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	34.58	 	 	$	22.33	 	 	$	2.60	 	 	$	25.93	 	

 	  	Quarter Ended December 31, 2017	 	
 	  	Oil /Bitumen	 	 	NGL	 	 	Gas	 	 	Total	 	
 	  	(Per Bbl)	 	 	(Per Bbl)	 	 	(Per Mcf)	 	 	(Per Boe)	 	
United States	  	$	54.18	 	 	$	18.46	 	 	$	2.29	 	 	$	26.18	 	
Canada	  	$	32.54	 	 	 	N/M	 	 	 	N/M	 	 	$	31.95	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	$	42.59	 	 	$	18.46	 	 	$	2.29	 	 	$	27.59	 	
Cash settlements	  	$	(0.38	) 	 	$	(0.30	) 	 	$	0.19	 	 	$	0.19	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	42.21	 	 	$	18.16	 	 	$	2.48	 	 	$	27.78	 	

 	  	Year Ended December 31, 2018	 	
 	  	Oil /Bitumen	 	 	NGL	 	 	Gas	 	 	Total	 	
 	  	(Per Bbl)	 	 	(Per Bbl)	 	 	(Per Mcf)	 	 	(Per Boe)	 	
United States	  	$	61.97	 	 	$	24.74	 	 	$	2.37	 	 	$	31.86	 	
Canada	  	$	19.37	 	 	 	N/M	 	 	 	N/M	 	 	$	19.12	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	$	42.04	 	 	$	24.74	 	 	$	2.37	 	 	$	29.08	 	
Cash settlements	  	$	(0.49	) 	 	$	(1.17	) 	 	$	0.01	 	 	$	(0.43	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	41.55	 	 	$	23.57	 	 	$	2.38	 	 	$	28.65	 	

 	  	Year Ended December 31, 2017	 	
 	  	Oil /Bitumen	 	 	NGL	 	 	Gas	 	 	Total	 	
 	  	(Per Bbl)	 	 	(Per Bbl)	 	 	(Per Mcf)	 	 	(Per Boe)	 	
United States	  	$	49.41	 	 	$	15.66	 	 	$	2.48	 	 	$	24.88	 	
Canada	  	$	29.99	 	 	 	N/M	 	 	 	N/M	 	 	$	29.39	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	$	39.23	 	 	$	15.66	 	 	$	2.48	 	 	$	25.96	 	
Cash settlements	  	$	0.23	 	 	$	(0.10	) 	 	$	0.08	 	 	$	0.27	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	39.46	 	 	$	15.56	 	 	$	2.56	 	 	$	26.23	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
CONSOLIDATED STATEMENTS OF EARNINGS
(in millions, except per share amounts)

 	  	Quarter Ended
December 31,	 	 	Year Ended
December 31,	 	
 	  	2018	 	 	2017	 	 	2018	 	 	2017	 	
Upstream revenues	  	$	2,565	 	 	$	1,333	 	 	$	6,285	 	 	$	5,307	 	
Marketing revenues	  	 	1,143	 	 	 	1,047	 	 	 	4,449	 	 	 	3,571	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	  	 	3,708	 	 	 	2,380	 	 	 	10,734	 	 	 	8,878	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Production expenses	  	 	556	 	 	 	463	 	 	 	2,225	 	 	 	1,823	 	
Exploration expenses	  	 	44	 	 	 	171	 	 	 	177	 	 	 	380	 	
Marketing expenses	  	 	1,113	 	 	 	1,048	 	 	 	4,363	 	 	 	3,619	 	
Depreciation, depletion and amortization	  	 	423	 	 	 	390	 	 	 	1,658	 	 	 	1,529	 	
Asset impairments	  	 	—  	 	 	 	—  	 	 	 	156	 	 	 	—  	 	
Asset dispositions	  	 	(268	) 	 	 	(17	) 	 	 	(263	) 	 	 	(217	) 	
General and administrative expenses	  	 	151	 	 	 	191	 	 	 	650	 	 	 	737	 	
Financing costs, net	  	 	70	 	 	 	79	 	 	 	594	 	 	 	317	 	
Restructuring and transaction costs	  	 	9	 	 	 	—  	 	 	 	114	 	 	 	—  	 	
Other expenses	  	 	126	 	 	 	9	 	 	 	140	 	 	 	(83	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total expenses	  	 	2,224	 	 	 	2,334	 	 	 	9,814	 	 	 	8,105	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings from continuing operations before income taxes	  	 	1,484	 	 	 	46	 	 	 	920	 	 	 	773	 	
Income tax expense	  	 	335	 	 	 	2	 	 	 	156	 	 	 	15	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings from continuing operations	  	 	1,149	 	 	 	44	 	 	 	764	 	 	 	758	 	
Net earnings from discontinued operations, net of income tax expense	  	 	—  	 	 	 	260	 	 	 	2,460	 	 	 	320	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings	  	 	1,149	 	 	 	304	 	 	 	3,224	 	 	 	1,078	 	
Net earnings attributable to noncontrolling interests	  	 	—  	 	 	 	121	 	 	 	160	 	 	 	180	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings attributable to Devon	  	$	1,149	 	 	$	183	 	 	$	3,064	 	 	$	898	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic net earnings per share:	  				 				 				 				
Basic earnings from continuing operations per share	  	$	2.50	 	 	$	0.08	 	 	$	1.53	 	 	$	1.44	 	
Basic earnings from discontinued operations per share	  	 	—  	 	 	 	0.27	 	 	 	4.61	 	 	 	0.27	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic net earnings per share	  	$	2.50	 	 	$	0.35	 	 	$	6.14	 	 	$	1.71	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted net earnings per share:	  				 				 				 				
Diluted earnings from continuing operations per share	  	$	2.48	 	 	$	0.08	 	 	$	1.52	 	 	$	1.43	 	
Diluted earnings from discontinued operations per share	  	 	—  	 	 	 	0.27	 	 	 	4.58	 	 	 	0.27	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted net earnings per share	  	$	2.48	 	 	$	0.35	 	 	$	6.10	 	 	$	1.70	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average common shares outstanding:	  				 				 				 				
Basic	  	 	459	 	 	 	525	 	 	 	499	 	 	 	525	 	
Diluted	  	 	462	 	 	 	528	 	 	 	502	 	 	 	528	 	
					
UPSTREAM REVENUES
(in millions)	  				 				 				 				
			
 	  	Quarter Ended
December 31,	 	 	Year Ended
December 31,	 	
 	  	2018	 	 	2017	 	 	2018	 	 	2017	 	
Oil, gas and NGL sales	  	$	1,143	 	 	$	1,390	 	 	$	5,677	 	 	$	5,150	 	
Derivative cash settlements	  	 	127	 	 	 	10	 	 	 	(84	) 	 	 	53	 	
Derivative valuation changes	  	 	1,295	 	 	 	(67	) 	 	 	692	 	 	 	104	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Upstream revenues	  	$	2,565	 	 	$	1,333	 	 	$	6,285	 	 	$	5,307	 	

PRODUCTION EXPENSES
(in millions)	  				 				 				 				
			
 	  	Quarter Ended
December 31,	 	 	Year Ended
December 31,	 	
 	  	2018	 	 	2017	 	 	2018	 	 	2017	 	
Lease operating expense	  	$	251	 	 	$	236	 	 	$	995	 	 	$	927	 	
Gathering, processing & transportation	  	 	220	 	 	 	163	 	 	 	891	 	 	 	647	 	
Production taxes	  	 	70	 	 	 	51	 	 	 	278	 	 	 	194	 	
Property taxes	  	 	15	 	 	 	13	 	 	 	61	 	 	 	55	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Production expenses	  	$	556	 	 	$	463	 	 	$	2,225	 	 	$	1,823	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)

 	  	Quarter Ended
December 31,	 	 	Year Ended
December 31,	 	
 	  	2018	 	 	2017	 	 	2018	 	 	2017	 	
Cash flows from operating activities:	  				 				 				 				
Net earnings	  	$	1,149	 	 	$	304	 	 	$	3,224	 	 	$	1,078	 	
Adjustments to reconcile net earnings to net cash from operating activities:	  				 				 				 				
Net earnings from discontinued operations, net of income tax expense	  	 	—  	 	 	 	(260	) 	 	 	(2,460	) 	 	 	(320	) 	
Depreciation, depletion and amortization	  	 	423	 	 	 	390	 	 	 	1,658	 	 	 	1,529	 	
Asset impairments	  	 	—  	 	 	 	—  	 	 	 	156	 	 	 	—  	 	
Leasehold impairments	  	 	19	 	 	 	139	 	 	 	95	 	 	 	219	 	
Accretion on discounted liabilities	  	 	15	 	 	 	16	 	 	 	61	 	 	 	63	 	
Total (gains) losses on commodity derivatives	  	 	(1,422	) 	 	 	57	 	 	 	(608	) 	 	 	(157	) 	
Cash settlements on commodity derivatives	  	 	127	 	 	 	10	 	 	 	(84	) 	 	 	53	 	
Gains on asset dispositions	  	 	(268	) 	 	 	(17	) 	 	 	(263	) 	 	 	(217	) 	
Deferred income tax expense (benefit)	  	 	358	 	 	 	(40	) 	 	 	226	 	 	 	(97	) 	
Share-based compensation	  	 	34	 	 	 	36	 	 	 	161	 	 	 	150	 	
Early retirement of debt	  	 	—  	 	 	 	—  	 	 	 	312	 	 	 	—  	 	
Total (gains) losses on foreign exchange	  	 	86	 	 	 	6	 	 	 	139	 	 	 	(132	) 	
Settlements of intercompany foreign denominated assets/liabilities	  	 	2	 	 	 	(1	) 	 	 	(241	) 	 	 	9	 	
Other	  	 	3	 	 	 	2	 	 	 	(5	) 	 	 	(1	) 	
Changes in assets and liabilities, net	  	 	16	 	 	 	(89	) 	 	 	(143	) 	 	 	32	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash from operating activities - continuing operations	  	 	542	 	 	 	553	 	 	 	2,228	 	 	 	2,209	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from investing activities:	  				 				 				 				
Capital expenditures	  	 	(600	) 	 	 	(670	) 	 	 	(2,451	) 	 	 	(1,968	) 	
Acquisitions of property and equipment	  	 	(20	) 	 	 	(7	) 	 	 	(55	) 	 	 	(46	) 	
Divestitures of property and equipment	  	 	317	 	 	 	39	 	 	 	1,013	 	 	 	426	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash from investing activities - continuing operations	  	 	(303	) 	 	 	(638	) 	 	 	(1,493	) 	 	 	(1,588	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from financing activities:	  				 				 				 				
Repayments of long-term debt principal	  	 	(95	) 	 	 	—  	 	 	 	(922	) 	 	 	—  	 	
Early retirement of debt	  	 	—  	 	 	 	—  	 	 	 	(304	) 	 	 	—  	 	
Repurchases of common stock	  	 	(759	) 	 	 	—  	 	 	 	(2,956	) 	 	 	—  	 	
Dividends paid on common stock	  	 	(37	) 	 	 	(32	) 	 	 	(149	) 	 	 	(127	) 	
Shares exchanged for tax withholdings	  	 	(1	) 	 	 	(2	) 	 	 	(48	) 	 	 	(59	) 	
Other	  	 	(6	) 	 	 	—  	 	 	 	(7	) 	 	 	—  	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash from financing activities - continuing operations	  	 	(898	) 	 	 	(34	) 	 	 	(4,386	) 	 	 	(186	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effect of exchange rate changes on cash:	  				 				 				 				
Settlements of intercompany foreign denominated assets/liabilities	  	 	(2	) 	 	 	1	 	 	 	241	 	 	 	(9	) 	
Other	  	 	(14	) 	 	 	(7	) 	 	 	(35	) 	 	 	15	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total effect of exchange rate changes on cash - continuing operations	  	 	(16	) 	 	 	(6	) 	 	 	206	 	 	 	6	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash of continuing operations	  	 	(675	) 	 	 	(125	) 	 	 	(3,445	) 	 	 	441	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from discontinued operations:	  				 				 				 				
Operating activities	  	 	—  	 	 	 	172	 	 	 	476	 	 	 	700	 	
Investing activities	  	 	—  	 	 	 	(136	) 	 	 	2,548	 	 	 	(611	) 	
Financing activities	  	 	—  	 	 	 	(81	) 	 	 	183	 	 	 	195	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash of discontinued operations	  	 	—  	 	 	 	(45	) 	 	 	3,207	 	 	 	284	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash	  	 	(675	) 	 	 	(170	) 	 	 	(238	) 	 	 	725	 	
Cash, cash equivalents and restricted cash at beginning of period	  	 	3,121	 	 	 	2,854	 	 	 	2,684	 	 	 	1,959	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash, cash equivalents and restricted cash at end of period	  	$	2,446	 	 	$	2,684	 	 	$	2,446	 	 	$	2,684	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reconciliation of cash, cash equivalents and restricted cash:	  				 				 				 				
Cash and cash equivalents	  	$	2,414	 	 	$	2,642	 	 	$	2,414	 	 	$	2,642	 	
Restricted cash included in other current assets	  	 	32	 	 	 	11	 	 	 	32	 	 	 	11	 	
Cash and cash equivalents included in current assets held for sale	  	 	—  	 	 	 	31	 	 	 	—  	 	 	 	31	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total cash, cash equivalents and restricted cash	  	$	2,446	 	 	$	2,684	 	 	$	2,446	 	 	$	2,684	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
CONSOLIDATED BALANCE SHEETS
(in millions)

 	  	December 31,
2018	 	 	December 31,
2017	 	
Current assets:	  				 				
Cash and cash equivalents	  	$	2,414	 	 	$	2,642	 	
Accounts receivable	  	 	885	 	 	 	989	 	
Current assets held for sale	  	 	197	 	 	 	760	 	
Other current assets	  	 	941	 	 	 	400	 	
	  	 	 	 	 	 	 	 	
Total current assets	  	 	4,437	 	 	 	4,791	 	
Oil and gas property and equipment, based on successful efforts accounting, net	  	 	12,813	 	 	 	13,318	 	
Other property and equipment, net	  	 	1,122	 	 	 	1,266	 	
	  	 	 	 	 	 	 	 	
Total property and equipment, net	  	 	13,935	 	 	 	14,584	 	
Goodwill	  	 	841	 	 	 	841	 	
Other long-term assets	  	 	353	 	 	 	296	 	
Long-term assets held for sale	  	 	—  	 	 	 	9,729	 	
	  	 	 	 	 	 	 	 	
Total assets	  	$	19,566	 	 	$	30,241	 	
	  	 	 	 	 	 	 	 	
Current liabilities:	  				 				
Accounts payable	  	$	662	 	 	$	633	 	
Revenues and royalties payable	  	 	898	 	 	 	748	 	
Short-term debt	  	 	162	 	 	 	115	 	
Current liabilities held for sale	  	 	69	 	 	 	991	 	
Other current liabilities	  	 	435	 	 	 	828	 	
	  	 	 	 	 	 	 	 	
Total current liabilities	  	 	2,226	 	 	 	3,315	 	
	  	 	 	 	 	 	 	 	
Long-term debt	  	 	5,785	 	 	 	6,749	 	
Asset retirement obligations	  	 	1,030	 	 	 	1,099	 	
Other long-term liabilities	  	 	462	 	 	 	549	 	
Long-term liabilities held for sale	  	 	—  	 	 	 	3,936	 	
Deferred income taxes	  	 	877	 	 	 	489	 	
Equity:	  				 				
Common stock	  	 	45	 	 	 	53	 	
Additional paid-in capital	  	 	4,486	 	 	 	7,333	 	
Retained earnings	  	 	3,650	 	 	 	702	 	
Accumulated other comprehensive earnings	  	 	1,027	 	 	 	1,166	 	
Treasury stock, at cost, 1.0 million shares in 2018	  	 	(22	) 	 	 	—  	 	
	  	 	 	 	 	 	 	 	
Total stockholders’ equity attributable to Devon	  	 	9,186	 	 	 	9,254	 	
Noncontrolling interests	  	 	—  	 	 	 	4,850	 	
	  	 	 	 	 	 	 	 	
Total equity	  	 	9,186	 	 	 	14,104	 	
	  	 	 	 	 	 	 	 	
Total liabilities and equity	  	$	19,566	 	 	$	30,241	 	
	  	 	 	 	 	 	 	 	
Common shares outstanding	  	 	450	 	 	 	525	 	
CAPITAL EXPENDITURES
(in millions)

 	  	Quarter Ended
December 31, 2018	 	  	Year Ended
December 31, 2018	 	
Upstream capital	  	$	629	 	  	$	2,423	 	
Land and other acquisitions	  	 	35	 	  	 	74	 	
	  	 	 	 	  	 	 	 	
Exploration and production (E&P) capital	  	 	664	 	  	 	2,497	 	
Capitalized interest	  	 	—  	 	  	 	41	 	
Other	  	 	8	 	  	 	38	 	
	  	 	 	 	  	 	 	 	
Devon capital expenditures	  	$	672	 	  	$	2,576	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
COSTS INCURRED
(in millions)

 	  	Total
Year Ended December 31,	 	
 	  	2018	 	  	2017	 	
Property acquisition costs:	  				  				
Proved properties	  	$	2	 	  	$	2	 	
Unproved properties	  	 	71	 	  	 	54	 	
Exploration costs	  	 	764	 	  	 	677	 	
Development costs	  	 	1,786	 	  	 	1,261	 	
	  	 	 	 	  	 	 	 	
Costs incurred	  	$	2,623	 	  	$	1,994	 	

 	  	United States
Year Ended December 31,	 	
 	  	2018	 	  	2017	 	
Property acquisition costs:	  				  				
Proved properties	  	$	2	 	  	$	2	 	
Unproved properties	  	 	71	 	  	 	50	 	
Exploration costs	  	 	679	 	  	 	590	 	
Development costs	  	 	1,537	 	  	 	1,036	 	
	  	 	 	 	  	 	 	 	
Costs incurred	  	$	2,289	 	  	$	1,678	 	

 	  	Canada
Year Ended December 31,	 	
 	  	2018	 	  	2017	 	
Property acquisition costs:	  				  				
Proved properties	  	$	—  	 	  	$	—  	 	
Unproved properties	  	 	—  	 	  	 	4	 	
Exploration costs	  	 	85	 	  	 	87	 	
Development costs	  	 	249	 	  	 	225	 	
	  	 	 	 	  	 	 	 	
Costs incurred	  	$	334	 	  	$	316	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
RESERVES RECONCILIATION

 	  	Total	 	
 	  	Oil / Bitumen
(MMBbls)	 	 	Gas
(Bcf)	 	 	NGL
(MMBbls)	 	 	Total
(MMBoe)	 	
As of December 31, 2017:	  				 				 				 				
Proved developed	  	 	393	 	 	 	5,632	 	 	 	410	 	 	 	1,742	 	
Proved undeveloped	  	 	288	 	 	 	355	 	 	 	63	 	 	 	410	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Proved	  	 	681	 	 	 	5,987	 	 	 	473	 	 	 	2,152	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revisions due to prices	  	 	23	 	 	 	91	 	 	 	12	 	 	 	51	 	
Revisions other than price	  	 	(6	) 	 	 	(167	) 	 	 	(23	) 	 	 	(57	) 	
Extensions and discoveries	  	 	105	 	 	 	446	 	 	 	64	 	 	 	243	 	
Production	  	 	(89	) 	 	 	(401	) 	 	 	(39	) 	 	 	(195	) 	
Sale of reserves	  	 	(7	) 	 	 	(1,195	) 	 	 	(61	) 	 	 	(267	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
As of December 31, 2018:	  				 				 				 				
Proved developed	  	 	401	 	 	 	4,333	 	 	 	359	 	 	 	1,482	 	
Proved undeveloped	  	 	306	 	 	 	428	 	 	 	67	 	 	 	445	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Proved	  	 	707	 	 	 	4,761	 	 	 	426	 	 	 	1,927	 	

 	  	United States	 	
 	  	Oil / Bitumen
(MMBbls)	 	 	Gas
(Bcf)	 	 	NGL
(MMBbls)	 	 	Total
(MMBoe)	 	
As of December 31, 2017:	  				 				 				 				
Proved developed	  	 	178	 	 	 	5,619	 	 	 	410	 	 	 	1,524	 	
Proved undeveloped	  	 	79	 	 	 	355	 	 	 	63	 	 	 	201	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Proved	  	 	257	 	 	 	5,974	 	 	 	473	 	 	 	1,725	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revisions due to prices	  	 	12	 	 	 	94	 	 	 	12	 	 	 	40	 	
Revisions other than price	  	 	(10	) 	 	 	(163	) 	 	 	(23	) 	 	 	(60	) 	
Extensions and discoveries	  	 	93	 	 	 	446	 	 	 	64	 	 	 	232	 	
Production	  	 	(47	) 	 	 	(397	) 	 	 	(39	) 	 	 	(153	) 	
Sale of reserves	  	 	(7	) 	 	 	(1,195	) 	 	 	(61	) 	 	 	(267	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
As of December 31, 2018:	  				 				 				 				
Proved developed	  	 	198	 	 	 	4,331	 	 	 	359	 	 	 	1,278	 	
Proved undeveloped	  	 	100	 	 	 	428	 	 	 	67	 	 	 	239	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Proved	  	 	298	 	 	 	4,759	 	 	 	426	 	 	 	1,517	 	

 	  	Canada	 	
 	  	Oil / Bitumen
(MMBbls)	 	 	Gas
(Bcf)	 	 	NGL
(MMBbls)	 	 	Total
(MMBoe)	 	
As of December 31, 2017:	  				 				 				 				
Proved developed	  	 	215	 	 	 	13	 	 	 	—  	 	 	 	218	 	
Proved undeveloped	  	 	209	 	 	 	—  	 	 	 	—  	 	 	 	209	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Proved	  	 	424	 	 	 	13	 	 	 	—  	 	 	 	427	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revisions due to prices	  	 	11	 	 	 	(3	) 	 	 	—  	 	 	 	11	 	
Revisions other than price	  	 	4	 	 	 	(4	) 	 	 	—  	 	 	 	3	 	
Extensions and discoveries	  	 	12	 	 	 	—  	 	 	 	—  	 	 	 	11	 	
Production	  	 	(42	) 	 	 	(4	) 	 	 	—  	 	 	 	(42	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
As of December 31, 2018:	  				 				 				 				
Proved developed	  	 	203	 	 	 	2	 	 	 	—  	 	 	 	204	 	
Proved undeveloped	  	 	206	 	 	 	—  	 	 	 	—  	 	 	 	206	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total Proved	  	 	409	 	 	 	2	 	 	 	—  	 	 	 	410	 	

DEVON ENERGY CORPORATION
FINANCIAL AND OPERATIONAL INFORMATION
 
NON-GAAP FINANCIAL MEASURES
This press release includes non-GAAP financial measures. These non-GAAP measures are not alternatives to GAAP measures, and you should not consider these non-GAAP measures in isolation or as a substitute for analysis of our results as reported under GAAP. Below is additional disclosure regarding each of the non-GAAP measures used in this press release, including reconciliations to their most directly comparable GAAP measure.
CORE EARNINGS
Devon’s reported net earnings include items of income and expense that are typically excluded by securities analysts in their published estimates of the company’s financial results. Accordingly, the company also uses the measures of core earnings and core earnings per share attributable to Devon. Devon believes these non-GAAP measures facilitate comparisons of its performance to earnings estimates published by securities analysts. Devon also believes these non-GAAP measures can facilitate comparisons of its performance between periods and to the performance of its peers. The following table summarizes the effects of these items on fourth-quarter 2018 earnings.

(in millions, except per share amounts)	  	Quarter Ended December 31, 2018	 	
 	  	Before-tax	 	  	After-tax	 	  	Per Diluted
Share	 	
Earnings attributable to Devon (GAAP)	  	$	1,484	 	  	$	1,149	 	  	$	2.48	 	
Adjustments:	  				  				  				
Asset dispositions	  	 	(268	) 	  	 	(206	) 	  	 	(0.45	) 	
Asset and exploration impairments	  	 	20	 	  	 	15	 	  	 	0.03	 	
Deferred tax asset valuation allowance	  	 	—  	 	  	 	9	 	  	 	0.02	 	
Fair value changes in financial instruments and foreign currency	  	 	(1,209	) 	  	 	(928	) 	  	 	(2.00	) 	
Restructuring and transaction costs	  	 	9	 	  	 	7	 	  	 	0.02	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings attributable to Devon (Non-GAAP)	  	$	36	 	  	$	46	 	  	$	0.10	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
NET DEBT
Devon defines net debt as debt less cash and cash equivalents. Devon believes that netting these sources of cash against debt provides a clearer picture of the future demands on cash from Devon to repay debt.

(in millions)	  	 	 	
 	  	December 31, 2018	 	
Total debt (GAAP)	  	$	5,947	 	
Less cash and cash equivalents	  	 	(2,414	) 	
	  	 	 	 	
Net debt (Non-GAAP)	  	$	3,533	 	

DEVON ENERGY CORPORATION
FORWARD LOOKING GUIDANCE
PRODUCTION GUIDANCE

 	  	Quarter 1	 	  	Full Year	 	
 	  	Low	 	  	High	 	  	Low	 	  	High	 	
Oil and bitumen (MBbls/d)	  				  				  				  				
New Devon	  	 	125	 	  	 	130	 	  	 	137	 	  	 	143	 	
Assets to be sold - Canada	  	 	109	 	  	 	113	 	  	 	108	 	  	 	112	 	
Assets to be sold - U.S.	  	 	3	 	  	 	5	 	  	 	3	 	  	 	5	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	237	 	  	 	248	 	  	 	248	 	  	 	260	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				
New Devon	  	 	65	 	  	 	70	 	  	 	70	 	  	 	75	 	
Assets to be sold - U.S.	  	 	26	 	  	 	30	 	  	 	26	 	  	 	30	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	91	 	  	 	100	 	  	 	96	 	  	 	105	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				
New Devon	  	 	490	 	  	 	540	 	  	 	510	 	  	 	550	 	
Assets to be sold - Canada	  	 	2	 	  	 	4	 	  	 	2	 	  	 	4	 	
Assets to be sold - U.S.	  	 	410	 	  	 	450	 	  	 	400	 	  	 	440	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	902	 	  	 	994	 	  	 	912	 	  	 	994	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				
New Devon	  	 	272	 	  	 	290	 	  	 	292	 	  	 	310	 	
Assets to be sold - Canada	  	 	109	 	  	 	114	 	  	 	108	 	  	 	113	 	
Assets to be sold - U.S.	  	 	97	 	  	 	110	 	  	 	96	 	  	 	108	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	478	 	  	 	514	 	  	 	496	 	  	 	531	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
PRICE REALIZATIONS GUIDANCE

 	  	Quarter 1	 	 	Full Year	 	
 	  	Low	 	 	High	 	 	Low	 	 	High	 	
Oil and bitumen - % of WTI	  				 				 				 				
U.S.	  	 	90	% 	 	 	100	% 	 	 	90	% 	 	 	100	% 	
Canada	  	 	60	% 	 	 	65	% 	 	 	47	% 	 	 	57	% 	
NGL - realized price	  	$	18	 	 	$	22	 	 	$	18	 	 	$	22	 	
Natural gas - % of Henry Hub	  	 	70	% 	 	 	80	% 	 	 	70	% 	 	 	80	% 	
OTHER GUIDANCE ITEMS - Expense line items include full-year impact of assets that are currently in the process of being sold.

 	  	Quarter 1	 	 	Full Year	 	
($ millions, except Boe and %)	  	Low	 	 	High	 	 	Low	 	 	High	 	
Marketing & midstream operating profit	  	$	15	 	 	$	25	 	 	$	50	 	 	$	70	 	
LOE & GP&T per BOE	  	$	9.00	 	 	$	9.25	 	 	$	8.80	 	 	$	9.05	 	
Production & property tax	  	$	75	 	 	$	85	 	 	$	300	 	 	$	340	 	
Exploration expenses	  	$	10	 	 	$	20	 	 	$	40	 	 	$	80	 	
Depreciation, depletion and amortization	  	$	425	 	 	$	475	 	 	$	1,800	 	 	$	1,900	 	
General & administrative expenses	  	$	155	 	 	$	175	 	 	$	535	 	 	$	585	 	
Financing costs, net	  	$	75	 	 	$	85	 	 	$	300	 	 	$	340	 	
Other expenses	  	$	10	 	 	$	20	 	 	$	50	 	 	$	60	 	
Current income tax rate	  	 	0	% 	 	 	0	% 	 	 	0	% 	 	 	0	% 	
Deferred income tax rate	  	 	20	% 	 	 	25	% 	 	 	20	% 	 	 	25	% 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total income tax rate	  	 	20	% 	 	 	25	% 	 	 	20	% 	 	 	25	% 	
CAPITAL EXPENDITURES GUIDANCE

 	  	Quarter 1	 	  	Full Year	 	
(in millions)	  	Low	 	  	High	 	  	Low	 	  	High	 	
New Devon upstream capital	  	$	475	 	  	$	525	 	  	$	1,800	 	  	$	2,000	 	
Assets to be sold upstream capital (assumes full year)	  	 	50	 	  	 	70	 	  	 	225	 	  	 	275	 	
Corporate	  	 	5	 	  	 	10	 	  	 	25	 	  	 	35	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Devon capital expenditures	  	$	530	 	  	$	605	 	  	$	2,050	 	  	$	2,310	 	

DEVON ENERGY CORPORATION
FORWARD LOOKING GUIDANCE
 
Oil Commodity Hedges

 	  	Price Swaps	 	  	Price Collars	 		
	Period	  	Volume (Bbls/d)	 	  	Weighted
Average Price
($/Bbl)	 	  	Volume
(Bbls/d)	 	  	Weighted
Average Floor
Price ($/Bbl)	 	  	Weighted
Average Ceiling
Price ($/Bbl)	 	
Q1-Q4 2019	  	 	50,882	 	  	$	59.38	 	  	 	89,937	 	  	$	54.39	 	  	$	64.40	 		
Q1-Q4 2020	  	 	2,489	 	  	$	60.55	 	  	 	14,940	 	  	$	51.90	 	  	$	62.07	 		

 	  	Three-Way Price Collars	 		
	Period	  	Volume (Bbls/d)	 	  	Weighted
Average Floor
Sold Price
($/Bbl)	 	  	Weighted
Average Floor
Purchased
Price ($/Bbl)	 	  	Weighted
Average Ceiling
Price ($/Bbl)	 	
Q1-Q4 2019	  	 	5,000	 	  	$	50.00	 	  	$	63.00	 	  	$	74.80	 		

Oil Basis Swaps	  		  				  				

	Period	  	Index	  	Volume (Bbls/d)	 	  	Weighted Average
Differential to WTI
($/Bbl)	 	
Q1-Q4 2019	  	Midland Sweet	  	 	28,000	 	  	$	(0.46	) 		
Q1-Q4 2019	  	Argus LLS	  	 	17,500	 	  	$	5.00	 		
Q1-Q4 2019	  	Argus MEH	  	 	16,000	 	  	$	2.84	 		
Q1-Q4 2019	  	NYMEX Roll	  	 	38,000	 	  	$	0.45	 		
Q1-Q4 2019	  	Western Canadian Select	  	 	61,411	 	  	$	(19.95	) 		
Q1-Q4 2020	  	NYMEX Roll	  	 	38,000	 	  	$	0.31	 		
Q1-Q4 2020	  	Western Canadian Select	  	 	3,661	 	  	$	(20.55	) 		
Natural Gas Commodity Hedges - Henry Hub

 	  	Price Swaps	 	  	Price Collars	 		
	Period	  	Volume (MMBtu/d)	 	  	Weighted
Average Price
($/MMBtu)	 	  	Volume
(MMBtu/d)	 	  	Weighted
Average Floor
Price
($/MMBtu)	 	  	Weighted
Average Ceiling
Price
($/MMBtu)	 	
Q1-Q4 2019	  	 	283,848	 	  	$	2.85	 	  	 	241,529	 	  	$	2.69	 	  	$	3.06	 		
Q1-Q4 2020	  	 	43,923	 	  	$	2.88	 	  	 	30,720	 	  	$	2.74	 	  	$	3.04	 		
Natural Gas Basis Swaps

	Period	  	Index	  	Volume (MMBtu/d)	 	  	Weighted Average
Differential to Henry
Hub ($/MMBtu)	 	
Q1-Q4 2019	  	Panhandle Eastern Pipe Line	  	 	84,466	 	  	$	(0.73	) 		
Q1-Q4 2019	  	El Paso Natural Gas	  	 	130,000	 	  	$	(1.46	) 		
Q1-Q4 2019	  	Houston Ship Channel	  	 	151,788	 	  	$	0.01	 		
Q1-Q4 2019	  	Transco Zone 4	  	 	7,397	 	  	$	(0.03	) 		
Q1-Q4 2020	  	Panhandle Eastern Pipe Line	  	 	30,000	 	  	$	(0.47	) 		
Q1-Q4 2020	  	El Paso Natural Gas	  	 	30,000	 	  	$	(0.64	) 		
Q1-Q4 2020	  	Houston Ship Channel	  	 	10,000	 	  	$	0.02	 		
Devon’s oil derivatives settle against the average of the prompt month NYMEX West Texas Intermediate futures price. Devon’s natural gas derivatives settle against the Inside FERC first of the month Henry Hub index. Commodity hedge positions are shown as of February 13, 2019.