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): November 5, 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 No.)	
			
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:

☐	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))	
Securities registered pursuant to Section 12(b) of the Act:
					
Title of each class	 	Trading
Symbol(s)	 	Name of each exchange
on which registered	
Common Stock, par value $0.10 per share	 	DVN	 	The New York Stock Exchange	
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 November 5, 2019, Devon Energy Corporation (the “Company”) announced its financial and operational results for the quarter ended September 30, 2019. In connection with this announcement, the Company provided an earnings release, its operations report for the third quarter of 2019 and certain supplemental financial information (including guidance and hedging information). Copies of these documents are furnished as Exhibits 99.1, 99.2 and 99.3, 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 9.01	Financial Statements and Exhibits.	

 	(d)	Exhibits	
					
Exhibit
    No.    	 	 	Description of Exhibits	
 	 	 	 	 	
 	99.1	 	 	Earnings release, dated November 5, 2019.	
 	 	 	 	 	
 	99.2	 	 	Third quarter 2019 operations report.	
 	 	 	 	 	
 	99.3	 	 	Supplemental financial information (including guidance and hedging information).	
 	 	 	 	 	
 	104	 	 	Cover Page Interactive Data File (embedded within the Inline XBRL document).	

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: November 5, 2019

Exhibit 99.1

NEWS RELEASE
Devon Energy Reports Third-Quarter 2019 Financial and Operational Results
OKLAHOMA CITY – Nov. 5, 2019 – Devon Energy Corp. (NYSE: DVN) today reported third-quarter net earnings of $109 million, or $0.27 per diluted share. Core earnings were $103 million, or $0.26 per diluted share. Supplemental financial tables for third-quarter results and updated 2019 guidance are available on the company’s website at www.devonenergy.com.
Highlights
 
 	•	 	Operating cash flow totaled $597 million, a 22 percent increase compared to the second quarter	
 
 	•	 	Free cash flow generation reached $56 million in third quarter	
 
 	•	 	$100 million midstream transaction executed in Delaware Basin	
 
 	•	 	Share-repurchase program decreased outstanding share count by 28 percent since 2018	
 
 	•	 	Third-quarter oil production increased 19 percent year-over-year, exceeding guidance	
 
 	•	 	Raised full-year 2019 oil production guidance for 3rd time this year	
 
 	•	 	Capital efficiency improved with no change to 2019 capital spending plan	
“The third quarter featured exceptional execution across all aspects of our strategic plan reflecting our unwavering commitment to deliver attractive financial returns, improve capital efficiency and grow shareholder distributions,” said Dave Hager, president and CEO. “Furthermore, our advantaged multi-basin portfolio is built to last, with significant capital allocation flexibility designed to deliver both high-return oil growth and increasing amounts of free cash flow in an environmentally responsible manner.”
Third-Quarter 2019 Results
Total net production from Devon’s retained assets averaged 325,000 oil-equivalent barrels (Boe) per day during the third quarter. Oil production averaged 148,000 barrels per day, a 19 percent increase from the same period a year ago. This result exceeded the company’s midpoint guidance by 3 percent or 4,000 barrels per day due to strong well productivity and timing of completions in the Delaware Basin.
For the third quarter, Devon’s upstream revenues totaled $1.1 billion. The company’s realized price during the period, including commodity hedges, was $27.73 per Boe, compared with the prior quarter of $27.84 per Boe. This lower price realization reflects lower crude, natural gas, and natural gas liquids pricing, offset by growth in higher-margin oil production and cash settlements on commodity hedges.
Production expense averaged $9.37 per Boe in the third quarter. Including costs reclassified to discontinued operations, production costs declined 19 percent compared to the year-ago quarter. The improved result was driven by lower lease operating expenses across Devon’s retained U.S. asset portfolio, decreased production taxes and the exit of higher-cost Canadian assets from Devon’s portfolio.
Corporate costs also declined during the quarter. General and administrative (G&A) expenses totaled $107 million in the third quarter. Including costs reclassified to discontinued operations, Devon’s G&A expense improved 27 percent year-over-year. The lower G&A costs were primarily driven by reduced personnel expense. Interest costs (including discontinued operations) were reduced $20 million year-over-year due to the company’s ongoing debt-reduction program.
 
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Financial Highlights
Operating cash flow totaled $597 million from continuing operations, a 22 percent increase compared to the previous quarter despite lower commodity prices. This level of cash flow funded third-quarter capital requirements of $541 million, resulting in $56 million of free cash flow.
Devon continues to maintain a strong balance sheet, with investment-grade credit ratings and excellent liquidity. The company’s $4.7 billion liquidity position includes $1.7 billion of cash (inclusive of restricted cash) and an undrawn $3 billion unsecured credit facility. During the quarter, Devon redeemed $1.5 billion of debt with cash on hand. At Sept. 30, 2019, the company’s total debt outstanding was $4.3 billion, with no maturities until late 2025.
Through Oct. 31, 2019, Devon had repurchased 147 million shares, or approximately 28 percent of outstanding shares since 2018, at a total cost of $4.8 billion, under its $5 billion authorization. In the third quarter, the company completed $550 million of share repurchases and returned $35 million of additional capital to shareholders through its quarterly dividend.
Asset-Level Overview
Delaware Basin: Net production from the company’s operations averaged 127,000 Boe per day, a 59 percent increase compared to the third-quarter 2018. This low-cost production growth across the basin drove a 12 percent year-over-year improvement in production costs to $9.06 per Boe. The most significant contributor of volume growth in the quarter was new well activity in the Leonard Shale. Devon brought online 15 Leonard wells in the quarter with average 30-day production rates of 2,200 Boe per day (71 percent oil), at an average completed well cost of $7.5 million.
Powder River Basin: Net production averaged 25,000 Boe per day in the quarter (71 percent oil). This represents a 33 percent increase in production compared to the year-ago period. Third-quarter volume growth was driven by 18 new wells targeting the Parkman, Teapot, Turner and Niobrara formations. This activity was highlighted by a 3-well spacing test in the Niobrara Shale that averaged 30-day rates of 1,300 Boe per day per well (87 percent oil). To date, Devon has commenced production on 8 successful Niobrara appraisal wells across its 200,000 net acre position in the oil fairway of the play. The company plans to accelerate Niobrara appraisal activity in 2020.
Eagle Ford: Third-quarter net production averaged 45,000 Boe per day. This high-margin production generated $313 million of free cash flow over the past year. Due to timing of completion activity, the company did not bring online any new wells in the third quarter. In the fourth quarter, Devon plans to bring online more than 25 Eagle Ford wells and expects production to average 50,000 to 55,000 Boe per day.
STACK: Third-quarter net production totaled 121,000 Boe per day, with liquids accounting for 56 percent of the volume mix. Devon brought online 16 operated wells during the quarter, with 30-day rates averaging 1,600 Boe per day. To date, these infill development projects, spaced at 4 to 6 wells per unit, are exceeding well productivity expectations and completed well costs have declined to as low as $6 million per well. The STACK asset is projected to generate $370 million of free cash flow in 2019.
For more detailed results and commentary regarding Devon’s operations and outlook, please refer to the company’s third-quarter 2019 operations report at www.devonenergy.com.
 
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Updated Guidance
Fourth-quarter 2019 oil production from retained assets is forecasted to average 154,000 to 160,000 barrels per day, a 6 percent sequential quarter improvement at the midpoint. The company’s updated guidance represents an estimated oil growth rate range of 20 percent to 21 percent for the full-year 2019 compared to 2018, a 550-basis point improvement compared to original guidance expectations.
Upstream capital from retained assets for the full-year 2019 remains unchanged at $1.83 billion to $1.87 billion. Fourth-quarter upstream capital from retained assets is expected to range from $375 million to $420 million. The reduction in capital spending from the third quarter is driven by timing of completions in the Delaware Basin and Eagle Ford and lower activity in the STACK play.
The company is also lowering its 2019 expense outlook for G&A to a range of $460 million to $470 million and financing costs to a range of $245 million to $255 million. This represents a 17 percent and 22 percent improvement, respectively, compared to original guidance expectations.
Divestiture Update
Subsequent to quarter end, the company entered into an agreement to form a midstream partnership in the Delaware Basin with QL Capital Partners, LP (“QLCP”). As part of this transaction, Devon will contribute gathering system and compression assets in the Cotton Draw area to the partnership 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 the partnership to fund the build out of the Cotton Draw midstream assets over the next several years.
Devon continued to advance the sale process for its Barnett Shale assets in north Texas. The data room was opened in the third quarter and multiple bids were received in September. Negotiations with advantaged bidders are progressing. The company’s sale process for its enhanced oil recovery project in the Rockies is also ongoing.
Environmental, Social & Governance
Devon is committed to delivering results that balance economic growth, environmental stewardship, strong governance and social responsibility. For access to Devon’s 2019 sustainability report, please visit www.devonenergy.com/sustainability. This report highlights the company’s commitment to operating a responsible, safe and ethical business while providing transparent reporting to all stakeholders.
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 third-quarter conference call will be held at 10 a.m. Central (11 a.m. Eastern) on Wednesday, Nov. 6, 2019, and will serve primarily as a forum for analyst and investor questions and answers.
Non-GAAP Disclosures
This release includes 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 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 and our related Form 10-Q.
 
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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.
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. with an emphasis on achieving strong corporate-level returns and capital-efficient cash-flow growth. For more information, please visit www.devonenergy.com and see our related Form 10-Q.

Investor Contacts	  	Media Contact	
Scott Coody, 405-552-4735	  	John Porretto, 405-228-7506	
Chris Carr, 405-228-2496	  		
 
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November 5, 2019 Q3 2019 Operations Report Exhibit 99.2

Q3 Summary – Efficiently Advancing the Business FINANCIAL RESULTS IMPROVING OUTLOOK OPERATING HIGHLIGHTS Operating cash flow increased 22% to $597 million (vs. Q2 2019) Repurchased $550 million of shares in Q3 ($4.8 billion since 2018) Outstanding share count to decline 30% by year-end (pg. 10) $100 million midstream transaction executed (pg. 12) Generated $56 million of free cash flow(1) in Q3 (pg. 3) Oil production exceeded top end of guidance (+19% vs. Q3 2018) Per-unit LOE improved 19% since Q3 2018 levels (pg. 4) Capital efficiency improvements accelerate in Delaware Basin (pg.16) Successful niobrara appraisal & spacing tests online (pg. 20) raising oil production guidance for the 3rd time in 2019 (pg. 5) Positioned for significant free cash flow in Q4 2019 (pg. 5) capital efficiency improvements highlight 2020 outlook (pgs. 7-9) (1) Free cash flow is a non-GAAP measure. Reconciliation provided in Q3 earnings materials.

Profitability continues to expand Share count (MM) and EBITDAX ($MM) EBITDAX ($MM) Share Count (MM) Share Count EBITDAX Share count down 27% EBITDAX up 30% Q3 2019 Change (vs Q2’19) Key Metrics(1) GAAP earnings (per share) Core earnings(2) (per share) EBITDAX(2) ($MM) $0.35 $0.29 $652 -13% +26% +4% Operating cash flow ($MM) Free cash flow(2) ($MM) Avg. basic share count (MM) $597 $56 397 +22% n/a -4% Q3 2019 – Financial Performance Profitability continues to expand in Q3 2019 Earnings and cash flow exceed consensus estimates Generated free cash flow of $56 million in quarter Key Financial Highlights Exceeded consensus estimates Represents results from Devon’s continuing operations. Refers to a non-GAAP measure. Reconciliation provided in Q3 earnings materials.

Beat Q3 midpoint guidance Q3 2019 – Operating Performance U.S. oil production(1) (MBOD) U.S. total production(1) (MBOED) Upstream capital ($MM) 148 325 $527(2) +19% +12% +1% WTI price ($/Bbl) Oil realizations (% of WTI) Q3 2019 (Continuing Ops.) $56.34 97% Change (vs. Q3’18) (Reported Results)(3) -19% +33% Key Metrics U.S. oil production exceeds guidance New Devon (MBOD) 148 (Q3 Guide: 141-147) 124 4,000 ABOVE MIDPOINT U.S. OIL PRODUCTION BARRELS PER DAY Represents New Devon performance (excludes Barnett Shale). Includes non-core upstream capital of $8 million. Represents reported amounts from Q3 2018, including discontinued operations. LOE & GP&T (per Boe) Prod. & property taxes ($MM) G&A expenses ($MM) Financing costs ($MM) $7.62 $68 $107 $60 -19% -32% -27% -25% G&A LOE & GP&T Interest Improving cost structure expands margins Per-unit cost (reported) ($/BOE) $11.86 $14.18 SINCE Q3 2018 DECLINE 16% Old DVN(3) DVN Today

Operational Success Driving Improved 2019 Outlook Scalable growth driving per-unit costs lower in Q4 Run-rate savings to reach >$200 million by year-end $1.7 billion debt redeemed YTD (annual interest savings: >$60 million) LOE & GP&T G&A Financing costs Lowering G&A expense outlook for 3rd time in 2019 Higher-cost Canadian assets exit portfolio Delaware, Eagle Ford and PRB to drive strong Q4 growth raising oil growth outlook for 3rd time in 2019 U.S. oil growth Q4 capital spending lower due to timing of completion activity Upstream capital Updated Guidance 20% – 21% (vs. 2018) $7.60 – $7.65 (per BOE) $460 – $470 ($ in millions) $245 – $255 ($ in millions) $1.83 – $1.87 ($ in billions) vs. Original Guidance Key Messages Represents New Devon performance target (excludes Barnett Shale). (1) (1) Improvement 15% Improvement 17% Improvement 22% Improvement Evaluating next steps for debt reduction program $50 Basis Point 550 Million Improvement Improved outlook Expect free cash flow to accelerate in Q4 2019

Strategic Framework for the 2020 Planning Cycle CAPITAL ALLOCATION PRIORITIES Maintain base production Pursue high-return growth projects Return excess cash to shareholders Fund dividends 1 2 3 4 WTI PRICE (ASSUMES $2.50 HENRY HUB) Maintain capital discipline Free cash flow accelerates GREATER THAN $50 $50 $45 Protect financial strength Exercise capital flexibility Maintain operational continuity Balance growth & free cash flow Fund dividends Improve financial strength (Program funded @ $48 WTI)

SHARE COUNT VS. 2019 NEW DEVON ASSETS E&P CAPITAL PROGRAM Preliminary 2020 Outlook 7%-9% Growth $1.7-$1.9 Billion OPTIMIZED FOR RETURNS DESIGNED FOR ULTRA-LOW BREAKEVEN PRICING 6%-8% Reduction DRIVEN BY LOW-RISK DEVELOPMENT DRILLING OIL GROWTH SHARE REDUCTION $ ENHANCING PER-SHARE CASH FLOW GROWTH Program funded at $48 WTI & $2.50 Henry Hub Low maintenance capital provides planning flexibility Expect oil volumes to average up to 160 MBOD in 2020 Positioned for attractive free cash flow (see pg. 8) Key Messages

2020 Plan Positioned for Attractive Free Cash Flow $675 2020e Free Cash Flow ($MM) (before dividends) $400 2020e Free Cash Flow Yield Free Cash Flow Free Cash Flow Yield $125 $55 WTI $2.50 HH MILLION MILLION MILLION FY2020 OUTLOOK Note: Free cash flow yield assumes market capitalization based on share price as of 11/01/19 multiplied by expected shares outstanding at year-end 2019 (~375 mm shares). Free cash flow represents operating cash flow less total capital requirements before dividend. OIL GROWTH: 7%-9% BREAKEVEN: $48 WTI (Assumes $2.50 Henry Hub) EXCLUDES BARNETT SHALE

2019 & 2020 Outlook = Improved Capital Efficiency Original Plan (2/19/19 Guide) Oil production remains on track New Devon 2019-2020 cumulative oil production (MMBO) Efficiencies driving lower capital requirements New Devon 2019-2020 cumulative upstream capital ($B) Current Plan (11/05/19 Guide) New Devon Cumulative Upstream Capital ($B) (Cumulative Capital) (Cumulative Capital) Original Plan (2/19/19 Guide) Current Plan (11/05/19 Guide) New Devon Cumulative Oil Production (MMBO) ~$400 MILLION LESS CAPITAL (VS. ORIGINAL PLAN) (Cumulative Oil) (Cumulative Oil)

Dedicated to disciplined allocation of capital Committed to Return of Capital to Shareholders $11.0 Billion 30% SHARE COUNT REDUCTION 527 ~375(1) 521 491 459 415 ~ 397 Assumes remaining authorization is completed by year-end and incremental shares are repurchased at current share price. 434 Repurchase program accelerates per-share growth Outstanding basic shares (MM) Share buyback New Devon capital Debt reduction Dividends ALLOCATED TO SHAREHOLDER RETURNS & DEBT REDUCTION 70% ~ Uses of Cash Since 2018 383

Building a Fortress Balance Sheet Aggressive debt reduction improves financial strength Net debt(1) ($B) $10.7 $2.6 >75% SINCE 2015 ($ in billions) Total debt (GAAP) $4.3 Less cash $1.7 Net debt (Non-GAAP)(1) $2.6 EBITDAX (Non-GAAP)(1)(2) $2.6 Net debt to EBITDAX ratio 1.0x Low leverage provides competitive advantage $485 $73 Significant liquidity with no near-term debt maturities Debt maturities ($MM) $4,700 1.0x NET DEBT TO EBITDAX REDUCTION Liquidity NO DEBT MATURITIES SIGNIFICANT FINANCIAL FLEXIBILITY UNTIL 2025 AS OF 9/30/2019 Cash Credit Facility Debt redemption program: targeting up to $3 billion $1.7 billion of debt retired YTD Evaluating next steps for debt reduction program Potential interest savings of ~$130 million annually Hedging program further protects financial strength Majority of oil and gas volumes protected in Q4 2019 Targeting ~50% oil & gas production in 2020 Net debt and EBITDAX are non-GAAP measures. Non-GAAP reconciliations are provided in Q3 earnings release materials. Based on last 12 months results from continuing operations.

Divestiture Program Accelerates Value Creation Resource depth allows for portfolio high-grading Cotton Draw midstream partnership formed Contributing gathering & compression assets Devon to remain operator of the assets Receive $100 million cash distribution in Q4 Partner to fund $40 million of expansion capital Barnett Shale divestiture process progressing Data rooms opened in early Q3 Initial bids received in September Ongoing negotiations with advantaged bidders Exited Canada for CAD $3.8 billion (USD $2.8B) Transaction closed in Q2 2019 Devon Assets Divestiture Assets POWDER RIVER STACK DELAWARE EAGLE FORD Rockies CO2 Barnett Shale Q3 Production: 100 MBOED Sales process: Ongoing Q3 Production: 3 MBOED Sales process: Ongoing ACCRETIVE MULTIPLE: ~10x CASH FLOW SOLD SALES PRICE: CAD $3.8 BILLION CANADIAN HEAVY OIL CLOSED: Q2 2019 Cotton draw (Midstream partnership) Proceeds: $100 million Gathering: 90 miles Compression: 4 stations NEW

Highly-Regarded ESG Performance For additional information see our 2019 Sustainability Report Included within the Dow Jones Sustainability Index top-quartile ESG ratings vs. peers ESG metrics incorporated in compensation structure Established methane emission reduction target Key Messages ENVIRONMENT SOCIAL GOVERNANCE Note: ISS scoring scale ranges from 1 to 10. The best score possible is 1. Peer group comprised of 13 E&P companies. DVN’s SCORE: 2 PEER AVERAGE: 3.8 +48% VERSUS PEER AVG. DVN’s SCORE: 2 PEER AVERAGE: 3.3 +40% VERSUS PEER AVG. DVN’s SCORE: 2 PEER AVERAGE: 5.2 +61% VERSUS PEER AVG. Devon is rated in the top-quartile of its peers (Highest rating achieved in governance) Note: Sustainalytics scores and rankings updated 10/21/2019. Peer group comprised of 20 E&P companies.

Q3 2019 - ASSET DETAIL NEW DEVON DELAWARE STACK POWDER RIVER EAGLE FORD(1) OTHER PRODUCTION Oil (MBbl/d) 148 70 32 18 22 6 NGL (MBbl/d) 79 28 37 2 11 1 Gas (MMcf/d) 588 167 317 28 75 1 Total (MBoe/d) 325 127 121 25 45 7 ASSET MARGIN (per Boe) Realized price $30.32 $33.48 $22.07 $41.20 $35.10 $46.41 Lease operating expenses ($3.73) ($4.17) ($2.08) ($7.28) ($3.20) ($15.06) Gathering, processing & transportation ($3.74) ($2.20) ($5.05) ($2.07) ($5.93) ($0.29) Production & property taxes ($2.06) ($2.69) ($0.86) ($4.73) ($1.95) ($3.30) Field-level cash margin $20.79 $24.42 $14.08 $27.12 $24.02 $27.76 CAPITAL INVESTMENT ($MM) Operated capital $444 $257 $59 $85 $38 $5 Non-operated capital $75 $5 $8 $4 $52 $6 Total capital investment $519 $262 $67 $89 $90 $11 . CAPITAL ACTIVITY Operated development rigs (avg.) 19 9 2 4 4 Operated frac crews (avg.) 7 3 1 1 2 Operated spuds 74 38 4 14 18 Operated wells tied-in 68 34 16 18 – Average lateral length (based on wells tied-in) 9,600’ 9,700’ 9,600’ 9,500’ N/A Operated working interest (based on wells tied-in) 79% 87% 56% 81% N/A Includes partner activity. Asset-Level Modeling Stats For additional modeling stats and updated guidance see our Q3 earnings release tables

Delaware Basin – Capital-Efficient Growth Engine Leonard Shale headlines Q3 operating performance Represents ~50% of new wells online (15 wells in Q3) Leonard well performance exceeding expectations Top project: N. Thistle 10 (EURs: 1.4 MMBOE/well) (pg. 17) Scalable infrastructure driving cost savings LOE rates decline >30% since 2016 (Q3 2019: $6.37/BOE) Oil & produced water gathered on pipe (avoids trucking) Operate ~40 disposal wells and 8 water reuse facilities Delivering savings of >$2 per barrel of water Positioned for strong operating results in Q4 2019 Expect to bring online >30 new wells Drilling & completion efficiencies accelerate (pg. 16) High-impact Cat Scratch 2.0 project flowing back (pg. 18) LOE rates to decline >10% by year-end (vs. Q3’19) Generating high-return production growth Production (MBOED) 127 79 Operating scale driving per-unit costs lower LOE & GP&T expense ($/BOE) >30% IMPROVEMENT Gas NGL Oil GROWTH 59% YEAR OVER YEAR

Productivity Improvement (2019 vs. 2018) 90 Day Oil IP Rate per 1K lateral, BOD (2019) PEER AVG. PEER AVG. APA CVX NBL XOM MTDR FANG PDCE CRZO PRIVATES WPX CXO MRO CDEV OXY EOG COP DVN Source: IHS, Goldman Sachs Global Investment Research Note: Bubble size represents 2019 wells as a percent of Delaware Basin total Delaware Basin – Step-Change in Operating Results Development focus driving best-in-class wells 90-day oil IPs, BOD vs. improvement in performance (2019 vs. 2018) Achieving best-in-class well productivity in 2019 Capital efficiency improvements continue to accelerate D&C costs decline by 12% in Q3 vs. 2018 ($851 per foot) Wolfcamp driving capital efficiency improvements (chart) Lower facility costs to contribute to future cost savings Drilling and completion efficiencies accelerate Drilled and completed feet per day (Wolfcamp formation) 65% COMPLETION IMPROVEMENT Drilling Completions 45% DRILLING IMPROVEMENT 900 750 700 625

Delaware – Development Projects Advancing on Plan Q3-2019a Q4-2019e Q1-2020e Q2-2020e Completion Spud Muffin (7 wells in the Bone Spring and Wolfcamp) Production Completion Lusitano (Phase 2: 5 wells in the Bone Spring and Wolfcamp) Production Cat Scratch (Phase 2: 10 Bone Spring wells) Drilling Completion Completion Thistle Cobra (7 wells in the Leonard and Wolfcamp) Production Production Chincoteague (5 Bone Spring wells) Drilling Completion Production 1 2 3 4 5 Green Wave (5 Wolfcamp wells) Drilling Completion Production 6 Projects Driving Q4 2019 Growth Future activity transitioning to Wolfcamp formation % of Delaware Basin activity 24% 45% 65% 2018 2019e 2020e Jayhawk (8 Wolfcamp wells) Drilling Completion Production Flagler (Phase 2: 10 wells in the Leonard and Bone Spring) Drilling Completion Production 7 8 High-confidence projects to drive strong Q4 growth Upcoming developments POTATO BASIN TODD COTTON DRAW THISTLE/GAUCHO RATTLESNAKE Eddy Lea New Mexico Texas Recent Developments Projects Underway Q3 2019 KEY WELLS 2,100 ~ BOED/WELL AVG. IP30 3 2 1 4 5 6 Belloq 5 Bone Spring wells Avg. IP30: 1,900 BOED/well Tomb Raider 5 Bone Spring & Leonard wells Avg. IP30: 2,400 BOED/well Bell Lake 5 Leonard wells Avg. IP30: 2,300 BOED/well Mean Green 4 Bone Spring & Wolfcamp wells Avg. IP30: 1,500 BOED/well 7 8 Chiles 3 Bone Spring wells Avg. IP30: 2,300 BOED/well DELAWARE BASIN DEVELOPMENT ACTIVITY N Thistle 10 6 Leonard wells Avg. IP30: 1,900 BOED/well

Todd Area – A Significant Long-Term Growth Platform Delivering highly-economic results across multiple formations Charged reservoir with stacked-pay potential Large, contiguous units with high working interest (>90%) 2019 capital activity: ~30 new wells online Q4 catalyst alert: Cat Scratch Fever 2.0 flowing back 10-wells offsetting prolific phase 1.0 (targeting 2nd Bone Spring) A visible, long-term growth platform in the Delaware Expect to bring online >30 new wells in 2020 Activity diversified between Leonard, Bone Spring & Wolfcamp Several hundred undrilled inventory locations remaining A VISIBLE LONG-TERM GROWTH PLATFORM 30 > NEW WELLS ONLINE IN 2020 A KEY GROWTH DRIVER IN UPCOMING YEAR Bone Spring Leonard Wolfcamp Ko Lanta 2 wells (9,700’ laterals) Avg. IP30: 2,600 BOED/well Tomb Raider 3 wells (9,900’ laterals) Avg. IP30: 3,500 BOED/well Boundary Raider 2 wells (9,800’ laterals) Avg. IP30: 3,900 BOED/well Belloq 5 wells (8,700’ laterals) Avg. IP30: 1,900 BOED/well Cat Scratch Fever 2.0 10 wells flowing back Eddy Lea Cat Scratch Fever 1.0 10 wells (8,300’ laterals) Avg. IP30: 3,600 BOED/well (Facility constrained rates) TODD DEVELOPMENT AREA STRONG GROWTH PLATFORM CAT SCRATCH 2.0 ONLINE Tomb Raider 4 wells (9,800’ laterals) Avg. IP30: 2,600 BOED/well Tomb Raider (4,700’ lateral) IP30: 1,500 BOED

Powder River Basin – Delivering Robust Oil Growth High-margin oil volume growth accelerating Turner program driving volume growth Initial Niobrara spacing tests successful (pg. 20) raising 2019 production exit-rate targets Expect >70% oil growth vs. Q4‘18 (prior target: >50%) Achieving operational efficiencies with Turner program Ranked #1 in industry for IP90 well performance D&C capital savings reach 20% per well vs. 2018 Well costs to improve to ~$6.5 million by year-end Operating scale to drive LOE >20% lower by Q4 2019 Raising oil growth outlook Net production (MBOED) Gas NGL Oil Ranked #1 in well productivity Avg. 90-day IPs BOED (Turner formation, 20:1) +50% VS. PEERS >20% IMPROVEMENT BY YEAR-END Operating scale drives costs lower LOE expense ($/BOE)

Niobrara – An Emerging Oil Resource Play Niobrara acreage resides in the core of oil fairway Significant potential with 200,000 net acres High working interest across position (>85%) Large, contiguous units secure operatorship Extended-reach drilling units maximize efficiencies Industry permitting & drilling activity accelerating 8 operated wells online (avg. IP30: 1,300 BOED; 87% oil) Delivering highest rate oil wells in basin Activity includes two successful spacing tests Appraisal activity focused in Atlas West area (see map) 2019 program: >10 operated spuds expected DVN & industry testing spacing of 3 to 7 wells/unit Potential to double Niobrara drilling activity in 2020 NIOBRARATYPE LOG 200 ft. Potential landing zones C B A SIGNIFICANT POTENTIAL 200,000 NET ACRES STACKED PAY POSITION IN OIL FAIRWAY POWDER RIVER BASIN NIOBRARA ACTIVITY Converse OIL FAIRWAY PDU WJ Ranch 22-1X Avg. IP30: 1,100 BOED (85% oil) Conley Draw 9-1X Avg. IP30: 1,300 BOED (89% oil) 100 ft. SDU Tillard 17-1X Avg. IP30: 1,200 BOED (88% oil) ATLAS WEST ATLAS EAST SSU MLT 16-2X Avg. IP30: 1,400 BOED (86% oil) SDU Tillard 25-1X Avg. IP30: 1,500 BOED (88% oil) (Stacked test with Turner) Tillard 18-1 spacing test (3 wells) Avg. IP30: 1,300 BOED/well (87% oil) Appraisal Wells Spacing Tests Upcoming Activity

Eagle Ford – Operational Momentum Established Strong production momentum heading into Q4 2019 Peak capital spending occurred in Q3 (+70% vs. 1H’19) Q4 2019e net production rate: 50-55 MBOED Growth driven by >25 Eagle Ford wells Achieving sustainable capital efficiencies Attained cost reductions of >$1 MM per well YTD Drilling costs per rig line improved by 20% Completion efficiencies & supply chain lowering costs Appraisal initiatives expanding resource opportunity Initial redevelopment wells successful (IP30: 2.2 MBOED) Refrac IRRs competing for capital (200 risked locations) Redevelopment & refrac spacing tests planned in 2020 Austin Chalk appraisal activity to continue next year 2020 targeted activity: average of 3-4 rig lines EAGLE FORD ACTIVITY Dewitt Karnes 2019 Refrac Program PRODUCTION RATE 50-55 Q4 2019 Activity >25 Eagle Ford wells MBOED Q4 2019e Muir C 4H Eagle Ford Refrac Avg. IP30 Uplift: 1,400 BOED Redevelopment Wells Avg. IP30: 2,200 BOED/well Krause B 2H Eagle Ford Refrac Avg. IP30 Uplift: 1,250 BOED Key 2019 Activity (in $MM) Last 12 months Revenue $740 Production expenses $205 Cash margin $535 Capital expenditures $222 Free cash flow $313 Substantial free cash flow Improved capital efficiency Drilling & completion cost ($MM) (6,500’ lateral) >$7.5 $6.5 Drilling Completions $1 MM DECLINE > (VS. 2018 AVG.)

STACK – Tailoring Activity to Current Price Environment Infill program achieving strong operational results Recent developments spaced at 4-6 wells per unit Well productivity exceeding type curve expectations Q3 net production: 121 MBOED (56% liquids) top highlight: Centaur project (IP30: 2,600 BOED/well) Prioritizing free cash flow over volume growth Free cash flow in 2019: ~$370 million Midship pipeline to provide pricing upside Firm oil transport to Gulf Coast provides flexibility Tailoring capital activity to current environment reducing Q4 2019 activity due to commodity prices Planning for lower activity levels in 2020 Evaluating partnerships to enhance capital efficiency Significant inventory provides long-term optionality Key Q3 2019 Results Future Developments 2019 Meramec Focus Area Blaine Kingfisher Canadian Centaur (5 wells/DSU) Avg. IP30: 2,600 BOED/well Harold (5 wells/DSU) Avg. IP30: 1,400 BOED/well Pickaroon (4 wells/DSU) Avg. IP30: 1,700 BOED/well Fleenor 2HX Avg. IP30: 2,300 BOED 370 $ FREE CASH FLOW MILLION IN 2019e Infill productivity exceeding type curve expectations Average cumulative production per well (MBOE) STACK DEVELOPMENT ACTIVITY Note: All results normalized for 10,000’ laterals Type Curve (10K LATERAL) 30-DAY IP (BOED) 1,300 – 1,600 EUR (MBOE) 1,200 – 1,400 D&C COST ~$7.5 MM ~

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 third-quarter 2019 earnings materials at www.devonenergy.com and Form 10-Q filed with the SEC. 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 99.3

 
					
Income Statement	  	 	2	 	
		
Cash Flow Statement	  	 	3	 	
		
Balance Sheet	  	 	4	 	
		
Production by Asset	  	 	5	 	
		
Capital & Well Activity by Asset	  	 	6	 	
		
Realized Price by Asset	  	 	7	 	
		
Per-Unit Field-Level Cash Margin by Asset	  	 	8	 	
		
Non-GAAP Core Earnings	  	 	9	 	
		
Non-GAAP EBITDAX, Net Debt and Free Cash Flow	  	 	10	 	

CONSOLIDATED STATEMENTS OF EARNINGS

(in millions, except per share amounts)	  	2019	 	 	2018	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Upstream revenues (1)	  	$	1,147	 	 	$	1,191	 	 	$	463	 	 	$	2,603	 	 	$	934	 	
Marketing revenues	  	 	700	 	 	 	730	 	 	 	765	 	 	 	1,114	 	 	 	1,222	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	  	 	1,847	 	 	 	1,921	 	 	 	1,228	 	 	 	3,717	 	 	 	2,156	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Production expenses (2)	  	 	368	 	 	 	371	 	 	 	365	 	 	 	402	 	 	 	417	 	
Exploration expenses	  	 	18	 	 	 	7	 	 	 	4	 	 	 	24	 	 	 	22	 	
Marketing expenses	  	 	684	 	 	 	713	 	 	 	750	 	 	 	1,105	 	 	 	1,201	 	
Depreciation, depletion and amortization	  	 	402	 	 	 	394	 	 	 	380	 	 	 	339	 	 	 	342	 	
Asset impairments	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	2	 	
Asset dispositions	  	 	(2	) 	 	 	(1	) 	 	 	(44	) 	 	 	(268	) 	 	 	(6	) 	
General and administrative expenses	  	 	107	 	 	 	114	 	 	 	135	 	 	 	136	 	 	 	128	 	
Financing costs, net	  	 	60	 	 	 	66	 	 	 	60	 	 	 	59	 	 	 	68	 	
Restructuring and transaction costs	  	 	10	 	 	 	12	 	 	 	51	 	 	 	6	 	 	 	6	 	
Other expenses	  	 	6	 	 	 	8	 	 	 	(17	) 	 	 	31	 	 	 	(9	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total expenses	  	 	1,653	 	 	 	1,684	 	 	 	1,684	 	 	 	1,834	 	 	 	2,171	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) from continuing operations before income taxes	  	 	194	 	 	 	237	 	 	 	(456	) 	 	 	1,883	 	 	 	(15	) 	
Income tax expense (benefit)	  	 	55	 	 	 	71	 	 	 	(110	) 	 	 	441	 	 	 	(171	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss) from continuing operations	  	 	139	 	 	 	166	 	 	 	(346	) 	 	 	1,442	 	 	 	156	 	
Net earnings (loss) from discontinued operations, net of income taxes	  	 	(30	) 	 	 	329	 	 	 	29	 	 	 	(293	) 	 	 	2,407	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss)	  	 	109	 	 	 	495	 	 	 	(317	) 	 	 	1,149	 	 	 	2,563	 	
Net earnings attributable to noncontrolling interests	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	26	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss) attributable to Devon	  	$	109	 	 	$	495	 	 	$	(317	) 	 	$	1,149	 	 	$	2,537	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic net earnings (loss) per share:	  				 				 				 				 				
Basic earnings (loss) from continuing operations per share	  	$	0.35	 	 	$	0.40	 	 	$	(0.81	) 	 	$	3.14	 	 	$	0.32	 	
Basic earnings (loss) from discontinued operations per share	  	 	(0.08	) 	 	 	0.80	 	 	 	0.07	 	 	 	(0.64	) 	 	 	4.85	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic net earnings (loss) per share	  	$	0.27	 	 	$	1.20	 	 	$	(0.74	) 	 	$	2.50	 	 	$	5.17	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted net earnings (loss) per share:	  				 				 				 				 				
Diluted earnings (loss) from continuing operations per share	  	$	0.35	 	 	$	0.40	 	 	$	(0.81	) 	 	$	3.12	 	 	$	0.32	 	
Diluted earnings (loss) from discontinued operations per share	  	 	(0.08	) 	 	 	0.79	 	 	 	0.07	 	 	 	(0.64	) 	 	 	4.82	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted net earnings (loss) per share	  	$	0.27	 	 	$	1.19	 	 	$	(0.74	) 	 	$	2.48	 	 	$	5.14	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average common shares outstanding:	  				 				 				 				 				
Basic	  	 	397	 	 	 	415	 	 	 	434	 	 	 	459	 	 	 	491	 	
Diluted	  	 	399	 	 	 	417	 	 	 	434	 	 	 	462	 	 	 	494	 	
	
(1)   UPSTREAM REVENUES	    	
			
(in millions)	  	2019	 	 	2018	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Oil, gas and NGL sales	  	$	1,020	 	 	$	1,051	 	 	$	1,068	 	 	$	1,170	 	 	$	1,310	 	
Derivative cash settlements	  	 	71	 	 	 	23	 	 	 	34	 	 	 	(16	) 	 	 	(175	) 	
Derivative valuation changes	  	 	56	 	 	 	117	 	 	 	(639	) 	 	 	1,449	 	 	 	(201	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Upstream revenues	  	$	1,147	 	 	$	1,191	 	 	$	463	 	 	$	2,603	 	 	$	934	 	

(2)   PRODUCTION EXPENSES	    	
			
(in millions)	  	2019	 	 	2018	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Lease operating expense	  	$	138	 	 	$	133	 	 	$	132	 	 	$	147	 	 	$	142	 	
Gathering, processing & transportation	  	 	162	 	 	 	161	 	 	 	159	 	 	 	180	 	 	 	181	 	
Production taxes	  	 	60	 	 	 	66	 	 	 	64	 	 	 	66	 	 	 	80	 	
Property taxes	  	 	8	 	 	 	11	 	 	 	10	 	 	 	9	 	 	 	14	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Production expenses	  	$	368	 	 	$	371	 	 	$	365	 	 	$	402	 	 	$	417	 	

2

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)	  	2019	 	 	2018	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Cash flows from operating activities:	  				 				 				 				 				
Net earnings (loss)	  	$	109	 	 	$	495	 	 	$	(317	) 	 	$	1,149	 	 	$	2,563	 	
Reconciliation of net earnings (loss) to net cash from operating activities:	  				 				 				 				 				
Net (earnings) loss from discontinued operations, net of income taxes	  	 	30	 	 	 	(329	) 	 	 	(29	) 	 	 	293	 	 	 	(2,407	) 	
Depreciation, depletion and amortization	  	 	402	 	 	 	394	 	 	 	380	 	 	 	339	 	 	 	342	 	
Asset impairments	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	2	 	
Leasehold impairments	  	 	13	 	 	 	1	 	 	 	1	 	 	 	19	 	 	 	14	 	
Accretion on discounted liabilities	  	 	10	 	 	 	10	 	 	 	10	 	 	 	8	 	 	 	9	 	
Total (gains) losses on commodity derivatives	  	 	(127	) 	 	 	(140	) 	 	 	605	 	 	 	(1,433	) 	 	 	376	 	
Cash settlements on commodity derivatives	  	 	71	 	 	 	23	 	 	 	31	 	 	 	(16	) 	 	 	(175	) 	
Gains on asset dispositions	  	 	(2	) 	 	 	(1	) 	 	 	(44	) 	 	 	(268	) 	 	 	(6	) 	
Deferred income tax expense (benefit)	  	 	53	 	 	 	69	 	 	 	(107	) 	 	 	446	 	 	 	(145	) 	
Share-based compensation	  	 	23	 	 	 	23	 	 	 	46	 	 	 	25	 	 	 	25	 	
Other	  	 	2	 	 	 	2	 	 	 	(14	) 	 	 	3	 	 	 	43	 	
Changes in assets and liabilities, net	  	 	13	 	 	 	(59	) 	 	 	(84	) 	 	 	(101	) 	 	 	(81	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash from operating activities - continuing operations	  	 	597	 	 	 	488	 	 	 	478	 	 	 	464	 	 	 	560	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from investing activities:	  				 				 				 				 				
Capital expenditures	  	 	(536	) 	 	 	(494	) 	 	 	(502	) 	 	 	(523	) 	 	 	(548	) 	
Acquisitions of property and equipment	  	 	(5	) 	 	 	(13	) 	 	 	(10	) 	 	 	(20	) 	 	 	(19	) 	
Divestitures of property and equipment	  	 	7	 	 	 	28	 	 	 	311	 	 	 	317	 	 	 	89	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash from investing activities - continuing operations	  	 	(534	) 	 	 	(479	) 	 	 	(201	) 	 	 	(226	) 	 	 	(478	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from financing activities:	  				 				 				 				 				
Repayments of long-term debt principal	  	 	—  	 	 	 	—  	 	 	 	(162	) 	 	 	(94	) 	 	 	(21	) 	
Repurchases of common stock	  	 	(561	) 	 	 	(187	) 	 	 	(998	) 	 	 	(759	) 	 	 	(1,698	) 	
Dividends paid on common stock	  	 	(35	) 	 	 	(37	) 	 	 	(34	) 	 	 	(37	) 	 	 	(38	) 	
Shares exchanged for tax withholdings and other	  	 	(1	) 	 	 	(3	) 	 	 	(19	) 	 	 	(8	) 	 	 	(3	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash from financing activities - continuing operations	  	 	(597	) 	 	 	(227	) 	 	 	(1,213	) 	 	 	(898	) 	 	 	(1,760	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash of continuing operations	  	 	(534	) 	 	 	(218	) 	 	 	(936	) 	 	 	(660	) 	 	 	(1,678	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from discontinued operations:	  				 				 				 				 				
Operating activities	  	 	(96	) 	 	 	135	 	 	 	(102	) 	 	 	78	 	 	 	293	 	
Investing activities	  	 	7	 	 	 	2,544	 	 	 	(47	) 	 	 	(77	) 	 	 	2,900	 	
Financing activities	  	 	(1,571	) 	 	 	—  	 	 	 	(8	) 	 	 	—  	 	 	 	71	 	
Effect of exchange rate changes on cash	  	 	(3	) 	 	 	37	 	 	 	2	 	 	 	(16	) 	 	 	10	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash of discontinued operations	  	 	(1,663	) 	 	 	2,716	 	 	 	(155	) 	 	 	(15	) 	 	 	3,274	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash	  	 	(2,197	) 	 	 	2,498	 	 	 	(1,091	) 	 	 	(675	) 	 	 	1,596	 	
Cash, cash equivalents and restricted cash at beginning of period	  	 	3,853	 	 	 	1,355	 	 	 	2,446	 	 	 	3,121	 	 	 	1,525	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash, cash equivalents and restricted cash at end of period	  	$	1,656	 	 	$	3,853	 	 	$	1,355	 	 	$	2,446	 	 	$	3,121	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reconciliation of cash, cash equivalents and restricted cash:	  				 				 				 				 				
Cash and cash equivalents	  	$	1,375	 	 	$	3,470	 	 	$	1,327	 	 	$	2,414	 	 	$	3,102	 	
Cash restricted for discontinued operations	  	 	280	 	 	 	370	 	 	 	—  	 	 	 	—  	 	 	 	—  	 	
Restricted cash included in other current assets	  	 	1	 	 	 	13	 	 	 	28	 	 	 	32	 	 	 	19	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total cash, cash equivalents and restricted cash	  	$	1,656	 	 	$	3,853	 	 	$	1,355	 	 	$	2,446	 	 	$	3,121	 	

3

CONSOLIDATED BALANCE SHEETS

(in millions)	  	September 30,	 	 	December 31,	 	
 	  	2019	 	 	2018	 	
Current assets:	  				 				
Cash and cash equivalents	  	$	1,375	 	 	$	2,414	 	
Cash restricted for discontinued operations	  	 	280	 	 	 	—  	 	
Accounts receivable	  	 	787	 	 	 	855	 	
Current assets associated with discontinued operations	  	 	21	 	 	 	283	 	
Other current assets	  	 	383	 	 	 	885	 	
	  	 	 	 	 	 	 	 	
Total current assets	  	 	2,846	 	 	 	4,437	 	
Oil and gas property and equipment, based on successful efforts accounting, net	  	 	9,122	 	 	 	8,982	 	
Other property and equipment, net	  	 	1,055	 	 	 	1,044	 	
	  	 	 	 	 	 	 	 	
Total property and equipment, net	  	 	10,177	 	 	 	10,026	 	
Goodwill	  	 	841	 	 	 	841	 	
Right-of-use assets	  	 	219	 	 	 	—  	 	
Other long-term assets	  	 	216	 	 	 	276	 	
Long-term assets associated with discontinued operations	  	 	95	 	 	 	3,986	 	
	  	 	 	 	 	 	 	 	
Total assets	  	$	14,394	 	 	$	19,566	 	
	  	 	 	 	 	 	 	 	
Current liabilities:	  				 				
Accounts payable	  	$	513	 	 	$	563	 	
Revenues and royalties payable	  	 	700	 	 	 	832	 	
Short-term debt	  	 	—  	 	 	 	162	 	
Current liabilities associated with discontinued operations	  	 	172	 	 	 	338	 	
Other current liabilities	  	 	273	 	 	 	331	 	
	  	 	 	 	 	 	 	 	
Total current liabilities	  	 	1,658	 	 	 	2,226	 	
	  	 	 	 	 	 	 	 	
Long-term debt	  	 	4,295	 	 	 	4,292	 	
Lease liabilities	  	 	244	 	 	 	—  	 	
Asset retirement obligations	  	 	526	 	 	 	606	 	
Other long-term liabilities	  	 	431	 	 	 	442	 	
Long-term liabilities associated with discontinued operations	  	 	175	 	 	 	2,285	 	
Deferred income taxes	  	 	523	 	 	 	529	 	
Stockholders’ equity:	  				 				
Common stock	  	 	39	 	 	 	45	 	
Additional paid-in capital	  	 	2,815	 	 	 	4,486	 	
Retained earnings	  	 	3,812	 	 	 	3,650	 	
Accumulated other comprehensive earnings (loss)	  	 	(116	) 	 	 	1,027	 	
Treasury stock, at cost, 0.3 million and 1.0 million shares in 2019 and 2018, respectively	  	 	(8	) 	 	 	(22	) 	
	  	 	 	 	 	 	 	 	
Total stockholders’ equity	  	 	6,542	 	 	 	9,186	 	
	  	 	 	 	 	 	 	 	
Total liabilities and stockholders’ equity	  	$	14,394	 	 	$	19,566	 	
	  	 	 	 	 	 	 	 	
Common shares outstanding	  	 	387	 	 	 	450	 	
 
4

PRODUCTION TREND

 	  	2019	 	  	2018	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
Oil (MBbls/d)	  				  				  				  				  				
Delaware Basin	  	 	70	 	  	 	67	 	  	 	60	 	  	 	45	 	  	 	44	 	
STACK	  	 	32	 	  	 	31	 	  	 	32	 	  	 	31	 	  	 	29	 	
Powder River Basin	  	 	18	 	  	 	15	 	  	 	15	 	  	 	13	 	  	 	15	 	
Eagle Ford	  	 	22	 	  	 	23	 	  	 	25	 	  	 	30	 	  	 	31	 	
Other	  	 	6	 	  	 	6	 	  	 	6	 	  	 	6	 	  	 	5	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	148	 	  	 	142	 	  	 	138	 	  	 	125	 	  	 	124	 	
U.S. divest assets	  	 	3	 	  	 	3	 	  	 	4	 	  	 	8	 	  	 	9	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total - US	  	 	151	 	  	 	145	 	  	 	142	 	  	 	133	 	  	 	133	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				  				
Delaware Basin	  	 	28	 	  	 	27	 	  	 	23	 	  	 	18	 	  	 	19	 	
STACK	  	 	37	 	  	 	40	 	  	 	35	 	  	 	37	 	  	 	40	 	
Powder River Basin	  	 	2	 	  	 	2	 	  	 	2	 	  	 	2	 	  	 	2	 	
Eagle Ford	  	 	11	 	  	 	12	 	  	 	12	 	  	 	15	 	  	 	15	 	
Other	  	 	1	 	  	 	1	 	  	 	1	 	  	 	1	 	  	 	1	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	79	 	  	 	82	 	  	 	73	 	  	 	73	 	  	 	77	 	
U.S. divest assets	  	 	30	 	  	 	30	 	  	 	31	 	  	 	32	 	  	 	36	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total - US	  	 	109	 	  	 	112	 	  	 	104	 	  	 	105	 	  	 	113	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				  				
Delaware Basin	  	 	167	 	  	 	158	 	  	 	146	 	  	 	127	 	  	 	103	 	
STACK	  	 	317	 	  	 	313	 	  	 	333	 	  	 	343	 	  	 	337	 	
Powder River Basin	  	 	28	 	  	 	22	 	  	 	18	 	  	 	20	 	  	 	18	 	
Eagle Ford	  	 	75	 	  	 	81	 	  	 	83	 	  	 	95	 	  	 	84	 	
Other	  	 	1	 	  	 	1	 	  	 	1	 	  	 	2	 	  	 	2	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	588	 	  	 	575	 	  	 	581	 	  	 	587	 	  	 	544	 	
U.S. divest assets	  	 	417	 	  	 	423	 	  	 	439	 	  	 	457	 	  	 	491	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total - US	  	 	1,005	 	  	 	998	 	  	 	1,020	 	  	 	1,044	 	  	 	1,035	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				  				
Delaware Basin	  	 	127	 	  	 	120	 	  	 	107	 	  	 	84	 	  	 	79	 	
STACK	  	 	121	 	  	 	124	 	  	 	123	 	  	 	126	 	  	 	126	 	
Powder River Basin	  	 	25	 	  	 	21	 	  	 	21	 	  	 	18	 	  	 	19	 	
Eagle Ford	  	 	45	 	  	 	49	 	  	 	50	 	  	 	61	 	  	 	60	 	
Other	  	 	7	 	  	 	7	 	  	 	7	 	  	 	6	 	  	 	7	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	325	 	  	 	321	 	  	 	308	 	  	 	295	 	  	 	291	 	
U.S. divest assets	  	 	103	 	  	 	103	 	  	 	108	 	  	 	116	 	  	 	127	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total - US	  	 	428	 	  	 	424	 	  	 	416	 	  	 	411	 	  	 	418	 	

5

CAPITAL EXPENDITURES

(in millions)	  	2019	 	  	2018	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
Delaware Basin	  	$	262	 	  	$	235	 	  	$	240	 	  	$	253	 	  	$	198	 	
STACK	  	 	67	 	  	 	94	 	  	 	112	 	  	 	195	 	  	 	167	 	
Powder River Basin	  	 	89	 	  	 	87	 	  	 	48	 	  	 	56	 	  	 	28	 	
Eagle Ford	  	 	90	 	  	 	53	 	  	 	48	 	  	 	32	 	  	 	35	 	
Other	  	 	11	 	  	 	9	 	  	 	9	 	  	 	6	 	  	 	12	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon upstream capital	  	 	519	 	  	 	478	 	  	 	457	 	  	 	542	 	  	 	440	 	
Divest assets upstream capital - US	  	 	8	 	  	 	16	 	  	 	10	 	  	 	21	 	  	 	23	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total upstream capital	  	 	527	 	  	 	494	 	  	 	467	 	  	 	563	 	  	 	463	 	
Land and other acquisitions	  	 	12	 	  	 	14	 	  	 	7	 	  	 	35	 	  	 	22	 	
Other	  	 	29	 	  	 	22	 	  	 	7	 	  	 	7	 	  	 	7	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total capital	  	$	568	 	  	$	530	 	  	$	481	 	  	$	605	 	  	$	492	 	

GROSS OPERATED SPUDS	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
			
 	  	2019	 	  	2018	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
Delaware Basin	  	 	38	 	  	 	23	 	  	 	39	 	  	 	31	 	  	 	25	 	
STACK	  	 	4	 	  	 	16	 	  	 	18	 	  	 	17	 	  	 	26	 	
Powder River Basin	  	 	14	 	  	 	17	 	  	 	9	 	  	 	12	 	  	 	6	 	
Eagle Ford	  	 	18	 	  	 	31	 	  	 	12	 	  	 	5	 	  	 	15	 	
Other	  	 	—  	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	74	 	  	 	87	 	  	 	78	 	  	 	65	 	  	 	72	 	

GROSS OPERATED WELLS TIED-IN	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
			
 	  	2019	 	  	2018	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
Delaware Basin	  	 	34	 	  	 	28	 	  	 	25	 	  	 	27	 	  	 	27	 	
STACK	  	 	16	 	  	 	21	 	  	 	29	 	  	 	25	 	  	 	26	 	
Powder River Basin	  	 	18	 	  	 	6	 	  	 	3	 	  	 	8	 	  	 	7	 	
Eagle Ford	  	 	—  	 	  	 	9	 	  	 	18	 	  	 	10	 	  	 	24	 	
Other	  	 	—  	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	68	 	  	 	64	 	  	 	75	 	  	 	70	 	  	 	84	 	

AVERAGE LATERAL LENGTH	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
			
(based on wells tied-in)	  	2019	 	  	2018	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
Delaware Basin	  	 	9,700’	 	  	 	7,500’	 	  	 	8,500’	 	  	 	8,800’	 	  	 	7,000’	 	
STACK	  	 	9,600’	 	  	 	9,000’	 	  	 	9,000’	 	  	 	8,400’	 	  	 	9,800’	 	
Powder River Basin	  	 	9,500’	 	  	 	9,500’	 	  	 	10,000’	 	  	 	9,500’	 	  	 	8,700’	 	
Eagle Ford	  	 	N/A	 	  	 	6,000’	 	  	 	6,000’	 	  	 	6,500’	 	  	 	6,000’	 	
Other	  	 	—  	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
New Devon	  	 	9,600’	 	  	 	8,000’	 	  	 	8,000’	 	  	 	8,400’	 	  	 	7,700’	 	

6

BENCHMARK PRICES

(average prices)	  	2019	 	 	2018	 	
 	  	Quarter 3	 	  	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Oil ($/Bbl) - West Texas Intermediate (Cushing)	  	$	56.34	 	  	$	59.85	 	 	$	54.88	 	 	$	58.80	 	 	$	69.60	 	
Natural Gas ($/Mcf) - Henry Hub	  	$	2.23	 	  	$	2.64	 	 	$	3.15	 	 	$	3.65	 	 	$	2.91	 	
NGL ($/Bbl) - Mont Belvieu Blended	  	$	16.18	 	  	$	19.05	 	 	$	22.94	 	 	$	26.30	 	 	$	33.05	 	
						
REALIZED PRICES	  	 	 	  	 	 	 	 	 	 	 	 	 	 	 	
			
 	  	2019	 	 	2018	 	
 	  	Quarter 3	 	  	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Oil (Per Bbl)	  				  				 				 				 				
Delaware Basin	  	$	53.85	 	  	$	55.54	 	 	$	49.48	 	 	$	49.04	 	 	$	57.90	 	
STACK	  	 	54.47	 	  	 	57.67	 	 	 	52.82	 	 	 	58.83	 	 	 	69.73	 	
Powder River Basin	  	 	52.50	 	  	 	56.79	 	 	 	49.21	 	 	 	55.62	 	 	 	67.01	 	
Eagle Ford	  	 	57.77	 	  	 	61.60	 	 	 	59.45	 	 	 	65.46	 	 	 	72.68	 	
Other	  	 	54.57	 	  	 	56.12	 	 	 	48.77	 	 	 	48.09	 	 	 	53.78	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
New Devon	  	 	54.43	 	  	 	57.17	 	 	 	51.99	 	 	 	56.08	 	 	 	65.27	 	
U.S. divest assets	  	 	52.33	 	  	 	52.71	 	 	 	46.21	 	 	 	50.65	 	 	 	58.53	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	 	54.39	 	  	 	57.09	 	 	 	51.83	 	 	 	55.78	 	 	 	64.80	 	
Cash settlements	  	 	2.17	 	  	 	(0.41	) 	 	 	3.63	 	 	 	0.79	 	 	 	(12.20	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	56.56	 	  	$	56.68	 	 	$	55.46	 	 	$	56.57	 	 	$	52.60	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas liquids (Per Bbl)	  				  				 				 				 				
Delaware Basin	  	$	10.27	 	  	$	13.77	 	 	$	17.64	 	 	$	21.24	 	 	$	29.66	 	
STACK	  	 	12.61	 	  	 	15.55	 	 	 	18.43	 	 	 	22.57	 	 	 	30.12	 	
Powder River Basin	  	 	15.01	 	  	 	17.74	 	 	 	19.64	 	 	 	22.76	 	 	 	28.33	 	
Eagle Ford	  	 	13.77	 	  	 	15.84	 	 	 	19.77	 	 	 	23.90	 	 	 	31.63	 	
Other	  	 	12.79	 	  	 	9.80	 	 	 	11.94	 	 	 	16.26	 	 	 	26.12	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
New Devon	  	 	12.02	 	  	 	15.00	 	 	 	18.33	 	 	 	22.42	 	 	 	30.23	 	
U.S. divest assets	  	 	12.25	 	  	 	14.22	 	 	 	19.38	 	 	 	21.54	 	 	 	28.23	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	 	12.09	 	  	 	14.79	 	 	 	18.64	 	 	 	22.15	 	 	 	29.59	 	
Cash settlements	  	 	1.84	 	  	 	1.03	 	 	 	0.48	 	 	 	0.18	 	 	 	(2.50	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	13.93	 	  	$	15.82	 	 	$	19.12	 	 	$	22.33	 	 	$	27.09	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gas (Per Mcf)	  				  				 				 				 				
Delaware Basin	  	$	0.90	 	  	$	(0.05	) 	 	$	1.84	 	 	$	1.68	 	 	$	1.81	 	
STACK	  	 	1.54	 	  	 	1.74	 	 	 	2.76	 	 	 	2.94	 	 	 	2.12	 	
Powder River Basin	  	 	1.96	 	  	 	2.16	 	 	 	2.92	 	 	 	3.85	 	 	 	2.63	 	
Eagle Ford	  	 	2.26	 	  	 	2.56	 	 	 	3.39	 	 	 	3.82	 	 	 	2.89	 	
Other	  	 	0.99	 	  	 	0.21	 	 	 	1.10	 	 	 	1.28	 	 	 	1.49	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
New Devon	  	 	1.47	 	  	 	1.37	 	 	 	2.62	 	 	 	2.84	 	 	 	2.20	 	
U.S. divest assets	  	 	1.70	 	  	 	1.94	 	 	 	2.43	 	 	 	2.98	 	 	 	2.23	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	 	1.56	 	  	 	1.61	 	 	 	2.53	 	 	 	2.90	 	 	 	2.21	 	
Cash settlements	  	 	0.24	 	  	 	0.20	 	 	 	(0.17	) 	 	 	(0.28	) 	 	 	0.01	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	1.80	 	  	$	1.81	 	 	$	2.36	 	 	$	2.62	 	 	$	2.22	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total oil equivalent (Per Boe)	  				  				 				 				 				
Delaware Basin	  	$	33.48	 	  	$	33.94	 	 	$	33.92	 	 	$	33.30	 	 	$	41.10	 	
STACK	  	 	22.07	 	  	 	23.96	 	 	 	26.65	 	 	 	29.40	 	 	 	31.48	 	
Powder River Basin	  	 	41.20	 	  	 	45.44	 	 	 	41.69	 	 	 	46.27	 	 	 	55.83	 	
Eagle Ford	  	 	35.10	 	  	 	37.50	 	 	 	39.41	 	 	 	44.20	 	 	 	49.44	 	
Other	  	 	46.41	 	  	 	47.43	 	 	 	42.03	 	 	 	41.53	 	 	 	48.40	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
New Devon	  	 	30.32	 	  	 	31.68	 	 	 	32.60	 	 	 	34.85	 	 	 	39.81	 	
U.S. divest assets	  	 	12.02	 	  	 	13.37	 	 	 	17.10	 	 	 	20.95	 	 	 	20.89	 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	 	25.93	 	  	 	27.24	 	 	 	28.58	 	 	 	30.94	 	 	 	34.06	 	
Cash settlements	  	 	1.80	 	  	 	0.60	 	 	 	0.93	 	 	 	(0.42	) 	 	 	(4.54	) 	
	  	 	 	 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	27.73	 	  	$	27.84	 	 	$	29.51	 	 	$	30.52	 	 	$	29.52	 	

7

BENCHMARK PRICES

(average prices)	  	2019	 	 	2018	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Oil ($/Bbl) - West Texas Intermediate (Cushing)	  	$	56.34	 	 	$	59.85	 	 	$	54.88	 	 	$	58.80	 	 	$	69.60	 	
Natural Gas ($/Mcf) - Henry Hub	  	$	2.23	 	 	$	2.64	 	 	$	3.15	 	 	$	3.65	 	 	$	2.91	 	
NGL ($/Bbl) - Mont Belvieu Blended	  	$	16.18	 	 	$	19.05	 	 	$	22.94	 	 	$	26.30	 	 	$	33.05	 	
						
FIELD-LEVEL CASH MARGIN (per Boe)	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
			
 	  	2019	 	 	2018	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Delaware Basin	  				 				 				 				 				
Realized price	  	$	33.48	 	 	$	33.94	 	 	$	33.92	 	 	$	33.30	 	 	$	41.10	 	
Lease operating expenses	  	 	(4.17	) 	 	 	(4.33	) 	 	 	(4.58	) 	 	 	(6.03	) 	 	 	(4.88	) 	
Gathering, processing & transportation	  	 	(2.20	) 	 	 	(2.31	) 	 	 	(2.23	) 	 	 	(2.06	) 	 	 	(2.01	) 	
Production & property taxes	  	 	(2.69	) 	 	 	(2.84	) 	 	 	(2.72	) 	 	 	(2.73	) 	 	 	(3.36	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	24.42	 	 	$	24.46	 	 	$	24.39	 	 	$	22.48	 	 	$	30.85	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
STACK	  				 				 				 				 				
Realized price	  	$	22.07	 	 	$	23.96	 	 	$	26.65	 	 	$	29.40	 	 	$	31.48	 	
Lease operating expenses	  	 	(2.08	) 	 	 	(1.84	) 	 	 	(1.87	) 	 	 	(1.84	) 	 	 	(2.16	) 	
Gathering, processing & transportation	  	 	(5.05	) 	 	 	(5.10	) 	 	 	(5.18	) 	 	 	(4.62	) 	 	 	(5.05	) 	
Production & property taxes	  	 	(0.86	) 	 	 	(1.25	) 	 	 	(1.33	) 	 	 	(1.30	) 	 	 	(1.71	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	14.08	 	 	$	15.77	 	 	$	18.27	 	 	$	21.64	 	 	$	22.56	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Powder River Basin	  				 				 				 				 				
Realized price	  	$	41.20	 	 	$	45.44	 	 	$	41.69	 	 	$	46.27	 	 	$	55.83	 	
Lease operating expenses	  	 	(7.28	) 	 	 	(6.95	) 	 	 	(8.00	) 	 	 	(6.58	) 	 	 	(6.56	) 	
Gathering, processing & transportation	  	 	(2.07	) 	 	 	(1.71	) 	 	 	(1.70	) 	 	 	(1.89	) 	 	 	(1.78	) 	
Production & property taxes	  	 	(4.73	) 	 	 	(4.99	) 	 	 	(4.97	) 	 	 	(5.39	) 	 	 	(6.81	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	27.12	 	 	$	31.79	 	 	$	27.02	 	 	$	32.41	 	 	$	40.68	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Eagle Ford	  				 				 				 				 				
Realized price	  	$	35.10	 	 	$	37.50	 	 	$	39.41	 	 	$	44.20	 	 	$	49.44	 	
Lease operating expenses	  	 	(3.20	) 	 	 	(2.85	) 	 	 	(2.81	) 	 	 	(2.69	) 	 	 	(2.34	) 	
Gathering, processing & transportation	  	 	(5.93	) 	 	 	(5.59	) 	 	 	(5.84	) 	 	 	(5.72	) 	 	 	(4.92	) 	
Production & property taxes	  	 	(1.95	) 	 	 	(2.43	) 	 	 	(2.23	) 	 	 	(2.44	) 	 	 	(2.72	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	24.02	 	 	$	26.63	 	 	$	28.53	 	 	$	33.35	 	 	$	39.46	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other	  				 				 				 				 				
Realized price	  	$	46.41	 	 	$	47.43	 	 	$	42.03	 	 	$	41.53	 	 	$	48.40	 	
Lease operating expenses	  	 	(15.06	) 	 	 	(20.34	) 	 	 	(17.05	) 	 	 	(17.29	) 	 	 	(17.07	) 	
Gathering, processing & transportation	  	 	(0.29	) 	 	 	(0.09	) 	 	 	(0.31	) 	 	 	(0.22	) 	 	 	0.25	 	
Production & property taxes	  	 	(3.30	) 	 	 	(4.33	) 	 	 	(3.28	) 	 	 	(3.73	) 	 	 	(4.17	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	27.76	 	 	$	22.67	 	 	$	21.39	 	 	$	20.29	 	 	$	27.41	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
New Devon - Total	  				 				 				 				 				
Realized price	  	$	30.32	 	 	$	31.68	 	 	$	32.60	 	 	$	34.85	 	 	$	39.81	 	
Lease operating expenses	  	 	(3.73	) 	 	 	(3.66	) 	 	 	(3.72	) 	 	 	(3.85	) 	 	 	(3.57	) 	
Gathering, processing & transportation	  	 	(3.74	) 	 	 	(3.80	) 	 	 	(3.92	) 	 	 	(3.85	) 	 	 	(3.86	) 	
Production & property taxes	  	 	(2.06	) 	 	 	(2.34	) 	 	 	(2.25	) 	 	 	(2.25	) 	 	 	(2.75	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	20.79	 	 	$	21.88	 	 	$	22.71	 	 	$	24.90	 	 	$	29.63	 	

8

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 third-quarter 2019 earnings.

(in millions, except per share amounts)	  	Quarter Ended September 30, 2019	 	
 	  	Before-tax	 	  	After-tax	 	  	Per Diluted Share	 	
Continuing Operations	  				  				  				
Net earnings (GAAP)	  	$	194	 	  	$	139	 	  	$	0.35	 	
Adjustments:	  				  				  				
Asset dispositions	  	 	(2	) 	  	 	(1	) 	  	 	(0.00	) 	
Asset and exploration impairments	  	 	14	 	  	 	11	 	  	 	0.03	 	
Deferred tax asset valuation allowance	  	 	—  	 	  	 	4	 	  	 	0.01	 	
Fair value changes in financial instruments	  	 	(57	) 	  	 	(44	) 	  	 	(0.12	) 	
Restructuring and transaction costs	  	 	10	 	  	 	8	 	  	 	0.02	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings (Non-GAAP)	  	$	159	 	  	$	117	 	  	$	0.29	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
Discontinued Operations	  				  				  				
Net loss (GAAP)	  	$	(43	) 	  	$	(30	) 	  	$	(0.08	) 	
Adjustments:	  				  				  				
Gain on sale of Canadian operations	  	 	(34	) 	  	 	(20	) 	  	 	(0.05	) 	
Deferred tax asset valuation allowance	  	 	—  	 	  	 	(4	) 	  	 	(0.01	) 	
Early retirement of debt	  	 	58	 	  	 	45	 	  	 	0.11	 	
Fair value changes in financial instruments and foreign currency and other	  	 	(6	) 	  	 	(9	) 	  	 	(0.01	) 	
Restructuring and transaction costs	  	 	5	 	  	 	4	 	  	 	0.01	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
Core loss (Non-GAAP)	  	$	(20	) 	  	$	(14	) 	  	$	(0.03	) 	
	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  				  				  				
Net earnings (GAAP)	  	$	151	 	  	$	109	 	  	$	0.27	 	
Adjustments:	  				  				  				
Continuing Operations	  	 	(35	) 	  	 	(22	) 	  	 	(0.06	) 	
Discontinued Operations	  	 	23	 	  	 	16	 	  	 	0.05	 	
	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings (Non-GAAP)	  	$	139	 	  	$	103	 	  	$	0.26	 	

9

EBITDAX
Devon believes EBITDAX provides information useful in assessing operating and financial performance across periods. Devon computes EBITDAX as net earnings from continuing operations before income tax expense; financing costs, net; exploration expenses; depreciation, depletion and amortization; 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 normal operations. EBITDAX 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.

(in millions)	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	  	Q3’19	 	 	Q2’19	 	 	Q1’19	 	 	Q4’18	 	 	TTM	 	 	Q3’18	 	 	Q2’18	 	 	Q1’18	 	
Net earnings (loss) (GAAP)	  	$	109	 	 	$	495	 	 	$	(317	) 	 	$	1,149	 	 	$	1,436	 	 	$	2,563	 	 	$	(335	) 	 	$	(153	) 	
Net (earnings) loss from discontinued operations, net of tax	  	 	30	 	 	 	(329	) 	 	 	(29	) 	 	 	293	 	 	$	(35	) 	 	 	(2,407	) 	 	 	(161	) 	 	 	(55	) 	
Financing costs, net	  	 	60	 	 	 	66	 	 	 	60	 	 	 	59	 	 	 	245	 	 	 	68	 	 	 	64	 	 	 	389	 	
Income tax expense (benefit)	  	 	55	 	 	 	71	 	 	 	(110	) 	 	 	441	 	 	 	457	 	 	 	(171	) 	 	 	13	 	 	 	(3	) 	
Exploration expenses	  	 	18	 	 	 	7	 	 	 	4	 	 	 	24	 	 	 	53	 	 	 	22	 	 	 	62	 	 	 	21	 	
Depreciation, depletion and amortization	  	 	402	 	 	 	394	 	 	 	380	 	 	 	339	 	 	 	1,515	 	 	 	342	 	 	 	342	 	 	 	305	 	
Asset impairments	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	2	 	 	 	154	 	 	 	—  	 	
Asset dispositions	  	 	(2	) 	 	 	(1	) 	 	 	(44	) 	 	 	(268	) 	 	 	(315	) 	 	 	(6	) 	 	 	23	 	 	 	(12	) 	
Share-based compensation	  	 	20	 	 	 	21	 	 	 	23	 	 	 	23	 	 	 	87	 	 	 	23	 	 	 	26	 	 	 	33	 	
Derivative and financial instrument non-cash valuation changes	  	 	(57	) 	 	 	(117	) 	 	 	638	 	 	 	(1,447	) 	 	 	(983	) 	 	 	202	 	 	 	322	 	 	 	(15	) 	
Restructuring and transaction costs	  	 	10	 	 	 	12	 	 	 	51	 	 	 	6	 	 	 	79	 	 	 	6	 	 	 	85	 	 	 	—  	 	
Accretion on discounted liabilities and other	  	 	7	 	 	 	8	 	 	 	(16	) 	 	 	30	 	 	 	29	 	 	 	(10	) 	 	 	6	 	 	 	(6	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
EBITDAX (Non-GAAP)	  	$	652	 	 	$	627	 	 	$	640	 	 	$	649	 	 	$	2,568	 	 	$	634	 	 	$	601	 	 	$	504	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
NET DEBT
Devon defines net debt as debt less cash, cash equivalents and cash restricted for discontinued operations. 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)	  	 	 	  	 	 	
 	  	September 30,
2019	 	  	December 31,
2015	 	
Total debt (GAAP)	  	$	4,295	 	  	$	13,032	 	
Less:	  				  				
Cash and cash equivalents	  	 	(1,375	) 	  	 	(2,310	) 	
Cash restricted for discontinued operations	  	 	(280	) 	  	 	—  	 	
	  	 	 	 	  	 	 	 	
Net debt (Non-GAAP)	  	$	2,640	 	  	$	10,722	 	
	  	 	 	 	  	 	 	 	
FREE CASH FLOW
Devon defines free cash flow as total operating cash flow less capital expenditures and acquisitions. Devon believes that free cash flow provides a useful measure of available cash generated by operating activities for other investing and financing activities.

(in millions)	  	 	 	
 	  	Quarter Ended
September 30, 2019	 	
Total operating cash flow (GAAP)	  	$	597	 	
Less capital expenditures and acquisitions:	  				
Capital expenditures	  	 	(536	) 	
Acquisitions	  	 	(5	) 	
	  	 	 	 	
Free cash flow (Non-GAAP)	  	$	56	 	

10

Devon Energy Fourth-Quarter 2019 Guidance
 
PRODUCTION GUIDANCE

 	  	Quarter 4	 	
 	  	    Low    	 	 	    High    	 	
Oil (MBbls/d)	  				 				
New Devon	  	 	154	 	 	 	160	 	
U.S. divest assets	  	 	2	 	 	 	3	 	
	  	 	 	 	 	 	 	 	
Total	  	 	156	 	 	 	163	 	
	  	 	 	 	 	 	 	 	
Natural gas liquids (MBbls/d)	  				 				
New Devon	  	 	78	 	 	 	82	 	
U.S. divest assets	  	 	26	 	 	 	30	 	
	  	 	 	 	 	 	 	 	
Total	  	 	104	 	 	 	112	 	
	  	 	 	 	 	 	 	 	
Gas (MMcf/d)	  				 				
New Devon	  	 	570	 	 	 	620	 	
U.S. divest assets	  	 	390	 	 	 	420	 	
	  	 	 	 	 	 	 	 	
Total	  	 	960	 	 	 	1,040	 	
	  	 	 	 	 	 	 	 	
Total oil equivalent (MBoe/d)	  				 				
New Devon	  	 	327	 	 	 	345	 	
U.S. divest assets	  	 	93	 	 	 	103	 	
	  	 	 	 	 	 	 	 	
Total	  	 	420	 	 	 	448	 	

PRICE REALIZATIONS GUIDANCE	  	 	 	 	 	 	
		
 	  	Quarter 4	 	
 	  	    Low    	 	 	    High    	 	
Oil - % of WTI	  	 	90	% 	 	 	100	% 	
NGL - realized price	  	$	13	 	 	$	16	 	
Natural gas - % of Henry Hub	  	 	50	% 	 	 	70	% 	
			
OTHER GUIDANCE ITEMS	  	 	 	 	 	 	
		
 	  	Quarter 4	 	
($ millions, except Boe and %)	  	    Low    	 	 	    High    	 	
Marketing & midstream operating profit	  	$	—  	 	 	$	—  	 	
LOE & GP&T per BOE	  	$	7.35	 	 	$	7.65	 	
Production & Property Tax	  	$	75	 	 	$	85	 	
Exploration expenses	  	$	5	 	 	$	15	 	
Depreciation, depletion and amortization	  	$	420	 	 	$	460	 	
General & administrative expenses	  	$	105	 	 	$	115	 	
Financing costs, net	  	$	60	 	 	$	70	 	
Other expenses	  	$	10	 	 	$	20	 	
Current income tax rate	  	 	0	% 	 	 	5	% 	
Deferred income tax rate	  	 	20	% 	 	 	25	% 	
	  	 	 	 	 	 	 	 	
Total income tax rate	  	 	20	% 	 	 	30	% 	

CAPITAL EXPENDITURES GUIDANCE	  	 	 	 	 	 	
		
 	  	Quarter 4	 	
(in millions)	  	    Low    	 	 	    High    	 	
New Devon Upstream capital	  	$	375	 	 	$	420	 	
Divest assets upstream capital	  	 	5	 	 	 	10	 	
Other	  	 	5	 	 	 	10	 	
	  	 	 	 	 	 	 	 	
Total	  	$	385	 	 	$	440	 	

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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)	 	
Q4 2019	  	 	35,600	 	  	$	61.21	 	  	 	79,500	 	  	$	54.06	 	  	$	64.13	 		
Q1-Q4 2020	  	 	7,238	 	  	$	57.29	 	  	 	31,932	 	  	$	51.85	 	  	$	61.93	 		
Q1-Q4 2021	  	 	493	 	  	$	52.75	 	  	 	1,479	 	  	$	48.48	 	  	$	58.48	 		

 	  	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)	 	
Q4 2019	  	 	5,000	 	  	$	50.00	 	  	$	63.00	 	  	$	74.80	 		
Oil Basis Swaps

	Period	  	Index	  	Volume (Bbls/d)	 	  	Weighted Average
Differential to WTI
($/Bbl)	 	
Q4 2019	  	Midland Sweet	  	 	28,000	 	  	$	(0.46	) 		
Q4 2019	  	Argus LLS	  	 	7,500	 	  	$	5.18	 		
Q4 2019	  	Argus MEH	  	 	26,000	 	  	$	3.33	 		
Q4 2019	  	NYMEX Roll	  	 	38,000	 	  	$	0.45	 		
Q1-Q4 2020	  	Argus MEH	  	 	9,000	 	  	$	3.44	 		
Q1-Q4 2020	  	NYMEX Roll	  	 	44,000	 	  	$	0.34	 		
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)	 	
Q4 2019	  	 	243,300	 	  	$	2.80	 	  	 	195,000	 	  	$	2.64	 	  	$	3.03	 		
Q1-Q4 2020	  	 	81,409	 	  	$	2.77	 	  	 	42,557	 	  	$	2.73	 	  	$	3.03	 		
Natural Gas Basis Swaps

	Period	  	Index	  	Volume (MMBtu/d)	 	  	Weighted Average
Differential to Henry
Hub ($/MMBtu)	 	
Q4 2019	  	Panhandle Eastern Pipe Line	  	 	20,000	 	  	$	(0.56	) 		
Q4 2019	  	El Paso Natural Gas	  	 	130,000	 	  	$	(1.46	) 		
Q4 2019	  	Houston Ship Channel	  	 	162,500	 	  	$	0.01	 		
Q1-Q4 2020	  	Panhandle Eastern Pipe Line	  	 	30,000	 	  	$	(0.47	) 		
Q1-Q4 2020	  	El Paso Natural Gas	  	 	45,000	 	  	$	(0.70	) 		
Q1-Q4 2020	  	Houston Ship Channel	  	 	10,000	 	  	$	0.02	 		
NGL Commodity Hedges

 	  	 	  	Price Swaps	 		
	Period	  	Product	  	Volume (Bbls/d)	 	  	Weighted Average
Price ($/Bbl)	 	
Q4 2019	  	Ethane	  	 	1,000	 	  	$	11.55	 		
Q4 2019	  	Natural Gasoline	  	 	4,500	 	  	$	55.93	 		
Q4 2019	  	Normal Butane	  	 	4,000	 	  	$	33.69	 		
Q4 2019	  	Propane	  	 	8,500	 	  	$	30.01	 		
Q1-Q4 2020	  	Natural Gasoline	  	 	1,000	 	  	$	44.84	 		
Q1-Q4 2020	  	Normal Butane	  	 	1,000	 	  	$	23.52	 		
Q1-Q4 2020	  	Propane	  	 	4,500	 	  	$	25.18	 		
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. Devon’s NGL derivatives settle against the average of the prompt month OPIS Mont Belvieu, Texas index. Commodity hedge positions are shown as of September 30, 2019.
 
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