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 2, 2021

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 2, 2021, Devon Energy Corporation (the “Company”) announced its financial and operational results for the quarterly period ended September 30, 2021. In connection with this announcement, the Company provided an earnings release and certain supplemental financial information (including guidance and hedging information). Copies of these documents are furnished as Exhibits 99.1 and 99.2, respectively, to this report and, along with certain other materials, 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 2, 2021.		
			
99.2	  	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 2, 2021

Exhibit 99.1

	 		 	Devon Energy Corporation
333 West Sheridan Avenue
Oklahoma City, OK 73102-5015	
			 		
Devon Energy Reports 46 Percent Increase in Operating Cash Flow and Record Free Cash Flow Generation in Third-Quarter 2021
OKLAHOMA CITY – Nov. 2, 2021 – Devon Energy Corp. (NYSE: DVN) today reported financial and operational results for the third-quarter 2021. Supplemental financial tables and forward-looking guidance are available on the company’s website at www.devonenergy.com.
KEY FINANCIAL AND OPERATIONAL HIGHLIGHTS
 
 	•	 	Fixed-plus-variable dividend increased by 71 percent to $0.84 per share	
 
 	•	 	Board authorizes a $1 billion share buyback, representing 4 percent of the company’s market capitalization	
 
 	•	 	Delaware Basin drove third-quarter results that were favorable to guidance on production and costs	
 
 	•	 	Operating cash flow increased 46 percent from the prior quarter to $1.6 billion	
 
 	•	 	Disciplined capital allocation limited reinvestment rates to 30 percent of cash flow	
 
 	•	 	Free cash flow generation accelerated to $1.1 billion, an 8-fold increase from the fourth quarter of 2020	
 
 	•	 	Balance sheet strengthened with cash balances increasing by $782 million to a total of $2.3 billion	
CEO PERSPECTIVE
“The power of Devon’s asset portfolio and disciplined cash-return strategy was evidenced by another quarter of operational and financial outperformance,” said Rick Muncrief, president and CEO. “The team’s outstanding execution, coupled with an improved cost structure, has allowed us to fully capture the benefits of rising commodity prices and deliver robust growth in free cash flow.”
“With this free cash flow, we are delivering on our commitment to accelerate the return of cash to shareholders with a 71 percent increase in the dividend and we have continued to strengthen our investment-grade balance sheet.”
“As a result of our improving financial outlook, I am excited to announce the next step in our cash-return strategy with the authorization of a $1 billion share-repurchase program,” Muncrief added. “While our market-leading dividend will remain the top priority for free cash flow, this program provides us with another avenue to opportunistically return value to shareholders and enhance per-share results.”
“Looking ahead to the remainder of this year and into 2022, we will continue to prioritize free cash flow over volume growth,” Muncrief commented. “With our operations successfully scaled to generate strong cash flow growth, we have no intention of pursuing production growth until it is clear that market fundamentals have sustainably recovered, and worldwide spare oil capacity is effectively absorbed.”
FINANCIAL SUMMARY
Devon reported net earnings of $838 million, or $1.24 per diluted share, in the third quarter of 2021. Adjusting for items analysts typically exclude from estimates, the company’s core earnings were $733 million, or $1.08 per diluted share.
Operating cash flow totaled $1.6 billion in the third quarter, a 46 percent increase from the prior quarter. With capital reinvestment rates limited to 30 percent of cash flow, the company generated $1.1 billion of free cash flow in the quarter. This represents an 8-fold increase in free cash flow compared to the fourth quarter of 2020 and is the highest quarterly amount in Devon’s 50-year history.
Based on the third-quarter financial performance, Devon’s board declared a fixed-plus-variable dividend of $0.84 per share. This payout represents a 71 percent increase compared to the payout declared from the previous quarter. The dividend is payable on Dec. 30, 2021 to shareholders of record at the close of business on Dec. 10, 2021.
 
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The company also continued to strengthen its investment-grade financial position, with cash balances increasing by $782 million in the quarter to a total of $2.3 billion. The company intends to further improve its financial strength by retiring and calling low-premium debt of approximately $1.0 billion in 2022 and 2023.
With the company’s improving financial outlook, in a separate release issued today, Devon announced the next step in its cash-return strategy with the authorization of a $1.0 billion share-repurchase program. This program is authorized through year-end 2022 and is equivalent to 4 percent of the company’s market capitalization.
OPERATING RESULTS
Devon’s total production averaged 608,000 oil-equivalent barrels (Boe) per day in the third quarter, exceeding guidance by 5 percent. This outperformance was driven by strong well productivity in the Delaware Basin and better-than-expected base production performance across the portfolio.
Upstream capital spending was in line with guidance at $442 million in the quarter. Devon exited the quarter running 16 operated drilling rigs and five completion crews, with approximately 80 percent of this activity allocated to the Delaware Basin.
Production expense for Devon totaled $9.91 per unit, a 1 percent decrease from the prior quarter. The improved cost structure was driven by operational efficiency gains and the benefits of scalable production growth in the Delaware Basin. The per-unit cost savings achieved in the field were partially offset by higher production taxes due to rising commodity prices.
The company’s corporate cost structure, which consists of general and administrative expenses and financing costs, improved by 25 percent year-over-year, on a pro forma basis. This positive result was driven by the capture of merger-related synergies that are on track to achieve $600 million in annual cash flow improvements.
ASSET-LEVEL HIGHLIGHTS
Delaware Basin: Production averaged 409,000 Boe per day, with oil reaching 52 percent of the product mix. This production result represents a 39 percent increase year over year, on a pro forma basis. The high-margin growth in the quarter was driven by 52 new wells that commenced first production across Devon’s 400,000 net acres in New Mexico and Texas. The completed well costs for this Wolfcamp-oriented development activity continued to be extremely low at $554 per lateral foot.
The top operating highlight from the quarter was the Boundary Raider project in Lea County, New Mexico. This development was a follow-up to the company’s original Bone Spring project in the area during 2018 that achieved record-setting well productivity rates in the basin. This edition of Boundary Raider developed the Upper Wolfcamp and delivered prolific initial 30-day production rates as high as 7,300 Boe per day.
Another noteworthy result in the quarter was the Thistle Cobra project. This 3-mile lateral Wolfcamp development exceeded pre-drill expectations by approximately 10 percent, with average 30-day rates reaching up to 6,300 Boe per day. This successful project also de-risked additional high-return Wolfcamp inventory in the area.
Anadarko Basin: Production averaged 75,000 Boe per day, with gas and NGLs representing over 80 percent of the total volume. During the quarter, Devon operated two drilling rigs in the basin supported by a $100 million drilling carry with Dow. The initial wells from this carry-enhanced activity were brought online in the third quarter. The four-well Miller-Miller project, targeting the Woodford formation, averaged 30-day production rates of 2,700 Boe per day. Completed well costs for this activity averaged $8 million per well.
The company is on track to drill up to 30 wells with Dow in 2021. With the recent rise in commodity prices, Devon and Dow are evaluating additional activity in 2022.
Williston Basin: Production averaged 58,000 Boe per day, with oil accounting for 67 percent. The company’s operational focus in the quarter was optimizing base production and harvesting free cash flow. For the full-year 2021, the company plans to bring online up to 20 new wells and generate more than $700 million of free cash flow from this high-margin asset.
 
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Eagle Ford: Production increased by 15 percent from the prior quarter to an average of 42,000 Boe per day. This growth was driven by 19 new development wells brought online in the quarter. Completed well costs for this activity were approximately $6 million per well and the average 30-day rates from this high-return program were 2,300 Boe per day. Devon and its partner plan to sustain production by running a two-rig drilling program for the remainder of the year.
Powder River Basin: Production averaged 20,000 Boe per day, of which 70 percent was oil. During the quarter, Devon brought online two new wells in Converse County that delivered average 30-day rates of 1,300 Boe per day (93 percent oil). The completed well cost for this activity targeting the Parkman formation averaged $5 million per well. The company has 300,000 net acres in the oil fairway of this emerging resource opportunity that is prospective for multiple benches.
OUTLOOK
Devon remains committed to a maintenance capital program and is firmly on track to meet the strategic objectives that underpin its operating plan in 2021. With efficiencies compressing cycle times and pulling forward activity, Devon now expects its production and capital spending to be at the high end of its 2021 guidance range. Detailed forward-looking guidance for the upcoming fourth quarter is available on the company’s website at www.devonenergy.com.
In 2022, due to market fundamentals, Devon will continue to prioritize free cash flow generation over the pursuit of volume growth. With this disciplined approach, the company’s preliminary plan is to maintain production in the range of 570,000 to 600,000 Boe per day, with an upstream capital investment of $1.9 billion to $2.2 billion.
ENVIRONMENTAL PERFORMANCE TARGETS
Devon recently established new environmental performance targets focused on reducing the carbon intensity of its operations. Highlights from these targets include reducing GHG emissions 50 percent by 2030, achieving net zero emissions by 2050 and initiatives to constructively engage with upstream and downstream stakeholders to improve performance. For more information, please refer to the Sustainability portion of Devon’s website at www.devonenergy.com/sustainability.
CONFERENCE CALL WEBCAST AND SUPPLEMENTAL EARNINGS MATERIALS
Also provided with today’s release is the company’s detailed earnings presentation that is available on the company’s website at www.devonenergy.com. The company’s third-quarter conference call will be held at 10:00 a.m. Central (11:00 a.m. Eastern) on Wednesday, Nov. 3, 2021, and will serve primarily as a forum for analyst and investor questions and answers.
ABOUT DEVON ENERGY
Devon Energy is a leading oil and gas producer in the U.S. with a premier multi-basin portfolio headlined by a world-class acreage position in the Delaware Basin. Devon’s disciplined cash-return business model is designed to achieve strong returns, generate free cash flow and return capital to shareholders, while focusing on safe and sustainable operations. For more information, please visit www.devonenergy.com.

Investor Contacts	  	Media Contact	
Scott Coody, 405-552-4735	  	Lisa Adams, 405-228-1732	
Chris Carr, 405-228-2496	  		
NON-GAAP DISCLOSURES
This press 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 and in the related Form 10-Q filed with the SEC.
FORWARD LOOKING STATEMENTS
This communication includes “forward-looking statements” within the meaning of the federal securities laws. 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
 
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communication 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 and adversely from our expectations due to a number of factors, including, but not limited to: the volatility of oil, gas and NGL prices; risks relating to the COVID-19 pandemic or other future pandemics; uncertainties inherent in estimating oil, gas and NGL reserves; the extent to which we are successful in acquiring and discovering additional reserves; the uncertainties, costs and risks involved in our operations, including as a result of employee misconduct; regulatory restrictions, compliance costs and other risks relating to governmental regulation, including with respect to environmental matters; risks related to regulatory, social and market efforts to address climate change; risks related to our hedging activities; counterparty credit risks; risks relating to our indebtedness; cyberattack risks; our limited control over third parties who operate some of our oil and gas properties; midstream capacity constraints and potential interruptions in production; the extent to which insurance covers any losses we may experience; competition for assets, materials, people and capital; risks related to investors attempting to effect change; our ability to successfully complete mergers, acquisitions and divestitures; risks related to the recent merger with WPX, including the risk that we may not realize the anticipated benefits of the merger or successfully integrate the two legacy businesses; and any of the other risks and uncertainties discussed in Devon’s 2020 Annual Report on Form 10-K (the “2020 Form 10-K”) or other SEC filings. The forward-looking statements included in this communication speak only as of the date of this communication, represent current reasonable management’s expectations as of the date of this communication and are subject to the risks and uncertainties identified above as well as those described in the 2020 Form 10-K and in other documents we file from time to time with the SEC. We cannot guarantee the accuracy of our forward-looking statements, and readers are urged to carefully review and consider the various disclosures made in the 2020 Form 10-K and in other documents we file from time to time with the SEC. All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements above. We do not undertake, and expressly disclaim, any duty to update or revise our forward-looking statements based on new information, future events or otherwise.
 
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Exhibit 99.2

Devon Energy Third-Quarter 2021
Supplemental Tables

TABLE OF CONTENTS:	  	PAGE:	 	
		
Income Statement	  	 	2	 	
		
Supplemental Information for Income Statement	  	 	3	 	
		
Cash Flow Statement	  	 	4	 	
		
Balance Sheet	  	 	5	 	
		
Production by Asset	  	 	6	 	
		
Capital and Well Activity by Asset	  	 	7	 	
		
Realized Price by Asset	  	 	8	 	
		
Per-Unit Cash Margin by Asset	  	 	9	 	
		
Non-GAAP Core Earnings (Loss), Non-GAAP EBITDAX and Net Debt	  	 	10	 	
		
Net Debt-to-EBITDAX, Free Cash Flow, Reinvestment Rate and Variable Dividend	  	 	11	 	
 
1

 
CONSOLIDATED STATEMENTS OF EARNINGS

																					
(in millions, except per share amounts)	  	2021	 	 	2020	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Oil, gas and NGL sales	  	$	2,635	 	 	$	2,154	 	 	$	1,757	 	 	$	786	 	 	$	678	 	
Oil, gas and NGL derivatives (1)	  	 	(335	) 	 	 	(703	) 	 	 	(528	) 	 	 	(117	) 	 	 	(87	) 	
Marketing and midstream revenues	  	 	1,166	 	 	 	966	 	 	 	821	 	 	 	611	 	 	 	476	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total revenues	  	 	3,466	 	 	 	2,417	 	 	 	2,050	 	 	 	1,280	 	 	 	1,067	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Production expenses (2)	  	 	555	 	 	 	513	 	 	 	458	 	 	 	271	 	 	 	271	 	
Exploration expenses	  	 	3	 	 	 	3	 	 	 	3	 	 	 	4	 	 	 	39	 	
Marketing and midstream expenses	  	 	1,165	 	 	 	965	 	 	 	842	 	 	 	618	 	 	 	478	 	
Depreciation, depletion and amortization	  	 	578	 	 	 	536	 	 	 	467	 	 	 	301	 	 	 	299	 	
Asset impairments	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	27	 	 	 	—  	 	
Asset dispositions	  	 	—  	 	 	 	(87	) 	 	 	(32	) 	 	 	(1	) 	 	 	—  	 	
General and administrative expenses	  	 	95	 	 	 	94	 	 	 	107	 	 	 	82	 	 	 	75	 	
Financing costs, net (3)	  	 	86	 	 	 	80	 	 	 	77	 	 	 	70	 	 	 	66	 	
Restructuring and transaction costs	  	 	18	 	 	 	23	 	 	 	189	 	 	 	17	 	 	 	32	 	
Other, net	  	 	2	 	 	 	(14	) 	 	 	(29	) 	 	 	1	 	 	 	—  	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total expenses	  	 	2,502	 	 	 	2,113	 	 	 	2,082	 	 	 	1,390	 	 	 	1,260	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings (loss) from continuing operations before income taxes	  	 	964	 	 	 	304	 	 	 	(32	) 	 	 	(110	) 	 	 	(193	) 	
Income tax expense (benefit)	  	 	120	 	 	 	43	 	 	 	(248	) 	 	 	(37	) 	 	 	(90	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss) from continuing operations	  	 	844	 	 	 	261	 	 	 	216	 	 	 	(73	) 	 	 	(103	) 	
Net earnings (loss) from discontinued operations, net of taxes	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	(25	) 	 	 	13	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss)	  	 	844	 	 	 	261	 	 	 	216	 	 	 	(98	) 	 	 	(90	) 	
Net earnings attributable to noncontrolling interests	  	 	6	 	 	 	5	 	 	 	3	 	 	 	4	 	 	 	2	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net earnings (loss) attributable to Devon	  	$	838	 	 	$	256	 	 	$	213	 	 	$	(102	) 	 	$	(92	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic net earnings (loss) per share:	  				 				 				 				 				
Continuing operations	  	$	1.24	 	 	$	0.38	 	 	$	0.33	 	 	$	(0.20	) 	 	$	(0.29	) 	
Discontinued operations	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	(0.07	) 	 	 	0.04	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic net earnings (loss) per share	  	$	1.24	 	 	$	0.38	 	 	$	0.33	 	 	$	(0.27	) 	 	$	(0.25	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted net earnings (loss) per share:	  				 				 				 				 				
Continuing operations	  	$	1.24	 	 	$	0.38	 	 	$	0.32	 	 	$	(0.20	) 	 	$	(0.29	) 	
Discontinued operations	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	(0.07	) 	 	 	0.04	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Diluted net earnings (loss) per share	  	$	1.24	 	 	$	0.38	 	 	$	0.32	 	 	$	(0.27	) 	 	$	(0.25	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Weighted average common shares outstanding:	  				 				 				 				 				
Basic	  	 	677	 	 	 	677	 	 	 	654	 	 	 	383	 	 	 	383	 	
Diluted	  	 	679	 	 	 	679	 	 	 	656	 	 	 	383	 	 	 	383	 	
 
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SUPPLEMENTAL INFORMATION FOR CONSLIDATED STATEMENTS OF EARNINGS

																					
(1) OIL, GAS AND NGL DERIVATIVES	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
(in millions)	  	2021	 	 	2020	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Derivative cash settlements	  	$	(370	) 	 	$	(367	) 	 	$	(232	) 	 	$	(27	) 	 	$	10	 	
Derivative valuation changes	  	 	35	 	 	 	(336	) 	 	 	(296	) 	 	 	(90	) 	 	 	(97	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil, gas and NGL derivatives	  	$	(335	) 	 	$	(703	) 	 	$	(528	) 	 	$	(117	) 	 	$	(87	) 	

																					
(2) PRODUCTION EXPENSES	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
(in millions)	  	2021	 	  	2020	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
Lease operating expense	  	$	215	 	  	$	210	 	  	$	199	 	  	$	91	 	  	$	100	 	
Gathering, processing & transportation	  	 	157	 	  	 	147	 	  	 	129	 	  	 	130	 	  	 	125	 	
Production taxes	  	 	176	 	  	 	143	 	  	 	117	 	  	 	47	 	  	 	42	 	
Property taxes	  	 	7	 	  	 	13	 	  	 	13	 	  	 	3	 	  	 	4	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Production expenses	  	$	555	 	  	$	513	 	  	$	458	 	  	$	271	 	  	$	271	 	

																					
(3) FINANCING COSTS, NET	  	 	 	 	 	 	 	 	 	 	 	 	  	 	 	
(in millions)	  	2021	 	 	2020	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	  	Quarter 3	 	
Interest based on outstanding debt	  	$	93	 	 	$	98	 	 	$	105	 	 	$	65	 	  	$	65	 	
Gain on early retirement of debt	  	 	—  	 	 	 	(10	) 	 	 	(20	) 	 	 	—  	 	  	 	—  	 	
Interest income	  	 	(1	) 	 	 	—  	 	 	 	(1	) 	 	 	—  	 	  	 	(5	) 	
Other	  	 	(6	) 	 	 	(8	) 	 	 	(7	) 	 	 	5	 	  	 	6	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	  	 	 	 	
Financing costs, net	  	$	86	 	 	$	80	 	 	$	77	 	 	$	70	 	  	$	66	 	

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CONSOLIDATED STATEMENTS OF CASH FLOWS

																					
(in millions)	  	2021	 	 	2020	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
Cash flows from operating activities:	  				 				 				 				 				
Net earnings (loss)	  	$	844	 	 	$	261	 	 	$	216	 	 	$	(98	) 	 	$	(90	) 	
Adjustments to reconcile net earnings (loss) to net cash from operating activities:	  				 				 				 				 				
Net (earnings) loss from discontinued operations, net of income taxes	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	25	 	 	 	(13	) 	
Depreciation, depletion and amortization	  	 	578	 	 	 	536	 	 	 	467	 	 	 	301	 	 	 	299	 	
Asset impairments	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	27	 	 	 	—  	 	
Leasehold impairments	  	 	1	 	 	 	1	 	 	 	1	 	 	 	3	 	 	 	36	 	
(Amortization) accretion of liabilities	  	 	(7	) 	 	 	(7	) 	 	 	(7	) 	 	 	8	 	 	 	8	 	
Total losses on commodity derivatives	  	 	335	 	 	 	703	 	 	 	528	 	 	 	117	 	 	 	87	 	
Cash settlements on commodity derivatives	  	 	(370	) 	 	 	(367	) 	 	 	(232	) 	 	 	(27	) 	 	 	10	 	
Gains on asset dispositions	  	 	—  	 	 	 	(87	) 	 	 	(32	) 	 	 	(1	) 	 	 	—  	 	
Deferred income tax expense (benefit)	  	 	119	 	 	 	24	 	 	 	(243	) 	 	 	(17	) 	 	 	—  	 	
Share-based compensation	  	 	19	 	 	 	20	 	 	 	41	 	 	 	18	 	 	 	31	 	
Early retirement of debt	  	 	—  	 	 	 	(10	) 	 	 	(20	) 	 	 	—  	 	 	 	—  	 	
Other	  	 	11	 	 	 	2	 	 	 	—  	 	 	 	—  	 	 	 	1	 	
Changes in assets and liabilities, net	  	 	68	 	 	 	17	 	 	 	(127	) 	 	 	2	 	 	 	58	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash from operating activities—continuing operations	  	 	1,598	 	 	 	1,093	 	 	 	592	 	 	 	358	 	 	 	427	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from investing activities:	  				 				 				 				 				
Capital expenditures	  	 	(474	) 	 	 	(504	) 	 	 	(499	) 	 	 	(217	) 	 	 	(204	) 	
Acquisitions of property and equipment	  	 	(10	) 	 	 	(5	) 	 	 	—  	 	 	 	(3	) 	 	 	—  	 	
Divestitures of property and equipment	  	 	1	 	 	 	49	 	 	 	15	 	 	 	5	 	 	 	1	 	
WPX acquired cash	  	 	—  	 	 	 	—  	 	 	 	344	 	 	 	—  	 	 	 	—  	 	
Distributions from equity method investments	  	 	9	 	 	 	8	 	 	 	10	 	 	 	—  	 	 	 	—  	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash from investing activities—continuing operations	  	 	(474	) 	 	 	(452	) 	 	 	(130	) 	 	 	(215	) 	 	 	(203	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from financing activities:	  				 				 				 				 				
Repayments of long-term debt	  	 	—  	 	 	 	(710	) 	 	 	(533	) 	 	 	—  	 	 	 	—  	 	
Early retirement of debt	  	 	—  	 	 	 	(32	) 	 	 	(27	) 	 	 	—  	 	 	 	—  	 	
Dividends paid on common stock	  	 	(329	) 	 	 	(229	) 	 	 	(203	) 	 	 	(138	) 	 	 	(43	) 	
Contributions from noncontrolling interests	  	 	1	 	 	 	3	 	 	 	—  	 	 	 	9	 	 	 	1	 	
Distributions to noncontrolling interests	  	 	(6	) 	 	 	(5	) 	 	 	(4	) 	 	 	(4	) 	 	 	(4	) 	
Acquisition of noncontrolling interests	  	 	—  	 	 	 	—  	 	 	 	(24	) 	 	 	—  	 	 	 	—  	 	
Shares exchanged for tax withholdings and other	  	 	(3	) 	 	 	(9	) 	 	 	(33	) 	 	 	(1	) 	 	 	—  	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net cash from financing activities—continuing operations	  	 	(337	) 	 	 	(982	) 	 	 	(824	) 	 	 	(134	) 	 	 	(46	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Effect of exchange rate changes on cash—continuing	  	 	(5	) 	 	 	2	 	 	 	3	 	 	 	—  	 	 	 	—  	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash of continuing operations	  	 	782	 	 	 	(339	) 	 	 	(359	) 	 	 	9	 	 	 	178	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash flows from discontinued operations:	  				 				 				 				 				
Operating activities	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	19	 	 	 	45	 	
Investing activities	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	310	 	 	 	1	 	
Effect of exchange rate changes on cash	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	2	 	 	 	4	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash of discontinued operations	  	 	—  	 	 	 	—  	 	 	 	—  	 	 	 	331	 	 	 	50	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net change in cash, cash equivalents and restricted cash	  	 	782	 	 	 	(339	) 	 	 	(359	) 	 	 	340	 	 	 	228	 	
Cash, cash equivalents and restricted cash at beginning of period	  	 	1,539	 	 	 	1,878	 	 	 	2,237	 	 	 	1,897	 	 	 	1,669	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Cash, cash equivalents and restricted cash at end of period	  	$	2,321	 	 	$	1,539	 	 	$	1,878	 	 	$	2,237	 	 	$	1,897	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reconciliation of cash, cash equivalents and restricted cash:	  				 				 				 				 				
Cash and cash equivalents	  	$	2,144	 	 	$	1,348	 	 	$	1,683	 	 	$	2,047	 	 	$	1,707	 	
Restricted cash	  	 	177	 	 	 	191	 	 	 	195	 	 	 	190	 	 	 	190	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total cash, cash equivalents and restricted cash	  	$	2,321	 	 	$	1,539	 	 	$	1,878	 	 	$	2,237	 	 	$	1,897	 	

4

 
CONSOLIDATED BALANCE SHEETS

									
(in millions)	  	September 30,
2021	 	 	December 31,
2020	 	
Current assets:	  				 				
Cash, cash equivalents and restricted cash	  	$	2,321	 	 	$	2,237	 	
Accounts receivable	  	 	1,517	 	 	 	601	 	
Income tax receivable	  	 	80	 	 	 	174	 	
Other current assets	  	 	309	 	 	 	248	 	
	  	 	 	 	 	 	 	 	
Total current assets	  	 	4,227	 	 	 	3,260	 	
Oil and gas property and equipment, based on successful efforts accounting, net	  	 	13,613	 	 	 	4,436	 	
Other property and equipment, net	  	 	1,465	 	 	 	957	 	
	  	 	 	 	 	 	 	 	
Total property and equipment, net	  	 	15,078	 	 	 	5,393	 	
Goodwill	  	 	753	 	 	 	753	 	
Right-of-use assets	  	 	244	 	 	 	223	 	
Investments	  	 	388	 	 	 	12	 	
Other long-term assets	  	 	367	 	 	 	271	 	
	  	 	 	 	 	 	 	 	
Total assets	  	$	21,057	 	 	$	9,912	 	
	  	 	 	 	 	 	 	 	
Current liabilities:	  				 				
Accounts payable	  	$	537	 	 	$	242	 	
Revenues and royalties payable	  	 	1,443	 	 	 	662	 	
Other current liabilities	  	 	1,525	 	 	 	536	 	
	  	 	 	 	 	 	 	 	
Total current liabilities	  	 	3,505	 	 	 	1,440	 	
Long-term debt	  	 	6,492	 	 	 	4,298	 	
Lease liabilities	  	 	256	 	 	 	246	 	
Asset retirement obligations	  	 	462	 	 	 	358	 	
Other long-term liabilities	  	 	1,281	 	 	 	551	 	
Stockholders’ equity:	  				 				
Common stock	  	 	68	 	 	 	38	 	
Additional paid-in capital	  	 	8,206	 	 	 	2,766	 	
Retained earnings	  	 	750	 	 	 	208	 	
Accumulated other comprehensive loss	  	 	(100	) 	 	 	(127	) 	
	  	 	 	 	 	 	 	 	
Total stockholders’ equity attributable to Devon	  	 	8,924	 	 	 	2,885	 	
Noncontrolling interests	  	 	137	 	 	 	134	 	
	  	 	 	 	 	 	 	 	
Total equity	  	 	9,061	 	 	 	3,019	 	
	  	 	 	 	 	 	 	 	
Total liabilities and equity	  	$	21,057	 	 	$	9,912	 	
	  	 	 	 	 	 	 	 	
Common shares outstanding	  	 	677	 	 	 	382	 	
 
5

 
PRODUCTION TREND

																					
 	  	2021	 	  	2020	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
Oil (MBbls/d)	  				  				  				  				  				
Delaware Basin	  	 	213	 	  	 	191	 	  	 	172	 	  	 	99	 	  	 	77	 	
Anadarko Basin	  	 	14	 	  	 	17	 	  	 	13	 	  	 	16	 	  	 	19	 	
Williston Basin	  	 	39	 	  	 	46	 	  	 	44	 	  	 	—  	 	  	 	—  	 	
Eagle Ford	  	 	20	 	  	 	18	 	  	 	16	 	  	 	18	 	  	 	22	 	
Powder River Basin	  	 	14	 	  	 	16	 	  	 	17	 	  	 	16	 	  	 	21	 	
Other	  	 	3	 	  	 	3	 	  	 	6	 	  	 	7	 	  	 	7	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	303	 	  	 	291	 	  	 	268	 	  	 	156	 	  	 	146	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Natural gas liquids (MBbls/d)	  				  				  				  				  				
Delaware Basin	  	 	100	 	  	 	82	 	  	 	60	 	  	 	43	 	  	 	38	 	
Anadarko Basin	  	 	25	 	  	 	26	 	  	 	21	 	  	 	25	 	  	 	30	 	
Williston Basin	  	 	9	 	  	 	9	 	  	 	8	 	  	 	—  	 	  	 	—  	 	
Eagle Ford	  	 	11	 	  	 	9	 	  	 	6	 	  	 	9	 	  	 	11	 	
Powder River Basin	  	 	3	 	  	 	3	 	  	 	3	 	  	 	3	 	  	 	3	 	
Other	  	 	—  	 	  	 	—  	 	  	 	1	 	  	 	—  	 	  	 	1	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	148	 	  	 	129	 	  	 	99	 	  	 	80	 	  	 	83	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Gas (MMcf/d)	  				  				  				  				  				
Delaware Basin	  	 	578	 	  	 	513	 	  	 	471	 	  	 	267	 	  	 	239	 	
Anadarko Basin	  	 	219	 	  	 	225	 	  	 	200	 	  	 	233	 	  	 	242	 	
Williston Basin	  	 	59	 	  	 	61	 	  	 	49	 	  	 	—  	 	  	 	—  	 	
Eagle Ford	  	 	67	 	  	 	59	 	  	 	47	 	  	 	60	 	  	 	73	 	
Powder River Basin	  	 	19	 	  	 	21	 	  	 	21	 	  	 	22	 	  	 	23	 	
Other	  	 	1	 	  	 	2	 	  	 	3	 	  	 	2	 	  	 	3	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	943	 	  	 	881	 	  	 	791	 	  	 	584	 	  	 	580	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  				  				  				  				  				
Delaware Basin	  	 	409	 	  	 	358	 	  	 	310	 	  	 	186	 	  	 	155	 	
Anadarko Basin	  	 	75	 	  	 	80	 	  	 	68	 	  	 	81	 	  	 	89	 	
Williston Basin	  	 	58	 	  	 	66	 	  	 	61	 	  	 	—  	 	  	 	—  	 	
Eagle Ford	  	 	42	 	  	 	37	 	  	 	30	 	  	 	37	 	  	 	46	 	
Powder River Basin	  	 	20	 	  	 	22	 	  	 	23	 	  	 	22	 	  	 	28	 	
Other	  	 	4	 	  	 	4	 	  	 	7	 	  	 	7	 	  	 	8	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	608	 	  	 	567	 	  	 	499	 	  	 	333	 	  	 	326	 	

6

 
CAPITAL EXPENDITURES

																					
(in millions)	  	2021	 	  	2020	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
Delaware Basin	  	$	363	 	  	$	394	 	  	$	355	 	  	$	153	 	  	$	179	 	
Anadarko Basin	  	 	15	 	  	 	11	 	  	 	13	 	  	 	3	 	  	 	1	 	
Williston Basin	  	 	13	 	  	 	19	 	  	 	20	 	  	 	—  	 	  	 	—  	 	
Eagle Ford	  	 	34	 	  	 	36	 	  	 	29	 	  	 	2	 	  	 	1	 	
Powder River Basin	  	 	15	 	  	 	5	 	  	 	27	 	  	 	22	 	  	 	11	 	
Other	  	 	2	 	  	 	2	 	  	 	3	 	  	 	3	 	  	 	3	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total upstream capital	  	$	442	 	  	$	467	 	  	$	447	 	  	$	183	 	  	$	195	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Midstream	  	 	11	 	  	 	22	 	  	 	24	 	  	 	3	 	  	 	7	 	
Other	  	 	28	 	  	 	20	 	  	 	16	 	  	 	3	 	  	 	5	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total capital	  	$	481	 	  	$	509	 	  	$	487	 	  	$	189	 	  	$	207	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
SUPPLEMENTAL INFORMATION FOR UPSTREAM CAPITAL EXPENDITURES

																					
GROSS OPERATED SPUDS	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
 	  	2021	 	  	2020	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
Delaware Basin	  	 	50	 	  	 	55	 	  	 	60	 	  	 	21	 	  	 	35	 	
Anadarko Basin	  	 	9	 	  	 	8	 	  	 	8	 	  	 	—  	 	  	 	—  	 	
Williston Basin	  	 	—  	 	  	 	—  	 	  	 	7	 	  	 	—  	 	  	 	—  	 	
Eagle Ford	  	 	10	 	  	 	11	 	  	 	14	 	  	 	—  	 	  	 	—  	 	
Powder River Basin	  	 	9	 	  	 	1	 	  	 	—  	 	  	 	2	 	  	 	—  	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	78	 	  	 	75	 	  	 	89	 	  	 	23	 	  	 	35	 	

																					
GROSS OPERATED WELLS TIED-IN	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
 	  	2021	 	  	2020	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
Delaware Basin	  	 	52	 	  	 	88	 	  	 	52	 	  	 	23	 	  	 	32	 	
Anadarko Basin	  	 	4	 	  	 	6	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	
Williston Basin	  	 	4	 	  	 	13	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	
Eagle Ford	  	 	19	 	  	 	9	 	  	 	12	 	  	 	—  	 	  	 	—  	 	
Powder River Basin	  	 	2	 	  	 	—  	 	  	 	10	 	  	 	2	 	  	 	9	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	81	 	  	 	116	 	  	 	74	 	  	 	25	 	  	 	41	 	

																					
AVERAGE LATERAL LENGTH	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
(based on wells tied-in)	  	2021	 	  	2020	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
Delaware Basin	  	 	9,700’	 	  	 	10,000’	 	  	 	10,000’	 	  	 	9,800’	 	  	 	9,900’	 	
Anadarko Basin	  	 	9,200’	 	  	 	9,600’	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	
Williston Basin	  	 	9,600’	 	  	 	10,000’	 	  	 	—  	 	  	 	—  	 	  	 	—  	 	
Eagle Ford	  	 	6,300’	 	  	 	5,600’	 	  	 	4,400’	 	  	 	—  	 	  	 	—  	 	
Powder River Basin	  	 	10,500’	 	  	 	—  	 	  	 	9,800’	 	  	 	13,600’	 	  	 	9,800’	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Total	  	 	8,900’	 	  	 	9,600’	 	  	 	9,100’	 	  	 	10,100’	 	  	 	9,900’	 	

7

 
REALIZED PRICING

																					
BENCHMARK PRICES	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
(average prices)	  	2021	 	  	2020	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
Oil ($/Bbl) - West Texas Intermediate (Cushing)	  	$	70.64	 	  	$	66.04	 	  	$	57.87	 	  	$	42.65	 	  	$	40.86	 	
Natural Gas ($/Mcf) - Henry Hub	  	$	4.02	 	  	$	2.83	 	  	$	2.71	 	  	$	2.67	 	  	$	1.98	 	
NGL ($/Bbl) - Mont Belvieu Blended	  	$	36.85	 	  	$	28.54	 	  	$	25.81	 	  	$	20.01	 	  	$	16.69	 	

REALIZED PRICES	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	  	2021	 	 	2020	 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Oil (Per Bbl)	  				 				 				 				 				
Delaware Basin	  	$	68.44	 	 	$	63.93	 	 	$	56.07	 	 	$	40.67	 	 	$	39.19	 	
Anadarko Basin	  	 	69.11	 	 	 	63.51	 	 	 	55.86	 	 	 	40.34	 	 	 	37.88	 	
Williston Basin	  	 	66.60	 	 	 	62.00	 	 	 	52.74	 	 	 	—  	 	 	 	—  	 	
Eagle Ford	  	 	68.32	 	 	 	64.04	 	 	 	54.90	 	 	 	37.83	 	 	 	33.68	 	
Powder River Basin	  	 	65.81	 	 	 	62.36	 	 	 	53.77	 	 	 	36.42	 	 	 	35.39	 	
Other	  	 	75.68	 	 	 	72.85	 	 	 	55.65	 	 	 	39.93	 	 	 	37.33	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	 	68.19	 	 	 	63.63	 	 	 	55.28	 	 	 	39.84	 	 	 	37.56	 	
Cash settlements	  	 	(10.60	) 	 	 	(13.29	) 	 	 	(9.13	) 	 	 	(1.83	) 	 	 	0.65	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	57.59	 	 	$	50.34	 	 	$	46.15	 	 	$	38.01	 	 	$	38.21	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Natural gas liquids (Per Bbl)	  				 				 				 				 				
Delaware Basin	  	$	31.34	 	 	$	23.81	 	 	$	26.25	 	 	$	13.67	 	 	$	11.49	 	
Anadarko Basin	  	 	33.20	 	 	 	25.55	 	 	 	23.14	 	 	 	15.65	 	 	 	12.68	 	
Williston Basin	  	 	19.36	 	 	 	14.76	 	 	 	18.51	 	 	 	—  	 	 	 	—  	 	
Eagle Ford	  	 	32.80	 	 	 	25.46	 	 	 	24.44	 	 	 	15.66	 	 	 	13.74	 	
Powder River Basin	  	 	40.66	 	 	 	35.46	 	 	 	30.19	 	 	 	19.39	 	 	 	13.10	 	
Other	  	 	54.51	 	 	 	41.19	 	 	 	31.86	 	 	 	24.24	 	 	 	21.74	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	 	31.25	 	 	 	23.89	 	 	 	25.01	 	 	 	14.77	 	 	 	12.36	 	
Cash settlements	  	 	(0.45	) 	 	 	(0.25	) 	 	 	(0.20	) 	 	 	(0.01	) 	 	 	(0.30	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	30.80	 	 	$	23.64	 	 	$	24.81	 	 	$	14.76	 	 	$	12.06	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Gas (Per Mcf)	  				 				 				 				 				
Delaware Basin	  	$	3.58	 	 	$	2.31	 	 	$	3.19	 	 	$	1.51	 	 	$	1.11	 	
Anadarko Basin	  	 	4.05	 	 	 	3.15	 	 	 	2.49	 	 	 	2.29	 	 	 	1.66	 	
Williston Basin	  	 	0.65	 	 	 	(1.60	) 	 	 	(0.48	) 	 	 	—  	 	 	 	—  	 	
Eagle Ford	  	 	4.08	 	 	 	3.25	 	 	 	3.15	 	 	 	2.38	 	 	 	1.95	 	
Powder River Basin	  	 	4.15	 	 	 	3.54	 	 	 	5.27	 	 	 	2.70	 	 	 	1.94	 	
Other	  	 	2.60	 	 	 	2.74	 	 	 	2.57	 	 	 	2.87	 	 	 	1.52	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	 	3.55	 	 	 	2.35	 	 	 	2.84	 	 	 	1.96	 	 	 	1.48	 	
Cash settlements	  	 	(0.78	) 	 	 	(0.15	) 	 	 	(0.15	) 	 	 	0.00	 	 	 	0.06	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	2.77	 	 	$	2.20	 	 	$	2.69	 	 	$	1.96	 	 	$	1.54	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total oil equivalent (Per Boe)	  				 				 				 				 				
Delaware Basin	  	$	48.29	 	 	$	42.84	 	 	$	40.95	 	 	$	26.94	 	 	$	24.00	 	
Anadarko Basin	  	 	35.62	 	 	 	30.34	 	 	 	25.35	 	 	 	19.79	 	 	 	16.81	 	
Williston Basin	  	 	48.55	 	 	 	43.98	 	 	 	40.79	 	 	 	—  	 	 	 	—  	 	
Eagle Ford	  	 	47.40	 	 	 	42.84	 	 	 	38.90	 	 	 	25.97	 	 	 	22.78	 	
Powder River Basin	  	 	55.93	 	 	 	52.55	 	 	 	47.58	 	 	 	31.08	 	 	 	29.83	 	
Other	  	 	70.49	 	 	 	65.37	 	 	 	50.58	 	 	 	37.67	 	 	 	34.15	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price without hedges	  	 	47.08	 	 	 	41.75	 	 	 	39.14	 	 	 	25.63	 	 	 	22.60	 	
Cash settlements	  	 	(6.60	) 	 	 	(7.11	) 	 	 	(5.17	) 	 	 	(0.86	) 	 	 	0.33	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Realized price, including cash settlements	  	$	40.48	 	 	$	34.64	 	 	$	33.97	 	 	$	24.77	 	 	$	22.93	 	

8

 
ASSET MARGINS

																					
BENCHMARK PRICES	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
(average prices)	  	2021	 	  	2020	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
 	  	Quarter 3	 	  	Quarter 2	 	  	Quarter 1	 	  	Quarter 4	 	  	Quarter 3	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	  	 	 	
Oil ($/Bbl) - West Texas Intermediate (Cushing)	  	$	70.64	 	  	$	66.04	 	  	$	57.87	 	  	$	42.65	 	  	$	40.86	 	
Natural Gas ($/Mcf) - Henry Hub	  	$	4.02	 	  	$	2.83	 	  	$	2.71	 	  	$	2.67	 	  	$	1.98	 	
NGL ($/Bbl) - Mont Belvieu Blended	  	$	36.85	 	  	$	28.54	 	  	$	25.81	 	  	$	20.01	 	  	$	16.69	 	

PER-UNIT CASH MARGIN BY ASSET (per Boe)	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	  	2021	 	 	2020	 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	  	Quarter 3	 	 	Quarter 2	 	 	Quarter 1	 	 	Quarter 4	 	 	Quarter 3	 	
 	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Delaware Basin	  				 				 				 				 				
Realized price	  	$	48.29	 	 	$	42.84	 	 	$	40.95	 	 	$	26.94	 	 	$	24.00	 	
Lease operating expenses	  	 	(3.52	) 	 	 	(3.91	) 	 	 	(3.97	) 	 	 	(2.38	) 	 	 	(3.00	) 	
Gathering, processing & transportation	  	 	(2.18	) 	 	 	(2.06	) 	 	 	(1.96	) 	 	 	(2.40	) 	 	 	(2.68	) 	
Production & property taxes	  	 	(3.31	) 	 	 	(3.08	) 	 	 	(2.95	) 	 	 	(2.08	) 	 	 	(1.80	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	39.28	 	 	$	33.79	 	 	$	32.07	 	 	$	20.08	 	 	$	16.52	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Anadarko Basin	  				 				 				 				 				
Realized price	  	$	35.62	 	 	$	30.34	 	 	$	25.35	 	 	$	19.79	 	 	$	16.81	 	
Lease operating expenses	  	 	(2.58	) 	 	 	(2.96	) 	 	 	(3.82	) 	 	 	(2.57	) 	 	 	(2.16	) 	
Gathering, processing & transportation	  	 	(6.14	) 	 	 	(6.06	) 	 	 	(6.31	) 	 	 	(8.39	) 	 	 	(7.39	) 	
Production & property taxes	  	 	(1.70	) 	 	 	(1.46	) 	 	 	(1.21	) 	 	 	(0.55	) 	 	 	(0.54	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	25.20	 	 	$	19.86	 	 	$	14.01	 	 	$	8.28	 	 	$	6.72	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Williston Basin	  				 				 				 				 				
Realized price	  	$	48.55	 	 	$	43.98	 	 	$	40.79	 	 	$	—  	 	 	$	—  	 	
Lease operating expenses	  	 	(5.83	) 	 	 	(4.87	) 	 	 	(5.13	) 	 	 	—  	 	 	 	—  	 	
Gathering, processing & transportation	  	 	(2.13	) 	 	 	(1.86	) 	 	 	(2.14	) 	 	 	—  	 	 	 	—  	 	
Production & property taxes	  	 	(4.47	) 	 	 	(4.27	) 	 	 	(3.82	) 	 	 	—  	 	 	 	—  	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	36.12	 	 	$	32.98	 	 	$	29.70	 	 	$	—  	 	 	$	—  	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Eagle Ford	  				 				 				 				 				
Realized price	  	$	47.40	 	 	$	42.84	 	 	$	38.90	 	 	$	25.97	 	 	$	22.78	 	
Lease operating expenses	  	 	(3.43	) 	 	 	(3.47	) 	 	 	(3.89	) 	 	 	(2.79	) 	 	 	(2.47	) 	
Gathering, processing & transportation	  	 	(4.17	) 	 	 	(5.56	) 	 	 	(6.73	) 	 	 	(5.89	) 	 	 	(4.73	) 	
Production & property taxes	  	 	(1.99	) 	 	 	(1.93	) 	 	 	(1.71	) 	 	 	(0.16	) 	 	 	(0.92	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	37.81	 	 	$	31.88	 	 	$	26.57	 	 	$	17.13	 	 	$	14.66	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Powder River Basin	  				 				 				 				 				
Realized price	  	$	55.93	 	 	$	52.55	 	 	$	47.58	 	 	$	31.08	 	 	$	29.83	 	
Lease operating expenses	  	 	(8.09	) 	 	 	(6.65	) 	 	 	(7.45	) 	 	 	(5.47	) 	 	 	(5.41	) 	
Gathering, processing & transportation	  	 	(2.93	) 	 	 	(3.02	) 	 	 	(2.66	) 	 	 	(3.01	) 	 	 	(2.30	) 	
Production & property taxes	  	 	(6.73	) 	 	 	(6.10	) 	 	 	(5.48	) 	 	 	(3.91	) 	 	 	(3.49	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	38.18	 	 	$	36.78	 	 	$	31.99	 	 	$	18.69	 	 	$	18.63	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Other	  				 				 				 				 				
Realized price	  	$	70.49	 	 	$	65.37	 	 	$	50.58	 	 	$	37.67	 	 	$	34.15	 	
Lease operating expenses	  	 	(16.42	) 	 	 	(16.69	) 	 	 	(17.15	) 	 	 	(15.35	) 	 	 	(19.92	) 	
Gathering, processing & transportation	  	 	(0.35	) 	 	 	(0.58	) 	 	 	(0.62	) 	 	 	(0.59	) 	 	 	(0.51	) 	
Production & property taxes	  	 	(4.19	) 	 	 	(5.25	) 	 	 	(4.60	) 	 	 	(3.38	) 	 	 	(3.62	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	49.53	 	 	$	42.85	 	 	$	28.21	 	 	$	18.35	 	 	$	10.10	 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Devon - Total	  				 				 				 				 				
Realized price	  	$	47.08	 	 	$	41.75	 	 	$	39.14	 	 	$	25.63	 	 	$	22.60	 	
Lease operating expenses	  	 	(3.85	) 	 	 	(4.06	) 	 	 	(4.44	) 	 	 	(2.97	) 	 	 	(3.32	) 	
Gathering, processing & transportation	  	 	(2.81	) 	 	 	(2.85	) 	 	 	(2.87	) 	 	 	(4.23	) 	 	 	(4.17	) 	
Production & property taxes	  	 	(3.25	) 	 	 	(3.05	) 	 	 	(2.88	) 	 	 	(1.66	) 	 	 	(1.52	) 	
	  	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Field-level cash margin	  	$	37.17	 	 	$	31.79	 	 	$	28.95	 	 	$	16.77	 	 	$	13.59	 	

9

 
NON-GAAP MEASURES
 
(all monetary values in millions, except per share amounts)
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 (loss) and core earnings (loss) 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 2021 earnings.

 	  	Quarter Ended September 30, 2021	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	
 	  	Before-tax	 	  	After-tax	 	  	After
Noncontrolling
Interests	 	  	Per
Diluted
Share	 	
 	  	 	 	  	 	 	  	 	 	  	 	 	
Total	  				  				  				  				
Earnings (GAAP)	  	$	964	 	  	$	844	 	  	$	838	 	  	$	1.24	 	
Adjustments:	  				  				  				  				
Asset and exploration impairments	  	 	1	 	  	 	1	 	  	 	1	 	  	 	0.00	 	
Deferred tax asset valuation allowance	  	 	—  	 	  	 	(101	) 	  	 	(101	) 	  	 	(0.15	) 	
Fair value changes in financial instruments and foreign currency	  	 	(31	) 	  	 	(23	) 	  	 	(23	) 	  	 	(0.04	) 	
Restructuring and transaction costs	  	 	18	 	  	 	18	 	  	 	18	 	  	 	0.03	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Core earnings (Non-GAAP)	  	$	952	 	  	$	739	 	  	$	733	 	  	$	1.08	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
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.

 	  	YTD ‘21	 	  	Q3 ‘21	 	  	Q2 ‘21	 	  	Q1 ‘21	 	
Net earnings (GAAP)	  	$	1,321	 	  	$	844	 	  	$	261	 	  	$	216	 	
Financing costs, net	  	 	243	 	  	 	86	 	  	 	80	 	  	 	77	 	
Income tax expense (benefit)	  	 	(85	) 	  	 	120	 	  	 	43	 	  	 	(248	) 	
Exploration expenses	  	 	9	 	  	 	3	 	  	 	3	 	  	 	3	 	
Depreciation, depletion and amortization	  	 	1,581	 	  	 	578	 	  	 	536	 	  	 	467	 	
Asset dispositions	  	 	(119	) 	  	 	—  	 	  	 	(87	) 	  	 	(32	) 	
Share-based compensation	  	 	58	 	  	 	18	 	  	 	20	 	  	 	20	 	
Derivative and financial instrument non-cash valuation changes	  	 	597	 	  	 	(35	) 	  	 	336	 	  	 	296	 	
Restructuring and transaction costs	  	 	230	 	  	 	18	 	  	 	23	 	  	 	189	 	
Accretion on discounted liabilities and other	  	 	(41	) 	  	 	2	 	  	 	(14	) 	  	 	(29	) 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
EBITDAX (Non-GAAP)	  	$	3,794	 	  	$	1,634	 	  	$	1,201	 	  	$	959	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Annualized EBITDAX (Non-GAAP)	  	$	5,059	 	  				  				  				
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.

 	  	September 30, 2021	 	  	June 30, 2021	 	
Total debt (GAAP)	  	$	6,492	 	  	$	6,502	 	
Less:	  				  				
Cash, cash equivalents and restricted cash	  	 	(2,321	) 	  	 	(1,539	) 	
	  	 	 	 	  	 	 	 	
Net debt (Non-GAAP)	  	$	4,171	 	  	$	4,963	 	

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NET DEBT-TO-EBITDAX
Devon defines net debt-to-EBITDAX as net debt divided by an annualized EBITDAX measure. Due to the merger with WPX closing in the first quarter of 2021, Devon has shown the first nine months of 2021 EBITDAX annualized divided by net debt to show a more meaningful net debt-to-EBITDAX measure. Devon believes this ratio provides information useful to investors in assessing the company’s credit position and debt leverage.

 	  	Quarter Ended
September 30, 2021	 	
Net debt (Non-GAAP)	  	$	4,171	 	
EBITDAX (Sep. 30, 2021 YTD annualized) (Non-GAAP)	  	$	5,059	 	
	  	 	 	 	
Net debt-to-EBITDAX (Non-GAAP)	  	 	0.8	 	
	  	 	 	 	
FREE CASH FLOW AND ADJUSTED FREE CASH FLOW
Devon defines free cash flow as total operating cash flow less capital expenditures, and Devon defines adjusted free cash flow as free cash flow less cash restructuring and transaction costs. Devon believes that free cash flow and adjusted free cash flow provide a useful measure of available cash generated by operating activities for other investing and financing activities.

 	  	Quarter Ended
September 30, 2021	 	  	Quarter Ended
June 30, 2021	 	  	Quarter Ended
March 31, 2021	 	  	Quarter Ended
December 31, 2020	 	
Total operating cash flow (GAAP)	  	$	1,598	 	  	$	1,093	 	  	$	592	 	  	$	358	 	
Less capital expenditures:	  				  				  				  				
Capital expenditures	  	 	(474	) 	  	 	(504	) 	  	 	(499	) 	  	 	(217	) 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Free cash flow (Non-GAAP)	  	 	1,124	 	  	 	589	 	  	 	93	 	  	 	141	 	
Cash restructuring and transaction costs (Non-GAAP)	  	 	14	 	  	 	23	 	  	 	167	 	  	 	17	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
Adjusted free cash flow (Non-GAAP)	  	$	1,138	 	  	$	612	 	  	$	260	 	  	$	158	 	
	  	 	 	 	  	 	 	 	  	 	 	 	  	 	 	 	
REINVESTMENT RATE
Devon defines reinvestment rate as accrued capital expenditures divided by operating cash flow. Devon believes this measure provides useful information to our investors as an indicator of the capital demands of our business relative to the cash flow generated from normal business operations.

 	  	Quarter Ended
September 30, 2021	 	
Capital expenditures (accrued)	  	$	481	 	
Operating cash flow	  	 	1,598	 	
	  	 	 	 	
Reinvestment rate (Non-GAAP)	  	 	30	% 	
	  	 	 	 	
VARIABLE DIVIDEND CALCULATION
Devon may pay a variable dividend up to 50 percent of its excess cash flow. Each quarter’s excess cash flow is computed as adjusted cash flow less capital expenditures and the fixed dividend.

 	  	Quarter Ended
September 30, 2021	 	
Operating cash flow (GAAP)	  	$	1,598	 	
Changes in assets and liabilities, net	  	 	(68	) 	
	  	 	 	 	
Cash from operations before balance sheet changes (Non-GAAP)	  	 	1,530	 	
Cash restructuring and transaction costs (Non-GAAP)	  	 	14	 	
	  	 	 	 	
Adjusted cash flow (Non-GAAP)	  	 	1,544	 	
Capital expenditures (Accrued)	  	 	(481	) 	
	  	 	 	 	
Adjusted free cash flow (Non-GAAP)	  	 	1,063	 	
Fixed quarterly dividend ($0.11/share)	  	 	(74	) 	
	  	 	 	 	
Excess free cash flow (Non-GAAP)	  	 	989	 	
50% Pay out (Board Discretion: Up to 50%)	  	 	50	% 	
	  	 	 	 	
Total variable dividend	  	$	494	 	

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FOURTH-QUARTER 2021 GUIDANCE

									
PRODUCTION GUIDANCE	  	 	 	  	 	 	
 	  	Quarter 4	 	
 	  	Low	 	  	High	 	
Oil (MBbls/d)	  	 	293	 	  	 	298	 	
Natural gas liquids (MBbls/d)	  	 	140	 	  	 	145	 	
Gas (MMcf/d)	  	 	900	 	  	 	950	 	
	  	 	 	 	  	 	 	 	
Total oil equivalent (MBoe/d)	  	 	583	 	  	 	601	 	

									
CAPITAL EXPENDITURES GUIDANCE	  	 	 	  	 	 	
 	  	Quarter 4	 	
(in millions)	  	Low	 	  	High	 	
Upstream capital	  	$	440	 	  	$	490	 	
Midstream capital	  	 	15	 	  	 	25	 	
Other capital	  	 	10	 	  	 	20	 	
	  	 	 	 	  	 	 	 	
Total capital	  	$	465	 	  	$	535	 	

									
PRICE REALIZATIONS GUIDANCE	  	 	 	 	 	 	
 	  	Quarter 4	 	
 	  	Low	 	 	High	 	
Oil - % of WTI	  	 	90	% 	 	 	100	% 	
NGL - % of WTI	  	 	42	% 	 	 	47	% 	
Natural gas - % of Henry Hub	  	 	80	% 	 	 	90	% 	

OTHER GUIDANCE ITEMS	  	 	 	 	 	 	
 	  	Quarter 4	 	
($ millions, except Boe and %)	  	Low	 	 	High	 	
Marketing & midstream operating profit	  	$	(10	) 	 	$	10	 	
LOE & GP&T per BOE	  	$	6.25	 	 	$	6.75	 	
Production & property taxes as % of upstream sales	  	 	7.0	% 	 	 	7.5	% 	
Exploration expenses	  	$	—  	 	 	$	5	 	
Depreciation, depletion and amortization	  	$	550	 	 	$	600	 	
General & administrative expenses	  	$	90	 	 	$	100	 	
Cash financing costs, net	  	$	90	 	 	$	100	 	
Other expenses	  	$	—  	 	 	$	10	 	
Current income tax rate	  	 	0	% 	 	 	0	% 	
Deferred income tax rate	  	 	20	% 	 	 	30	% 	
	  	 	 	 	 	 	 	 	
Total income tax rate	  	 	20	% 	 	 	30	% 	

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CONTINGENT PAYMENTS FOR BARNETT SHALE DIVESTITURE (4-year period beginning in 2021)

															
WTI Threshold	 	 	WTI Annual
Earnout Amount	 	 	Henry Hub
Threshold	 	 	Henry Hub
Annual Earnout
Amount	 	
$	50.00	 	 	$	10,000,000	 	 	$	2.75	 	 	$	20,000,000	 	
$	55.00	 	 	$	12,500,000	 	 	$	3.00	 	 	$	25,000,000	 	
$	60.00	 	 	$	15,000,000	 	 	$	3.25	 	 	$	35,000,000	 	
$	65.00	 	 	$	20,000,000	 	 	$	3.50	 	 	$	45,000,000	 	
2021 & 2022 HEDGING POSITIONS

																						
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 2021	  	 	66,460	 	  	$	41.24	 	  	 	48,250	 	  	$	38.82	 	  	$	48.82	 		
Q1-Q4 2022	  	 	26,112	 	  	$	43.75	 	  	 	22,501	 	  	$	48.36	 	  	$	58.58	 		

 	  	Price Swaptions	 	  	Price Call Options	 		
	Period	  	Volume (Bbls/d)	 	  	Weighted
Average
Price ($/Bbl)	 	  	Volume (Bbls/d)	 	  	Weighted
Average Price
($/Bbl)	 	
Q4 2021	  	 	—  	 	  	$	—  	 	  	 	5,000	 	  	$	39.50	 		
Q1-Q4 2022	  	 	10,000	 	  	$	46.67	 	  	 	—  	 	  	$	—  	 		

Oil Basis Swaps	  	 	  	 	 	  	 	 		
	Period	  	Index	  	Volume (Bbls/d)	 	  	Weighted Average
Differential to WTI
($/Bbl)	 	
Q4 2021	  	Midland Sweet	  	 	23,000	 	  	$	0.84	 		
Q4 2021	  	BRENT/WTI Spread	  	 	1,000	 	  	$	(8.00	) 		
Q4 2021	  	Guernsey Light Sweet	  	 	4,000	 	  	$	(1.49	) 		
Q4 2021	  	NYMEX Roll	  	 	13,000	 	  	$	0.39	 		
Q1-Q4 2022	  	BRENT/WTI Spread	  	 	1,000	 	  	$	(7.75	) 		
Q1-Q4 2022	  	NYMEX Roll	  	 	29,000	 	  	$	0.45	 		

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 2021	  	 	254,000	 	  	$	2.63	 	  	 	133,000	 	  	$	2.55	 	  	$	3.05	 		
Q1-Q4 2022	  	 	3,452	 	  	$	2.85	 	  	 	149,274	 	  	$	2.71	 	  	$	3.44	 		
 
2

2021 & 2022 HEDGING POSITIONS (continued)

																		
 	  	Price Swaptions	 	  	Price Call Options	 		
	Period	  	Volume
(MMBtu/d)	 	  	Weighted
Average
Price
($/MMBtu)	 	  	Volume
(MMBtu/d)	 	  	Weighted
Average
Price ($/
MMBtu)	 	
Q4 2021	  	 	—  	 	  	$	—  	 	  	 	50,000	 	  	$	 2.68	 		
Q1-Q4 2022	  	 	100,000	 	  	$	2.70	 	  	 	—  	 	  	$	—  	 		

Natural Gas Basis Swaps	  	 	 	  	 	 		
	Period	  	Index	  	Volume
(MMBtu/d)	 	  	Weighted Average
Differential to Henry
Hub ($/MMBtu)	 	
Q4 2021	  	El Paso Natural Gas	  	 	35,000	 	  	$	(0.92	) 		
Q4 2021	  	WAHA	  	 	80,000	 	  	$	(0.65	) 		
Q1-Q4 2022	  	WAHA	  	 	70,000	 	  	$	(0.57	) 		

NGL Commodity Hedges	  	 	 	  	 	 		
  	  	 	  	Price Swaps	 		
	Period	  	Product	  	Volume
(Bbls/d)	 	  	Weighted Average
Price ($/Bbl)	 	
Q4 2021	  	Natural Gasoline	  	 	1,000	 	  	$	47.57	 		
Q4 2021	  	Normal Butane	  	 	1,000	 	  	$	31.40	 		
Q4 2021	  	Propane	  	 	1,000	 	  	$	27.88	 		
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 October 28, 2021.
 
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