DVNDevon Energy

To the extent that you disclose material additions to your proved reserves, expand your disclosure to provide a general discussion of the technologies used to establish the appropriate level of certainty for your reserves estimates. Refer to Item 1202(a)(6) of Regulation S-K.

The Company respectfully advises the Staff that the Company will include the following expanded disclosure in response to the

Staff’s comment in its amendment to the Registration Statement on page 103 in the section titled “The Merger—Dividend Policy”:

Following the closing of the merger, Devon expects to pursue a “fixed plus variable” dividend strategy. Under this strategy, Devon plans to pay, on a quarterly basis, a fixed dividend amount and, potentially, a variable dividend amount, if any, to its stockholders.

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The declaration and payment of any future dividend, whether fixed or variable, will remain at the full discretion of the Devon Board and will depend on Devon’s financial results, cash requirements, future prospects, COVID-19 impacts and other factors deemed relevant by the Devon Board. In determining the amount of the quarterly fixed dividend, the Devon Board expects to consider a number of factors, including Devon’s financial condition, the commodity price environment and a general target of paying out approximately 10% of operating cash flow through the fixed dividend. Any variable dividend amount will be determined by the Devon Board on a quarterly basis and will equal up to 50% of “excess free cash flow,” which Devon defines as operating cash flow less (i) capital expenditures and (ii) the fixed quarterly dividend amount. The Devon Board will consider a number of factors in determining if a variable dividend payment will be made. Devon expects that the most critical factors will consist of Devon’s financial condition, including its cash balances and leverage metrics, as well as the commodity price outlook. For additional information regarding risks associated with Devon’s dividends, please see “Risk Factors—Risks Relating to Devon and

WPX—Declaration, payment and amounts of dividends, if any, distributed to stockholders of Devon will be uncertain.”

We also intend to add a cross reference to the foregoing disclosure in the section titled “ The Merger—Recommendation of the WPX Board and its Reasons for the Merger.”

We thank you for your prompt attention to this letter responding to the Comment Letter and look forward to hearing from you at your earliest convenience. If you have any questions regarding this filing, please contact Frank Bayouth at (713) 655-5115; Eric Otness at (713) 655-5135; or Jenna Godfrey at (202) 371-7567.

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The explanation for the changes that occurred in total proved reserves indicates that a portion of the change attributed to extensions and discoveries for fiscal 2018 and 2017 was the result of infill drilling. Refer to subparagraphs (a) and (d) of FASB ASC 932235-50-5 and tell us your rationale for classifying reserves resulting from drilling an infill well as an extension.

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The change in the total net quantities of proved reserves attributed to extensions and discoveries appears to be significantly greater than the corresponding change in the net quantities of proved undeveloped reserves for each of the last three fiscal years presented, e.g.

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a difference of 71 MMBoe or 44% between the 160 MMBoe change attributed to total proved reserves and the 89 MMboe change attributed to proved undeveloped reserves for the period ending December 31, 2019. Expand the discussion of the significant changes that occurred in your total proved reserves attributed to extensions and discoveries to explain the reason(s) for these differences. Refer to FASB ASC 932-235-50-5.

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Expand the discussion of the changes that occurred in your proved undeveloped reserves to include an explanation of the material change due to revisions other than price. Your explanation should address the overall change for the line item by separately identifying and quantifying the net amount attributable to each factor that contributed to the change, including offsetting factors, so that the change in net proved

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undeveloped reserves between periods is fully reconciled. In particular, disclosure relating to revisions in previous estimates for reasons other than price should identify such individual underlying factors as changes caused by well performance, improved recovery, or changes resulting from the removal of proved undeveloped locations due to changes in a previously adopted development plan. Refer to the disclosure requirements in Item 1203(b) of Regulation S-K.

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Disclosure in this section states that the WPX Board considered the implementation of a "Fixed Plus Variable" dividend strategy in recommending that WPX stockholders vote for the Merger Proposal. We also note Devon Energy's Form 10-Q for the quarterly period ended September 30, 2020 states that upon closing of the Merger it intends to implement a fixed plus variable dividend strategy, with variable dividends up to

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50% of excess quarterly free cash, subject to certain criteria. Please expand your disclosure to discuss the criteria for the payment of the variable dividend and clarify how you expect the combined company to compute "excess free cash flow" in determining such variable dividend.

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Please be advised that we will not be in a position to declare this registration statement effective until you have resolved all comments on your Exchange Act reports. Please refer to the comment letter dated November 16, 2020 regarding your annual report on Form 10-K for the fiscal year ended December 31, 2019.

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Disclosure provided on pages 6 and 7 relating to your U.S. operating areas indicates that you are planning to drill a total of approximately 660 gross wells during 2015 compared to the 1,061 gross wells drilled during 2014.

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In this regard, we note significant reductions in certain areas such as the Barnett Shale where you plan to drill 10 gross wells compared to the 84 gross wells drilled during 2014 and in the Mississippian- Woodford Trend where you plan to drill 50 gross wells compared to the 236 gross wells drilled during 2014. For each of your U.S. operating areas, please explain how you have taken into consideration the reduction in the number of wells you plan to drill in 2015 in adopting a development plan that still results in converting your proved undeveloped reserves as of December 31, 2014 within five years of the initial disclosure of these reserves. As part of your response, provide us with the net reserve quantities, if any, that you removed in each of your U.S. operating areas as a result of the changes for 2015 related to your plans to drill certain wells that had previously been scheduled to be drilled during 2014 but were not, in fact, drilled during that year.

For each of our operating areas, we record proved undeveloped reserves when all the requirements of Rule 4-10 of Regulation S-X have been met. We specifically comply with Rule 4-10(a)(31)(ii) when two criteria have been met: 1) We have established a development plan that has been approved by our Reserves Committee of the Board of Directors and will result in converting the proved undeveloped reserves within five years from the initial disclosure of the reserves and 2) the associated development capital requirements are equal to or less than the management-approved capital program on a

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year-by-year basis. If either of these criteria cease to be met, we remove the associated proved undeveloped reserves from our proved reserves disclosures.

As we applied this evaluation process at the end of 2014, we considered the reductions in the number of wells planned for 2015. Table 1 in the enclosed Exhibit 1 summarizes, by operating area, the net proved undeveloped reserves that we removed at the end of 2014 associated with wells that were originally scheduled to be drilled in 2014 but were not. Table 1 also summarizes our proved undeveloped reserves as of December 31, 2014 by operating area.

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Please expand the tabular disclosure provided here and elsewhere on page 29 to include the total annual production volumes, by final product sold, for each of the last three fiscal years. Refer to the presentation requirements in Item 1204(a) of Regulation S-K.

We will include total annual production volumes within the tabular disclosure for significant properties in future filings in accordance with Item 1204(a) of Regulation S-K. However, daily volumes is the more meaningful production measure used by our investors and us to evaluate production trends. Therefore, we intend to continue disclosing and referencing daily production for each of our operating areas within Management’s Discussion and Analysis in accordance with Item 303(a) of Regulation S-K. Read in the reply ↗

You disclose the negative revisions relating to your proved undeveloped reserves, other than price for the fiscal year ending December 31, 2014, were primarily due to evaluations of certain U.S. onshore dry-gas areas which the Company does not expect to develop in the next five years.

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We note similar disclosure of negative revisions for each fiscal year since you began providing separate disclosure of the changes in proved undeveloped reserves relating to your U.S. properties, starting December 31, 2011. Your disclosures identify the largest revisions were related to the dry-gas areas in the Barnett Shale for the fiscal year ending 2014 and to the Barnett Shale and Carthage areas for the fiscal years ending 2013, 2012 and 2011. Given the successive nature of your revisions, please tell us how you have complied with the requirement of reasonable certainty for proved reserves relating to an adopted development plan and schedule as set forth in the definition of undeveloped reserves under Rule 4-10(a)(31)(ii) of Regulation S-X and in the answer to Question 131.04 in the Compliance and Disclosure Interpretations (C&DIs), issued October 26, 2009 and updated May 16, 2013. You may find the C&DIs on our website at the following address: http://www.sec.gov/divisions/corpfin/guidance/oilandgas-interp.htm.

As briefly summarized in our response to question 1, we have designed policies and processes for recording proved undeveloped reserves, particularly with regards to reasonable certainty and adopted development plans, that comply with the Rule 4-10 requirements referenced in your question.

Additionally, in our response to question 4 below, we provide additional quantitative analysis of the successive reserve reductions we recognized in 2011 through 2014.

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As noted in the response, the reductions to our proved undeveloped reserves resulted from management decisions to shift capital to operating areas generating the highest returns across our portfolio of assets as prices changed and acquisition, divestiture and exploration activity occurred. While the operating areas from which we were shifting capital, namely U.S. dry gas regions, were similar in each year, the driving factors and areas receiving more capital were unique to both the year and the allocation decisions being made. For example, in 2011 we shifted capital from dry-gas regions to liquids-rich regions due to rising prices for natural gas liquids and oil in contrast to declining natural gas prices. In 2013, we began shifting more capital toward the Delaware Basin as a result of our oil-focused exploration successes. In 2014, we shifted a large portion of our capital toward our Eagle Ford asset that was acquired in early 2014.

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We note your explanation of the changes in proved undeveloped reserves related to revisions other than price indicates these changes are “primarily” due to removing those reserves which the Company does not expect to develop in the next five years.

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If your revisions are related to more than one unrelated cause, for example, changes in your corporate plans to drill certain wells and changes for well performance, provide us with the net quantities attributable to each separate cause relating to your disclosure for each of the four years 2011 through 2014.

Table 2 in the enclosed Exhibit 1 summarizes the proved undeveloped reserves revisions other than price for 2011 through 2014. In each year, as indicated in our disclosure explanation, the largest factor causing the revisions related to changes to our drilling plans that resulted in the removal of proved undeveloped reserves. In each year, the drilling plan changes resulted from management decisions to shift capital to operating areas generating the highest returns across our portfolio of assets as prices changed and acquisition, divestiture and exploration activity occurred.

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The other less significant revisions to our proved undeveloped reserves presented in Table 2 relate to well performance and cost structure and were generally positive in each year.

In our future filings, we will provide more detailed explanations for the revisions other than price we deem to be both significant and unrelated.

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To help us understand the historical record and the associated activity impacting your reported proved undeveloped reserves, please provide us with a schedule that shows the ultimate disposition or current status for all of the PUD locations (e.g. number of gross locations) scheduled to be drilled in the 12 month period following disclosure as of December 31, 2011, 2012, 2013 and 2014.

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Your analysis of the ultimate disposition or current status for each period should account for the total number of gross PUD locations that were:  scheduled to be drilled during the 12 months following disclosure at the end of the fiscal year,  actually drilled during the 12 months following disclosure at the end of the fiscal year,  deferred and actually drilled in another year (identify the year and number of gross PUD locations drilled in that specific year),  removed from the PUD category (identify the reason, e.g. no plans to drill, sold, performance, price, etc., the year and the number of gross PUD locations related to each reason), and  undrilled and remaining as PUDs at 12/31/2014.

Table 3 in the enclosed Exhibit 1 provides the requested reconciliation of our PUD locations for the U.S. and Canada, excluding our Jackfish Heavy Oil project in Canada. Because the development timeline and spacing unit (pads rather than wells) for Jackfish differ from the rest of our PUD locations, the Jackfish PUD locations are reconciled separately in Table 4. Read in the reply ↗

To help us understand the changes specific to the Barnett Shale, please provide us with:  the changes in the proved undeveloped Barnett Shale reserves pursuant to Item 1203(b) of Regulation S-K for each of the four fiscal years 2011 through 2014, and  a schedule that shows the ultimate disposition or current status for all of your Barnett Shale PUD locations (e.g.

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number of gross locations) scheduled to be drilled in the 12 month period following disclosure as of December 31, 2011, 2012, 2013 and 2014. You may furnish the materials relating to comments 5 and 6 in hard copy format or on digital media such as flash drive or compact disk. If you would like to have these supplemental materials returned to you, please comply with the provisions of Rule 418(b) of Regulation C, which provides for the return of supplemental information as long as certain express conditions are met. If you wish to request confidential treatment of those materials which they are in our possession, please follow the procedures set forth in Rule 83 of the Freedom of Information Act.

Table 5 in the enclosed Exhibit 1 reconciles the changes in our Barnett Shale proved undeveloped reserves as requested.

Table 6 in the enclosed Exhibit 1 provides the requested reconciliation of our Barnett Shale PUD locations.

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In connection with the above response to the staff’s comment, Devon acknowledges that:

Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

Staff comments or changes to disclosure in response to staff comments do not foreclose the Commission from taking any action with respect to the filing; and

Devon may not assert

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staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

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On pages 7, 37, and elsewhere in the 10 -K you refer to your joint venture with Sinopec Corporation. You state on page 40 that the joint venture had remaining commitments at the end of 2013. The 20-F filed April 28, 2014 by China Petroleum & Chemical Corporation (“CPCC”) indicates that CPCC is also known as “Sinopec Corp.” We are aware of recent state government and university divestment or similar initiatives

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regarding CPCC due to its contacts with Iran and Sudan. Iran and Sudan are designated by the State Department as state sponsors of terrorism, and are subject to U.S. economic sanctions and export controls. Please discuss for us the potential for your relationship with Sinopec to have an adverse impact upon your reputation and share value.

In 2012, we entered into a joint venture with Tip Top Energy Production US LLC (“Tip Top”), a Sinopec affiliate, involving Devon’s acreage positions in five oil and gas exploration plays, which are all located in the United States. As a Delaware limited liability company, Tip Top is governed by applicable U.S. law. Additionally, the agreements related to the joint venture contemplate that the joint venture will act in accordance with applicable law.

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Pursuant to our joint venture agreement, Tip Top acquired a 33.3 percent interest in these plays in exchange for an approximate $900 million cash payment and a commitment to fund approximately $1.6 billion of Devon’s share of future exploration, development and drilling costs associated with these plays. Devon has no other business relationships with Tip Top or Sinopec outside of this joint venture.

Cecilia Blye

United States Securities and Exchange Commission

We broadly marketed this joint venture opportunity to a wide variety of potential partners, ultimately selecting Tip Top as our joint venture partner. When we entered into the joint venture, we were aware of Tip Top’s affiliation with Sinopec and considered such affiliation in our decision to enter into the joint venture. We did not believe that our joint venture with Tip Top would have a material adverse impact on our reputation and share value. Rather, we expected that the joint venture would be viewed favorably by our investors. When our joint venture with Tip Top was announced on January 3, 2012, our stock rose 6.6% from the previous closing price, which was noticeably better than the 4.0% gain experienced by our peer group on the same day.

We market and sell all oil and gas production from the joint venture plays to our customers, which have only included U.S.-based customers to date. Furthermore, Tip Top does not take delivery of any production from the joint venture; therefore, there is no possibility that Sinopec is selling production from the plays to Iran, Sudan or other known state sponsors of terrorism. We do not have any contacts with, or business activities in or involving, Iran or Sudan. We do not have any future plans to conduct business in those countries.

Devon has not received any inquiries from investors or analysts questioning or otherwise concerned with the Sinopec joint venture. In addition, we are not aware of any Devon investors selling or closing their investment as a result of our joint venture with Sinopec.

We do not believe that the joint venture with Tip Top has had or will have a material adverse impact on Devon’s reputation or share value.

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In connection with the above response to the Staff’s comment, Devon acknowledges that:

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Devon is responsible for the adequacy and accuracy of the disclosure in the filing;

Staff comments or changes to disclosure in response to Staff comments do not foreclose the Commission from taking any action with respect to the filing; and

Devon may not assert Staff comments as a defense in any proceeding initiated by the Commission or any person under the federal securities laws of the United States.

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