Via EDGAR

December 4, 2017

Mr. Brad Skinner

Senior Assistant Chief Accountant

United States Securities and Exchange Commission

Division of Corporation Finance

100 F Street, N.E.

Washington, D.C. 20549-3561

Re: Oasis Petroleum Inc.

Form 10-K for Fiscal Year Ended December 31, 2016

Filed on February 23, 2017

File No. 001-34776

Ladies and Gentlemen:

Set forth below are the responses of Oasis Petroleum Inc. (the “Company,” “we,” “us” or “our”), to comments received from the staff of the Division of Corporation Finance (the “Staff”) of the Securities and Exchange Commission (the “Commission”) by letter dated November 17, 2017, with respect to Form 10-K for Fiscal Year Ended December 31, 2016, File No. 001-34776, filed with the Commission on February 23, 2017 (the “Form 10-K”).

For your convenience, each response is prefaced by the exact text of the Staff’s corresponding comment in bold, italicized text. All references to page numbers and captions correspond to the Form 10-K unless otherwise specified.

Form 10-K for the Fiscal Year Ended December 31, 2016

Business, page 4

Proved Undeveloped Reserves, page 8

1. Your discussion of the changes in proved undeveloped reserves indicates that the line item entry representing revisions in the previous estimates of reserves is the result of an aggregation of separate and unrelated factors with offsetting effects, e.g. positive revisions relating to larger completion designs and a higher gas oil ratio and negative revisions due to the removal of proved undeveloped locations that are no longer aligned with the anticipated five-year drilling plan and negative revisions due to lower commodity prices.

Please expand your disclosure to reconcile the overall change in the line item by separately identifying and quantifying the net amount attributable to each factor so that the change in net reserves between periods is fully explained. In regards to your disclosure of revisions in the previous estimates of reserves, please expand your discussion to identify any additional factors such as changes caused by well

Securities and Exchange Commission

December 4, 2017

Page 2

performance, uneconomic proved undeveloped locations or changes resulting from the removal of proved undeveloped locations due to changes in a previously adopted development plan in addition to the changes in the net quantities caused by commodity prices. Refer to Item 1203(b) of Regulation S-K. This comment also applies to the comparable disclosure of the revisions in net quantities of total proved reserves pursuant to FASB ASC 932¬235-50-5 for each of the periods presented on page 122.

RESPONSE: We acknowledge the Staff’s comment, and we respectfully submit to the Staff that the Company’s disclosure as to the changes attributed to revisions in proved undeveloped reserves for the year ended December 31, 2016 were made in accordance with Item 1203(b) of Regulation S-K and, as such, the Company believes the disclosure regarding changes in proved undeveloped reserves is materially accurate as presented. However, the Company agrees in future filings to quantify the individual factors driving its net revisions. For the year ended December 31, 2016, its net positive revision in proved undeveloped reserves of 30,030 MBoe was attributable to positive revisions of 27,608 MBoe due to larger completion designs, 8,221 MBoe due to a higher gas to oil ratio and 5,744 MBoe due to ownership adjustments, offset by 9,455 MBoe due to the removal of proved undeveloped reserves that were no longer aligned with the Company’s anticipated five-year drilling plan and 1,617 MBoe due to the impact of price on producing life.

Similarly, we respectfully submit to the Staff that the Company’s disclosure as to the changes attributed to revisions in total proved reserves for the periods presented were made in accordance with FASB ASC 932-235-50-5 and, as such, the Company believes the disclosure regarding changes in total proved reserves is materially accurate as presented. For the year ended December 31, 2016, the Company’s net positive revision in proved reserves of 31,136 MBoe was attributable to positive revisions of 30,374 MBoe due to well performance and larger completion designs, 8,221 MBoe due to a higher gas to oil ratio and 8,165 MBoe due to ownership adjustments, offset by 9,455 MBoe due to the removal of proved undeveloped reserves that were no longer aligned with the Company’s anticipated five-year drilling plan and 8,206 MBoe due to lower commodity prices. For the year ended December 31, 2015, the Company’s net negative revision in proved reserves of 84,635 MBoe was primarily attributable to negative revisions of 71,945 MBoe due to the removal of proved undeveloped reserves that were not economic at the lower oil price or were no longer aligned with the Company’s anticipated five-year drilling plan and 17,214 MBoe due to the impact of price on producing life, partially offset by positive revisions of 3,004 MBoe due to ownership adjustments and 1,914 MBoe due to performance. For the year ended December 31, 2014, the Company’s net negative revision in proved reserves of 25,117 MBoe was primarily attributable to negative revisions of 21,411 MBoe due to the removal of proved undeveloped reserves that were not aligned with the Company’s anticipated five-year drilling plan and 3,796 MBoe due to performance.

In future filings, beginning with the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, the Company will quantify the individual material factors underlying changes in the Company’s proved undeveloped reserves and total proved reserves.

Securities and Exchange Commission

December 4, 2017

Page 3

2. The disclosure provided on page 8 indicates that approximately 33% of your proved undeveloped reserves at December 31, 2016 are attributable to wells that have been drilled but not yet completed. Please provide us with the total number of gross wells and the net quantities of proved undeveloped reserves attributable to those wells as of December 31, 2016 which are not scheduled to be completed and the related reserves converted to developed reserves within five years of the initial disclosure as proved undeveloped reserves. To the extent that there are any such reserves, please tell us the specific circumstances that you believe justify a period longer than five years from the initial disclosure date to complete the development these reserves.

RESPONSE: We acknowledge the Staff’s comment, and we respectfully submit to the Staff that for the year ended December 31, 2016, two gross wells that were drilled but not yet completed were scheduled to be completed, and the related proved undeveloped reserves converted to developed reserves, five years and four months beyond the initial disclosure as proved undeveloped reserves. These two wells were initially disclosed as proved undeveloped reserves on December 31, 2012 and 2013, respectively, and, at the time of their initial disclosure, they were scheduled to be developed within five years, and the wells were, in fact, drilled within five years of their initial disclosure date. When the Company performed its annual evaluation of proved undeveloped reserves as of December 31, 2016, the Company had the financial capacity and resources to complete these two wells within five years of initial booking of the associated reserves as proved undeveloped reserves. The Company had flexibility in its 2017-2018 capital program, and believed that these wells could be completed earlier than what the December 31, 2016 schedule estimated. There are 1,089 MBoe of proved undeveloped reserves attributable to these two wells, representing approximately 0.35% of the Company’s total proved reserves.

Production, Revenues and Price History, page 10

3. Tell us how you considered the requirements with regard to disclosure of production, by final product sold, for each field and/or geological formation that contains 15% or more of your total proved reserves. Refer to Item 1204(a) of Regulation S-K and the definition of a field provided in Rule 4-10(a)(15) of Regulation S-X.

RESPONSE:    We acknowledge the Staff’s comment and respectfully advise the Staff that, upon consideration of the requirements pursuant to Item 1204(a) of Regulation S-K, we determined that for the year ended December 31, 2016, the Company’s production, by final product sold, was generated from only one named field and/or geological formation. In this regard, we note that Rule 4-10(a)(15) of Regulation S-X defines a “field” as:

An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated . . . laterally by local geological barriers . . . . Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. [Emphasis Added]

Securities and Exchange Commission

December 4, 2017

Page 4

In accordance with the definition set forth above, we group the Company’s Williston Basin assets into one named field and/or geological formation and operate such assets consistent with this classification. We refer to this one named field and/or geological formation as the Bakken and Three Forks formations. The Company’s target horizontal zones in the Bakken and Three Forks formations produce from a continuous hydrocarbon formation present across all of the Company’s operated properties in the Williston Basin, as the Three Forks formation is generally found immediately beneath the Bakken formation. All of the Company’s wells in the Bakken and Three Forks formations are drilled, completed and equipped in a similar manner. Additionally, the Company’s properties in the Bakken and Three Forks formations share sales arrangements, infrastructure and substantially similar cost structures. Purchasers of the Company’s products do not make any differentiation based on the wells or reservoirs from which such production originated, and such production is generally commingled at central pipeline or rail delivery points.

We believe this approach is consistent both with the manner in which other registrants that operate in the Williston Basin report their results, including production by final product sold, and the understanding of investors. The final products sold from our reserves are oil and natural gas, which are presented.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, page 52

Non-GAAP Financial Measures, page 72

4. The adjustments you make in connection with your presentation of Adjusted Net Income (Loss) for the year ended December 31, 2015 result in changing a GAAP loss for the period to non-GAAP income. However, the number of shares used to determine adjusted diluted earnings per share does not appear to have been adjusted to include the impact of dilutive securities which had been excluded from the calculation of GAAP loss per share. Revise your presentation to include dilutive securities in your calculation of adjusted diluted earnings per share. Note that similar considerations apply in circumstances where non-GAAP adjustments result in changing GAAP income to non-GAAP loss such as appears to have occurred for the three and six month periods ended June 30, 2017; anti-dilutive securities should be excluded from your calculation of adjusted loss per share.

RESPONSE: We acknowledge the Staff’s comment and respectfully advise the Staff that the Company did not have dilutive securities under the treasury stock method for the year ended December 31, 2015. The treasury stock method assumes that any proceeds from the exercise of options and warrants (and their equivalents) would be used to purchase common stock at the average market price during the period. To have dilutive securities under the treasury stock method for restricted stock, the average unamortized compensation cost (assumed proceeds) from all unvested shares outstanding must be less than the cost to repurchase such unvested shares at the average stock price during the period. For the year ended December 31, 2015, our average unamortized compensation cost of $43.6 million exceeded the cost to repurchase all 2,842,144 unvested shares at the average 2015 stock price of $13.14 per share.

Securities and Exchange Commission

December 4, 2017

Page 5

In future filings, we will include a revised calculation of non-GAAP diluted loss per share for the three and six month periods ended June 30, 2017. The revised non-GAAP diluted loss per share will divide Adjusted Net Loss by weighted average shares outstanding excluding anti-dilutive securities. For the three and six month periods ended June 30, 2017, the impact is immaterial and does not change the reported non-GAAP diluted loss per share amount. The following table reflects non-GAAP diluted loss per share for the three and six month periods ended June 30, 2017 as previously reported and as revised:

	Three Months Ended June 30, 2017						Six Months Ended June 30, 2017
	Previously Reported			As Revised			Previously Reported			As Revised
	(in thousands, except per share data)
Adjusted Net Loss	$	(11,152	)	$	(11,152	)	$	(22,619	)	$	(22,619	)
Diluted weighted average shares outstanding		234,917			233,283			236,281			233,176
Non-GAAP Diluted Loss Per Share	$	(0.05	)	$	(0.05	)	$	(0.10	)	$	(0.10	)

*    *     *    *    *

Securities and Exchange Commission

December 4, 2017

Page 6

Please direct any questions that you have with respect to the foregoing or if any additional supplemental information is required by the Staff, please contact David P. Oelman of Vinson & Elkins L.L.P. at (713) 758-3708 or Thomas G. Zentner of Vinson & Elkins L.L.P. at (713) 758-3671.

Very truly yours,
OASIS PETROLEUM INC.
By:	/s/ Michael H. Lou
Name:	Michael H. Lou
Title:	Chief Financial Officer

Enclosures

cc: David P. Oelman, Vinson & Elkins L.L.P.

Thomas G. Zentner, Vinson & Elkins L.L.P.