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This summary provides a brief overview of information included elsewhere in this offering memorandum and the documents we incorporate by reference herein. Because it is abbreviated, this summary does not include all of the information that you should consider before investing in the notes. You should read the entire offering memorandum carefully before making an investment decision, including the information presented under the heading “Risk factors,” the documents incorporated by reference in this offering memorandum and any other documents to which we refer for a more complete understanding of this offering. We have provided definitions for certain oil and natural gas terms used in this offering memorandum in the “Glossary of oil and natural gas terms” beginning on page A-1 of this offering memorandum.

We are an independent exploration and production (“E&P”) company focused on the acquisition and development of onshore, unconventional crude oil and natural gas resources in the United States. Oasis Petroleum North America LLC (“OPNA”) and Oasis Petroleum Permian LLC conduct our E&P activities and own our oil and gas properties located in the North Dakota and Montana regions of the Williston Basin and the Texas region of the Permian Basin, respectively. In addition to our E&P segment, we also operate a midstream business through OMP, a leading gathering and processing master limited partnership that owns, develops, operates and acquires a diversified portfolio of midstream assets in North America. We own OMP’s general partner and approximately 77% of OMP. We derive significant cash flows from the midstream segment through distributions from our ownership of OMP limited partner units.

On May 3, 2021, we entered into a purchase and sale agreement (the “Williston PSA”) with QEP Energy Company (“QEP”), a wholly-owned subsidiary of Diamondback Energy, Inc (“Diamondback”). Pursuant to the Williston PSA, among other things, we will acquire approximately 95,000 net acres (the “Acquired Williston Assets”) in the Williston Basin from Diamondback (the “Williston Basin Acquisition”) in a cash transaction for aggregate consideration of approximately $745.0 million, subject to customary purchase price adjustments (including a $74.5 million deposit to offset cash due at closing) (the “Purchase Price”). The Purchase Price is expected to be financed through cash on hand, consideration from the Permian Basin Sale and the net proceeds from this offering. The transaction was approved unanimously by the board of directors of each company. The effective date of the Williston Basin Acquisition was April 1, 2021, and closing is expected to occur in July 2021, subject to customary closing conditions.

The Acquired Williston Assets data, except for the SEC pricing estimates of proved reserves, provided below is based on publicly available information, which we have not prepared or reviewed for accuracy. SEC pricing estimates of proved reserves and related information for the Acquired Williston Assets were prepared in accordance with the Petroleum Resource Management System (“PRMS”) using the SEC pricing for the year ended December 31, 2020, and have been reviewed by DeGolyer and MacNaughton, independent reserve engineers. Additional historical financial statements and pro forma information surrounding the Williston Basin Acquisition, including the Acquired Williston Assets, will be furnished on a Current Report on Form 8-K following the completion of the Williston Basin Acquisition.

The Acquired Williston Assets consist of approximately 95,000 net acres, which produced approximately 27,000 barrels of oil equivalent (“Boe”) per day during the first quarter of 2021 on a two-stream basis of crude oil and natural gas. The following table provides key operational highlights of the Acquired Williston Assets, including our estimates of oil production and total production for the first quarter of 2021:

On May 20, 2021, Oasis Petroleum Permian LLC (“OPP”), a wholly-owned subsidiary of the Company, entered into a purchase and sale agreement (the “Permian PSA”) with Percussion Petroleum Operating II, LLC (“Percussion”), pursuant to which OPP agreed to sell to Percussion its remaining upstream assets in the Texas region of the Permian Basin (the “Primary Divested Assets”) for aggregate consideration of up to $450.0 million, consisting of $375.0 million cash at closing (offset by a $31.9 million deposit made by Percussion at signing) and up to three earn-out payments of $25.0 million per year for each of 2023, 2024 and 2025 if the average daily settlement price of NYMEX West Texas Intermediate crude oil exceeds $60 per barrel for such year (the “Primary Permian Basin Sale”). The Primary Divested Assets consist of approximately 24,000 net acres, which contained net proved reserves of approximately 30.3 MMBoe at December 31, 2020 and produced approximately 7,186 Boe per day during the first quarter of 2021 on a two-stream basis of crude oil and natural gas. The closing of the Primary Permian Basin Sale is expected to occur on or around June 29, 2021, subject to customary closing conditions.

In addition to the sale of the Primary Divested Assets, the Company previously sold certain other assets in the Texas region of the Permian Basin (such assets, together with the Primary Divested Assets, collectively, the “Divested Assets”) for aggregate consideration of $31.0 million to separate buyers in two transactions which closed in May 2021 (the “Additional Permian Sale,” and, together with the Primary Permian Basin Sale, the “Permian Basin Sale”). The proceeds from the Permian Basin Sale will be used to fund a portion of the Purchase Price and for general corporate purposes. However, the Primary Permian Basin Sale is not conditioned upon the completion of the

In accordance with the terms of the Permian PSA, immediately after execution thereof, the Company entered into new hedge contracts on Percussion’s behalf that Percussion will be obligated to assume upon closing of the Primary Permian Basin Sale. The Company entered into swaps, collars, and three-way collars for crude oil with a weighted average floor price of $56.02 per Bbl and weighted average ceiling price of $61.71 per Bbl. The commodity contracts included total notional amounts of 1,085,600 Bbls, 2,475,800 Bbls and 2,427,900 Bbls which settle across the second half of 2021, calendar year 2022 and calendar year 2023, respectively, based on NYMEX West Texas Intermediate crude oil. These derivative instruments do not qualify for or were not designated as hedging instruments for accounting purposes.

Unless otherwise indicated, all financial and operational information in this offering memorandum does not give effect to the Williston Basin Acquisition or the Permian Basin Sale. Additional pro forma information surrounding the Permian Basin Sale, including the Divested Assets, will be furnished on a Current Report on Form 8-K following the completion of the Permian Basin Sale. Because the Divested Assets constitute substantially all of the assets of OPP, it is expected that OPP will be released from its obligations as a guarantor under the indenture that will govern the notes offered hereby pursuant to the terms thereof upon the consummation of the Permian Basin Sale.

Our estimated net proved reserves and related PV-10 at December 31, 2020 are based on reports prepared by DeGolyer and MacNaughton, our independent reserve engineers. In preparing its reports, DeGolyer and MacNaughton evaluated 100% of the reserves and discounted values at December 31, 2020 in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”) applicable to companies involved in crude oil and natural gas producing activities. Our estimated net proved reserves and PV-10 do not include probable or possible reserves and were determined using the preceding 12 months’ unweighted arithmetic average of the first-day-of-the-month index prices for crude oil and natural gas, which were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $39.54 per Bbl for crude oil and $2.03 per MMBtu for natural gas for the year ended December 31, 2020. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead. The information in the following table does not give any effect to or reflect our commodity derivatives. Future operating costs, production taxes and capital costs were based on current costs as of each year-end. PV-10 represent the present value of the future net revenues discounted at 10%, before income taxes.

There are numerous uncertainties inherent in estimating reserves and related information, and different reservoir engineers often arrive at different estimates for the same properties. There can be no assurance that our estimated net proved reserves will be produced within the periods indicated or that prices and costs will remain constant. A substantial or extended decline in crude oil prices could result in a significant decrease in our estimated net proved reserves and PV-10 in the future.


	Proved Developed				Proved Undeveloped
	Crude oil (MMBbls)	Natural gas (Bcf)	Total (MMBoe)	PV-10 (in millions)(1)	Crude oil (MMBbls)	Natural gas (Bcf)	Total (MMBoe)	PV-10 (in millions)(1)
Williston Basin	72.3	241.9	112.6	$ 775.2	23.3	97.2	39.6	$ 146.5
Permian Basin	13.2	20.8	16.6	$ 161.7	11.0	16.3	13.7	$ 31.6
Total	85.5	262.7	129.2	$ 936.9	34.3	113.5	53.3	$ 1,115.0

(1) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. For a reconciliation of total proved developed and proved undeveloped PV-10 to Standardized Measure, please see “—Reconciliation of standardized measure to PV-10” below.

(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. A reconciliation of PV-10 to Standardized Measure for the Acquired Williston Assets is not available or included in this offering memorandum.

SEC pricing estimates of proved reserves and related information for the Acquired Williston Assets were prepared in accordance with PRMS using the SEC pricing for the year ended December 31, 2020, and have been reviewed by our independent petroleum engineers. NYMEX Strip Pricing estimates of proved reserves and related information for the Acquired Williston Assets are generated using volumes from independent petroleum engineers adjusted for NYMEX West Texas Intermediate crude oil index prices with respect to oil and condensate, and NYMEX Henry

(1) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. A reconciliation of PV-10 to Standardized Measure for the Divested Assets at April 1, 2021 is not available or included in this offering memorandum.

NYMEX Strip Pricing estimates of proved reserves and related information for the Permian Basin Sale are generated using volumes from independent petroleum engineers rolled forward to April 1, 2021 and adjusted for NYMEX West Texas Intermediate crude oil index prices with respect to oil and condensate, and NYMEX Henry Hub natural gas prices with respect to natural gas, in each case based on timing and location differentials and as of May 18, 2021.

Our pro forma proved reserves, after (i) giving effect to the Williston Basin Acquisition and the Permian Basin Sale at April 1, 2021, (ii) rolling forward our Williston Basin assets from December 31, 2020 to April 1, 2021 and (iii) adjusting for NYMEX West Texas Intermediate crude oil index prices with respect to oil and condensate and NYMEX Henry Hub natural gas prices with respect to natural gas, in each case, based on timing and location differentials and as of May 18, 2021, are summarized in the table below:

(1) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effect of income taxes on discounted future net cash flows. A reconciliation of PV-10 to Standardized Measure for our pro forma proved reserves after giving effect to the Williston Basin Acquisition and the Permian Basin Sale is not available or included in this offering memorandum.

On May 21, 2021, we entered into the Fourth Amendment to the Oasis Credit Facility (the “Fourth Amendment”) to, among other things, provide that (i) no borrowing base reduction shall occur in connection with the issuance of senior notes in an aggregate principal amount not in excess of $550.0 million issued after the effective date of the Fourth Amendment and prior to the effectiveness of the scheduled redetermination to occur on or about October 1, 2021 (the “October 1 Redetermination”), (ii) the borrowing base shall be reduced by $100.0 million upon the consummation of the Primary Permian Basin Sale and (iii) subject to satisfaction of certain conditions, the borrowing base shall be automatically increased by $250.0 million if the Williston Basin Acquisition is consummated prior to the effectiveness of the October 1 Redetermination. The Fourth Amendment also amends the exceptions from the restricted payments negative covenant to provide increased restricted payment flexibility, permitting unlimited restricted payments subject to (x) no event of default under the Oasis Credit Facility, (y) at least 25% availability under the Oasis Credit Facility and (z) the pro forma leverage ratio being not more than 1.5 to 1.0; provided that if the conditions described in clauses (x) and (y) are satisfied and the pro forma leverage ratio is less than 2.0 to 1.0, but more than 1.5 to 1.0, restricted payments are permitted in an amount such that all restricted payments made in reliance on such exception since the closing date of the Oasis Credit Facility will not exceed the positive amount of free cash flow.

On May 17, 2021, Oasis entered into a series of transactions with certain hedge counterparties to modify the swap price to $50 per barrel based on NYMEX West Texas Intermediate crude oil index pricing for hedges totaling 19 MBblpd in 2022 and 14 MBblpd in 2023 (the “Hedging Transactions”). The amount paid for the modification of these hedges totaled $82.4 million.

The U.S. Army Corps of Engineers (“Corps”) is currently conducting a court-ordered environmental review to determine whether the Dakota Access Pipeline (“DAPL”) poses a threat to the drinking water supply of the Standing Rock Sioux Reservation. Once this review is finished, which completion is estimated by the Corps to occur by no later than March 2022, the Corps will determine whether DAPL is safe to operate or must be permanently shut down. On April 9, 2021, the Biden Administration announced that the Corps will not take immediate action to shut down DAPL while it conducts the environmental review, and on May 3, 2021, the Corps filed a Status Report with the federal district court, confirming that it currently is not seeking a shutdown of DAPL while the agency conducts the environmental review. In a related legal proceeding involving the Standing Rock Sioux Tribe’s request for an injunction to shut down DAPL while the environmental review is being conducted, U.S. District Judge James Boasberg ruled on May 21, 2021 that the Dakota Access pipeline will not be forced to shut down while the Corps conducts the environmental review, indicating that the tribe had failed to make a successful showing of irreparable harm based on the threat of an oil spill.

incentive distribution rights for total consideration of approximately $512.5 million, including cash consideration of $231.5 million and 14.8 million OMP common units (the “Midstream Simplification”). The effective date for the Midstream Simplification was January 1, 2021. Following the Midstream Simplification, we own approximately 77% of the limited partnership interests in OMP and none of the limited liability company interests in Bobcat DevCo or Beartooth DevCo.

As we have disclosed previously, management continues to believe the Company’s ownership in OMP is a source of unrecognized value and has prioritized value creation options in the near term. Those options may include taking steps to deconsolidate OMP, as well as obtaining liquidity through partial sales of our equity interests in OMP from time to time depending on market conditions.

Market conditions have improved but remain uncertain as the worldwide response to COVID-19 continues to evolve. Federal, state and local public health and governmental authorities have begun implementation of programs to administer vaccines, and certain regions across the United States have begun to partially lift restrictions previously imposed to contain the spread of COVID-19. Global economic activity levels have improved as these restrictions have begun to be lifted, and energy demand has gradually increased. Despite moderate improvements in market conditions, uncertainties related to COVID-19 remain, including the impact of new virus strains, the risk of renewed restrictions and the uncertainty of successful administration of effective treatments and vaccines. In response to the current economic environment and impacts of COVID-19, we reduced our workforce during the first quarter of 2021 to adjust our business to expected lower levels of activity and operate in a sustainable and cost-efficient manner.

In response to the outbreak of the COVID-19 pandemic in 2020, we adopted a work-from-home system for all office-based employees and deployed additional safety protocols at our operating sites in order to keep the field-based employees and contractors supporting our operations safe while continuing operations running without material disruption. Our Crisis Management Team continues to monitor public health data and guidance, engages with peer companies, and participates with industry associations to ensure alignment with guidance for employee health and safety. In the first quarter of 2021, we began a phased return-to-office program while continuing to follow enhanced safety standards and best practices, including enhanced daily cleaning in common spaces of office locations, required use of facial coverings in common spaces, restricting use of conference rooms and group gatherings, adherence to social distancing requirements and establishing training requirements and procedures.

Our revenue, profitability and ability to return cash to shareholders depend substantially on factors beyond our control, such as economic, political and regulatory developments as well as competition from other sources of energy. Prices for crude oil, natural gas and NGLs can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for crude oil, natural gas and NGLs, as well as market uncertainty, economic conditions and a variety of additional factors. Commodity prices have experienced significant fluctuations in recent years and may continue to fluctuate widely in the future. Commodity prices have moderately increased in recent months due to improving economic activity and increased energy demand following government sponsored stimulus programs and easing of COVID-19 restrictions in certain regions. Following historic production cuts in 2020 to balance oil markets, OPEC and other non-OPEC oil-producing countries, including Russia, announced plans on April 1, 2021 to gradually curb previously implemented production cuts in response to improved economic activity and reductions in the surplus of inventory. Despite commodity price increases in recent months, uncertainties related to COVID-19 and the balance between the supply of and demand for crude oil and natural gas remain.

In an effort to improve price realizations from the sale of our crude oil, natural gas and NGLs, we manage our commodities marketing activities in-house, which enables us to market and sell our crude oil, natural gas and NGLs to a broader array of potential purchasers. We enter into crude oil, natural gas and NGL sales contracts with purchasers who have access to transportation capacity, utilize derivative financial instruments to manage our commodity price risk and enter into physical delivery contracts to manage our price differentials. During the first quarter of 2021, our crude oil price differentials averaged $1.58 per barrel discount to the NYMEX West Texas Intermediate crude oil index price. Due to the availability of other markets and pipeline connections, we do not

Additionally, we sell a significant amount of our crude oil production through gathering systems connected to multiple pipeline and rail facilities. These gathering systems, which originate at the wellhead, reduce the need to transport barrels by truck from the wellhead, helping remove trucks from local highways and reduce greenhouse gas emissions. As of March 31, 2021, 90% of our gross operated crude oil production and substantially all of our gross operated natural gas production were connected to gathering systems.

You should read the following summary financial data in conjunction with (i) “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and (ii) our historical consolidated financial statements and related notes thereto, in each case, included in our 2020 Annual Report and 2021 10-Q, which are incorporated by reference into this offering memorandum. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable. The financial information included or incorporated by reference in this offering memorandum may not be indicative of our future results of operations, financial position and cash flows. As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the consolidated financial statements of the Successor are not comparable to the consolidated financial statements of the Predecessor. See “Basis of presentation” above for more information.

The following summary historical consolidated financial data for the Successor period from November 20, 2020 through December 31, 2020, the Predecessor period from January 1, 2020 through November 19, 2020 (the “2020 Predecessor Period”), and for the years ended December 31, 2019 and 2018 and the balance sheet data as of December 31, 2020 and 2019 have been derived from our audited consolidated financial statements, which are incorporated by reference in this offering memorandum. The summary historical consolidated financial data for the three months ended March 31, 2021 and 2020 and the balance sheet data as of March 31, 2021 have been derived from our unaudited consolidated financial statements, which are incorporated by reference in this offering memorandum. The balance sheet data as of March 31, 2020 and December 31, 2018 are not included or incorporated by reference into this offering memorandum. The summary historical consolidated financial data does not give effect to the Williston Basin Acquisition or the Permian Basin Sale.


	Successor		Predecessor		Successor		Predecessor

	Three months ended March 31,				Period from Nov. 20, 2020 through Dec. 31, 2020		Period from Jan. 1, 2020 through Nov. 19, 2020		Year ended December 31,
	2021		2020						2019		2018

	(in thousands)
Statement of operations data:
Revenues:
Oil and gas revenues	$	245,461	$	239,128	$	86,442	$	603,585	$	1,408,771	$	1,590,024
Purchased oil and gas sales	48,460		86,278		7,227		186,367		408,791		550,344
Midstream revenues	61,312		56,411		26,031		166,631		212,208		120,504
Other services revenues	226		5,981		215		6,836		41,974		61,075
Total revenues	355,459		387,798		119,915		963,419		2,071,744		2,321,947
Expenses:
Lease operating expenses	35,260		49,769		17,841		118,372		223,384		193,912
Midstream expenses	27,898		13,084		10,572		42,987		62,146		32,758
Other services expenses	—		4,931		—		6,658		28,761		41,200
Gathering, processing and transportation expenses	15,711		29,464		9,124		85,896		128,806		107,193
Purchased oil and gas expenses	48,410		85,203		7,357		185,893		409,180		553,461


Production taxes	16,280		19,326		5,938		45,439		112,592		133,696
Depreciation, depletion and amortization	39,990		203,755		16,094		291,115		787,192		636,296
Exploration expenses	423		1,168		—		2,748		6,658		27,432
Rig termination	—		—		—		1,279		384		—
Impairment	3		4,823,678		—		4,937,143		10,257		384,228
General and administrative expenses	20,737		31,174		14,224		145,294		123,506		121,346
Litigation settlement	—		—		—		22,750		20,000		—
Total operating expenses	204,712		5,261,552		81,150		5,885,574		1,912,866		2,231,522
Gain (loss) on sale of properties	88		11,226		11		10,396		(4,455)		28,587
Operating income (loss)	150,835		(4,862,528)		38,776		(4,911,759)		154,423		119,012
Other income (expense):
Net gain (loss) on derivative instruments	(181,515)		285,322		(84,615)		233,565		(106,314)		28,457
Interest expense, net of capitalized interest	(8,697)		(95,757)		(3,168)		(181,484)		(176,223)		(159,085)
Gain (loss) on extinguishment of debt	—		83,887		—		83,867		4,312		(13,848)
Reorganization items, net	—		—		—		786,831		—		—
Other income (expense)	458		63		(402)		1,407		440		121
Total other income (expense), net	(189,754)		273,515		(88,185)		924,186		(277,785)		(144,355)
Loss before income taxes	(38,919)		(4,589,013)		(49,409)		(3,987,573)		(123,362)		(25,343)
Income tax benefit	3,654		254,738		3,447		262,962		32,715		5,843
Net loss including non-controlling interests	(35,265)		(4,334,275)		(45,962)		(3,724,611)		(90,647)		(19,500)
Less: Net income (loss) attributable to non-controlling interests	8,327		(23,414)		3,950		(84,283)		37,596		15,796
Net loss attributable to Oasis	$	(43,592)	$	(4,310,861)	$	(49,912)	$	(3,640,328)	$	(128,243)	$	(35,296)


	Successor		Successor		Predecessor

	As of March 31,		As of December 31,
	2021		2020		2019		2018

	(in thousands)
Balance sheet data:
Cash and cash equivalents	$	113,054	$	15,856	$	20,019	$	22,190
Total property, plant and equipment, net	1,719,549		1,728,787		6,977,776		7,027,109
Total assets	2,297,178		2,159,037		7,499,253		7,626,142
Long-term debt	674,238		710,000		2,711,573		2,735,276
Total stockholders’ equity	962,003		1,012,739		3,837,081		3,918,880


	Successor		Predecessor		Successor		Predecessor

	Three months ended March 31,				Period from Nov. 20, 2020 through Dec. 31, 2020		Period from Jan. 1, 2020 through Nov. 19, 2020		Year ended December 31,
	2021		2020						2019		2018
	(in thousands)
Other financial data:
Net cash provided by operating activities	$	190,413	$	107,775	$	95,255	$	202,936	$	892,853	$	996,421
Net cash used in investing activities	(41,868)		(130,768)		(9,881)		(92,403)		(828,756)		(1,613,536)
Net cash provided by (used in) financing activities	(55,717)		136,976		(85,702)		(109,998)		(66,268)		(622,585)
Adjusted EBITDA(1)	169,200		166,982		55,119		592,342		1,039,549		958,682

Management believes Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of Adjusted EBITDA. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. We believe that Adjusted EBITDA is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet debt service requirements.


	Successor		Predecessor		Successor		Predecessor

	Three months ended March 31,				Period from Nov. 20, 2020 through Dec. 31, 2020		Period from Jan. 1, 2020 through Nov. 19, 2020		Year ended December 31,
	2021		2020						2019		2018
	(in thousands)
Adjusted EBITDA reconciliation to net loss including non-controlling interests:
Net loss including non-controlling interests	$	(35,265)	$	(4,334,275)	$ (45,962)		$	(3,724,611)	$	(90,647)	$	(19,500)
(Gain) loss on sale of properties	(88)		(11,226)		(11)		(10,396)		4,455		(28,587)
(Gain) loss on extinguishment of debt	—		(83,887)		—		(83,867)		(4,312)		13,848
Net loss (gain) on derivative instruments	181,515		(285,322)		84,615		(233,565)		106,314		(28,457)
Derivative settlements	(22,596)		5,020		(76)		224,416		19,098		(213,528)
Interest expense, net of capitalized interest(1)	8,697		95,757		3,168		181,484		176,223		159,085
Depreciation, depletion and amortization	39,990		203,755		16,094		291,115		787,192		636,296
Impairment(2)	3		4,823,678		—		4,937,143		10,257		384,228
Rig termination	—		—		—		1,279		384		—
Exploration expenses	423		1,168		—		2,748		6,658		27,432
Equity-based compensation expenses	2,198		6,807		270		31,315		33,607		29,273
Litigation settlement(3)	—		—		—		22,750		20,000		—
Reorganization items, net	—		—		—		(786,381)		—		—
Income tax benefit	(3,654)		(254,738)		(3,447)		(262,962)		(32,715)		(5,843)
Other non-cash adjustments	(2,023)		245		468		2,324		3,035		4,435
Adjusted EBITDA	$	169,200	$	166,982	$	55,119	$	592,342	$	1,039,549	$	958,682
Adjusted EBITDA attributable to OMP	(56,459)		(72,928)		(24,473)		(197,684)		(263,995)		(177,512)
Adjusted EBITDA attributable to DevCo interests	—		26,535		7,734		70,017		105,053		108,754
Cash distributions from OMP to Oasis	13,266		13,237		—		53,040		45,342		30,804
Adjusted EBITDA attributable to Oasis	$	126,007	$	133,826	$	38,380	$	517,715	$	925,949	$	920,728

(1) For the three months ended March 31, 2020, interest expense includes specified default interest charges of $29.3 million related to the Amended and Restated Credit Agreement, dated as of October 16, 2018 (as amended prior to the Emergence Date, the “Predecessor Credit Facility”), by and among the Predecessor, as borrower, the lenders party thereto, and Wells Fargo, as administrative agent and $25.9 million related to the OMP Credit Facility. In addition, for the 2020 Predecessor Period, interest expense includes specified default interest charges of $30.3 million related to the Predecessor Credit Facility and $28.0 million related to the OMP Credit Facility. These specified default interest charges were waived upon our emergence from bankruptcy.

(3) During the year ended December 31, 2019, we recorded a $20.0 million loss contingency accrual, which represented our estimate of the probable amount that would be incurred from our legal proceedings with Mirada Energy, LLC, Mirada Wild Basin Holding Company, LLC and Mirada Energy Fund I, LLC (collectively “Mirada”) based upon available information at that time. On September 28, 2020, we entered into the Mirada Settlement Agreement, which provides for, among other things, payment of $42.8 million to certain Mirada related parties and the release of all claims asserted in the case Mirada filed against us. We recorded an incremental $22.8 million loss accrual for the settlement during the 2020 Predecessor Period. See “Item 8. Financial Statements and Supplementary Data—Note 24—Commitments and Contingencies” included in our 2020 Annual Report and incorporated by reference into this offering memorandum for more information about our legal proceedings.

The following table presents summary data with respect to our estimated net proved oil and natural gas reserves as of the dates indicated. For additional information regarding our reserves, as well as the impact of the SEC’s rules governing the presentation of reserve information, see Item 1. “Business” included in our 2020 Annual Report and incorporated by reference into this offering memorandum. The reserve estimates presented in the table below as of December 31, 2020, 2019 and 2018 are based on reports prepared by DeGolyer and MacNaughton, independent reserve engineers, and were prepared consistent with the SEC’s rules regarding oil and natural gas reserve reporting that are currently in effect. The following table does not give effect to the Williston Basin Acquisition or the Permian Basin Sale.


	At December 31,
	2020		2019		2018
Reserves Data (1)
Estimated proved reserves:
Crude oil (MMBbls)	119.8		200.8		228.4
Natural gas (Bcf)	376.2		513.5		552.7
Total estimated proved reserves (MMBoe)	182.5		286.4		320.5
Percent crude oil	66%		70%		71%
Estimated proved developed reserves:
Crude oil (MMBbls)	85.4		113.4		144.5
Natural gas (Bcf)	262.7		314.0		339.4
Total estimated proved developed reserves (MMBoe)	129.2		165.8		201.1
Percent proved developed	71%		58%		63%
Estimated proved undeveloped reserves:
Crude oil (MMBbls)	34.3		87.4		83.9
Natural gas (Bcf)	113.5		199.5		213.3
Total estimated proved undeveloped reserves (MMBoe)	53.3		120.6		119.4
Future net revenues (in millions)	$	1,793.6	$	5,385.4	$	8,341.6
Standardized Measure (in millions)(2)	$	948.9	$	2,844.4	$	4,050.3
PV-10 (in millions)(3)	$	1,115.0	$	2,934.4	$	4,674.3

(1) Our estimated net proved reserves and related future net revenues, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic average first-day-of-the-month prices for the prior 12 months were $39.54 per Bbl for crude oil and $2.03 per MMBtu for natural gas, $55.85 per Bbl for crude oil and $2.62 per MMBtu for natural gas and $65.66 per Bbl for crude oil and $3.16 per MMBtu for natural gas for the years ended December 31, 2020, 2019 and 2018, respectively. These prices were adjusted by lease for quality, transportation fees, geographical differentials, marketing bonuses or deductions and other factors affecting the price received at the wellhead.

(2) Standardized Measure represents the present value of estimated future net cash flows from proved crude oil and natural gas reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect timing of future cash flows. Standardized Measure is based on internally-generated estimates and has not been included in reserve reports provided by DeGolyer and MacNaughton, independent reserve engineers.


	Successor		Predecessor		Successor		Predecessor

	Three months ended March 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
	2021		2020						2019		2018
Operating Data:
Net production volumes:
Crude oil (MBbls)	3,313		4,923		1,593		14,226		22,824		23,050
Natural gas (MMcf)	11,015		14,176		5,008		42,199		55,906		42,430
Oil equivalents (MBoe)	5,149		7,286		2,428		21,258		32,142		30,122
Average daily production (Boepd)	57,205		80,066		57,809		65,612		88,061		82,525
Average sales prices:
Crude oil average sales price (per Bbl)	$	56.09	$	43.22	$	43.36	$	36.75	$	55.27	$	61.84
Crude oil average realized price after the effect of derivative settlements(1)	49.11		44.24		43.36		48.13		55.89		52.65
Natural gas average sales price (per Mcf)(2)	5.41		1.86		3.47		1.91		2.64		3.88
Natural gas average realized price after the effect of derivative settlements(1)(2)	5.46		1.86		3.45		1.91		2.72		3.84
Average costs (per Boe):
Production costs(3)
Williston Basin	$	10.50	$	10.75	$	11.81	$	9.96	$	11.04	$	10.08
Permian Basin	5.72		12.16		6.44		7.39		10.10		8.31
Total
Lease operating expenses	6.85		6.83		7.35		5.57		6.95		6.44
Gathering, processing and transportation expenses	3.05		4.04		3.76		4.04		4.01		3.56
Production taxes	3.16		2.45		2.45		2.14		3.50		4.44
E&P general and administrative expenses	3.04		3.20		5.04		5.92		3.39		3.63
E&P Cash G&A(4)	2.72		2.29		5.04		4.41		2.07		2.48

(1) Average realized prices after the effect of derivative settlements include the cash received or paid for the cumulative gains or losses on our commodity derivatives settled in the periods presented, but do not include proceeds from derivative liquidations. Our commodity derivatives do not qualify for or were not designated as hedging instruments for accounting purposes.

(4) E&P Cash G&A, a non-GAAP financial measure, represents general and administrative (“G&A”) expenses less non-cash equity-based compensation expenses, other non-cash charges and G&A expenses attributable to the Company’s midstream business segment and other services. See “—Operational non-GAAP financial measure” below for a reconciliation of G&A expenses to E&P Cash G&A.

PV-10 is derived from Standardized Measure, which is the most directly comparable GAAP financial measure. PV-10 is a computation of Standardized Measure on a pre-tax basis. PV-10 is equal to Standardized Measure at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and gas properties. PV-10, however, is not a substitute for Standardized Measure. Our PV-10 measure and Standardized Measure do not purport to represent the fair value of our crude oil and natural gas reserves.

We define E&P Cash G&A as total G&A expenses less non-cash equity-based compensation expenses, other non-cash charges and G&A expenses attributable to midstream and others services. E&P Cash G&A is not a measure of G&A expenses as determined by GAAP. Management believes that the presentation of E&P Cash G&A provides useful additional information to investors and analysts to assess our operating costs in comparison to peers without regard to equity-based compensation programs, which can vary substantially from company to company.


	Successor		Predecessor		Successor		Predecessor

	Three months ended March 31,				Period from November 20, 2020 through December 31, 2020		Period from January 1, 2020 through November 19, 2020		Year Ended December 31,
	2021		2020						2019		2018
General and administrative expenses:	$	20,737	$	31,174	$	14,224	$	145,294	$	123,506	$	121,346
Equity-based compensation expenses	(1,688)		(6,621)		—		(29,746)		(32,251)		(27,910)
G&A expenses attributable to midstream and other services	(5,062)		(7,888)		(1,989)		(21,791)		(24,805)		(18,864)
E&P Cash G&A	$	13,987	$	16,665	$	12,235	$	93,757	$	66,450	$	74,572

An investment in the notes involves risks. You should carefully consider the risks described below, as well as the risks disclosed in Item 1A. “Risk Factors” in our 2020 Annual Report, which are incorporated herein by reference, and the other information contained and incorporated by reference into this offering memorandum, before making an investment decision. If any of the described risks actually were to occur, our business, financial condition, results of operations or growth prospects could be affected materially and adversely. In that case, our ability to fulfill our obligations under the notes could be materially affected, and you could lose all or part of your investment. Furthermore, the COVID-19 pandemic (including federal, state and local governmental responses, broad economic impacts and market disruptions) has heightened risks discussed in the risk factors described or incorporated by reference in this offering memorandum.

This offering memorandum and the documents we have incorporated by reference into this offering memorandum also include forward-looking statements that involve risks and uncertainties, some of which are described in the documents incorporated by reference into this offering memorandum. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of various factors, including the risks and uncertainties faced by us described below or incorporated by reference into this offering memorandum.

Our ability to achieve the anticipated benefits of the Williston Basin Acquisition will depend in part upon whether we can integrate the acquired assets and operations into our existing businesses in an efficient and effective manner. We may not be able to accomplish this integration process successfully. The successful acquisition and integration of producing properties, including those acquired from QEP, a wholly-owned subsidiary of Diamondback, requires an assessment of several factors, including:

Our review may not reveal all existing or potential problems or permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections were not performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. The integration process may be subject to delays or changed circumstances, and we can give no assurance that the acquired properties will perform in accordance with our expectations or that our expectations with respect to integration or cost savings as a result of the Williston Basin Acquisition will materialize. The Williston Basin Acquisition involves risks that may cause our business to suffer, including:

We have incurred significant costs associated with the Williston Basin Acquisition and expect to continue to incur significant costs associated with combining the operations of the assets with our operations. The substantial majority of the expenses resulting from the Williston Basin Acquisition were composed of transaction costs related to the Williston Basin Acquisition and our integration efforts. Unanticipated costs may also be incurred in the integration process. Although we expect that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the acquired assets with our assets, should allow us to offset incremental transaction and acquisition-related costs overtime, this net benefit may not be achieved in the near term, or at all.

Further, the notes will be issued prior to the consummation of the Williston Basin Acquisition and the Primary Permian Basin Sale. If the Williston Basin Acquisition is not consummated on or prior to September 27, 2021 (or such later date if the Outside Date is extended pursuant to the Williston PSA) or, if prior to such date, the Williston PSA is terminated without the Williston Basin Acquisition being consummated, then in either case, the notes will be redeemed at a redemption price equal to 100% of the issue price of the notes, plus accrued and unpaid interest, if any, to, but excluding, the redemption date.

The Primary Permian Basin Sale is subject to customary closing conditions. We may not be able to consummate the Primary Permian Basin Sale on the terms contemplated by the Permian PSA or at all, or obtain the proceeds that could be realized from the transaction, if the required consents and other customary closing conditions are not satisfied. Any difficulties with respect to the consummation of this transaction may adversely affect our business, financial condition or results of operations. In particular, to the extent the Primary Permian Basin Sale fails to close on the terms contemplated by the Permian PSA, or if we receive lower cash consideration than originally planned, then the amount of cash that we may allocate to the funding of our capital budget, and the timing of such funding, will be affected. Additionally, failure to consummate the Primary Permian Basin Sale on the terms contemplated by the Permian PSA may adversely affect our intended strategy of prioritizing our Williston Basin assets and may divert management’s focus on such strategy.


			Acquired Williston Assets(1)
Net Williston Acreage (in thousands)			95
Williston Acreage Held by Production			99%
Average Working Interest in Williston Acreage			84%
Williston Oil Production (Mbblpd)			17.7
Total Williston Production (Mboepd)			27.0


	Year Ended December 31,
	2020	2019
Production volumes:(1)
Oil and condensate (Mbbl)	7,137.2	7,992.8
Gas (Bcf)	12.0	14.0
NGL (Mbbl)	2,143.8	2,073.2
Total (Mboe)	11,284.9	12,403.8


	OAS	Acquired Williston Assets(1)	Divested Assets	Pro Forma(2)
Net Acreage (in thousands)	426	95	(24)	497
Oil Production (Mbblpd)	36.8	17.7	(5.8)	48.7
Total Production (Mboepd)	57.2	27.0	(7.2)	77.0


	Proved Developed				Proved Undeveloped
	Crude oil	Natural gas	Total	PV-10	Crude oil	Natural gas	Total	PV-10
	(MMBbls)	(Bcf)(1)	(MMBoe)(1)(2)	(in millions)(3)	(MMBbls)	(Bcf)(1)	(MMBoe)(1)(2)	(in millions)(3)
SEC pricing(4)	35.4	89.7	50.4	$ 350.4	3.6	3.7	4.2	$ 14.6
NYMEX Strip Pricing(5)	42.8	112.7	61.5	$ 765.7	3.8	3.9	4.5	$ 57.3