January Investor Presentation

January 2018 Investor Presentation

Forward-Looking / Cautionary Statements Forward-Looking Statements This presentation, including the oral statements made in connection herewith, contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company's drilling program, production, derivative instruments, capital expenditure levels and other guidance included in this presentation. When used in this presentation, the words "could," "should," "will, "believe," "anticipate," "intend," "estimate," "expect," "project," the negative of such terms and other similar expressions are intended to identify forward- looking statements, although not all forward-looking statements contain such identifying words. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the headings Risk Factors and Cautionary Statement Regarding Forward-Looking Statements included in the prospectus supplement. These include, but are not limited to, the Company s ability to consummate the acquisition discussed in this presentation, the Company's ability to integrate acquisitions into its existing business, changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as the Company's ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company's business and other important factors. Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, the Company s actual results and plans could differ materially from those expressed in any forward-looking statements. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law. Cautionary Statement Regarding Oil and Gas Quantities The Securities Exchange Commission (the SEC ) requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities of the exploration and development companies may justify revisions of estimates that were made previously. If significant, such revisions could impact the Company s strategy and future prospects. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves; however, we currently do not disclose probable or possible reserves in our SEC filings. In this presentation, proved reserves at December 31, 2016 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-themonth prices of $42.60 per barrel of oil and $2.47 per MMBtu of natural gas. The reserve estimates for the Company at year-end 2010 through 2016 presented in this presentation are based on reports prepared by DeGolyer and MacNaughton ("D&M"). We may use the terms that the SEC rules prohibit from being included in filings with the SEC, including "unproved reserves," "EUR per well" and "upside potential," to describe estimates of potentially recoverable hydrocarbons. These are the Company's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities have not been reviewed by independent engineers. Additionally, these quantities may not constitute "reserves" within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System or SEC rules and do not include any proved reserves. Estimated ultimate recovery ( EUR ) estimates and drilling locations have not been risked by Company management. Actual locations drilled and quantities that may be ultimately recovered from the Company's interests will differ substantially. There is no commitment by the Company to drill all of the drilling locations that have been attributed to these quantities. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling and completion services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, EUR per well and upside potential may change significantly as development of the Company's oil and gas assets provide additional data. Type curves do not represent EURs of individual wells. Our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. 2

Oasis Investment Highlights and Strengths Portfolio Strength Well positioned in the core of the two best U.S. oil basins Over 20 years of Williston core inventory that is resilient to low commodity prices and provides superior cash margins in mid to high WTI price world (1) Complimentary assets that mitigate business risk and enhance capital allocation options Operational Excellence Full-field development competencies Oilfield services relationships Integrated business model leverage Financial Strength Decreasing financial leverage and increasing shareholder returns Strong hedge book provides downside protection Material Management Participation Personally invested in the success of the company Management is a top ten active shareholder (2) 1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March 2014 2) Guidance issued 2/26/15 1) Assumes inventory as of 12/31/16 at 2017 guided rate of completions 2) Based on latest public filings as of 1/19/2018. Management includes 4 Named Executive Officers and Directors only. Excludes index funds / passive investors 3

A Top Unconventional Operator Focused on the Core of the Two Best US Oil Basins (1) Top Tier Asset Position Concentrated & controlled position 518k net acres in the Williston, with pending acquisition of ~20k in the Delaware (Permian) (2) Williston >90% held by production Inventory substantially all operated; Williston 100% and Permian 90% Manageable drilling requirements for HBP Over ~20 years of highly economic inventory in the Williston at 2017 completion levels and substantial running room in the Delaware upon acquisition closing 1,614 locations economic @ $45 WTI & lower in the Williston Over 600 core Delaware locations with substantial upside from additional stacked pay formations Capital Discipline and Returns Focused Continuing to improve economics Operational efficiencies and innovation in the Williston and Delaware Basins further increases shareholder value Testing completion designs across position; continuing to expand core Vertical integration capitalizes on Oasis depth of inventory and enhances shareholder returns Deleveraging balance sheet in current commodity price environment Protecting cash flow through strong hedge book Strength of asset and the Oasis team drive production growth of ~15% in 2017 & 2018 Disciplined acquisition strategy 1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March 2014 2) Guidance issued 2/26/15 1) As of 12/31/16 unless otherwise noted 2) Delaware acreage as of 12/11/17 announcement 4

Returns-Focused, Oil-Weighted, Core-Concentrated and Leveraging Operational Scale Our Williston Asset Core Extended Core Combined Stats Net Acres (thousand) (1) Fairway Williston Delaware PF OAS 517.8 20.3 538.1 Our Delaware Asset Core Core & Extended Core Net Inventory (1) Williston Delaware PF OAS 1,085 507 1,592 Core IRR (2) Williston Delaware PF OAS >75% >75% >75% Active Rigs (3) Williston 5 Delaware [x]f 1 PF OAS 6 Nov. 2017 Production (mboepd) Williston Delaware PF OAS >72 ~3.5 >75.5 1) 2) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March 2014 Leveraging Operational Scale and Full-field Development Experience Across Our Guidance issued 2/26/15 1) 2) 3) Oasis s Williston Basin Inventory as of 12/31/2016, Delaware as of 12/11/17 Assumes $55 WTI and $3.00 HH Oasis active rigs as of January 1, 2018 Premier Oil Basins with the Objective of Optimizing Capital Efficiency and Full-Cycle Returns 5

Unique Value and Strategic Opportunities Derived from our Vertically Integrated Platform Strategic Advantages Oasis Midstream Our midstream assets allow us to minimize operating costs and ensure quality, timing & capacity of service Ability to work ahead of potential bottlenecks and maintain regulatory compliance Ensures access to key delivery points Our Delaware asset is largely undedicated for midstream assets and services Potential to provide LOE and other cost savings Oasis Midstream Partners (NYSE: OMP) provides access to optimal cost of capital Oasis funded midstream capital returned through future drop down potential of retained interest in DevCos Option to develop future projects at OAS and drop to OMP Oasis Well Services OWS provides material cost-advantages, availability of quality service and flexibility, particularly when operating in active basins Enhances overall operational scale and intelligence Natural hedge against cost inflation in a tightening services market Supply chain management advantage, as many Oasis vendors have operations in both the Williston and the Delaware Long-standing substantial relationships will allow Oasis to efficiently build scale in the Delaware Assets and Capabilities Oil and natural gas gathering & processing (LOE savings and surety of midstream services) Crude oil transportation and storage (G,M,&T savings) Freshwater distribution and produced water gathering and disposal (LOE savings, especially in high water-cut areas Two OWS spreads currently running in the Williston Opportunity to expand operations into the Delaware Basin Possibly moving one OWS spread And/or forming a third spread to work in the Delaware Top tier efficiency 6

Recent Accomplishments & Highlights Improving Economics through Innovation Core Bakken production results continue to improve, driving production to over 70 mboepd in October and over 72 mboepd in November, already surpassing planned 2017 exit rate Further completion design innovation improving well economics Dialing in proppant intensity, water volumes pumped, and stage counts Maximizing economics across DSUs Infrastructure Delivering Increased Margins Better oil differentials/realizations diffs expected to be between $0.50 and $1.00 in 4Q17 Capturing increasing gas volumes in Wild Basin and improving gas realizations Improved operating costs Completed Oasis Midstream Partners ( OMP ) IPO in 3Q17 Oasis Advantages Transferable to Acquired Assets Ability to leverage existing supply chain vendor relationships Basin leading completion designs driving well performance Low cost operator Opportunity to leverage OMP s operating capabilities and footprint Multiplying success through core bolt-on acquisitions Improving capital efficiency & operational performance 7

Mboepd Delaware Williston Update to 2017 and Issuance of 2018 Capital Plan Increasing 4Q17 production guidance from 69-72Mboepd to 71-73Mboepd Combined exit rate for 2018 production of >88 Mboe/d (1) Williston: 83+ Mboepd Delaware: 5 Mboepd Production Highlights 2018 Development Plan Expect to drill and complete 100 to 120 operated wells ~70% WI 5 rigs throughout the year +Non-op activity 2017 well costs are $6.8mm (4mmlb) and $7.7mm (10mmlb) Targeting ~$500mm of non-core asset sales in 2018 Differentials expected to be below $2.00 per bbl Production Growth Profile Expect to drill 16 to 20 wells, complete 6 to 8 wells 1 rig initially with potential to add a second in 2H18 ~$100mm of total capital Minimal outspend at $55 WTI on Delaware asset 100 80 60 50 66 62 72 > 88 83 (1) Targeted spending within cash flow at $55 WTI, excluding infrastructure projects Complementary infrastructure projects expected to be dropped to MLP in future 40 20 0 2016 2017E 2016 Exit 2017E Exit 2018E Exit Williston Delaware 1) Exit rate does not account for potential production loss from anticipated Williston Basin divestitures 8

Williston Basin 9

Robust Inventory in the Heart of the Williston Basin (1) Enhanced Completion Expansion Increased Strength of Inventory (Net/Gross Locations) MONTANA Sheridan Roosevelt Montana Richland NORTH DAKOTA Divide Williams Red Bank Painted Woods Indian Hills (1 rig) Foreman Butte McKenzie Wild Basin (2 rigs) Other operator non-core enhanced completions Cottonwood Dunn Burke Alger (2 rigs) Mountrail 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0 Breakeven Oil Price (WTI) 770 483 (Gross) (Net) 844 602 (Gross) (Net) 1,459 1,084 YE16 YE16 YE16 Core Extended Core Fairway Core Extended Fairway Below $40 Below $45 Core $45 to $55 (Gross) (Net) 3,073 operated locations in the heart of the play 770 core locations (~1/3 in Wild Basin) 1,614 locations with breakeven prices below $45 WTI Equates to >20 years of remaining highly economic Williston inventory at 2017 pace of completions Further upside with increasing frac intensity across all three areas Anticipated Oasis 2018 non-core enhanced expansion tests 1) As of 12/31/16 10

$ per Boe $ in Millions Operational Excellence: Demonstrated Capital Efficiency & Low Operating Cost Structure Track Record of Efficient Full-Field Development Substantially Improving Capital Efficiency in Core Experienced in full field horizontal development targeting stacked pays Over 750 wells drilled since 2010, averaging ~10,000 feet of lateral length through multiple development zones Spud to rig release timing decreased from 21.6 days in 2014 to 13.6 days Continuously improving frac efficiency through large pad development around zipper fracs and optimizing logistics Demonstrated success in bringing down well costs over time Improved cost structure $15 $12 $9 $6 $3 $- $14 $8.5 $13 $10.6 2014 Base 2014 High Intensity Well Level F&D ($ per Boe) $8 $5 $6.8 Current Core Well Cost ($MM) $20 $15 $10 $5 $0 Williston Slickwater Well Cost ($MM) Improving Operating Cost Structure $12 $10 $10.6 $12 $10 $10.18 $9.34 $8 $6 $7.7 $6.8 $8 $6 $7.84 $7.35 $7.50 7.00 $5.72 $4.76 $4 $2 $0 4Q14 10MM LB Frac 4MM LB Frac 50 Stages $4 $2 $0 $2.80 $2.65 $1.00 $0.50 2014 2015 2016 4Q17E 2014 2015 2016 2017E 4Q17E LOE ($/Boe) Differential to WTI ($/Bbl) 11

Cumulative Avg Normalized Oil Rate (Mbbls) Cumulative Avg Normalized Oil Rate (Mbbls) Wild Basin High Intensity Type Curve and Performance Update Wild Basin Bakken Well Performance Wild Basin Three Forks Well Performance 350 300 Constrained Production 350 300 Constrained Production 250 250 200 200 150 150 100 100 50 50 0 0 50 100 150 200 250 300 350 400 Producing Days 50 Stg 4 mmlb (8 wells) 1,550 MBOE Type Curve Johnsrud 3BX (20 mmlb) Rolfson 3BX (10 mmlb) Recent 10mmlbs (10 wells) Wild Basin Highlights 0 0 50 100 150 200 250 300 350 400 Producing Days 50 Stage 4 mmlb (12 wells) 1,200 MBOE Type Curve Recent 10mmlbs (10 wells) Early time performance provides accelerated production versus type curve, positively impacting returns IRR >70% for Bakken wells at $50 WTI and improved Bakken differentials Assuming $6.8MM current well costs 50 stages & 4MM pound completion Innovation in well design yielding further improvements in economics $7.7MM well cost for 50 stages & 10MM pound completion Wild Basin represents approximately 1/3 of Core Williston inventory 12

IRR Cumulative Avg Normalized Oil Rate (Mbbls) Cumulative Avg Normalized Oil Rate (Mbbls) Williston Core (Ex. Wild Basin) High Intensity Type Curve and Performance Core (Ex. Wild Basin) Bakken Well Performance Core (Ex. Wild Basin) Three Forks Well Performance 250 Constrained Production 250 Constrained Production 200 200 150 150 100 100 50 50 0 0 30 60 90 120 150 180 210 240 270 Producing Days 1,090 MBOE Type Curve Bakken Avg (29 wells) 10mmlbs+ Indian Hills (3 wells) Teal (20mmlb equivalent) (4,400 ft lateral normalized 2x to a 10,000 ft lateral) 0 0 30 60 90 120 150 180 210 240 270 Producing Days 870 MBOE Type Curve Three Forks Avg (15 wells) Recent 10mmlbs (2 wells) Core (Ex. Wild Basin) Highlights Substantial improvements in well performance across our core acreage, not just in Wild Basin Additional upside remains with our active completion testing program. Limited data on 10+MM pound fracs outside of Wild Basin at present, but encouraging results from several peers yield potential for further performance increases above these type curves Core Ex. Wild Basin represents approximately 2/3 of our remaining Williston core inventory 13

Strategically Located Infrastructure in the Heart of the Williston OMP Asset Highlights Williston Midstream Asset Footprint (1) Gathering & Processing Assets in Wild Basin Approximately 86 miles of crude and gas gathering lines Divide Burke 80MMscfpd processing plant operational 200MMscfpd processing plant under construction Crude Oil Transportation and Storage Sheridan Cottonwood FERC-regulated crude mainline to DAPL receipt point 240Mbbls of storage to increase flexibility, minimize curtailments Freshwater Distribution and Produced Water Gathering and Disposal Extensive network of approximately 610 miles of water handling pipelines Only 45% of system constructed in Wild Basin as of YE2016 21 SWDs, including 3 in Wild Basin Roosevelt Hebron Richland Red Bank Indian Hills McKenzie Williams Wild Basin Johnson s Corner Alger Mountrail Strategic Advantage to Oasis Integrating development of upstream and midstream assets Reduces overall operating expense Increases oil and gas realizations Oasis funded midstream capital returned through future drop down potential of retained interest in Bobcat and Beartooth DevCos Williston Basin Oasis Midstream Project Area Dedicated, Undedicated Saltwater Disposal Wells (21) Crude/Gas/Water Pipelines Water Pipelines Core Extended Core Fairway Beartooth Acreage Dedication Bighorn / Bobcat Acreage Dedication Gas Processing Plant Johnson s Corner Connection Billings Dunn Stark 1) DevCo highlights are illustrative and do not resemble acreage dedications 14

Oil and Gas Infrastructure in the Williston Marketing Highlights 3 rd Party Crude Oil Gathering Infrastructure Crude oil gathering Realized $1.82/bbl differential in 3Q17 MONTANA NORTH DAKOTA Signing longer term contracts at fixed differentials Provides marketing flexibility to access to 4 pipeline and 10 different rail connection points 90% gross operated oil production flowing through pipeline systems in 3Q17 Gas gathering and processing Average realization of $3.50/mcf in 3Q17 Substantially all wells connected to gathering system 85% gas production captured in 3Q17, vs. North Dakota goal of 85% Infrastructure considerations Drives higher oil and gas realizations Provides surety of production when all infrastructure in place Need infrastructure in place when wells come on-line Regulatory environment Red Bank Painted Woods Foreman Butte Oasis acreage Oil gathering infrastructure Rail connection points Indian Hills Pipeline connection points Wild Basin North Cottonwood South Cottonwood Alger 15

Delaware Basin 16

Delaware Basin Transaction Summary Acquiring ~20.3K consolidated net acres in the core of the Delaware Basin oil window Acreage located in Loving, Ward and Winkler counties, the deepest part of the play and heart of oil-directed activity, with multistacked pay through known productive formations Adds 507 high-return, oil-weighted and low-risk net core drilling locations, with material upside Materially delineated position November 2017 production of ~3.5 mboe/d (78% is oil, ~$170MM of PDP value) (1) $946 million purchase price financed with a mix of common stock and cash (expected February 2018 close) Common Stock issued to sellers (EnCap / Pinebrook): 46 million shares Public Common Stock offering: 32 million shares ($302.6 million net proceeds) Remainder to be initially financed with cash from RBL facility Anticipate selling $500 million of attractive, non-core Williston Basin assets, helping the purchase of high-return core assets (consolidating into high full-cycle returns) Accretive to NAV / share, full-cycle returns and liquidity / leverage (post-asset sales) Attractive Valuation below relevant geographical comparable transactions Highly de-risked and purchased in a much higher commodity price environment New Delaware Basin asset is highly complementary to our top-tier Williston Basin position Synergies with our existing operational scale, vertical integration (OMS/OMP and OWS) and deep experience in unconventional full-field development (largely undedicated acreage provides midstream upside) Continuing to drive value in the Williston through technical and operational expertise, along with best-in-class capital efficiency 1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March 2014 2) Guidance issued 2/26/15 Now Strategically Positioned in the Core of the Two Best U.S. Oil Basins 1) Assumes 11/30/2017 NYMEX strip pricing 17

Core Delaware Basin Assets with Highly Attractive Attributes Key Asset Highlights Premier Position in the Core of the Delaware Advantaged geologic position Deepest part of the Delaware Basin Thick reservoirs with high OOIP Oil-rich and overpressured Ideal for full-scale development Highly contiguous blocks of acreage Ample take-away infrastructure Acreage position built for long laterals Largely configured for 2-mile laterals Operated with manageable drilling required for HBP Top-tier well results Recently drilled wells are outperforming offset operators 1.2MMBOE type curve Accomplished strong results with ~1,600 lb/ft completions vs. ~2,000 lb/ft of offset operators Material midstream development opportunities Organic midstream growth opportunities inherent in assets Acreage largely undedicated for hydrocarbon gathering and completely undedicated for water gathering Attractive avenue for growth for OMP Acquisition Overview Gross Acres (thousands) 40.5 Net Acres (thousands) 20.3 % Operated 90% % Average Core Operated Working Interest 76% 1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with November Sanish that 2017 were Production divested in March (boe/d) 2014 2) Guidance issued 2/26/15 ~3,500 November 2017 Production % Oil 78% 18

Thick, Multi-Stacked Pay Potential with Large Inventory Upside Formation Type Log (Not to Scale) Development Pattern Wells per DSU Column Thickness Delaware Basin Net Inventory Bone Spring Lime / Avalon 6+ 1,000 1 st Bone Spring 6+ 650 507 2nd Bone Spring 4+ 700 BS 2 Lower Shale 6+ 250 Core Total Potential Locations 3rd Bone Spring 4 250 Delaware Basin Gross Operated Inventory Wolfcamp A Upper Lower 6 6 190 180 Wolfcamp B Upper Lower 6 6 180 150 601 Wolfcamp C 6 250 Core Inventory Additional Upside Total 34 / 56+ 1,200 / 3,800 Core Total Potential Locations 19

OAS Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 Peer 16 Peer 17 Peer 18 Peer 19 Contiguous Acreage Blocks Combined with High Oil Cuts Deliver Efficient and Compelling Development Opportunities Summary Highlights Assets in the Deepest and Oiliest Part of the Play Acreage located in the black oil window with high reservoir pressure delivering outstanding well performance results Acreage is located in the deepest and oiliest area of the Delaware basin Continuous formation targets allow long lateral development Approximately 2/3 of identified locations are two-mile laterals Highest oil cut among Delaware peers (Wolfcamp A&B) 100% ~85% 80% 60% 40% 20% 0% Source: IHS Offset operators: APC, CPE, CRZO, CDEV, CVX, XEC, CXO, COP, DVN, FANG, EOG, HK, JAG, MTDR, NBL, PDCE, REN, RSPP, WPX 20

Operators Unlocking Formation Targets with Strong Well Performance 2 1 8 15 21 6 17 29 26 27 28 14 20 10 3 18 30 5 16 23 22 9 13 11 24 25 7 4 19 12 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 Lateral 180 IP Rate / Compl Well Name Operator Length Selected Wells Lateral (ft) 180 1,000' IP (Bbls) Rate / Compl Date Well Name Operator 2nd Bone Spring Length (ft) 1,000' (Bbls) Date Ludeman I 3 Ludeman I Well 3 Name RSP 2nd Permian Bone Spring Lateral 7,109 RSP Operator 3rd Permian Bone Spring Length 7,109(ft) 180 IP 68Rate / 1,000' 68(Bbls) 4/16/2017 Compl 4/16/2017 Date Rudd Draw 26-21 1H RSP 2nd 3rd Permian Bone Spring 6,707 135 12/29/2016 Ludeman Rudd University Draw I Blk 326-21 20 1305H 1H RSP Exxon Permian 7,109 6,707 7,894 135 68 72 12/29/2016 4/16/2017 8/2/2016 University Miami Beach Blk 34-123 20 1305H Exxon Cimarex 3rd Bone Spring7,894 4,348 180 72 8/2/2016 1/3/2017 Rudd Miami University Draw Beach Blk 26-21 34-123 21 1804H 1H RSP Cimarex ExxonPermian 6,707 4,348 3,256 135 180 205 12/29/2016 1/14/2015 1/3/2017 University Blk 20 21 1305H 1804H Exxon Wolfcamp A 7,894 3,256 205 72 1/14/2015 8/2/2016 Miami Hughes Beach & Talbot 34-123 75-24 2H Cimarex Anadarko Wolfcamp A 4,348 4,821 180 89 1/3/2017 1/8/2016 University Hughes UL Rock & Of Blk Talbot Ages 21 1804H 75-24 3922-17 2H 1H Exxon Anadarko Felix II 10,196 3,256 4,821 205 89 71 1/14/2015 9/21/2016 1/8/2016 UL Hughes Rock & Of Talbot Ages 75-23 3922-17 2H 1H Felix Anadarko II Wolfcamp A 10,196 4,672 136 71 12/11/2016 9/21/2016 Hughes UTL 4344-21 & Talbot 1H 75-24 75-23 2H Anadarko Jagged Peak 4,821 4,672 9,996 136 89 91 12/11/2016 7/29/2016 1/8/2016 UL UTL University Rock 4344-21 Of Blk Ages 1H 20 1311H 3922-17 1H Felix Jagged ExxonII Peak 10,196 9,996 9,666 71 91 63 9/21/2016 7/29/2016 8/10/2016 Hughes University UTL L. J. & Beldin Blk Talbot 201211-17 1311H 75-23 2H3H Anadarko Exxon Jagged Peak 4,672 9,666 9,561 136 63 76 12/11/2016 8/10/2016 9/24/2016 UTL Caprito 4344-21 L. J. 99 Beldin 302H 1H1211-17 3H Jagged Abraxas Peak 9,996 9,561 4,460 103 91 76 11/11/2016 7/29/2016 9/24/2016 University Caprito RK-Utl 3031B-17 99 Blk 302H 20 1311H 1H Exxon Abraxas Jagged Peak 10,432 9,666 4,460 103 63 65 11/11/2016 11/18/2016 8/10/2016 UTL RK-Utl University L. 3031B-17 J. Beldin 20-4 Lov 1211-17 1H3H 3H Jagged Shell Peak 10,432 9,561 4,578 115 76 65 11/18/2016 9/24/2016 1/18/2016 Caprito University Deuces 99 Wild 20-4 302H 28-17 Lov 2H 3H Abraxas Shell Anadarko 4,460 4,578 4,723 103 115 71 11/11/2016 1/18/2016 2/10/2016 RK-Utl Deuces UL 21 Bighorn 3031B-17 Wild 28-17 1H 1H2H Jagged Anadarko Forge Energy Peak 10,432 4,723 9,400 65 71 93 11/18/2016 2/10/2016 5/29/2016 University UL Mesquite 21 Bighorn Heat 20-41H 28-41 Lov 3HUnit 1H Shell Forge Anadarko Energy 4,578 9,400 6,552 115 93 89 10/31/2016 1/18/2016 5/29/2016 Deuces Mesquite Corbets Wild 34-149 Heat 28-17 28-41 2WA2H Unit 1H Anadarko Callon 4,723 6,552 9,723 89 71 10/31/2016 11/27/2016 2/10/2016 Corbets UL 21 Lead Bighorn 34-149 King 4035-16 1H 2WA 1H Forge Callon Felix IIEnergy 9,400 9,723 4,850 71 93 11/27/2016 12/31/2016 5/29/2016 Mesquite UL Lead 21 Pahaska King Heat 4035-16 28-41 1H Unit 1H 1H Anadarko Felix Forge IIEnergy 6,552 4,850 4,301 101 89 93 10/31/2016 12/31/2016 11/7/2016 Corbets UL Quinn 21 37 Pahaska 34-149 2H 1H 2WA Callon Forge WPX Energy 9,723 4,301 4,780 101 71 81 11/27/2016 11/7/2016 3/17/2017 Quinn UL Lead 21 37 Yellowtail King 2H 4035-16 1H 1H Felix WPX Forge II Energy 4,850 4,780 9,512 93 81 87 12/31/2016 3/17/2017 3/1/2017 UL Stella 21 State Pahaska Yellowtail 34-208 1HWRD 1H Forge Shell Energy 4,301 9,512 4,770 101 68 87 11/7/2016 1/31/2017 3/1/2017 Quinn Stella State 37 2H 34-208 WRD 1H 2H WPX Shell Energy 4,780 4,770 68 84 81 3/17/2017 1/31/2017 1/24/2017 Stella UL 21 18 State Yellowtail Dyk 1H 34-208 1HWRD 2H Shell Forge Energy 9,512 4,770 6,893 84 87 1/24/2017 3/30/2017 3/1/2017 Stella UL 18 State Dyk 1H 34-208 WRD 1H Shell Forge Energy Wolfcamp B 4,770 6,893 68 87* 1/31/2017 3/30/2017 Stella HALEY State 28-43 34-208 4H WRD 2H Shell Cimarex Wolfcamp B 4,770 4,928 84 25 1/24/2017 9/10/2017 UL HALEY UTL 182932-17 Dyk 28-43 1H 1H 4H Forge Cimarex Jagged Energy Peak 10,321 6,893 4,928 25 87 69 3/30/2017 9/10/2017 6/28/2016 UTL 2932-17 38-17 2H1H Jagged Wolfcamp Peak B 10,321 4,529 69 81 6/28/2016 3/31/2017 HALEY UTL Mitchell 38-17 28-43 39 2H W101PA 4H Cimarex Jagged Mewbourne Peak 4,928 4,529 4,801 118 25 81 9/10/2017 3/31/2017 2/6/2017 UTL Mitchell 2932-17 39 W101PA 1H Jagged Mewbourne Wolfcamp Peak C 10,321 4,801 118 69 6/28/2016 2/6/2017 UTL University 38-17 B20 2H 1W Jagged Mewbourne Wolfcamp Peak C 4,529 4,847 81 58 3/31/2017 1/14/2017 Mitchell University 39 B20 W101PA 1W 12 Mewbourne 4,801 4,847 4,585 118 58 67 1/14/2017 3/24/2017 2/6/2017 University B20 12 1_W201PA Mewbourne Wolfcamp C 4,585 4,551 67 63 3/24/2017 2/25/2016 University B20 B21 1W 1_W201PA 8 Mewbourne 4,847 4,551 4,444 58 63 38 10/28/2016 1/14/2017 2/25/2016 University B20 B21 12 8 Mewbourne 4,585 4,444 67 38 10/28/2016 3/24/2017 University B20 1_W201PA Mewbourne 4,551 63 2/25/2016 University B21 8 Mewbourne 4,444 38 10/28/2016 Source: IHS, Drilling Info and Public Data. 21

Average Oil Production (bbl/d per 1000') Exceptional Well Performance With Potential Completion Design Upside Summary Highlights Normalized Average Oil Rate (Wolfcamp A & B) (1) Peer-leading well performance Wells flow for extended periods, driving lower LOE costs Bighorn well has been flowing for 18 months Expected LOE costs of $2 - $3 per boe Upside potential with further completion optimization Offset operators have demonstrated improved well performance by pumping bigger completion volumes (2,000 + lb/ft) Oasis wells have been completed with 1,600 lb/ft, on average, but expect to use 2,000+ going forward 300 200 100 Overpressure helps deliver larger volumes over longer periods 50 Normalized Months Source: IHS 1) Average Oil Rate for Wolfcamp A&B Wells that came online on January 1,2016 and forward Offset operators: APC (243), CPE (6), CRZO 16), CDEV (85), CVX (18), XEC (205), CXO (223), COP (34), DVN (14), FANG (44), EGN (28), EOG (176), XOM (12), FELIX (11), HK (20), JAG (37), MTDR (49), NBL (84), PE (84), PDCE (25), Primexx (9), REN (24), ROSE (9), RSPP (28), ADR 130), WPX (100) 10 1 2 3 4 5 6 7 8 9 10 11 12 22

Cumulative Oil Production (Mbo)/1,000' Cumulative Oil Production (Mbo) /1,000' Oasis Delaware Well Results are Outperforming Those of Offset Peers Oasis Well Results Outperform Offset Operators (1) Oasis Wells are Outperforming Peer Type Curves 60 Oasis WC A Average 4 Wells 60 All wells still flowing without artificial lift 50 50 UL 21 Bighorn 1H (WC A) 9,400ft Lateral - (11,906ft TVD) UL 21 Pahaska 1H (WC A) 4,301ft Lateral - (12,142ft TVD) 40 40 30 30 UL 21 Yellowtail 1H (WC A) 9,512ft Lateral - (12,002ft TVD) 20 20 Offset Operator Type Curve EUR: 1MMbo (1.2 MMboe) 10 10 UL 18 DYK 1H (WC A) 6,893ft Lateral - (11,401ft TVD) 0 0 3 6 9 12 15 18 21 24 Normalized Months 0 0 3 6 9 12 15 18 Normalized Months Source: IHS, Peer disclosure 1) Data is defined as Wolfcamp A and B wells in Loving, Reeves, Ward and Winkler counties, with a first production of January 2016 or later. Offset operators and well counts used include: ATLANTIC(5), CDEV(14), CXO(25), EOG(56), FELIX II(3), OAS(4), JAG(20), PE(12), RDS(57), RSPP(18) 23

Financial Highlights 24

Financial Highlights Free Cash Flow Positive (1) Free Cash Flow positive in 2015 & 2016 Projected to be Free Cash Flow positive, excluding midstream CapEx, in 2017 Expect to be Free Cash Flow positive on entire upstream business in 2018 with Cash Flow from the Williston Assets funding Delaware outspend @ $55 WTI Long Term Debt Current balance of $2,053MM, excluding revolver Current ratings of notes: S&P: BB- (upgraded 9/19/17) Moody s: B3 Strong Borrowing Base & Liquidity Oasis Borrowing Base of $1.6Bn ($1.15Bn Committed) $395MM drawn under revolver at 9/30/17 $10MM of LCs Interest coverage is only financial covenant: Covenant of 2.5x (4.3x LTM 3Q17) Pro forma for Gas Plant II Assignment (includes capital spent on Gas Plant II thru October 2017) OMP has $67 million outstanding on its revolver (2) $1,200 $1,000 $800 $600 $400 $200 No Near-Term Maturities $0 2017 2018 2019 2020 2021 2022 2023 Revolver balance Revolver capacity 7.25% Notes 6.5% Notes 6.875% Notes 6.875% Notes 2.625% Notes 1) Free Cash Flow defined as Adjusted EBITDA less cash interest and CapEx (excluding capitalized interest, which is included in cash interest). Non-GAAP reconciliation can be found on our website www.oasispetroleum.com. 2) OMP has a $200MM revolving credit facility that was undrawn as of 9/30/17. Pro forma adjustment includes reimbursement of capital spent through October 2017 on Gas Plant II. 25

Key Investment Highlights for Oasis Petroleum Operational scale with top-tier assets in the two best U.S. oil basins focused on the Core of the North American Core Premier Assets Large, contiguous acreage positions configured for efficient full-field development Extensive inventory of high-return and low-risk drilling locations, supporting attractive development economics across commodity price cycles Concentrated acreage position in the heart of the Williston basin Upside catalysts are near-term and highly visible Vertical integration provides operational flexibility Public midstream MLP a vehicle for growth, liquidity and value illumination Focused on capital discipline and delivering returns to shareholders Disciplined Management Prudently managing balance sheet while being one of the first E&P companies to become free cash flow positive Significant liquidity supported by $1.6 billion borrowing base 26

Appendix 27

Protecting Execution Plan and Balance Sheet via Strong Hedge Position (1) Oil Hedge Position Volume (Mbopd) 2H17 1H18 2H18 2019 Swap Volume 14.3 37.0 35.0 7.0 Price $50.03 $50.89 $50.84 $50.82 2-Way Collars Volume 4.0 3.0 3.0 - Floor $46.25 $48.67 $48.67 $0.00 Ceiling $54.37 $53.07 $53.07 $0.00 3-Way Collars Volume 3.0 - - - Sub Floor $31.67 $0.00 $0.00 $0.00 Floor $45.83 $0.00 $0.00 $0.00 Ceiling $59.94 $0.00 $0.00 $0.00 Total Volume 21.3 40.0 38.0 7.0 Gas Hedge Position Gas Vol (MMBtu/d) 2H17 1H18 2H18 2019 Swap Volume 11.0 19.0 19.0 - Price $3.30 $3.05 $3.05 1) As of 11/7/17 28

Expanding Takeaway Capacity out of Williston Basin Takeaway Options Takeaway Capacity (Mbopd) (1) ANS 3,500 Clearbrook 3,000 2,500 ANS Guernsey Brent 2,000 1,500 1,000 500 Railroad Pipeline 2017 Pipe adds WTI LLS - 2010 2011 2012 2013 2014 2015 2016 2017 Pipeline / Refining Rail Basin Production NDIC Production Forecast Pipeline and rail provide multiple destinations for Bakken crude Oasis can ship crude via rail or pipe to achieve the highest realizations New pipelines provide excellent optionality for low cost transportation Given the pipe and rail options, there is ample capacity for Bakken crude production Current Capacity Additions (MBopd) YE2016 2017 2018 Pipeline / Local refining 851 470 - Rail 1,520 - - Additions in Year 470 - Total Takeaway 2,371 2,841 2,841 Current Production 1,090 % of Production on Rail 10% 1) Source: North Dakota Pipeline Authority 29

Key Metrics Key metrics YE 2016 Net acreage (000s) 518 Estimated net PDP - MMBoe 190.6 Estimated net PUD - MMBoe 114.5 Estimated net proved reserves - MMBoe 305.1 Percent developed 62% 9/30/2017 Operated rigs running 5 Operated wells waiting on completion 82 Bakken/TFS well counts Producing @ YE 2016 Producing @ 3Q17 2017 Plan Gross operated 909 960 76 Net operated 693 729 51.7 Work ing interest in operated wells 76% 76% 68% Net non-operated 63 67 3.5 Total net wells 757 796 55.2 (3) Key acreage acquisitions (Net acres / Boepd then current) $83MM in June 2007 175,000 / 1,000 West Williston East Nesson Delaware $16MM in May 2008 48,000 / 0 $27MM in June 2009 37,000 / 800 $11MM in September 2009 46,000 / 300 $82MM in 4Q 2010 26,700 / 500 $1,542MM in 3Q/4Q 2013 136,000 / 9,000 25,000 / 300 $768MM in December 2016 55,000 / 12,000 $946MM in December 2017 20,300 / 3,500 30

Financial and Operational Results / Guidance Guidance (1) Select Operating Metrics FY13 FY14 FY15 1Q 16 2Q 16 3Q 16 4Q 16 FY16 1Q 17 2Q 17 3Q 17 FY17 Production (MBoepd) 33.9 45.7 50.5 50.3 49.5 48.5 53.1 50.4 63.2 61.9 66.1 65.6-66.1 Production (MBopd) 30.5 40.8 44.1 42.5 41.2 39.4 42.7 41.5 49.3 47.8 51.8 % Oil 90% 89% 87% 85% 83% 81% 80% 82% 78% 77% 78% 78% WTI ($/Bbl) $98.05 $92.07 $48.75 $33.59 $45.66 $44.94 $49.48 $43.40 $51.91 $48.29 $48.18 Realized Oil Prices ($/Bbl) (2) $92.34 $82.73 $43.04 $28.74 $40.81 $40.54 $44.57 $38.64 $47.03 $44.61 $46.35 Differential to WTI 6% 10% 12% 14% 11% 10% 10% 11% 9% 8% 4% $2.65 - $2.80 Realized Natural Gas Prices ($/Mcf) $6.78 $6.81 $2.08 $1.44 $1.42 $1.84 $2.98 $1.99 $3.81 $3.19 $3.50 LOE ($/Boe) $7.65 $10.18 $7.84 $6.78 $7.00 $8.00 $7.60 $7.35 $7.71 $7.92 $7.45 $7.50 - $7.70 Cash Marketing, Transportation & Gathering ($/Boe) $1.52 $1.61 $1.62 $1.60 $1.55 $1.58 $1.66 $1.60 $1.77 $2.17 $2.50 $2.20 - $2.30 G&A ($/Boe) $6.09 $5.54 $5.02 $5.32 $4.86 $5.12 $4.89 $5.04 $4.19 $4.18 $3.70 Production Taxes (% of oil & gas revenue) 9.3% 9.8% 9.6% 9.2% 9.0% 9.3% 8.7% 9.0% 8.6% 8.7% 8.5% 8.5-8.6% DD&A Costs ($/Boe) $24.81 $24.74 $26.34 $26.74 $27.19 $25.08 $24.43 $25.84 $22.27 $22.23 $21.75 Select Financial Metrics ($ MM) Oil Revenue $1,028.1 $1,231.2 $692.5 $111.2 $152.9 $147.1 $175.1 $586.3 $208.6 $194.0 $221.0 Gas Revenue 50.5 72.8 29.2 6.1 6.4 9.2 17.2 38.9 28.7 24.6 27.6 Bulk Oil Sales 5.8 - - - - 1.9 8.4 10.3 27.6 8.1 21.2 OMS and OWS Revenue 57.6 86.2 68.1 13.0 19.7 19.1 17.3 69.2 20.2 27.4 34.9 Total Revenue $1,142.0 $1,390.2 $789.7 $130.3 $179.1 $177.3 $218.0 $704.7 $285.1 $254.1 $304.7 LOE 94.6 169.6 144.5 31.1 31.5 35.7 37.2 135.4 43.9 44.7 45.3 Cash Marketing, Gathering & Transportation (3) 18.8 26.8 29.9 7.3 7.0 7.0 8.0 29.3 10.0 12.3 15.2 Production Taxes 100.5 127.6 69.6 10.8 14.4 14.6 16.8 56.6 20.3 19.0 21.1 Exploration Costs & Rig Termination 2.3 3.1 6.3 0.4 0.3 0.5 0.6 1.8 1.5 1.7 0.9 Bulk Oil Purchases 5.8 - - - - 1.9 8.4 10.3 28.0 8.0 21.7 Non-Cash Valuation Adjustment (3) 1.4 2.3 1.8 1.2 (0.5) - (0.1) 0.6 0.9 (0.2) (0.2) OMS and OWS Expenses 30.7 50.3 28.0 4.4 8.9 8.2 4.6 26.0 7.2 11.4 13.4 G&A 75.3 92.3 92.5 24.4 21.9 22.8 23.9 93.0 23.8 23.5 22.5 $92.5 - $97.5 Adjusted EBITDA (4) $821.9 $952.8 $820.2 $132.9 $132.2 $104.4 $130.9 $500.3 $150.6 $141.3 $179.6 DD&A Costs 307.1 412.3 485.3 122.4 122.5 111.9 119.4 476.3 126.7 125.3 132.3 Interest Expense 107.2 158.4 149.6 38.7 35.0 31.7 34.9 140.3 36.3 36.8 37.4 E&P CapEx 897.8 1,437.0 465.7 47.3 60.3 31.1 69.8 208.4 90.8 100.8 149.9 475.0 OMS and OWS CapEx 34.2 106.2 118.7 35.7 52.8 42.1 40.4 171.1 13.1 66.4 84.7 $239-264 Non E&P CapEx 10.9 29.4 25.6 4.6 5.3 5.0 5.6 20.5 5.9 5.8 5.7 20.0 Total CapEx (5) $942.9 $1,572.6 $610.0 $87.5 $118.4 $78.2 $115.9 $400.0 $109.8 $173.0 $240.3 734-759 Select Non-Cash Expense Items ($ MM) Impairment of Oil and Gas Properties $1.2 $47.2 $46.0 $3.6 - $0.4 $0.7 $4.7 $2.7 $3.2 $0.1 Amortization of Restricted Stock (6) 12.0 21.3 25.3 6.7 6.2 5.8 5.3 24.1 6.7 7.1 6.6 $28 - $30 Amortization of Restricted Stock ($/boe) (6) $0.97 $1.28 $1.37 $1.47 $1.39 $1.30 $1.09 $1.31 $1.18 $1.26 $1.09 1) Guidance was provided in 11/7/2017 press release, and partially updated in 12/11/17 press release 2) Average sales prices for oil are calculated using total oil revenues, excluding bulk oil sales, divided by net oil production. 3) Excludes marketing expense associated with non-cash valuation change on our pipeline imbalances and line fill inventory. These items are included under "Non-Cash Valuation Adjustment. 4) Non GAAP Adjusted EBITDA Reconciliation can be found on the Oasis website at www.oasispetroleum.com. 5) Excludes capital for acquisitions of $1,563.0MM and $781.5MM in 2013 and 2016, respectively. 6) Non-Cash Amortization of Restricted Stock is included in G&A. 31

Key Company Facts / External Support Oasis Petroleum Inc. Exchange / Ticker Shares Outstanding (as of 01/22/18) Share Price (close on 01/22/18) Approximate Equity Market Capitalization NYSE / OAS 269.3 MM $9.15 per share $2.46 BN External Support Independent Registered Public Accounting Firm Legal Advisors Reserves Engineers PricewaterhouseCoopers DLA Piper LLP / Vinson & Elkins LLP DeGolyer and MacNaughton 32