January 2018 Investor Presentation Forward-Looking / Cautionary Statements

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

(1) Core Extended Core Fairway Net Acres (thousand) Core Williston Delaware PF OAS 517.8 20.3 538.1

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 Delaware PF OAS 5 [x]1 f 6

Nov. 2017 Production (mboepd)

Williston Delaware PF OAS >72 ~3.5 >75.5

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 issuedLeveraging 2/26/15 Operational Scale and Full-field Development Experience Across Our Premier Oil Basins with the Objective of Optimizing Capital Efficiency and Full-Cycle Returns 1) Oasis’s Williston Basin Inventory as of 12/31/2016, Delaware as of 12/11/17 2) Assumes $55 WTI and $3.00 HH 3) Oasis active rigs as of January 1, 2018 5 Unique Value and Strategic Opportunities Derived from our Vertically Integrated Platform

Oasis Midstream Oasis Well Services

 Our midstream assets allow us to minimize operating costs and  OWS provides material cost-advantages, availability of quality ensure quality, timing & capacity of service service and flexibility, particularly when operating in active basins □ Ability to work ahead of potential bottlenecks and maintain  Enhances overall operational scale and intelligence regulatory compliance □ Ensures access to key delivery points  Natural hedge against cost inflation in a tightening services market  Our Delaware asset is largely undedicated for midstream  Supply chain management advantage, as many Oasis vendors Strategic assets and services have operations in both the Williston and the Delaware Advantages □ Potential to provide LOE and other cost savings □ Long-standing substantial relationships will allow Oasis to efficiently build scale in the Delaware  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

 Oil and natural gas gathering & processing (LOE  Two OWS spreads currently running in the Williston savings and surety of midstream services)  Opportunity to expand operations into the Delaware Basin  Crude oil transportation and storage (G,M,&T □ Possibly moving one OWS spread Assets and savings) □ And/or forming a third spread to work in the Delaware Capabilities  Freshwater distribution and produced water gathering and disposal (LOE savings, especially in  Top tier efficiency high water-cut areas

6 Recent Accomplishments & Highlights

. 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 Improving Economics exit rate through Innovation . Further completion design innovation improving well economics □ Dialing in proppant intensity, water volumes pumped, and stage counts □ Maximizing economics across DSUs

. Better oil differentials/realizations – diffs expected to be between $0.50 and $1.00 in 4Q17 Infrastructure . Capturing increasing gas volumes in Wild Basin and improving gas realizations Delivering Increased Margins . Improved operating costs . Completed Oasis Midstream Partners (“OMP”) IPO in 3Q17

. Ability to leverage existing supply chain vendor relationships Oasis Advantages . Basin leading completion designs driving well performance Transferable to . Low cost operator Acquired Assets . Opportunity to leverage OMP’s operating capabilities and footprint . Multiplying success through core bolt-on acquisitions

Improving capital efficiency & operational performance

7 Update to 2017 and Issuance of 2018 Capital Plan

Production Highlights 2018 Development Plan

. Increasing 4Q17 production guidance from 69- . Expect to drill and complete 100 to 120 operated 72Mboepd to 71-73Mboepd wells □ ~70% WI □ 5 rigs throughout the year □ +Non-op activity . Combined exit rate for 2018 production of >88 Mboe/d (1) . 2017 well costs are $6.8mm (4mmlb) and $7.7mm

Williston (10mmlb) □ Williston: 83+ Mboepd . Targeting ~$500mm of non-core asset sales in 2018 □ Delaware: 5 Mboepd . Differentials expected to be below $2.00 per bbl

. 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

Production Growth Profile Delaware . Minimal outspend at $55 WTI on Delaware asset

(1) . Targeted spending within cash flow at $55 WTI, 100 > 88 excluding infrastructure projects 80 72 66 62 83 □ Complementary infrastructure projects

60 50 expected to be dropped to MLP in future Mboepd 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)

Burke MONTANA NORTH DAKOTA 1,800 1,600 1,459 (Gross) 1,400 Sheridan Divide Cottonwood 1,200 1,000 844 (Gross) Williams 770 (Gross) 800

600 1,084 (Net) 400 602 (Net) 200 483 (Net) Roosevelt Red Bank 0 YE16 YE16 YE16 Alger Core Extended Core Fairway (2 rigs) Breakeven Oil Core Extended Fairway Below $40 Below $45 $45 to $55 Painted Price (WTI) Core Woods Montana Indian Hills (1 rig) Mountrail 3,073 operated locations in the heart of the play Wild Basin . 770 core locations (~1/3 in Wild Basin) (2 rigs) . 1,614 locations with breakeven prices below $45 Richland Foreman Butte WTI . Equates to >20 years of remaining highly economic Williston inventory at 2017 pace of completions McKenzie Dunn . Further upside with increasing frac intensity across all three areas Other operator non-core enhanced completions

Anticipated Oasis 2018 non-core enhanced expansion tests

1) As of 12/31/16

10 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 $15 $14 $20 stacked pays $13 $12 . Over 750 wells drilled since 2010, averaging ~10,000 feet of $15 lateral length through multiple development zones $9 $8 $10 . Spud to rig release timing decreased from 21.6 days in 2014 to $5 $6 $10.6 13.6 days $8.5 $6.8 $5

$ per $ per Boe $3

. Continuously improving frac efficiency through large pad $ in Millions development around zipper fracs and optimizing logistics $- $0 . Demonstrated success in bringing down well costs over time 2014 Base 2014 High Current Core Intensity . Improved cost structure Well Level F&D ($ per Boe) Well Cost ($MM)

Williston Slickwater Well Cost ($MM) Improving Operating Cost Structure

$12 $12 $10.6 $10.18 $10 $10 $9.34 $7.7 $7.84 $7.50 $8 $8 $7.35 $6.8 $5.72 $6 7.00 $6 $4.76 $4 $4 $2.80

$2 $2.65 $1.00 $2 $0.50 $0 $0 2014 2015 2016 4Q17E 2014 2015 2016 2017E 4Q17E 4Q14 10MM LB Frac 4MM LB Frac LOE ($/Boe) Differential to WTI ($/Bbl) 50 Stages 11 Wild Basin High Intensity Type Curve and Performance Update

Wild Basin Bakken Well Performance Wild Basin Three Forks Well Performance

350 350

Constrained Constrained

) ) Production Production

300 300

Mbbls Mbbls

250 250

200 200

Normalized Normalized Oil Rate ( Normalized Oil Rate (

150 150

Avg Avg

100 100

Cumulative Cumulative 50 50

0 0 0 50 100 150 200 250 300 350 400 0 50 100 150 200 250 300 350 400 Producing Days Producing Days 50 Stg 4 mmlb (8 wells) 1,550 MBOE Type Curve 50 Stage 4 mmlb (12 wells) 1,200 MBOE Type Curve Johnsrud 3BX (20 mmlb) Rolfson 3BX (10 mmlb) Recent 10mmlbs (10 wells) Recent 10mmlbs (10 wells) Wild Basin Highlights

. 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 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

250 250 Constrained Constrained Production Production

200 200

150 150

100 100

50 50

Cumulative Avg Normalized Oil Rate (Mbbls) Rate Oil CumulativeNormalized Avg Cumulative Avg Normalized Oil Rate (Mbbls) Rate Oil CumulativeNormalized Avg

0 0 0 30 60 90 120 150 180 210 240 270 0 30 60 90 120 150 180 210 240 270 Producing Days Producing Days 1,090 MBOE Type Curve Bakken Avg (29 wells) 870 MBOE Type Curve Three Forks Avg (15 wells) 10mmlbs+ Indian Hills (3 wells) Teal (20mmlb equivalent) Recent 10mmlbs (2 wells) (4,400 ft lateral normalized 2x to a 10,000 ft lateral)

Core (Ex. Wild Basin) Highlights IRR

. 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 Burke . Approximately 86 miles of crude and gas gathering lines Divide . 80MMscfpd processing plant operational Cottonwood . 200MMscfpd processing plant under construction Sheridan Crude Oil Transportation and Storage . FERC-regulated crude mainline to DAPL receipt point Red Bank Williams . 240Mbbls of storage to increase flexibility, minimize Roosevelt curtailments Alger Freshwater Distribution and Produced Water Gathering and Mountrail Disposal Hebron Wild Basin . Extensive network of approximately 610 miles of water handling pipelines Indian Hills . Only 45% of system constructed in Wild Basin as of YE2016 . 21 SWDs, including 3 in Wild Basin Richland Johnson’s McKenzie Corner Strategic Advantage to Oasis

Williston Basin – Oasis Midstream Project Area – Dedicated, Undedicated . Integrating development of upstream and midstream assets Saltwater Disposal Wells (21) Crude/Gas/Water Pipelines . Reduces overall operating expense Water Pipelines Core Dunn . Increases oil and gas realizations Extended Core Fairway Billings Beartooth Acreage Dedication . Oasis funded midstream capital returned through future drop Bighorn / Bobcat Acreage Dedication Gas Processing Plant down potential of retained interest in Bobcat and Beartooth Johnson’s Corner Connection

DevCos Stark

1) DevCo highlights are illustrative and do not resemble acreage dedications 14 Oil and Gas Infrastructure in the Williston

Marketing Highlights 3rd Party Crude Oil Gathering Infrastructure

Crude oil gathering MONTANA NORTH DAKOTA . Realized $1.82/bbl differential in 3Q17

. Signing longer term contracts at fixed differentials North Cottonwood . 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 South Cottonwood Red Bank Gas gathering and processing

. Average realization of $3.50/mcf in 3Q17 Alger Painted . Substantially all wells connected to gathering system Woods . 85% gas production captured in 3Q17, vs. North Dakota goal of 85% Indian Hills Foreman Wild Butte Basin 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 Oasis acreage . Regulatory environment Oil gathering infrastructure Rail connection points Pipeline connection points

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 multi- stacked 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 2/26/15Now 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 Acquisition Overview . Material midstream development opportunities Gross Acres (thousands) 40.5 □ Organic midstream growth opportunities inherent in assets Net Acres (thousands) 20.3 □ Acreage largely undedicated for hydrocarbon gathering and % Operated 90%

completely undedicated for water gathering % Average Core Operated Working Interest 76% □ Attractive avenue for growth for OMP 1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with NovemberSanish that 2017 were Productiondivested in Ma(boerch/d) 2014 ~3,500 2) Guidance issued 2/26/15 November 2017 Production % Oil 78%

18 Thick, Multi-Stacked Pay Potential with Large Inventory Upside

Formation Type Log Development Pattern Wells Column (Not to Scale) per DSU Thickness Delaware Basin Net Inventory

Bone Spring 6+ 1,000’ Lime / Avalon

1st Bone Spring 6+ 650’ 507

2nd Bone Spring 4+ 700’

Core Total Potential Locations BS 2 Lower Shale 6+ 250’

Delaware Basin Gross Operated Inventory 3rd Bone Spring 4 250’

Upper 6 190’ Wolfcamp A Lower 6 180’

Upper 6 180’ Wolfcamp B Lower 6 150’ 601 Wolfcamp C 6 250’

Core Inventory Total 34 / 56+ 1,200’ / Additional Upside 3,800’ Core Total Potential Locations

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%

OAS

Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 1 Peer 2

Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15 Peer 16 Peer 17 Peer 18 Peer 19

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

Lateral 180 IP Rate / Compl Well Name SelectedOperator WellsLengthLateral (ft) 1801,000' IP (Bbls)Rate / ComplDate Well Name Operator2nd Bone SpringLength (ft) 1,000' (Bbls) Date Ludeman I 3 RSP2nd Permian Bone SpringLateral7,109 180 IP68 Rate / 4/16/2017Compl Ludeman I Well3 Name RSPOperator 3rdPermian Bone SpringLength7,109 (ft) 1,000'68 (Bbls) 4/16/2017Date 1 Rudd Draw 26-21 1H RSP2nd 3rdPermian Bone Spring6,707 135 12/29/2016 1 RuddLudemanUniversity Draw IBlk 326-21 20 1305H 1H RSPExxon Permian 6,7077,1097,894 1356872 12/29/20164/16/20178/2/2016 8 6 UniversityMiami Beach Blk 34-12320 1305H ExxonCimarex3rd Bone Spring7,8944,348 18072 8/2/20161/3/2017 2 MiamiRuddUniversity Draw Beach Blk 26-21 34-12321 1804H 1H CimarexRSPExxon Permian 4,3486,7073,256 180135205 12/29/20161/14/20151/3/2017 3 University Blk 2120 1804H1305H Exxon Wolfcamp A 3,2567,894 20572 1/14/20158/2/2016 2 4 MiamiHughes Beach & Talbot 34-123 75-24 2H CimarexAnadarkoWolfcamp A 4,3484,821 18089 1/3/20171/8/2016 5 UL Rock Of Ages 3922-17 1H Felix II 10,196 71 9/21/2016 15 HughesUniversity & BlkTalbot 21 1804H75-24 2H AnadarkoExxon 4,8213,256 20589 1/14/20151/8/2016 ULHughes Rock & Of Talbot Ages 75-23 3922-17 2H 1H FelixAnadarko II Wolfcamp A 10,1964,672 13671 12/11/20169/21/2016 6 HughesUTL 4344-21 & Talbot 1H 75-2375-24 2H AnadarkoJagged Peak 4,6724,8219,996 1368991 12/11/20167/29/20161/8/2016 7 UTLULUniversity Rock 4344-21 Of Blk Ages 1H20 1311H 3922-17 1H JaggedFelixExxon II Peak 10,1969,9969,666 917163 7/29/20169/21/20168/10/2016 26 21 17 29 8 UniversityHughesUTL L. J. & BeldinBlkTalbot 20 1211-17 1311H75-23 2H 3H ExxonAnadarkoJagged Peak 9,6664,6729,561 1366376 12/11/20168/10/20169/24/2016 30 27 28 20 10 9 UTLCaprito L.4344-21 J.99 Beldin 302H 1H 1211-17 3H JaggedAbraxas Peak 9,5619,9964,460 1037691 11/11/20169/24/20167/29/2016 5 14 3 10 CapritoUniversityRK-Utl 3031B-17 99 Blk302H 20 1311H1H AbraxasExxonJagged Peak 10,4324,4609,666 1036365 11/11/201611/18/20168/10/2016

22 11 RK-UtlUTLUniversity L. 3031B-17J. Beldin20-4 Lov 1211-17 1H 3H 3H JaggedShell Peak 10,4329,5614,578 1156576 11/18/20169/24/20161/18/2016

16 12 UniversityCapritoDeuces 99Wild 20-4302H 28-17 Lov 2H3H ShellAbraxasAnadarko 4,5784,4604,723 11510371 11/11/20161/18/20162/10/2016 13 DeucesRK-UtlUL 21 Bighorn3031B-17 Wild 28-17 1H 1H 2H AnadarkoJaggedForge Energy Peak 10,4324,7239,400 716593 11/18/20162/10/20165/29/2016 9 14 ULUniversityMesquite 21 Bighorn Heat 20-4 1H28-41Lov 3H Unit 1H ForgeShellAnadarko Energy 9,4004,5786,552 1159389 10/31/20165/29/20161/18/2016 13 11 15 MesquiteDeucesCorbets Wild34-149 Heat 28-17 28-41 2WA 2H Unit 1H AnadarkoCallon 6,5524,7239,723 8971 10/31/201611/27/20162/10/2016 24 16 CorbetsUL 21Lead Bighorn 34-149King 4035-16 1H 2WA 1H CallonForgeFelix II Energy 9,7239,4004,850 7193 11/27/201612/31/20165/29/2016 17 ULMesquite Lead21 Pahaska King Heat 4035-16 28-41 1H Unit 1H 1H FelixAnadarkoForge II Energy 4,8506,5524,301 1019389 12/31/201610/31/201611/7/2016 18 ULCorbetsQuinn 21 37Pahaska 34-149 2H 1H2WA ForgeCallonWPX EnergyEnergy 4,3019,7234,780 1017181 11/27/201611/7/20163/17/2017 19 QuinnUL Lead21 37Yellowtail King2H 4035-16 1H 1H WPXFelixForge IIEnergy Energy 4,7804,8509,512 819387 12/31/20163/17/20173/1/2017 25 20 ULStella 21 StateYellowtailPahaska 34-208 1H1H WRD 1H ForgeShell Energy 9,5124,3014,770 1016887 11/7/20161/31/20173/1/2017 12 21 StellaQuinn State37 2H 34-208 WRD 1H2H ShellWPX Energy 4,7704,780 688481 1/31/20173/17/20171/24/2017 23 UL 18 Dyk 1H Forge Energy 6,893 87 3/30/2017 7 22 StellaUL 21 StateYellowtail 34-208 1H WRD 2H ShellForge Energy 4,7709,512 8487 1/24/20173/1/2017 19 23 ULStella 18 StateDyk 1H 34-208 WRD 1H ForgeShell EnergyWolfcamp B 6,8934,770 6887* 3/30/20171/31/2017 HALEY 28-43 4H Cimarex 4,928 9/10/2017 18 4 Stella State 34-208 WRD 2H Shell Wolfcamp B 4,770 8425 1/24/2017 24 ULHALEYUTL 18 2932-17 Dyk 28-43 1H 1H4H ForgeCimarexJagged Energy Peak 10,3216,8934,928 258769 3/30/20179/10/20176/28/2016 25 UTL 2932-1738-17 2H 1H JaggedWolfcamp Peak B 10,3214,529 6981 6/28/20163/31/2017 26 UTLHALEYMitchell 38-17 28-4339 2HW101PA 4H JaggedCimarexMewbourne Peak 4,5294,9284,801 1182581 3/31/20179/10/20172/6/2017 MitchellUTL 2932-17 39 W101PA 1H MewbourneJaggedWolfcamp Peak C 10,3214,801 11869 6/28/20162/6/2017 27 UTLUniversity 38-17 B20 2H 1W JaggedMewbourneWolfcamp Peak C 4,5294,847 8158 3/31/20171/14/2017 28 MitchellUniversity 39 B20 W101PA 1W12 Mewbourne 4,8014,8474,585 1185867 1/14/20173/24/20172/6/2017 29 University B20 121_W201PA MewbourneWolfcamp C 4,5854,551 6763 3/24/20172/25/2016 30 University B20B21 1_W201PA81W Mewbourne 4,5514,4444,847 633858 10/28/20162/25/20161/14/2017 University B21B20 812 Mewbourne 4,4444,585 3867 10/28/20163/24/2017 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 Exceptional Well Performance With Potential Completion Design Upside

Summary Highlights Normalized Average Oil Rate (Wolfcamp A & B) (1)

300 . Peer-leading well performance Overpressure helps deliver larger volumes . Wells flow for extended periods, driving lower LOE costs over longer periods 200 □ 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 100 (2,000 + lb/ft) . Oasis wells have been completed with 1,600 lb/ft, on average, but expect to use 2,000+ going forward

50 Average Oil Production (bbl/d per 1000') per 1000') (bbl/d Production Oil Average

10 1 2 3 4 5 6 7 8 9 10 11 12 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) 22 Oasis Delaware Well Results are Outperforming Those of Offset Peers

Oasis Well Results Outperform Offset Operators (1) Oasis Wells are Outperforming Peer Type Curves

All wells still flowing without artificial lift Oasis WC A Average 4 Wells 60 60

UL 21 Bighorn 1H (WC A) 9,400ft Lateral - (11,906ft TVD) 50 50

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)

Offset Operator Type Curve EUR: 1MMbo (1.2 MMboe)

20 20

Cumulative Oil Production (Mbo) /1,000' (Mbo) Production Oil Cumulative Cumulative Oil Production (Mbo)/1,000' Production Oil Cumulative

10 10 UL 18 DYK 1H (WC A) 6,893ft Lateral - (11,401ft TVD)

0 0 0 3 6 9 12 15 18 21 24 0 3 6 9 12 15 18 Normalized Months 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) Long Term Debt

. Free Cash Flow positive in 2015 & 2016 . Current balance of $2,053MM, excluding revolver . Projected to be Free Cash Flow positive, excluding midstream . Current ratings of notes: CapEx, in 2017 □ S&P: BB- (upgraded 9/19/17) . Expect to be Free Cash Flow positive on entire upstream □ Moody’s: B3 business in 2018 with Cash Flow from the Williston Assets funding Delaware outspend @ $55 WTI

Strong Borrowing Base & Liquidity No Near-Term Maturities

$1,200 . Oasis Borrowing Base of $1.6Bn ($1.15Bn Committed) . $395MM drawn under revolver at 9/30/17 $1,000 □ $10MM of LCs $800 . Interest coverage is only financial covenant: □ Covenant of 2.5x (4.3x LTM 3Q17) $600 . Pro forma for Gas Plant II Assignment (includes capital spent $400 on Gas Plant II thru October 2017) OMP has $67 million (2) outstanding on its revolver $200

$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”

 Large, contiguous acreage positions configured for efficient full-field development Premier Assets  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  Prudently managing balance sheet while being one of the first E&P companies to Management 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 Gas Hedge Position

Volume (Mbopd) 2H17 1H18 2H18 2019 Gas Vol (MMBtu/d) 2H17 1H18 2H18 2019 Swap Swap Volume 14.3 37.0 35.0 7.0 Volume 11.0 19.0 19.0 - Price $50.03 $50.89 $50.84 $50.82 Price $3.30 $3.05 $3.05 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

1) As of 11/7/17

28 Expanding Takeaway Capacity out of Williston Basin

Takeaway Options Takeaway Capacity (Mbopd) (1)

ANS 3,500

3,000 Clearbrook 2,500

2,000 Brent Guernsey 1,500 ANS 1,000

500

WTI - 2010 2011 2012 2013 2014 2015 2016 2017 Railroad Pipeline / Refining Rail Pipeline LLS Basin Production NDIC Production Forecast 2017 Pipe adds

Current Capacity Additions . Pipeline and rail provide multiple destinations for Bakken crude (MBopd) YE2016 2017 2018 . Oasis can ship crude via rail or pipe to achieve the highest Pipeline / Local refining 851 470 - realizations Rail 1,520 - - . New pipelines provide excellent optionality for low cost Additions in Year 470 - transportation Total Takeaway 2,371 2,841 2,841 . Given the pipe and rail options, there is ample capacity for Bakken crude production 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

Producing @ Producing @ Bakken/TFS well counts 2017 Plan YE 2016 3Q17 Gross operated 909 960 76 Net operated 693 729 51.7 Working 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 West Williston East Nesson Delaware then current) $83MM in June 2007 175,000 / 1,000 $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 NYSE / OAS

Shares Outstanding (as of 01/22/18) 269.3 MM

Share Price (close on 01/22/18) $9.15 per share

Approximate Equity Market Capitalization $2.46 BN

External Support

Independent Registered Public Accounting Firm PricewaterhouseCoopers

Legal Advisors DLA Piper LLP / Vinson & Elkins LLP

Reserves Engineers DeGolyer and MacNaughton

32