Investor PresentationJanuary 2018

Forward-Looking / Cautionary Statements

Forward-Looking StatementsThis presentation, including the oral statements made in connection herewith, containsforward-looking statements within the meaning of Section 27A of the Securities Act of 1933and Section 21E of the Securities Exchange Act of 1934. All statements, other thanstatements of historical facts, included in this presentation that address activities, events ordevelopments that the Company expects, believes or anticipates will or may occur in thefuture are forward-looking statements. Without limiting the generality of the foregoing,forward-looking statements contained in this presentation specifically include theexpectations of plans, strategies, objectives and anticipated financial and operating results ofthe Company, including the Company's drilling program, production, derivative instruments,capital expenditure levels and other guidance included in this presentation. When used inthis presentation, the words "could," "should," "will,“ "believe," "anticipate," "intend,""estimate," "expect," "project," the negative of such terms and other similar expressions areintended to identify forward- looking statements, although not all forward-looking statementscontain such identifying words. These statements are based on certain assumptions madeby the Company based on management's experience and perception of historical trends,current conditions, anticipated future developments and other factors believed to beappropriate. Such statements are subject to a number of assumptions, risks anduncertainties, many of which are beyond the control of the Company, which may causeactual results to differ materially from those implied or expressed by the forward-lookingstatements. When considering forward-looking statements, you should keep in mind the riskfactors and other cautionary statements described under the headings “Risk Factors” and“Cautionary Statement Regarding Forward-Looking Statements” included in the prospectussupplement. These include, but are not limited to, the Company’s ability to consummate theacquisition discussed in this presentation, the Company's ability to integrate acquisitions intoits existing business, changes in oil and natural gas prices, weather and environmentalconditions, the timing of planned capital expenditures, availability of acquisitions,uncertainties in estimating proved reserves and forecasting production results, operationalfactors affecting the commencement or maintenance of producing wells, the condition of thecapital markets generally, as well as the Company's ability to access them, the proximity toand capacity of transportation facilities, and uncertainties regarding environmentalregulations or litigation and other legal or regulatory developments affecting the Company'sbusiness and other important factors. Should one or more of these risks or uncertaintiesoccur, or should underlying assumptions prove incorrect, the Company’s actual results andplans 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 madeand the Company undertakes no obligation to correct or update any forward-lookingstatement, whether as a result of new information, future events or otherwise, except asrequired by applicable law.

Cautionary Statement Regarding Oil and Gas QuantitiesThe Securities Exchange Commission (the “SEC”) requires oil and gas companies, in their filings withthe SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis ofgeoscience and engineering data, can be estimated with reasonable certainty to be economicallyproducible—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, andgovernment 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 orprobabilistic methods are used for the estimation. The accuracy of any reserve estimate depends onthe quality of available data, the interpretation of such data and price and cost assumptions made byreserve engineers. In addition, the results of drilling, testing and production activities of the explorationand development companies may justify revisions of estimates that were made previously. Ifsignificant, 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 ultimatelyrecovered. The SEC also permits the disclosure of separate estimates of probable or possiblereserves that meet SEC definitions for such reserves; however, we currently do not disclose probableor possible reserves in our SEC filings.

In this presentation, proved reserves at December 31, 2016 are estimated utilizing SEC reserverecognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $42.60 per barrel of oil and $2.47 per MMBtu of natural gas. The reserve estimates forthe Company at year-end 2010 through 2016 presented in this presentation are based on reportsprepared 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 potentiallyrecoverable hydrocarbons. These are the Company's internal estimates of hydrocarbon quantities thatmay be potentially discovered through exploratory drilling or recovered with additional drilling orrecovery techniques. These quantities have not been reviewed by independent engineers. Additionally,these quantities may not constitute "reserves" within the meaning of the Society of PetroleumEngineer's Petroleum Resource Management System or SEC rules and do not include any provedreserves. Estimated ultimate recovery (“EUR”) estimates and drilling locations have not been risked byCompany management. Actual locations drilled and quantities that may be ultimately recovered fromthe Company's interests will differ substantially. There is no commitment by the Company to drill all ofthe drilling locations that have been attributed to these quantities. Factors affecting ultimate recoveryinclude the scope of our ongoing drilling program, which will be directly affected by the availability ofcapital, 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 asdevelopment of the Company's oil and gas assets provide additional data. Type curves do notrepresent 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 offuture drilling activity, which may be affected by significant commodity price declines or drilling costincreases.

2

Oasis Investment Highlights and Strengths

1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March 20142) Guidance issued 2/26/15

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) Assumes inventory as of 12/31/16 at 2017 guided rate of completions2) 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)

1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March 20142) Guidance issued 2/26/15

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 12/31/16 unless otherwise noted2) Delaware acreage as of 12/11/17 announcement

4

Returns-Focused, Oil-Weighted, Core-Concentrated and Leveraging Operational Scale

1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March 20142) Guidance issued 2/26/15

5

Our Delaware AssetOur Williston Asset Combined Stats

Net Acres (thousand) (1)

Williston517.8

Delaware20.3

PF OAS538.1

Core & Extended CoreNet Inventory (1)

Williston1,085

Delaware507

PF OAS1,592

Core IRR (2)

Williston>75%

Delaware>75%

PF OAS>75%

Active Rigs (3)

[x]fWilliston

5Delaware

1PF OAS

6

Nov. 2017 Production (mboepd)

Williston>72

Delaware~3.5

PF OAS>75.5

Core Fairway

Leveraging Operational Scale and Full-field Development Experience Across Our Premier Oil Basins with the Objective of Optimizing Capital Efficiency and Full-Cycle Returns

Core

1) Oasis’s Williston Basin Inventory as of 12/31/2016, Delaware as of 12/11/172) Assumes $55 WTI and $3.00 HH3) Oasis active rigs as of January 1, 2018

Extended Core

Unique Value and Strategic Opportunities Derived from our Vertically Integrated Platform

6

Oasis Midstream Oasis Well Services

Assets and Capabilities

Strategic Advantages

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

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

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

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

Recent Accomplishments & Highlights

Improving capital efficiency & operational performance

7

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

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

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

8350

66 6272

88

0

20

40

60

80

100

2016 2017E 2016 Exit 2017E Exit 2018E ExitWilliston Delaware

Update to 2017 and Issuance of 2018 Capital Plan

8

2018 Development 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 Growth Profile

Mbo

epd

1) Exit rate does not account for potential production loss from anticipated Williston Basin divestitures

(1)>

Production Highlights

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

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

Targeted spending within cash flow at $55 WTI, excluding infrastructure projects□ Complementary infrastructure projects

expected to be dropped to MLP in futureW

illis

ton

Del

awar

e

Williston Basin

9

483 602

1,084

770 844

1,459

0200400600800

1,0001,2001,4001,6001,800

YE16 YE16 YE16

Core ExtendedCore

Fairway

Robust Inventory in the Heart of the Williston Basin (1)

Increased Strength of Inventory (Net/Gross Locations)

1) As of 12/31/16

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

10

CoreBelow $40

Extended CoreBelow $45

Fairway$45 to $55Breakeven Oil

Price (WTI)

(Net)

(Gross)

(Net)

(Gross)

(Net)

(Gross)

Anticipated Oasis 2018 non-core enhanced expansion tests

Alger

Wild Basin

Indian Hills

Cottonwood

Painted Woods

Red Bank

Enhanced Completion Expansion

MONTANA NORTH DAKOTA

DivideSheridan

Roosevelt

Richland

McKenzie Dunn

Williams

Burke

Mountrail

Montana

Foreman Butte

(2 rigs)

(1 rig)

Other operator non-core enhanced completions

(2 rigs)

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

Williston Slickwater Well Cost ($MM)

$7.50

$2.80

$1.00

$10.18

$7.84 $7.35

7.00

$9.34

$5.72 $4.76

$2.65 $0.50 $0

$2

$4

$6

$8

$10

$12

2014 2015 2016 4Q17E 2014 2015 2016 2017E 4Q17E

LOE ($/Boe) Differential to WTI ($/Bbl)

Improving Operating Cost Structure

Operational Excellence: Demonstrated Capital Efficiency & Low Operating Cost Structure

11

Track Record of Efficient Full-Field Development

$14 $13

$5 $8

$8.5 $10.6 $6.8

$0

$5

$10

$15

$20

$-

$3

$6

$9

$12

$15

2014 Base 2014 HighIntensity

Current Core

$ in

Mill

ions

$ pe

r B

oe

Well Level F&D ($ per Boe) Well Cost ($MM)

Substantially Improving Capital Efficiency in Core

$10.6

$7.7$6.8

$0

$2

$4

$6

$8

$10

$12

4Q14 10MM LB Frac 4MM LB Frac50 Stages

0

50

100

150

200

250

300

350

0 50 100 150 200 250 300 350 400

50 Stg 4 mmlb (8 wells) 1,550 MBOE Type CurveJohnsrud 3BX (20 mmlb) Rolfson 3BX (10 mmlb)Recent 10mmlbs (10 wells)

0

50

100

150

200

250

300

350

0 50 100 150 200 250 300 350 400

50 Stage 4 mmlb (12 wells) 1,200 MBOE Type Curve

Recent 10mmlbs (10 wells)

Wild Basin Three Forks Well Performance

Wild Basin High Intensity Type Curve and Performance Update

12

Wild Basin Bakken Well Performance

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

Wild Basin Highlights

Cum

ulat

ive

Avg

Nor

mal

ized

Oil

Rat

e (M

bbls

) Constrained Production

Cum

ulat

ive

Avg

Nor

mal

ized

Oil

Rat

e (M

bbls

)

Producing DaysProducing Days

Constrained Production

0

50

100

150

200

250

0 30 60 90 120 150 180 210 240 270

Cum

ulat

ive

Avg

Nor

mal

ized

Oil

Rate

(Mbb

ls)

Producing Days870 MBOE Type Curve Three Forks Avg (15 wells)

Recent 10mmlbs (2 wells)

0

50

100

150

200

250

0 30 60 90 120 150 180 210 240 270

Cum

ulat

ive

Avg

Nor

mal

ized

Oil

Rate

(Mbb

ls)

Producing Days1,090 MBOE Type Curve Bakken Avg (29 wells)10mmlbs+ Indian Hills (3 wells) Teal (20mmlb equivalent)

Williston Core (Ex. Wild Basin) High Intensity Type Curve and Performance

13

IRR

Core (Ex. Wild Basin) Three Forks Well PerformanceCore (Ex. Wild Basin) Bakken Well Performance

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

(4,400 ft lateral normalized 2x to a 10,000 ft lateral)

Constrained Production

Constrained Production

Strategically Located Infrastructure in the Heart of the Williston

14

Williston Midstream Asset Footprint (1)OMP Asset Highlights

Gathering & Processing Assets in Wild Basin Approximately 86 miles of crude and gas gathering lines 80MMscfpd processing plant operational 200MMscfpd processing plant under construction

Crude Oil Transportation and Storage FERC-regulated crude mainline to DAPL receipt point 240Mbbls of storage to increase flexibility, minimize

curtailmentsFreshwater 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

McKenzie

Dunn

DivideBurke

Mountrail

Sheridan

RooseveltWilliams

Richland

Wild Basin

Stark

Billings

Alger

Cottonwood

Red Bank

Hebron

Indian Hills

Johnson’s Corner

Williston Basin – Oasis Midstream Project Area – Dedicated, Undedicated

Saltwater Disposal Wells (21)Crude/Gas/Water PipelinesWater PipelinesCoreExtended CoreFairwayBeartooth Acreage DedicationBighorn / Bobcat Acreage DedicationGas Processing PlantJohnson’s Corner Connection

1) DevCo highlights are illustrative and do not resemble acreage dedications

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 BeartoothDevCos

Oil and Gas Infrastructure in the Williston

Crude oil gathering Realized $1.82/bbl differential in 3Q17

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

Marketing Highlights

15

3rd Party Crude Oil Gathering Infrastructure

Oasis acreageOil gathering infrastructureRail connection pointsPipeline connection points

Indian Hills

MONTANA NORTH DAKOTA

Red Bank

North Cottonwood

SouthCottonwood

Foreman Butte

Painted Woods

Wild Basin

Alger

Delaware Basin

16

Delaware Basin Transaction Summary

1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March 20142) Guidance issued 2/26/15

17

Now Strategically Positioned in the Core of the Two Best U.S. Oil Basins

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) Assumes 11/30/2017 NYMEX strip pricing

Core Delaware Basin Assets with Highly Attractive Attributes

1) As of 12/31/14, unless otherwise noted, and does not include acreage or reserves associated with Sanish that were divested in March 20142) Guidance issued 2/26/15

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

18

Premier Position in the Core of the DelawareKey Asset Highlights

Acquisition OverviewGross Acres (thousands) 40.5

Net Acres (thousands) 20.3

% Operated 90%

% Average Core Operated Working Interest 76%

November 2017 Production (boe/d) ~3,500

November 2017 Production % Oil 78%

601

Core Total Potential Locations

Thick, Multi-Stacked Pay Potential with Large Inventory Upside

19

Delaware Basin Net Inventory

250’

700’

250’

190’

180’

180’

150’

250’

1,000’Bone Spring Lime / Avalon

1st Bone Spring

2nd Bone Spring

BS 2 Lower Shale

Wolfcamp A

Wolfcamp C

Wolfcamp B

3rd Bone Spring

Core InventoryAdditional Upside

Formation Type Log(Not to Scale)

Development Pattern Wells per DSU

Column Thickness

6+

6+

4+

6+

4

6

6

6

6

6

Upper

Lower

Upper

Lower

Delaware Basin Gross Operated Inventory

507

Core Total Potential Locations

Total 34 / 56+ 1,200’ / 3,800’

650’

~85%

0%

20%

40%

60%

80%

100%

OA

SP

eer 1

Pee

r 2P

eer 3

Pee

r 4P

eer 5

Pee

r 6P

eer 7

Pee

r 8P

eer 9

Pee

r 10

Pee

r 11

Pee

r 12

Pee

r 13

Pee

r 14

Pee

r 15

Pee

r 16

Pee

r 17

Pee

r 18

Pee

r 19

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

Contiguous Acreage Blocks Combined with High Oil Cuts Deliver Efficient and Compelling Development Opportunities

20

Source: IHSOffset operators: APC, CPE, CRZO, CDEV, CVX, XEC, CXO, COP, DVN, FANG, EOG, HK, JAG, MTDR, NBL, PDCE, REN, RSPP, WPX

Summary Highlights Assets in the Deepest and Oiliest Part of the Play

Highest oil cut among Delaware peers (Wolfcamp A&B)

Well Name OperatorLateral

Length (ft)180 IP Rate / 1,000' (Bbls)

Compl Date

Ludeman I 3 RSP Permian 7,109 68 4/16/2017

Rudd Draw 26-21 1H RSP Permian 6,707 135 12/29/2016University Blk 20 1305H Exxon 7,894 72 8/2/2016Miami Beach 34-123 Cimarex 4,348 180 1/3/2017University Blk 21 1804H Exxon 3,256 205 1/14/2015

Hughes & Talbot 75-24 2H Anadarko 4,821 89 1/8/2016UL Rock Of Ages 3922-17 1H Felix II 10,196 71 9/21/2016Hughes & Talbot 75-23 2H Anadarko 4,672 136 12/11/2016UTL 4344-21 1H Jagged Peak 9,996 91 7/29/2016University Blk 20 1311H Exxon 9,666 63 8/10/2016UTL L. J. Beldin 1211-17 3H Jagged Peak 9,561 76 9/24/2016Caprito 99 302H Abraxas 4,460 103 11/11/2016RK-Utl 3031B-17 1H Jagged Peak 10,432 65 11/18/2016University 20-4 Lov 3H Shell 4,578 115 1/18/2016Deuces Wild 28-17 2H Anadarko 4,723 71 2/10/2016UL 21 Bighorn 1H Forge Energy 9,400 93 5/29/2016Mesquite Heat 28-41 Unit 1H Anadarko 6,552 89 10/31/2016Corbets 34-149 2WA Callon 9,723 71 11/27/2016UL Lead King 4035-16 1H Felix II 4,850 93 12/31/2016UL 21 Pahaska 1H Forge Energy 4,301 101 11/7/2016Quinn 37 2H WPX Energy 4,780 81 3/17/2017UL 21 Yellowtail 1H Forge Energy 9,512 87 3/1/2017St ll St t 34 208 WRD 1H Sh ll 4 770 68 1/31/2017

2nd Bone Spring

3rd Bone Spring

Wolfcamp A

Operators Unlocking Formation Targets with Strong Well Performance

Selected Wells

21

10

1

8

3

4

17

2

5

7

12

13

14

15

18

11

16

9

19

20

21

26

22

23

24

25

27

6

*

15

6

2

22

4

7

5

8

17

18

19

16

21

14

13

23

24

9

11

26

12

28

29

28

30

27

2930

1

103

20

25

Source: IHS, Drilling Info and Public Data.

UL 18 Dyk 1H Forge Energy 6,893 87 3/30/2017

Wolfcamp B

UTL 2932-17 1H Jagged Peak 10,321 69 6/28/2016UTL 38-17 2H Jagged Peak 4,529 81 3/31/2017Mitchell 39 W101PA Mewbourne 4,801 118 2/6/2017

University B20 1W Mewbourne 4,847 58 1/14/2017University B20 12 Mewbourne 4,585 67 3/24/2017University B20 1_W201PA Mewbourne 4,551 63 2/25/2016University B21 8 Mewbourne 4,444 38 10/28/2016

Wolfcamp C

Exceptional Well Performance With Potential Completion Design Upside

22

Summary Highlights

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

Overpressure helps deliver larger volumes over longer periods

Source: IHS 1) Average Oil Rate for Wolfcamp A&B Wells that came online on January 1,2016 and forwardOffset 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

50

100

200

300

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

1 2 3 4 5 6 7 8 9 10 11 12

Aver

age

Oil

Prod

uctio

n (b

bl/d

per

100

0')

Normalized Months

0

10

20

30

40

50

60

0 3 6 9 12 15 18

Cum

ulat

ive

Oil

Prod

uctio

n (M

bo) /

1,00

0'

Normalized Months

0

10

20

30

40

50

60

0 3 6 9 12 15 18 21 24

Cum

ulat

ive

Oil

Prod

uctio

n (M

bo)/1

,000

'

Normalized Months

Oasis Delaware Well Results are Outperforming Those of Offset Peers

Oasis Wells are Outperforming Peer Type Curves

Source: IHS, Peer disclosure1) 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)

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Oasis Well Results Outperform Offset Operators (1)

Offset Operator Type CurveEUR: 1MMbo (1.2 MMboe)

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

UL 21 Pahaska 1H (WC A)4,301ft Lateral - (12,142ft TVD)

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

UL 21 Yellowtail 1H (WC A)9,512ft Lateral - (12,002ft TVD)

Oasis WC A Average 4 Wells

All wells still flowing without artificial lift

Financial Highlights

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$0

$200

$400

$600

$800

$1,000

$1,200

2017 2018 2019 2020 2021 2022 2023

Revolver balance Revolver capacity 7.25% Notes 6.5% Notes6.875% Notes 6.875% Notes 2.625% Notes

Financial Highlights

Strong Borrowing Base & Liquidity

Current balance of $2,053MM, excluding revolver Current ratings of notes:

□ S&P: BB- (upgraded 9/19/17)□ Moody’s: B3

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

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.

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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)

Long Term Debt

No Near-Term Maturities

Key Investment Highlights for Oasis Petroleum

Concentrated acreage position in the heart of the Williston basin

Vertical integration provides operational flexibility

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Premier Assets

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

Extensive inventory of high-return and low-risk drilling locations, supporting attractive development economics across commodity price cycles

Upside catalysts are near-term and highly visible

Public midstream MLP a vehicle for growth, liquidity and value illumination

Disciplined Management

Focused on capital discipline and delivering returns to shareholders

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

Appendix

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Protecting Execution Plan and Balance Sheet via Strong Hedge Position (1)

Oil Hedge Position Gas Hedge Position

Volume (Mbopd) 2H17 1H18 2H18 2019Swap

Volume 14.3 37.0 35.0 7.0 Price $50.03 $50.89 $50.84 $50.82

2-Way CollarsVolume 4.0 3.0 3.0 - Floor $46.25 $48.67 $48.67 $0.00Ceiling $54.37 $53.07 $53.07 $0.00

3-Way CollarsVolume 3.0 - - - Sub Floor $31.67 $0.00 $0.00 $0.00Floor $45.83 $0.00 $0.00 $0.00Ceiling $59.94 $0.00 $0.00 $0.00Total Volume 21.3 40.0 38.0 7.0

Gas Vol (MMBtu/d) 2H17 1H18 2H18 2019Swap

Volume 11.0 19.0 19.0 - Price $3.30 $3.05 $3.05

1) As of 11/7/17

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ANS

RailroadPipeline

Guernsey

WTI

Clearbrook

Brent

LLS

ANS

2017 Pipe adds

Expanding Takeaway Capacity out of Williston Basin

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

Takeaway Capacity (Mbopd) (1)Takeaway Options

Current Capacity Additions

(MBopd) YE2016 2017 2018Pipeline / 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%

-

500

1,000

1,500

2,000

2,500

3,000

3,500

2010 2011 2012 2013 2014 2015 2016 2017

Pipeline / Refining RailBasin Production NDIC Production Forecast

29

1) Source: North Dakota Pipeline Authority

Key metrics YE 2016Net acreage (000s) 518Estimated net PDP - MMBoe 190.6Estimated net PUD - MMBoe 114.5Estimated net proved reserves - MMBoe 305.1

Percent developed 62% 9/30/2017

Operated rigs running 5Operated 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

Key acreage acquisitions (Net acres / Boepd then current) West Williston East Nesson Delaware

$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

Key Metrics

30

(3)

Guidance(1)

Select Operating Metrics FY13 FY14 FY15 1Q 16 2Q 16 3Q 16 4Q 16 FY16 1Q 17 2Q 17 3Q 17 FY17Production (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 - $2.80Realized Natural Gas Prices ($/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 - $7.70Cash Marketing, Transportation & Gathering ($/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 - $2.30G&A ($/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 $240.3 734 - 759Select Non-Cash Expense Items ($ 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

Financial and Operational Results / Guidance

31

1) Guidance was provided in 11/7/2017 press release, and partially updated in 12/11/17 press release2) 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.

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 SupportIndependent Registered Public Accounting Firm PricewaterhouseCoopers

Legal Advisors DLA Piper LLP / Vinson & Elkins LLP

Reserves Engineers DeGolyer and MacNaughton

32