investor presentation - oasis petroleum...production on target with a strong reserve base q1 2014...

www.oasispetroleum.com1

INVESTOR PRESENTATIONJune 2014


www.oasispetroleum.com 2

Forward-Looking StatementsThis presentation 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. Allstatements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipateswill or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specificallyinclude the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company's drilling program, production, derivativeinstruments, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based onmanagement's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements aresubject 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 thoseimplied or expressed by the forward-looking statements. These include, but are not limited to, the Company’s ability to complete the West Williston and East Nesson Acquisitions, theCompany’s ability to integrate acquired properties into its existing business, changes in oil and natural gas prices, weather and environmental conditions, the timing of planned capitalexpenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement ormaintenance 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 that couldcause actual results to differ materially from those projected as described in the Company's reports filed with the SEC.

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-lookingstatement, whether as a result of new information, future events or otherwise, except as required by applicable law.

Cautionary Statement Regarding Oil and Gas QuantitiesThe 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 andengineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economicconditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations—prior to the time at which contracts providing theright to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SECalso 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 orpossible reserves in our SEC filings.

In this presentation, proved reserves at December 31, 2013 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12‐month average first‐day‐of‐the‐month prices of $96.96 per barrel of oil and $3.66 per MMBtu of natural gas. The reserve estimates for the Company at December 31, 2013, 2012, 2011 and 2010 and for the West Williston Acquisition presented in this presentation are based on reports prepared by DeGolyer and MacNaughton (“D&M”).

We may use the terms "unproved reserves," "EUR per well" and "upside potential" to describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from beingincluded in filings with the SEC. These are the Company’s internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered withadditional drilling or recovery techniques. These quantities may not constitute "reserves" within the meaning of the Society of Petroleum Engineer’s Petroleum Resource ManagementSystem or SEC rules and do not include any proved reserves. EUR estimates and drilling locations have not been risked by Company management. Actual locations drilled and quantitiesthat 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 which have beenattributed 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, drillingand production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors; and actualdrilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, per well EUR and upside potential may change significantly asdevelopment of the Company’s oil and gas assets provide additional data.

Our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and theundertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.

Forward-Looking / Cautionary Statements



Top Pure Play in the Bakken(1)

(1) As of 12/31/13 and does not include acreage or reserves associated with Sanish that were divested in March 2014(2) As of 12/31/13 based on current rig plan

Top tier asset position 506,960 net acres 403 Operated drill blocks

Production on target with a strong reserve base Q1 2014 production 42.9 MBoepd Q2 2014 production of 43-46 MBoepd Proved Reserves 219 MMBoe with PV-10 of $5.2 billion

Driving operational efficiencies Focus on capital cost structure and allocation Testing various completion techniques Driving down LOE to pre-acquisition levels

Advancing / expanding infrastructure development Doubling Oasis Well Services Growing Oasis Midstream Services

3,590 Gross operated locations ~17 years of inventory(2)



Large, Concentrated Acreage Blocks(1)

Concentrated position in Williston Basin: 507k net acres

West Williston: 362K net acres

East Nesson: 145K net acres

Operational control – 94% operated allows for control of rig pace, cost and development

Held-by-production – 82% HBP allows for flexibility in developing asset

High working interest – 68% average WI drives high impact of operated program

Highlights

(53)

West Williston East Nesson

*Acreage in 000s in parenthesis

Montana North Dakota

(75)

(49)

(96)

(75)

(52)

(92)

OTHER(14)

(1) As of 12/31/13 and does not include acreage associated with Sanish that was divested in March 2014


280

1,532

2,020

403

2,607

3,590

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Operated DSUs Net Op and NonOpLocations

Gross Operated Locations

YE 2012 YE 2013

3,590 gross operated locations across 506,960 net acres

94% of net locations are operated 68% average working interest in operated

locations

Gross operated inventory life: ~17 years on current rig plan

Grew inventory 78% year-over-year through acquisitions, downspacing, and lower bench TFS

24 downspacing tests in 2012 - 2014 are now producing

Early performance is encouraging leading to our comfort on ~10 wells per DSU included in our inventory

Growing Inventory(1)

Inventory Highlights Remaining Drilling Locations

(1) As of 12/31/13



39.8

78.7

143.3

219.3

17.0

35.8

70.0

113.7

0

50

100

150

200

250

12/31/10 12/31/11 12/31/12 12/31/13

30.2 30.2

33.1

42.1 42.9

43-46

10.7

22.5

33.9

46-50

0

10

20

30

40

50

60

1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 2011 2012 2013 2014

Production and Reserve Growth Continues

(1) Guidance announced 5/5/14(2) YE13 pro forma for Sanish divestiture of 8.6 MMBoe(3) Growth calculated from 12/31/12 to 12/31/13

Organic growth and acquisitions drive continued production and reserve growth

Actual Production Guidance

Range

Average Daily Production (MBoepd)(1) Estimated Net Proved Reserves (MMBoe)(2)

Total Proved Developed



2014 Plan

2014 Focus Items 2014 Guidance

Inventory acceleration with 16 rigs

Full field development with best practices

Optimizing downspacing

Further TFS delineation

Improving well economics

Completion techniques increasing production Cost and production optimization (lowering cost per

well and operating costs)

Full DSU Development

46%

40%

11%

4%

Bakken

TFS 1

TFS 2

TFS 3

Operated: 205 gross (147.8 net)

Operated and non-operated: 155.5 net

Metric 2014 Range

Production (MBoepd)

Full Year 2014 46.0 - 50.0

2Q14 43.0 - 46.0

Full Year Financial Metrics

LOE ($/Boe) $7.50 - $9.00

MG&T ($/Boe) $1.20 - $1.60

G&A ($ in MMs) $85 - $95

Production taxes (%) 9.5% - 11.0%

D&C E&P Total

CapEx Budget ($MMs) $1,250 $1,367 $1,425



55%

45%

Development drilling

Completion/spacing optimization and acreage hold

Capital Allocation

MONTANA NORTH DAKOTA

2014 Rig AllocationCapital Discipline

2014 Completion Activity

Rig dedicated to development drilling

Rig dedicated to completion/spacing optimization or acreage hold

Rig allocation designed to: Maximize asset value Increase returns across inventory portfolio Balance infrastructure capacity

Approximately 55% of completion activity is dedicated to development drilling

Remainder of rigs focused on: Completion optimization Spacing optimization New acquired acreage hold


Estimate

Cost Increased % of Wells

Test Reduction EUR 2H14

Base Design 40%

Slickwater a 20%

Proppant Optimization a a 25%

Coil Tubing and Cemented Liners a a 15%

Objective

2014 Completion Techniques

Slickwater Completions – West WillistonImproving Capital Efficiency

Completing ~60% of wells in 2H14 with alternative completion techniques

Improving economics to increase production or lower per well costs through completion technology:

Slickwater Increase/decrease proppant Proppant mix Coil tubing completions Indian

Hills

Red Bank

Painted Woods

Foreman Butte

White Unit

Increased production from slickwater completions

White Unit – Illustrative well spacing

Bakken

TFS 1

TFS 2

TFS 3

TFS 4

Early time results with greater than 25% production uplift in multiple areas

Completing ~20% of wells with slickwater in 2H14 to expand feasibility across acreage and test spacing

Completing White on partial unit on up to 5 wells per formation pattern with slickwater wells

Effective 4-5 well per formation spacing



0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

1 31 61 91

Days Producing

750 Mboe Indian Hills Type Curve Indian Hills Base (46 well average)

Indian Hills Slickwater 2 well average

0%

10%

20%

30%

40%

Foreman Butte(12 mo. cum.)

East RedBank(12 mo. cum.)

Indian Hills(3 mo. cum.)

Slickwater Results

% Increase over Surrounding WellsIndian Hills Results (Cumulative Time Plot)(Boe)

28 slickwaterwells vs.

44 base wells


40 base wells


46 base wells

(3) (3) (4)

>30% >30%

25%

(1)

(1) Population includes Oasis Bakken wells only(2) Indian Hills 750 MBoe Bakken type curve parameters: Qi=1,211 Boepd, b=1.6, initial decline 82%, terminal decline 6%(3) Slickwater wells drilled by previous operator of Oasis’ wells or industry. Base wells are surrounding wells drilled by industry.(4) Slickwater and base wells include only Oasis wells

(2)


Attractive Well Costs and Economics

Oasis’ Bakken EURs vary across our acreage position from 450 MBoe to 750 MBoe

Oasis applies different completion techniques across basin to drive higher returns across all EUR profiles

Well costs tend to correlate with EURs Lower well costs / lower half of EUR range Higher well costs / higher half of EUR range

Lowering Well Costs Compelling Well Economics

Illustration(1) Lower Half Mid Upper Half

EUR (Mboe) 525 600 675

Current well cost ($MM)(2) $6.5 $7.2 $7.9

IRR @ $90/bbl WTI 56% 58% 62%

F&D ($/Boe) $15.48 $15.00 $14.63

$9.7

$7.9 $7.6 $9.4

$7.5 $7.2

$0

$2

$4

$6

$8

$10

2012 4Q13 1Q14

($MM)

Excludes OWS Includes OWS

Driving down costs through:

Pad development operations

Efficiency gains

Completion and well design optimization

Exceeded year-end target of $7.3 million in 1Q14

(1) Assumes 10% differential, $8/mcf gas which includes liquids uplift, North Dakota production taxes, and 80% NRI. Bakken type curve parameters: b=1.6, initial decline 76%, terminal decline 6%, GOR varies by type curve

(2) Includes benefit from OWS of $0.4MM per well


Attractive Economics Across Acreage Position

Oasis’ well costs and completion techniques drive strong economics across all bands of the type curve

Hebron wells in Montana have, on average, performed in line with the 450 MBoe type curve

Oasis utilizes a low cost well with effective stimulation to drive strong returns in Montana

Hebron Actual Production ResultsDriving Returns Across the Position

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

1 91 181 271 361 451 541 631 721

Days Producing450 Mboe type curve Hebron (40 wells)

Montana Well Economics

~90,000 net acres (~50,000 net acres in Hebron)

Recent well cost: $6.4MM ($6MM including OWS)

EUR: ~450 MBoe

Strong Economics Across Acreage Position

(Boe)

Recent Current Well Cost

Well Cost Including OWS Savings

Well cost ($MM) $6.4 $6.0

IRR @ $90/bbl WTI(1) 51% 59%

IRR @ $100/bbl WTI(1) 65% 75%

(1) Assumes 10% differential, $8/mcf gas which includes liquids uplift, Montana production taxes, and 80% NRI. Bakken type curve parameters: Qi=563, b=1.6, initial decline 76%, terminal decline 6%, GOR 900


Lower Three Forks Activity

Preliminary results from producing lower bench TFS wells are very encouraging

Oasis expects to complete ~30 wells in TFS2 and TFS3 in 2014, 15 of which are not currently in inventory

Potential to increase drilling locations through lower benches of TFS

Improving Inventory Potential Lower TFS Activity

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

1 31 61 91 121 151

Days on production

OAS TFS Range OAS TFS 2 and 3 wells

600 MBoe

400 MBoe

Current Lower TFS economic bound

Bonita (TFS 2)

Lower TFS Production(1)

(1) Includes wells with more than 30 days of production

Oasis acreage

Selected cores

OAS TFS 2 producer

OAS TFS 3 producer

2014 TFS 2

2014 TFS 3

Expanding Lower TFS economic bound


North Cottonwood

SouthCottonwood

Foreman Butte

Delta

Meiers

Shaw

Indian HillsHebron

Freya

Bonita

State

Mallard

Omlid

PatsyHagen Banks

BrierHysted

Lefty

Loren

Martell

White

Red Bank

Painted Woods

Paul S

Cornell

Autumn Wind

Mangum

Langved

Osage

Ava



Pad Development

Transition to Full Pad Development

90% of drilling in 2014 will be on multi-well pads with increasing pad size

Multi-well pads reduce per well capital costs by approximately 5-10%

First full DSU development in 2014 with 15-20 wells in DSU

Benefits of full DSU development Reduces cycle time Reduces the cost and time associated with

frac protect Improves fracture stimulation efficiency % Wells on Pads

8 Well Simultaneous Operations

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

2012 1Q13 2Q13 3Q13 4Q13 1Q14

Multi-well pads


Oasis Well Services (“OWS”)

OWS Performing 4 Well Simultaneous Completion

2nd frac spread delivery expectations in 1H14; will ramp to 100% utilization by 2H14

2 spreads will complete ~50-60% of Oasis operated wells

Short payback of $20 million incremental CapExfor an additional crew

Visible inventory for multiple frac spreads

OWS savings per well 2014 Plan($000s)

$250

$400 $400

$0

$100

$200

$300

$400

$500

2012 2013 1Q14


Infrastructure Development(1)

Crude Oil Gathering Infrastructure

Oasis legacy acreage

Oasis 3Q14 acquisitions

Oil gathering infrastructure

Rail connection points

Pipeline connection points

Indian Hills


Red Bank

North Cottonwood

SouthCottonwood

Montana

Foreman Butte

Painted Woods

Crude oil gathering (3rd party system)

Realized 9.1% differential in 1Q14 (11.8% in 4Q13)

Provides marketing flexibility to access to 3 pipeline and 7 different rail connection points

~75% oil production flowing through pipeline systems

Gas and liquids gathering (3rd party systems)

Average realization of $9.24/mcf in 1Q14

~97% of wells connected to gathering system

Salt water disposal (Oasis owned system)

Reduces operating expenses and simplifies operations

~53% flowing through gathering systems

~80% disposed in disposal wells

Infrastructure on recent acquisitions

Minimal oil and water infrastructure

18-24 months to put in infrastructure for development

Infrastructure Highlights

(1) As of 3/31/14


Balance Sheet

Liquidity of $1.5 BN

Borrowing base of $1.75BN

Elected commitments of $1.5BN

No near-term debt maturities

Debt Ratings (Moody’s / S&P)

Corporate: B1/BB-

Notes: B2/B+

Hedge program designed to protect drilling

1H14 remaining: 33,500 Bopd hedged

2H14: 27,500 Bopd hedged



Divested non-operated properties for ~$322 million

Closed March 5, 2014

Proceeds for revolver repayment/general corporate purposes

Solid financial profile with substantial liquidity provides business flexibility

Strong Balance Sheet and Liquidity Liquidity and Capitalization as of 3/31/14 ($MM)

Cash and marketable securities $56

Current elected commitments 1,500

Borrowing / LCs (65)

Total Liquidity $1,491

Debt

Revolver $60

7.25% Senior Notes due 2019 400



6.875% Senior Notes due 2022 1,000

Total long-term debt 2,260

Total Enterprise Value(1)$7,291

(1) Calculated as book debt less cash plus market value of equity

($50.27/share as of 5/29/14)


Investment Highlights

Oil focused, pure play in the Williston Basin

Large, concentrated acreage position with increasing identified drilling inventory

Substantial upside potential with known catalysts

Improving capital and operational efficiency

Growing production profile with capital going towards increasing reserves and lowering costs

Proven management team and great people growing long-term shareholder value


APPENDIX



Risk Management(1)

(1) As of 5/22/14

Type Remaining Term Sub-Floor Floor Ceiling Swaps BOPD Total Barrels

2014

Full Year

Swaps Apr - Dec $95.90 9,500 2,612,500

Swaps w/Sub-Floor Apr - Dec $70.00 $92.60 6,000 1,650,000

Two-Way Collars Apr - Dec $90.00 $100.71 3,500 962,500

Three-Way Collars Apr - Dec $70.59 $90.59 $105.25 8,500 2,337,500

1H14

Swaps Apr - June $99.42 4,000 364,000

Three-Way Collars Apr - June $70.00 $90.00 $103.98 2,000 182,000 Total 2014 Hedges (Weighted Average) $70.33 $90.39 $103.93 $95.00 29,485 8,108,500

Remaining 1H14 Hedges 33,500

Total 2H14 Hedges 27,500

2015

Full Year

Swaps Jan - Dec $90.15 10,000 3,650,000

1H15

Swaps Jan - June $91.26 9,000 1,629,000 Total 2015 Hedges (Weighted Average) $90.49 14,463 5,279,000



Weighted Average Prices ($/Bbl)


Type Curves in Williston Basin(1)

Years

Middle Bakken Type Curve (MBoe) TFS Type Curve (MBoe)

HighMidpointLow

HighMidpointLow

Years

Middle Bakken Type Curve Metrics TFS Type Curve

Low End Midpoint High End Low End Midpoint High End

450 600 750 Gross Reserves (MBoe) 400 500 600

536 704 873 IP – 7 day average (Boepd) 480 592 704

415 545 675 1st 60 days - average (Boepd) 371 458 545

359 471 584 2nd 30 days - average (Boepd) 321 396 471

Cumulative (Mboe)

14 19 23 30 day 13 16 19

25 33 41 60 day 22 27 33

55 72 89 180 day 49 60 72

85 111 138 365 day 76 93 111

(1) Type curve parameters: Qi=varies, b=1.6, initial decline 76%, terminal decline 6%


-

500

1,000

1,500

2,000

2,500

3,000

2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

March 2014 production: 1,055MBopd

Expanding Takeaway Capacity out of Bakken (1)

North Dakota Montana Refineries Pipelines Rail

(1) Actual and announced projects per North Dakota Pipeline Authority. (2) Per North Dakota Pipeline Authority Monthly Update dated 5/30/14. Considers North Dakota March preliminary production and assumes Montana/SD production is flat from February.

Expanding takeaway capacity with increased pipeline coming in 2016

(2)

Takeaway CapacityProductionMbopd



0x

10x

20x

30x

40x

50x

60x

$0

$20

$40

$60

$80

$100

$120

WTI ($/bbl) HH ($/mmbtu) WTI - HH Price Ratio

Oil Weighted Production

WTI – Henry Hub Price Disparity ($/bbl to $/Mmbtu)(1) Oasis Oil and Gas Production (per MBoe)

MBoepd % Oil

Oil weighted production drives high realized prices, especially given the disparity in pricing between WTI and Henry Hub

Price Ratio

(1) As of 5/29/14

$4.74

$103.58

22x

7.5 11.2

14.4 16.2

18.5

22.6 25.0

27.6 27.4 29.5

37.5 38.3

0.4

0.4

0.8 1.4

1.9

1.7

2.5

2.6 2.8

3.6

4.6 4.5

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

-

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14

Oil Gas % Oil


Key Metrics by Project Area

(1) As of 12/31/13 and does not include non-op properties divested March 5, 2014(2) East Nesson includes production of 1,649 Boepd from non-op properties divested March 5, 2014(3) As of 3/31/14

Key Statistics West Williston East NessonTotal

Williston2014 CapEx Budget ($MM)

Net acreage (000s)(1) 362 145 507 Dri l l ing and completion $1,250

Estimated net PDP - MMBoe (1) 79.5 34.3 113.7 Oas is Midstream Services ("OMS") 60

Estimated net PUD - MMBoe (1) 74.5 31.0 105.5 Leasehold 25

Estimated net proved reserves - MMBoe(1) 154.0 65.3 219.3 Faci l i ties and other misc. 19

Percent developed(1) 51.6% 52.5% 51.8% Micro-seis and other tests 13

1Q14 production (Mboe/d)(2) 28.2 14.6 42.9 Total E&P CapEx 1,367

Operated rigs running(3) 10 5 15 Oas is Wel l Services ("OWS") 35

Bakken / TFS operated wel ls waiting on completion (3)25 22 47 Non-E&P 23

Total CapEx $1,425

2014 completed wells (Budget)

Gross operated 123 82 205

Net operated 85.1 62.7 147.8

Working interest in operated wel ls 69% 76% 72%

Net non-operated 5.2 2.5 7.7

Total net wells 90.3 65.2 155.5

Key acreage acquisitions (Net acres / Boepd 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


Williston Inventory (1)

(1) As of 12/31/13 not including non-op properties divested March 2014. Inventory assumes on average 10 wells per DSU

Bakken TFS Total Bakken TFS Total

Operated

PUD Wells

West Williston 201 53 254 134 33 167

East Nesson 85 19 104 61 12 73

Total PUD Wells 286 72 358 195 45 240

Non-Proven Wells

West Williston 829 1,118 1,947 585 747 1,332

East Nesson 516 769 1,285 347 531 878

Total Non-Proven Wells 1,345 1,887 3,232 932 1,278 2,210

Total Operated

West Williston 1,030 1,171 2,201 719 780 1,499

East Nesson 601 788 1,389 408 542 951

Total Operated 1,631 1,959 3,590 1,128 1,322 2,450

Non-Operated

West Williston 57 57 113

East Nesson 23 23 44

79 79 157

Operated and Non-Operated

West Williston 776 836 1,612

East Nesson 431 565 995

1,207 1,401 2,607

Gross Net

Total Non-Operated

Total Inventory

DSUs DSUs % Total

7 Wells per DSU 137 34%



Total DSUs 403 100%

Spacing Assumptions

34%

40%

26%

7 Wells per DSU 10 Wells per DSU

15 Wells per DSU


Bakken / TFS Drilling Program by Project Area(1)

Bakken / Three Forks Producing Wells

West Williston East Nesson Sanish Total Williston Basin

Gross Net Gross Net Gross Net Gross Net

Producing on or before 12/31/13

Operated 311 240.6 145 115.2 - - 456 355.8

Non-Operated 151 12.6 109 8.4 323 25.0 583 46.0

Production started in 1Q14

Operated 28 20.3 12 9.6 - - 40 29.9

Non-Operated 11 0.8 1 - - - 12 0.8

Divest/Adjust 1Q2014

Operated (1) (0.9) 1 0.9 - - - -

Non-Operated - - (12) (1.3) (323) (25.0) (335) (26.3)

End of Q1 Producing

Operated 338 260.0 158 125.7 - - 496 385.7

Non-Operated 162 13.4 98 7.2 - - 260 20.5

(1) Producing wells exclude all well associated with non-operated assets divested in March 2014


Financial and Operational Results / Guidance

Actual

Select Operating Metrics FY 10 FY11 1Q 12 2Q 12 3Q 12 4Q 12 FY12 1Q 13 2Q 13 3Q 13 4Q 13 FY13 1Q 14 2Q 14 FY14

Production (MBoepd) 5.2 10.7 17.6 20.4 24.3 27.6 22.5 30.2 30.2 33.1 42.1 33.9 42.9 43 - 46 46 - 50

Production (MBopd) 4.9 10.2 16.2 18.5 22.6 25.0 20.6 27.6 27.3 29.5 37.5 30.5 38.3

% Oil 94% 95% 92% 91% 93% 91% 92% 91% 91% 89% 89% 90% 89%

WTI ($/Bbl) $80.19 $94.55 $103.03 $93.23 $92.41 $88.21 $93.39 $94.30 $94.17 $105.86 $97.39 $98.05 $98.63

Realized oil prices ($/Bbl) $69.60 $86.18 $88.10 $82.36 $83.71 $86.82 $85.22 $93.33 $91.15 $100.75 $85.87 $92.34 $89.66

Differential to WTI 13% 9% 14% 12% 9% 2% 9% 1% 3% 5% 12% 6% 9%

Realized natural gas prices ($/Mcf) $6.52 $8.02 $8.32 $6.52 $5.33 $6.31 $6.52 $7.18 $5.98 $6.80 $7.04 $6.78 $9.24

LOE ($/Boe) (1) $7.43 $8.36 $6.12 $6.49 $7.23 $6.68 $6.68 $7.18 $6.65 $7.18 $9.05 $7.65 $10.37 $7.50 - $9.00

Cash marketing, transportation & gathering ($/Boe) (1) $0.24 $0.34 $0.74 $1.06 $1.23 $1.03 $1.04 $1.23 $1.82 $1.70 $1.36 $1.52 $1.53 $1.20 - $1.60

G&A ($/Boe) $10.39 $7.52 $7.60 $7.31 $6.22 $6.93 $6.95 $5.10 $6.07 $5.50 $7.25 $6.09 $6.10

Production Taxes (% of oil & gas revenue) (1) 10.7% 10.2% 9.6% 9.5% 9.2% 9.4% 9.4% 9.1% 9.1% 9.4% 9.6% 9.3% 9.6% 9.5% - 11%

DD&A Costs ($/Boe) $19.91 $19.16 $24.23 $23.87 $25.85 $26.01 $25.14 $24.42 $24.33 $23.91 $26.14 $24.81 $23.66

Select Financial Metrics ($ MM)

Oil Revenue $124.7 $321.7 $129.9 $138.6 $173.8 $199.8 $642.0 $231.7 $226.8 $273.7 $295.9 $1,028.1 $309.2

Gas Revenue 4.2 8.8 6.5 6.6 5.0 8.9 27.0 10.0 9.2 13.3 18.1 50.5 22.6

Bulk Purchase of Oil Revenue - - 1.5 - - - 1.5 - 5.8 - 0.0 5.8 0.0

OWS and OMS Revenue - - 0.7 3.9 6.0 5.7 16.2 6.7 12.7 18.5 19.6 57.6 17.7

Total Revenue $128.9 $330.4 $138.6 $149.1 $184.7 $214.3 $686.7 $248.3 $254.6 $305.5 $333.6 $1,142.0 $349.5

LOE 14.1 32.7 9.8 12.0 16.1 16.9 54.9 19.5 18.3 21.8 35.0 94.6 40.0

Cash marketing, gathering & transportation (2) 0.5 1.4 1.2 2.0 2.7 2.7 8.6 3.3 5.0 5.2 5.3 18.8 5.2

Production Taxes 13.8 33.9 13.3 13.7 16.4 19.5 63.0 22.1 21.4 26.8 30.2 100.5 31.8

Exploration Costs 0.3 1.7 2.8 - 0.3 0.1 3.2 1.9 0.4 0.5 (0.5) 2.3 0.4

Bulk purchase of oil cost and non-cash valuation adjustment (2) - - 1.4 - - (0.7) 0.7 0.1 5.8 0.5 0.8 7.2 (0.7)

OWS and OMS expenses - - 0.5 1.2 5.4 4.7 11.8 2.9 6.6 10.3 10.8 30.7 10.9

G&A (1) 19.7 29.4 12.2 13.5 13.9 17.6 57.2 13.9 16.7 16.7 28.1 75.3 23.5 $85 - $95

Adjusted EBITDA (3) $82.2 $234.5 $101.1 $108.5 $139.2 $163.5 $512.3 $191.4 $185.5 $219.6 $225.4 $821.9 $239.8

DD&A costs 37.8 75.0 38.9 44.2 57.7 66.0 206.7 66.3 66.8 72.7 101.3 307.1 91.3

Interest expense 1.4 29.6 13.9 14.1 21.0 21.2 70.1 21.2 21.4 22.9 41.7 107.2 40.2

E&P CapEx (1,4) 345.6 637.3 267.0 263.2 311.4 270.1 1,111.7 238.7 178.5 243.2 256.3 916.7 297.1 $1,367

Non E&P CapEx 6.8 28.7 21.3 4.1 5.3 6.2 36.9 1.6 4.9 6.5 13.1 26.2 10.4 $58

Total CapEx (1,4) $352.4 $666.0 $288.3 $267.3 $316.7 $276.3 $1,148.6 $240.3 $183.4 $249.7 $269.5 $942.9 $307.5 $1,425

Select Non-Cash Expense Items ($ MM)

Impairment of oil and gas properties $12.0 $3.6 $0.4 $2.2 $0.0 $1.0 $3.6 $0.5 $0.2 $0.1 $0.4 $1.2 $0.8

Amortization of restricted stock (5) 1.2 3.7 1.6 2.3 2.7 3.7 10.3 2.3 3.1 3.0 3.6 12.0 4.5

Amortization of restricted stock ($/boe) (5) $0.65 $0.93 $0.99 $1.25 $1.22 $1.46 $1.26 $0.84 $1.12 $1.00 $0.92 $0.97 $1.17

(1) Guidance was provided in press release on 2/4/14. 2014 has impact of selling certain non-operated properties in early March 2014. 2Q14 production guidance issued 5/5/14.(2) Excludes marketing expense of $1.4MM in 1Q12 and $5.8MM in 2Q13 associated with the bulk oil purchase, ($0.7MM) in 4Q12, $0.1MM in 1Q13, $0.5MM in 3Q13, $0.8MM in

4Q13 and ($0.7MM) in 1Q14 associated with non-cash valuation change on our pipeline imbalances and line fill inventory. These items are included under "Bulk Purchase of Oil Cost and non-cash valuation adjustment.“

(3) Non GAAP Adjusted EBITDA Reconciliation can be found on the Oasis website at www.oasispetroleum.com.(4) Excludes capital for acquisitions in 2013 of $1,563MM.(5) Non-Cash Amortization of Restricted Stock is included in G&A.

http://www.oasispetroleum.com/


Key Company Facts / External Support

Oasis Petroleum Inc.

Exchange / Ticker NYSE / OAS

Shares Outstanding (as of 3/31/13) 101.2 MM

Share Price (close on 5/29/14) $50.27 per share

Approximate Equity Market Capitalization $5.0BN

External Support

Independent Financial/Tax Auditor PricewaterhouseCoopers

Legal Advisors DLA Piper LLP / Vinson & Elkins, LLP

Reserves Engineers DeGolyer and MacNaughton

investor presentation - oasis petroleum...production on target with a strong reserve base q1 2014...

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