aggressively drilling - oasis petroleum...in this presentation, proved reserves at june 30, 2013 are...

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Aggressively Drilling the Williston Basin

INVESTOR PRESENTATION November 2013


Forward-Looking Statements This 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. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. Without limiting the generality of the foregoing, forward-looking statements contained in this presentation specifically include the expectations of plans, strategies, objectives and anticipated financial and operating results of the Company, including the Company's drilling program, production, derivative instruments, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include, but are not limited to, the Company’s ability to complete the West Williston and East Nesson Acquisitions, the Company’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 capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as the Company's ability to access them, the proximity to and capacity of transportation facilities, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting the Company's business and other important factors that could cause 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-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

Cautionary Statement Regarding Oil and Gas Quantities The SEC requires oil and gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions (using unweighted average 12-month first day of the month prices), operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves; however, we currently do not disclose probable or possible reserves in our SEC filings. In this presentation, proved reserves at June 30, 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 $91.53 per barrel of oil and $3.44 per MMBtu of natural gas. The reserve estimates for the Company at June 30, 2013 presented in this presentation are based on internal estimates, approximately 93% of which have been audited by DeGolyer and MacNaughton (“D&M”), independent reserve engineers. The reserve estimates for the Company at December 31, 2012, 2011 and 2010 and for the West Williston Acquisition at June 30, 2013 presented in this presentation are based on reports prepared by 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 being included 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 with additional drilling or recovery techniques. These quantities may not constitute "reserves" within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or SEC rules and do not include any proved reserves. EUR estimates and drilling locations have not been risked by Company management. Actual locations drilled and quantities that may be ultimately recovered from the Company’s interests will differ substantially. There is no commitment by the Company to drill all of the drilling locations which have been attributed to these quantities. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling 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, per well EUR and upside potential may change significantly as development 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 the undertaking 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) Pro forma as of 6/30/13 based on current rig count of 14 at a pace of 185 wells per year

492,000 net acres

Estimated production range of 42-46 MBoepd in 4th quarter 2013

Proved reserves of 216 MMBoe with PV-10 of $5.0 billion

399 operated drill blocks / ~16 years of inventory(1)

Driving operational efficiencies and infrastructure development


Large, Concentrated Acreage Blocks(1)

West Williston East Nesson

*Sanish is a non-op position

**Acreage in 000s in parenthesis

(1) Pro forma as of 6/30/13

Montana North Dakota • Operational control – 91% operated allows for control of rig pace, cost and development

• Held-by-production – 86% HBP allows for flexibility in developing asset

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

• West Williston: 346,000 net acres • East Nesson: 146,000 net acres

(51)

(63)

(50) (91)

(74)

(52)

(86)

(8)

Highlights


2,874 gross operated locations across 492,000 net acres

91% of net locations are operated

68% average working interest in operated locations

Gross operated inventory life: ~16 years @ 185 wells/year

Inventory

Drilling Locations (1)

(1) Assumes 4 wells per formation (MB and TFS 1) in spacing units, based on 1,280 acre spacing unit

Inventory Highlights(1)

1,235 841 924

1,639

1,118 1,226

399

2,874

1,959 2,150

0

500

1,000

1,500

2,000

2,500

3,000

3,500

Gross OperatedSpacing Units

Gross OperatedInventory

Net OperatedInventory

Net Operated andNon-Operated

InventoryBakken Three Forks


Inventory Growth through Downspacing and TFS

4 Bakken Up to 6

Current Potential2,874 ??

Gross Operated Inventory

4 TFS 1 Up to 6

0 TFS 2 Up to 6

0 TFS 3 Up to 6

Wells per DSU per Formation

Current Formation Potential


Inventory Growth – Downspacing Activity in the Basin

Oasis testing up to 7 wells per formation in Bakken and TFS 1 22 DSU spacing tests in 2013 13 DSUs now producing

Preliminary findings indicate 4-6 wells per formation (MB and TFS 1) per DSU depending on location

Industry testing up to 8 wells per formation in MB, TFS 1, TFS 2 and TFS 3

Improving Inventory Potential

Oasis downspacing tests

Industry downspacing tests

Downspacing Activity

Industry Downspacing Tests(1) (1) Tangrsud (CLR) – 4 wells per zone through TFS 3

(2) Polar (KOG) – 6 MB wells and 3 wells in TFS 1 and 3 wells in TFS 2

(3) Rollefstad (CLR) – 4 wells per zone through TFS 3

(4) Charlotte (CLR) – 4 wells per zone through TFS 3

(5) Wahpeton (CLR) – 8 wells per zone through TFS 3

(6) Hidden Bench (WLL) – 4 MB wells and 3 wells in TFS 1

(7) Smokey (KOG) – 6 MB wells and 3 wells in TFS 1 and 3 wells in TFS 2

(8) Hawkinson (CLR) – 4 wells per zone through TFS 3

6 tests

8 tests

6 tests

2 tests

1

8

3

4 5

2

7 6

(1) Source: Company provided investor presentations

Oasis acreage


Oasis lower bench TFS

Industry lower bench TFS

Inventory Growth – Lower Bench TFS Activity in the Basin

Oasis has two TFS 2 and one TFS 3 wells producing in Indian Hills with encouraging results One TFS 2 well in Cottonwood is waiting on

completion 15 additional lower bench wells spud in next two

quarters Oasis has 7 core wells across acreage position

through TFS 4 Industry tests are in and around our acreage with

positive results

Improving Inventory Potential

TFS Wells(1)

Oasis Selected Operated Other Selected Wells

TFS 2 and 3 TFS activity in lower benches

(1) Bonita TFS 2 (5) Rosenvold (CLR) TFS 2, 3, and 4 (2) Mangum TFS 3 (6) Stedman (CLR) TFS 2 and 3

(3) Paul S TFS 2 (7) Barney (CLR) TFS 2 and 3

(4) Patsy TFS 2 (8) Polar (KOG) TFS 1 and TFS 2 (5) Omlid TFS 3 (9) Angus (CLR) TFS 2

(10) Charlotte (CLR) TFS 2 and 3 (11) Riverview (EOG) TFS 2 (12) Sunline (COP) TFS 2 (13) Chitwood (WLL) TFS 2 (14) Smokey (KOG) TFS 1 and TFS 2

Oasis core wells

Lower TFS Activity

1

3

6 7

5

13

11 4 5

14

8

Oasis acreage

9

10

(1) Source: Company provided investor presentations

12

2


Production and Reserve Growth Continues

Average Daily Production (MBoepd)(1)

(1) Guidance as of 11/6/13 (2) Growth calculated from 12/31/12 to mid-year estimate

Organic growth combined with acquisitions drive continued production and reserve growth

Estimated Net Proved Reserves (MMBoe)

39.8

78.7

143.3

215.6

17.0 35.8

70.0

100.8

0

50

100

150

200

250

2010 2011 2012 6/30/2013

Total Proved Developed

Historical Guidance range

8 812

1518

2024

2830 30

33

42-46

0

5

10

15

20

25

30

35

40

45

50

1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 E

(MBoepd)


$10.5

$8.0 $7.5

$7.5 $7.3

$0

$2

$4

$6

$8

$10

$12

1H2012 3Q13 YE14 Target

($MM)

Attractive Well Costs and Economics

Driving down costs through: Lower service costs Efficiency gains Completion and well design optimization Pad development operations

Lowering Well Costs Compelling Well Economics

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

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

Well assumptions assume similar characteristics except for well cost and EUR. Assumes $90/bbl WTI with 8% differential, 80% NRI and 700 GOR

Excludes OWS Includes OWS

Illustration Lower Half Midpoint Upper HalfEUR Range Low Midpoint Midpoint High MidpointEUR (MBoe) 525 600 675Current well cost ($MM) $6.5 $7.5 $8.5

IRR @ $90/bbl WTI 55% 58% 58%F&D ($/Boe) $15 $16 $16


8 Well Pad Utilizing Simultaneous Operations

Reduces costs by 5 to 10% compared to single well Reduces downtime during frac operations Decreases rig mobilization time and cost Lowers facilities and surface costs

Moving from 60-70% of wells on pads in 2013 to 80-90% of wells on pads in 2014

4 wells drilling batch mode

4 wells frac’ing

Above Ground Storage Tank

Transitioning into Full Pad Development during 2013


Oasis Well Services (“OWS”)

Exceeding expectations – performance and savings Retain control and drives down well cost of the highest cost

item of well Improves cash flow

CapEx: Save ~$500k per gross well on 40-50% of operated wells

EBITDA: Improve EBITDA ~$200k per gross well Frac 4-6 wells per month with one frac spread

OWS Performing 4 Well Simultaneous Completion

Historical Highlights

Insert picture

2014 Plan

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 CapEx for an

additional crew Visible inventory for multiple frac spreads


Infrastructure Development1

Crude Oil Gathering Infrastructure

Oasis stand-alone acreage Oil gathering infrastructure Rail connection points Pipeline connection points

Indian Hills

MONTANA NORTH DAKOTA

Red Bank

North Cottonwood

South Cottonwood

Montana

Painted Woods

Foreman Butte

Infrastructure Highlights

Crude oil gathering (3rd party system) • Realized 3% differential YTD • Provides marketing flexibility to access to 3

pipeline and 7 different rail connection points • ~85%+ oil production flowing through pipeline

systems, as of 9/30/13 Gas and liquids gathering (3rd party system) • Realized $6.65/mcf YTD 2013 • ~95% flowing through gathering system

Salt Water Disposal (Oasis owned system) • Reduces operating expenses and simplifies

operations • 57% flowing through gathering systems • 87% disposed in disposal wells

(1) As of 9/30/13


Balance Sheet

Pro forma liquidity of $1.0BN as of 9/30/13 Borrowing base of $1.5BN No near-term debt maturities Debt Ratings (Moody’s / S&P)

Corporate: B2/BB- Notes: B3/B

Hedge program designed to protect drilling 4Q13: 32,500 Bopd hedged 2014:

1H14: 27,500 Bopd hedged 2H14: 21,500 Bopd hedged

Strong Balance Sheet and Liquidity

Solid financial profile with substantial liquidity provides business flexibility

Liquidity and Capitalization as of 9/30/13 ($MM)

As of 9/30/13 As Reported Pro Forma(1)

Cash and marketable securities $125 $145Restricted cash 986 -Current borrowing base 1,500 1,500Borrowings / LCs (165) (605)Total l iquidity(2) $2,446 $1,040

DebtRevolver $160 $6007.25% Senior Notes due 2019 400 4006.5% Senior Notes due 2021 400 4006.875% Senior Notes due 2023 400 4006.875% Senior Notes due 2022 1,000 1,000Total long-term debt 2,360 2,800

Total Enterprise Value(3) $6,164 $7,570

(1)(2)(3)

Pro forma reflects the closing of the acquisition and funding on 10/1/13

Calculated as book debt less cash (including restricted) plus market value of equity ($52.55/share as of 11/06/13)

Total liquidity includes restricted cash


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 of11/6/13

Type Remaining Term Sub-Floor Floor Ceiling Swaps BOPD Total Barrels 2013

Swaps Oct - Dec $98.00 10,500 966,000 Two-Way Collars Oct - Dec $93.41 $104.85 11,000 1,012,000 Three-Way Collars Oct - Dec $68.12 $91.88 $110.83 10,630 977,960 Put Spreads (No Ceil ing) Oct - Dec $70.00 $90.00 370 34,040

Total 4Q 2013 Hedges (Weighted Average) $68.18 $92.61 $107.79 $98.00 32,500 2,990,000

20141H14

Swaps Jan-Jun $99.42 4,000 724,000 Three-Way Collars Jan-Jun $70.00 $90.00 $103.98 2,000 362,000

Full YearSwaps Jan-Dec $93.07 3,500 1,277,500 Swaps with sub-floor Jan-Dec $70.00 $92.60 6,000 2,190,000 Two-Way Collars Jan-Dec $90.00 $101.14 3,500 1,277,500 Three-Way Collars Jan-Dec $70.59 $90.59 $105.25 8,500 3,102,500

Total 2014 Hedges (Weighted Average) $70.32 $90.38 $104.05 $93.92 24,475 8,933,500 Total 1H14 Hedges 27,500 Total 2H14 Hedges 21,500

Weighted Average Prices ($/Bbl)


Middle Bakken Type Curve

(1) Includes OWS Impact

Years

High: 750 Mboe Average: 600 Mboe Low: 450 Mboe

Average Low End High End

Gross Reserves (MBoe) 600 450 750IP – 7 day average (Boepd) 704 536 8731st 60 days - average (Boepd) 545 415 6752nd 30 days - average (Boepd) 471 359 584Cumulative (Mboe)30 day 19 14 2360 day 33 25 41180 day 72 55 89365 day 111 85 138

3Q13 Average Well Cost ($MM) $7.5


-

300

600

900

1,200

1,500

1,800

2,100

2,400

1H2007

2H2007

1H2008

2H2008

1H2009

2H2009

1H2010

2H2010

1H2011

2H2011

1H2012

2H2012

1H2013

2H2013

1H2014

2H2014

1H2015

2H2015

1H2016

2H2016

Expanding Takeaway Capacity out of Bakken (1)

(1) Actual and announced projects. Public filings and North Dakota Pipeline Authority and includes data supplied by IHS Global Inc; Copyright 2010. (2) Per North Dakota Pipeline Authority Monthly Update dated October 15, 2013. Considers North Dakota August preliminary production and assumes Montana/SD production is flat to May.

Take-Away Capacity (MBopd)

North Dakota Production

Montana Production

August 2013 production: 989MBopd(2)

Production

Refinery Rail and Trucking Pipelines


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 Stand-Alone 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 11/1/2013

$3.46

$94.61

27x

7.5

11.2 14.4

16.2 18.5

22.6 25.0

27.6 27.4 29.5

0.4

0.4 0.8

1.4 1.9

1.7 2.5

2.6 2.8 3.6

95% 96% 94% 92% 91% 93%

91%

92% 91% 89%

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

2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13Oil Gas % Oil


$10.5

$8.8 $8.4 $8.2 $8.0 $8.0 $8.5 $8.1 $7.8 $7.5 $7.8

$0

$2

$4

$6

$8

$10

$12

1H2012 YE12 1Q13 2Q13 3Q13 YE '13 Target

Stand-Alone 2013 Capital Plan – Improving Capital Efficiency

2013 Plan Highlights ($MM)

Current well costs at $7.5MM, including OWS impact Driving down costs through: Lower service costs Efficiency gains Completion and well design optimization Pad development operations

Capital Efficiency ($MM)

CapEx Budget 2013Dril l ing and completion $897Oasis Midstream Services ("OMS") 43Leasehold 25Facil ities and other misc. 21Micro-seis and other tests 10Total E&P CapEx 996Oasis Well Services ("OWS") 14Non-E&P 10Total CapEx $1,020

Year over Year Capital Efficiency Improvement

Average budgeted well cost of $8.5MM - $8.7MM, before OWS impact

128 gross (94.9 net) operated wells completed 105.8 total net wells completed

2013 2012 DeltaWells completed

Gross operated 128 117 11

Net operated 94.9 95.8 (0.9) Net non-operated 10.9 9.8 1.1

Total net wells 105.8 105.6 0.2

Drilling and completion CapEx ($MM) $897 $1,008 ($111)

Includes OWS Excludes OWS


Metric West Williston East Nesson Sanish Total Williston

Net Acreage (000s)(1) 346 138 8 492

Estimated net PDP - MMBoe(2) 66.2 26.7 7.9 100.8

Estimated net PUD - MMBoe(2) 78.3 35.4 1.1 114.8

Estimated net Proved Reserves - MMBoe(2) 144.5 62.1 9.0 215.6

Percent Developed(2) 46% 43% 89% 47% 3Q13 production (Mboe/d) 19.3 11.0 2.8 33.1

Operated rigs running(1) 9 5 0 14

Bakken / TFS Wells(3)

Operated waiting on completion 22 15 0 372013 completed wells (plan) - prior to acquisitions announced 9/5/13

Gross operated 75 53 0 128Net operated 56.8 38.1 0.0 94.9Working interest in operated wel l s 76% 72% 0% 74%Net non-operated 2.9 2.3 5.8 10.9Total net wells 59.7 40.4 5.8 105.8

2013 CapEx Budget ($MM) - prior to acquisitions announced 9/5/13Dri l l ing capi ta l $520 $329 $48 $897 Leasehold 25 Infrastructure and faci l i ties 54 Geologic, Geophys ica l and other 20 Total E&P CapEx 996 Oas is Wel l Services 14 Non E&P 10 Total Company CapEx $1,020

Key acreage acquisitions (Net acres / Boepd then current)$83MM in June 2007 175,000 / 1,000$16MM in May 2008$27MM in June 2009$11MM in September 2009$82MM in 4Q 2010 26,700 / 500$1,542MM in 3Q/4Q 2013 136,000/9,000 25,000/300

48,000 / 037,000 / 80046,000 / 300

Key Metrics by Project Area

(1) Current (2) Pro forma as of 9/30/13 (3) As of 9/30/13 excluding acquisitions


Williston Inventory (1) – For Stand-Alone

(1) As of 12/31/12. Inventory assumes four wells in the Bakken and TFS formations in all core project areas

Bakken TFS Total Bakken TFS Total Bakken TFS Total Bakken TFS Total Bakken TFS Total Bakken TFS TotalOperated

West Williston 144 21 165 104.2 14.1 118.2 425 679 1,104 289.2 477.9 767.1 569 700 1,269 393.4 491.9 885.4 East Nesson 62 11 73 40.2 6.4 46.6 288 390 678 197.3 269.9 467.2 350 401 751 237.5 276.3 513.9

Total Operated 206 32 238 144.3 20.5 164.9 713 1,069 1,782 486.6 747.8 1,234.4 919 1,101 2,020 630.9 768.3 1,399.2 Non Operated

West Williston 5 3 8 0.2 0.0 0.2 344 372 716 44.0 47.3 91.3 349 375 724 44.1 47.3 91.4 East Nesson 5 2 7 0.1 0.2 0.3 104 136 240 11.8 14.5 26.3 109 138 247 12.0 14.7 26.6 Sanish 23 9 32 2.5 0.7 3.3 39 109 148 2.8 8.9 11.8 62 118 180 5.3 9.7 15.0 Total Non-operated 33 14 47 2.8 0.9 3.7 487 617 1,104 58.7 70.7 129.3 520 631 1,151 61.5 71.6 133.1

Company Total InventoryWest Williston 149 24 173 104.3 14.1 118.4 769 1,051 1,820 333.2 525.2 858.4 918 1,075 1,993 437.6 539.2 976.8 East Nesson 67 13 80 40.3 6.6 46.9 392 526 918 209.2 284.4 493.6 459 539 998 249.5 291.0 540.5 Sanish 23 9 32 2.5 0.7 3.3 39 109 148 2.8 8.9 11.8 62 118 180 5.3 9.7 15.0 Total Inventory 239 46 285 147.2 21.4 168.6 1,200 1,686 2,886 545.2 818.5 1,363.7 1,439 1,732 3,171 692.4 839.9 1,532.3

PUD Non-Proven Total Inventory Gross Net Gross Net Gross Net


Bakken / TFS Drilling Program by Project Area – For Stand-Alone

Gross Net Gross Net Gross Net Gross Net

Operated 185 148.5 92 76.9 0 0 277 225.4Non-Operated 55 4.6 95 7.0 290 22.6 440 34.2

Production started in Q3 2013:Operated 16 11.9 22 15.8 0 0.0 38 27.7Non-Operated 3 0.0 5 0.3 20 1.6 28 1.9

Total Producing Wells on 9/30/13:Operated 201 160.4 114 92.7 0 0 315 253.1Non-Operated 58 4.6 100 7.3 310 24.2 468 36.1

(1) Well counts include changes that occurred in the current reporting period for wells producing on or before June 30, 2013.

Bakken/Three Forks Producing Wells

Producing on or before 6/30/13: (1)

West Williston East Nesson Sanish Total Williston Basin


Financial and Operational Results / Guidance

ActualSelect Operating Metrics FY 10 FY11 1Q 12 2Q 12 3Q 12 4Q 12 FY12 1Q 13 2Q 13 3Q 13 4Q 13 FY13Production (MBoepd) 5.2 10.7 17.6 20.4 24.3 27.6 22.5 30.2 30.2 33.1 42.0 - 46.0Production (MBopd) 4.9 10.2 16.2 18.5 22.6 25.0 20.6 27.6 27.3 29.5 % Oil 94% 95% 92% 91% 93% 91% 92% 91% 91% 89%WTI ($/Bbl) $80.19 $94.55 $103.03 $93.23 $92.41 $88.21 $93.39 $94.30 $94.17 $105.86 Realized oil prices ($/Bbl) $69.60 $86.18 $88.10 $82.36 $83.71 $86.82 $85.22 $93.33 $91.15 $100.75 Differential to WTI 13% 9% 14% 12% 9% 2% 9% 1% 3% 5%Realized natural gas prices ($/Mcf) $6.52 $8.02 $8.32 $6.52 $5.33 $6.31 $6.52 $7.18 $5.98 $6.80

LOE ($/Boe) $7.43 $8.36 $6.12 $6.49 $7.23 $6.68 $6.68 $7.18 $6.65 $7.18 $6.25 - $7.50Cash marketing, transportation & gathering ($/Boe) (2) $0.24 $0.34 $0.74 $1.06 $1.23 $1.03 $1.04 $1.23 $1.82 $1.70 $1.25 - $1.60G&A ($/Boe) $10.39 $7.52 $7.60 $7.31 $6.22 $6.93 $6.95 $5.11 $6.07 $5.50 Production Taxes (% of oil & gas revenue) 10.7% 10.2% 9.6% 9.5% 9.2% 9.4% 9.4% 9.1% 9.1% 9.4% 9.0% - 10.5%DD&A Costs ($/Boe) $19.91 $19.16 $24.23 $23.87 $25.85 $26.01 $25.14 $24.42 $24.33 $23.91 Select Financial Metrics ($ MM)Oil Revenue $124.7 $321.7 $129.9 $138.6 $173.8 $199.8 $642.0 $231.7 $226.8 $273.7 Gas Revenue 4.2 8.8 6.5 6.6 5.0 8.9 27.0 10.0 9.2 13.3 Bulk Purchase of Oil Revenue - - 1.5 - - - 1.5 - 5.8 - OWS and OMS Revenue - - 0.7 3.9 6.0 5.7 16.2 6.6 12.7 18.5 Total Revenue $128.9 $330.4 $138.6 $149.1 $184.7 $214.3 $686.7 $248.3 $254.6 $305.5 LOE 14.1 32.7 9.8 12.0 16.1 16.9 54.9 19.5 18.3 21.8 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 Production Taxes 13.8 33.9 13.3 13.7 16.4 19.5 63.0 22.1 21.4 26.8 Exploration Costs 0.3 1.7 2.8 - 0.3 0.1 3.2 1.9 0.4 0.5 Bulk purchase of oil cost and non-cash valuation adjustment (2) - - 1.4 - - (0.7) 0.7 0.1 5.8 0.5 OWS and OMS expenses - - 0.5 1.2 5.4 4.7 11.8 2.9 6.6 10.3 G&A 19.7 29.4 12.2 13.5 13.9 17.6 57.2 13.9 16.7 16.7 $75 - $82Adjusted EBITDA (3) $82.2 $234.5 $101.1 $108.5 $139.2 $163.5 $512.3 $191.4 $185.5 $219.6 DD&A costs 37.8 75.0 38.9 44.2 57.7 66.0 206.7 66.3 66.8 72.7 Interest expense 1.4 29.6 13.9 14.1 21.0 21.2 70.1 21.2 21.4 22.9 E&P CapEx(4) 345.6 637.3 267.0 263.2 311.4 270.1 1,111.7 238.7 184.1 243.6 $996 Non E&P CapEx 6.8 28.7 21.3 4.1 5.3 6.2 36.9 1.6 4.9 6.5 $24 Total CapEx(4) $352.4 $666.0 $288.3 $267.3 $316.7 $276.3 $1,148.6 $240.3 $189.0 $250.1 $1,020 Select Non-Cash Expense Items ($ 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 $0.1 Amortization of restricted stock (5) 1.2 3.7 1.6 2.3 2.7 3.7 10.3 2.3 3.1 3.0 Amortization of restricted stock ($/boe) (5) $0.65 $0.93 $0.99 $1.25 $1.22 $1.46 $1.26 $0.84 $1.12 $1.00

Guidance (1)

(1) Guidance for 4Q13 production was provided in press release on 11/6/13 (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, and $0.5MM in 3Q13 associated

with non-cash valuation change on our pipeline imbalances. 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. (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 11/6/13) 93.7 MM

Share Price (close on 11/6/13) $52.55 per share

Approximate Equity Market Capitalization $4.9BN

External Support Independent Financial/Tax Auditor PricewaterhouseCoopers

Legal Advisors DLA Piper LLP / Vinson & Elkins, LLP

Reserve Auditors DeGolyer and MacNaughton

aggressively drilling - oasis petroleum...in this presentation, proved reserves at june 30, 2013 are...

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