investor presentation - oasis petroleum...production on target with a strong reserve base q1 2014...
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www.oasispetroleum.com1
INVESTOR PRESENTATIONJune 2014
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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
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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)
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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
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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
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www.oasispetroleum.com 6
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
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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
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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
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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
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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
33 slickwaterwells vs.
40 base wells
2 slickwaterwells vs.
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)
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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
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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
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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
MONTANA NORTH DAKOTA
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
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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
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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
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Infrastructure Development(1)
Crude Oil Gathering Infrastructure
Oasis legacy acreage
Oasis 3Q14 acquisitions
Oil gathering infrastructure
Rail connection points
Pipeline connection points
Indian Hills
MONTANA NORTH DAKOTA
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
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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
1H15: 19,000 Bopd hedged
2H15: 10,000 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
6.5% Senior Notes due 2021 400
6.875% Senior Notes due 2023 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)
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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
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APPENDIX
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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) $90.49 14,463 5,279,000
Total 1H15 Hedges 19,000
Total 2H15 Hedges 10,000
Weighted Average Prices ($/Bbl)
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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%
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-
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
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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
$103.58
22x
7.5 11.2
14.4 16.2
18.5
22.6 25.0
27.6 27.4 29.5
37.5 38.3
0.4
0.4
0.8 1.4
1.9
1.7
2.5
2.6 2.8
3.6
4.6 4.5
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
-
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14
Oil Gas % Oil
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Key Metrics by Project Area
(1) As of 12/31/13 and does not include non-op properties divested March 5, 2014(2) East Nesson includes production of 1,649 Boepd from non-op properties divested March 5, 2014(3) As of 3/31/14
Key Statistics West Williston East NessonTotal
Williston2014 CapEx Budget ($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
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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%
10 Wells per DSU 163 40%
15 Wells per DSU 103 26%
Total DSUs 403 100%
Spacing Assumptions
34%
40%
26%
7 Wells per DSU 10 Wells per DSU
15 Wells per DSU
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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
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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.
www.oasispetroleum.com28
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
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