investor presentation

Transcription

INVESTOR PRESENTATION
1
September 2014
www.oasispetroleum.com
Forward-Looking / Cautionary Statements
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 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 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.
2
2
Top Pure Play in the Bakken(1)
Top tier asset position
 506,960 net acres
 403 Operated drill blocks
 3,590 Gross operated locations
 ~17 years of inventory(2)
Production on target with a strong reserve base
 Q2 2014 production 43.7 MBoepd
 Q3 2014 production of 47-49 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
(1)
(2)
As of 12/31/13 and does not include acreage or reserves associated with Sanish that were divested in March 2014
As of 12/31/13 based on current rig plan
3
3
Large, Concentrated Acreage Blocks(1)
Highlights




Concentrated position in Williston Basin:
507k net acres

West Williston: 362K net acres

East Nesson: 145K net acres
West Williston
Montana
East Nesson
North Dakota
(92)
Operational control – 94% operated
allows for control of rig pace, cost and
development
(52)
(75)
Held-by-production – 82% HBP allows for
flexibility in developing asset
High working interest – 68% average WI
drives high impact of operated program
(49)
(53)
(96)
(75)
OTHER
(14)
*Acreage in 000s in parenthesis
Delineated Bakken/TFS acreage
Oasis’s acreage is in the core of the Bakken / Three Forks delivering
highly economic wells
(1)
As of 12/31/13 and does not include acreage associated with Sanish that was divested in March 2014
4
4
Company Growth
Average Daily Production
(MBoepd)(2)
Remaining Drilling Locations(1)
4,000
Estimated Net Proved Reserves
(MMBoe)(4)
250
60
3,590
3,500
46-50
50
219.3
200
3,000
2,616
40
2,500
33.9
150
2,020
2,000
143.3
30
1,532
22.5
113.7
100
1,500
20
78.7
1,000
500
10.7
280
50
10
403
39.8
0
0
0
Operated DSUs
YE2012
Net Op and NonOp
Locations
Gross Operated
Locations
YE2013
2011
2012
Actual Production
2013
2014
Guidance
Range
70.0
35.8
17.0
12/31/10
Total Proved
12/31/11
12/31/12
12/31/13
Developed
Organic growth and acquisitions drive continued
production and reserve growth
5
(1) As of 12/31/13
(2) Guidance announced 5/5/14
(3) CAGR calculated from 2011 to midpoint of 2014 guidance range.
(4) www.oasispetroleum.com
YE13 pro forma for Sanish divestiture of 8.6 MMBoe
(5) CAGR calculated from 12/31/10 to 12/31/13
5
2014 Plan
2014 Focus Items

Inventory acceleration with 16 rigs

Full field development with best practices

Optimizing downspacing

Further TFS delineation

Improving well economics


2014 Guidance
Completion techniques increasing production
Cost and production optimization (lowering cost per
well and operating costs)
Metric
Production (MBoepd)
Full Year 2014
3Q14
Full Year Financial Metrics
LOE ($/Boe)
MG&T ($/Boe)
G&A ($ in MMs)
Production taxes (%)
CapEx Budget ($MMs)
2014 Range
46.0 47.0 -
D&C
$1,250
50.0
49.0
$8.50
$1.20
$85
9.7%
- $10.00
- $1.60
$95
- 10.2%
E&P
$1,367
Total
$1,425
Completion Plan

Operated: 205 gross (147.8 net)

Operated and non-operated: 155.5 net
4%
11%
Bakken
46%
TFS 1
TFS 2
TFS 3
40%
6
6
Development Program
2014 Rig Allocation
Capital Discipline

Rig allocation designed to:

Maximize asset value

Increase returns across inventory portfolio

Balance infrastructure capacity

Approximately 60% of completion activity is
dedicated to full field development

Remainder of rigs focused on:

Completion optimization

Spacing optimization

New acquired acreage hold
MONTANA
NORTH
DAKOTA
Full Field Development

Benefits of full field development

Reduces cycle time

Reduces the cost and time associated with
frac protect

Improves fracture stimulation efficiency

Reduces per well capital costs

Considerations

Planning is critical

Escalating importance of infrastructure
7
Rig dedicated to
development
drilling
Rig dedicated to
completion/spacing
optimization or acreage hold
7
Attractive Well Costs and Economics
Lowering Well Costs – Base Design
($MM)
$10
$9.7
$9.4
$8
$7.9
$7.6
$7.5
$7.3
Compelling Well 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
$6
$4
$2
$0
2012
4Q13
Excludes OWS Includes OWS
1H14
Reached year-end target of $7.3 million in 1H14
Driving down costs through:
(1)
(2)
8

Pad development operations

Efficiency gains

Completion and well design optimization
Illustration(1)
EUR (Mboe)
Well cost ($MM) (2)
IRR
Implied F&D ($/Boe)
Months to payback capital
Lower Half
525
Mid
600
Upper Half
675
$6.5
$7.2
$7.9
72%
$15.48
15
73%
$15.00
15
79%
$14.63
14
Assumes 2013 realized prices: $92.34/bbl & $6.78/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
Includes benefit from OWS of $0.3MM per well
Attractive Economics Across Acreage Position
Driving Returns Across the Position
Hebron Actual Production Results
(Boe)

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
30,000

Oasis utilizes a low cost well with effective stimulation to
drive strong returns in Montana
20,000

Montana tax structure more attractive than North Dakota
40,000
35,000
25,000
15,000
10,000
5,000
Montana Base Well Economics

~90,000 net acres (~50,000 net acres in Hebron)

Development well cost: $6.4MM ($6MM including OWS)

EUR: ~450 MBoe
Well cost ($MM)
IRR(1)
Months to payback capital
0
1
70%
16
21
31
41
51
61
71
81
Days Producing
450 MBOE

Development Development Economics
Economics
including OWS Savings
$6.4
$6.0
11
Hebron 40 wells
Slickwater
Preliminary production from slickwater in Montana has
resulted in 35% production uplift compared to Hebron
type curve and is increasing
81%
13
Strong Economics Across Acreage Position
(1)
9
Assumes 2013 realized prices: $92.34/bbl & $6.78/mcf gas which includes liquids uplift, Montana production taxes, and 80% NRI. Bakken type curve parameters: b=1.6, initial decline 76%, terminal
decline 6%, GOR 900
Lower Three Forks Activity
Improving Inventory Potential
Lower TFS Activity

Preliminary results from producing lower bench TFS
wells are very encouraging

Oasis expects to complete ~30 wells in TFS 2 and TFS
3 in 2014, about half of which are testing areas with
no lower TFS included in the YE13 inventory

Potential to increase drilling locations through lower
benches of TFS
MONTANA
NORTH
DAKOTA
North
Cottonwood
South
Cottonwood
Red
Bank
Production from Select TFS Wells
90
600
MBoe
80
Cumulative MBOE
70
Montana
Painted
Woods
Indian
Hills
60
50
400
MBoe
40
Foreman
Butte
30
Oasis acreage
20
Current Lower TFS
economic bound
10
TFS 2
0
1
31
61
91
121
Days on Production
TFS 2
10
Selected cores
151
Expanding Lower TFS
economic bound
TFS 3
TFS 3
Completion Optimization
High Intensity Completions
Completion Summary

Completing ~70% of wells in 2H14 with alternative
completion techniques
Economic results or 2014 planned slickwater
and/or high sand proppant completions

>30% of wells planned to be completed with high intensity
frac jobs including slickwater or high sand proppants
Red Bank TFS Slickwater
Montana Bakken Slickwater

Early time results with greater than 30% production uplift

North
Cottonwood
White Unit
1st TFS well with slickwater producing 37% better
than base design TFS well in Red Bank


1st Montana well with slickwater producing 35%
better than Montana type curve
Completing White on partial unit on up to 5 wells per
formation pattern with slickwater wells
% Increase over Surrounding Wells
40%
> 35%
37%
Montana
Painted
Woods
Indian
Hills
35%
35%
Foreman
Butte
30%
South
Cottonwood
Red
Bank
White Unit
Illustrative well spacing
25%
Bakken
20%
TFS 1
TFS 2
15%
10%
TFS 3
5%
0%
(1)
(2)
(3)
11
(1)
Bakken Average
(12 Month Cum)
Red Bank TFS
(46 days)
Includes slickwater wells drilled by industry, including Oasis
Slickwater and base wells include only Oasis wells
Slickwater well compared to Hebron type curve (450 Mboe)
(2)
(3)
Montana Bakken
(28 days)
TFS 4
Effective 4-5 well per
formation spacing
11
Oasis Well Services (“OWS”)
OWS savings per well
2014 Plan
($MMs)
$0.5
 2nd frac spread at 100% utilization in August 2014
$0.40
$0.4
$0.35
$0.3
 2 spreads will complete ~30-40% of Oasis
completions
 Visible inventory for multiple frac spreads
$0.25
 Short payback of incremental CapEx for an
additional spread
$0.2
$0.1
$0.0
2012
2013
1H14
OWS Performing 4 Well Simultaneous
Completion
OWS first spread has returned 2.8x the cash invested into business since inception
12
Infrastructure Development(1)
Infrastructure Highlights
Crude oil gathering (3rd party system)

Realized 8.3% differential in 2Q14

Provides marketing flexibility to access to 3 pipeline and 7
different rail connection points

~75% oil production flowing through pipeline systems
Crude Oil Gathering Infrastructure
MONTANA
NORTH DAKOTA
North
Cottonwood
South
Cottonwood
Gas and liquids gathering (3rd party systems)

Average realization of $7.56/mcf in 2Q14

~96% of wells connected to gathering system
Red Bank
Montana
Painted
Woods
Salt water disposal (Oasis owned system)

Reduces operating expenses and simplifies operations

~52% flowing through gathering systems

~75% disposed in disposal wells
Foreman
Butte
Indian
Hills
Infrastructure:
 Drives strong cash margins
Oasis 3Q13 acquisitions
 Enables flexibility in operations
Oil gathering infrastructure
 Improves execution
Rail connection points
(1)
13
Oasis legacy acreage
Pipeline connection points
As of 6/30/14
Expanding Takeaway Capacity out of Bakken
Takeaway Capacity(1)
Takeaway Options
(MBOPD)
ANS
3,500
3,000
Clearbrook
2,500
Brent
Guernsey
ANS
2,000
1,500
1,000
WTI
Railroad
Pipeline
500
2010
LLS
Pipeline / Refining
2016 Pipe adds




2011
(Bopd)
Pipeline and rail provide multiple destinations for Bakken
crude
Oasis can ship crude via rail or pipe to achieve the highest
realizations
New pipelines in 2016 provide excellent optionality for low
cost transportation
Given the pipe and rail options, there is ample capacity for
Bakken crude production
2012
2013
Rail
2014
Basin Production
Current
Capacity
YE2013
2014
2015
2016
2017
NDIC Production Forecast
Additions
2015
2016
Pipeline / Local refining
583,000
200,000
60,000
Rail loading capacity
965,000
230,000
160,000
430,000
220,000
745,000
1,978,000
2,198,000
2,943,000
Additions in Year
Total Takeaway
1,548,000
745,000
-
(1) Per North Dakota Pipeline Authority as of June 26, 2014
14
Balance Sheet
Strong Balance Sheet and Liquidity
 Liquidity of $1.4 BN
 Borrowing base of $1.75BN
 Elected commitments of $1.5BN
 No near-term debt maturities
 Improving debt ratings (Moody’s / S&P)
Corp.
Notes
YE13
B2/BBB3/B
Liquidity and Capitalization as of 6/30/14 ($MM)
Cash and marketable securities
Current elected commitments
1,500
Borrowing / LCs
(105)
Total Liquidity
$1,422
Debt
Current
B1/BBB2/B+
 Hedge program designed to protect drilling
 2H14: 35,500 Bopd hedged
$27
Revolver
$100
7.25% Senior Notes due 2019
400
400
400
1,000
Total long-term debt
2,300
Total Enterprise Value (1)
$7,256
(1)
Calculated as book debt less cash plus market value of equity
($49.19/share as of 8/29/14)
Solid financial profile with substantial liquidity provides business flexibility
15
Investment Highlights
16

Oil focused, pure play in the Williston Basin

Large, concentrated acreage position with increasing identified
drilling inventory

Substantial upside potential with known catalysts

Improving capital and operational efficiency

Growing production profile with capital going towards increasing
reserves and lowering costs

Proven management team and great people growing long-term
shareholder value
APPENDIX
17
Risk Management(1)
Weighted Average Prices ($/Bbl)
Type
2014
Full Year
Swaps
Swaps w/Sub-Floor
Two-Way Collars
Three-Way Collars
Total 2014 Hedges
Remaining Term
Jul
Jul
Jul
Jul
- Dec
- Dec
- Dec
- Dec
2015
Full Year
Swaps
Jan - Dec
Two-Way Collars
Jan - Dec
1H15
Swaps
Jan - June
Deferred Puts
Jan - June
Two-Way Collars
Jan - June
Total 2015 Hedges (Weighted Average)
Total 1H15 Hedges
Total 2H15 Hedges
(1)
Floor
Ceiling
$95.90
$92.60
$70.00
$70.59
$70.34
Swaps
$95.22
$90.59
$93.25
$106.39
$105.25
$105.91
$86.00
$103.42
$90.00
$90.00
$87.77
$99.10
$102.70
BOPD
Total Barrels
9,500
6,000
11,500
8,500
35,500
1,738,500
1,098,000
2,104,500
1,555,500
6,496,500
$90.15
10,000
5,000
3,650,000
1,825,000
$91.26
9,000
6,000
2,000
23,430
32,000
15,000
1,629,000
1,086,000
362,000
8,552,000
$94.62
$90.49
As of 6/30/14
18
Sub-Floor
18
Type Curves in Williston Basin(1)
TFS Type Curve (MBoe)
Middle Bakken Type Curve (MBoe)
High
Midpoint
Low
High
Midpoint
Low
Years
Years
Middle Bakken Type Curve
(1)
19
Metrics
Low End
Midpoint
High End
450
536
600
704
750
873
415
359
545
471
675
584
14
25
55
85
19
33
72
111
23
41
89
138
TFS Type Curve
Low End
Midpoint
High End
Gross Reserves (MBoe)
IP – 7 day average (Boepd)
400
480
500
592
600
704
1st 60 days - average (Boepd)
2nd 30 days - average (Boepd)
Cumulative (Mboe)
30 day
60 day
180 day
365 day
371
321
458
396
545
471
13
22
49
76
16
27
60
93
19
33
72
111
Type curve parameters: Qi=varies, b=1.6, initial decline 76%, terminal decline 6%
Oil Weighted Production
WTI – Henry Hub Price Disparity ($/bbl to $/Mmbtu)(1)
Price
Ratio
$120
60x
$100
50x
Oasis Oil and Gas Production (per MBoe)
MBoepd
% Oil
50
100%
45
$95.96
$80
40x
$60
30x
90%
4.6
40
35
2.6
30
24x
$40
$4.02
$0
0x
80%
70%
3.6
60%
2.5
25
50%
1.9
20
0.8
15
10x
4.8
1.7
20x
$20
2.8
4.5
10
5
1.4
37.5
0.4
22.6
0.4
11.2
14.4
16.2
25.0
27.6
27.4
38.3
38.9
40%
30%
29.5
20%
18.5
10%
7.5
-
0%
2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14
Oil
WTI ($/bbl)
HH ($/mmbtu)
Gas
% Oil
WTI - HH Price Ratio
Oil weighted production drives high realized prices, especially given
the disparity in pricing between WTI and Henry Hub
(1) As of 8/29/14
20
20
Key Metrics by Project Area
362
Total
Williston
145
507
79.5
34.3
113.7
Oa s i s Mi ds trea m Servi ces ("OMS")
60
West Williston
Net a crea ge (000s )
(1)
Es tima ted net PDP - MMBoe
(1)
Es tima ted net PUD - MMBoe
(1)
Estimated net proved reserves - MMBoe
Percent devel oped
(1)
(1)
$1,250
Dri l l i ng a nd compl etion
74.5
31.0
105.5
Lea s ehol d
25
65.3
219.3
Fa ci l i ties a nd other mi s c.
19
51.6%
52.5%
51.8%
Mi cro-s ei s a nd other tes ts
13
30.4
13.3
43.7
9
7
16
Oa s i s Wel l Servi ces ("OWS")
35
35
32
67
Non-E&P
23
Total CapEx
$1,425
(2)
Ba kken / TFS opera ted wel l s wa i ting on compl etion
2014 CapEx Budget ($MM)
154.0
2Q14 production (Mboe/d)
Opera ted ri gs runni ng
East Nesson
(2)
Total E&P CapEx
1,367
2014 completed wells (Budget)
Gros s opera ted
123
82
62.7
205
Net opera ted
85.1
147.8
Worki ng i nteres t i n opera ted wel l s
69%
76%
72%
Net non-opera ted
5.2
2.5
7.7
Total net wells
90.3
65.2
155.5
Key acreage acquisitions (Net acres / Boepd then current)
$83MM i n June 2007
$16MM i n Ma y 2008
48,000 / 0
$27MM i n June 2009
37,000 / 800
$11MM i n September 2009
46,000 / 300
$82MM i n 4Q 2010
26,700 / 500
$1,542MM i n 3Q/4Q 2013
136,000 / 9,000
(1)
(2)
21
175,000 / 1,000
25,000 / 300
As of 12/31/13 and does not include non-op properties divested March 5, 2014
As of 6/30/14
Williston Inventory (1)
Gross
TFS
Bakken
Operated
PUD Wells
West Williston
East Nesson
Total PUD Wells
Non-Proven Wells
West Williston
East Nesson
Total Non-Proven Wells
Total Operated
West Williston
East Nesson
Total Operated
Total
Total
201
85
286
53
19
72
254
104
358
134
61
195
33
12
45
167
73
240
829
516
1,345
1,118
769
1,887
1,947
1,285
3,232
585
347
932
747
531
1,278
1,332
878
2,210
1,030
601
1,631
1,171
788
1,959
2,201
1,389
3,590
719
408
1,128
780
542
1,322
1,499
951
2,450
57
23
79
57
23
79
113
44
157
776
431
1,207
836
565
1,401
1,612
995
2,607
Non-Operated
West Williston
East Nesson
Total Non-Operated
Operated and Non-Operated
West Williston
East Nesson
Total Inventory
DSUs
7 Wells per DSU
10 Wells per DSU
15 Wells per DSU
Total DSUs
Net
TFS
Bakken
DSUs
137
163
103
403
% Total
34%
40%
26%
100%
Spacing Assumptions
26%
34%
40%
7 Wells per DSU
(1)
22
As of 12/31/13 not including non-op properties divested March 2014. Inventory assumes
on average 10 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
Total Williston Basin
Gross
Net
Gross
Net
Gross
Net
Producing on or before 3/31/14
Operated
Non-Operated
Production started in 2Q14
Operated
Non-Operated
Total Producing Wells on 6/30/14
Operated
Non-Operated
(1)
23
338
162
260.1
13.3
158
98
125.0
7.1
496
260
385.1
20.4
26
14
20.0
0.9
15
3
10.8
0.1
41
17
30.8
1.0
364
176
280.1
14.2
173
101
135.8
7.2
537
277
415.9
21.4
Producing wells exclude all well associated with non-operated assets divested in March 2014. Well counts include changes that occurred in the current reporting period for wells producing on or
before 3/31/14.
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
3Q 14
FY14
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
43.7
47 - 49
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
38.9
% Oil
94%
95%
92%
91%
93%
91%
92%
91%
91%
89%
89%
90%
89%
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
$103.02
Realized oil prices ($/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
$94.48
13%
9%
14%
12%
9%
2%
9%
1%
3%
5%
12%
6%
9%
8%
Realized natural gas prices ($/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
$7.56
LOE ($/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
$10.21
$8.50 - $10.00
Cash marketing, transportation & gathering ($/Boe) (1)
G&A ($/Boe)
$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
$1.76
$1.20 - $1.60
$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
$5.22
Production Taxes (% of oil & gas revenue) (1)
DD&A Costs ($/Boe)
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%
9.7%
$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
$24.48
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
$334.6
Gas Revenue
4.2
8.8
6.5
6.6
5.0
8.9
27.0
10.0
9.2
13.3
18.1
50.5
22.6
19.6
-
-
1.5
-
5.8
-
0.0
5.8
0.0
0.0
Production (MBoepd)
Differential to WTI
9.7% - 10.2%
Select Financial Metrics ($ MM)
Bulk Purchase of Oil Revenue
-
-
1.5
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
18.2
$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
$372.4
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
40.6
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
7.0
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
34.5
Total Revenue
LOE
Cash marketing, gathering & transportation (2)
Production Taxes
Exploration Costs
0.3
Bulk purchase of oil cost and non-cash valuation adjustment (2)
OWS and OMS expenses
1.4
-
-
-
0.5
1.2
0.3
0.1
3.2
1.9
0.4
0.5
(0.5)
2.3
0.4
0.5
(0.7)
0.7
0.1
5.8
0.5
0.8
7.2
(0.7)
0.1
5.4
4.7
11.8
2.9
6.6
10.3
10.8
30.7
10.9
8.8
-
29.4
12.2
13.5
13.9
17.6
57.2
13.9
16.7
16.7
28.1
75.3
23.5
20.8
Adjusted EBITDA (3)
DD&A costs
$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
$254.7
97.3
$85 - $95
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
39.0
E&P CapEx (1,4)
Non E&P CapEx
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
326.9
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
24.9
$58
$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
$351.8
$1,425
$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
$0.0
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
5.2
$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
$1.30
Amortization of restricted stock
(5)
Amortization of restricted stock ($/boe) (5)
24
-
-
19.7
Impairment of oil and gas properties
(3)
(4)
(5)
2.8
-
G&A (1)
Total CapEx (1,4)
Select Non-Cash Expense Items ($ MM)
(1)
(2)
1.7
-
$1,367
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.
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; ($0.7MM) in 1Q14 and $.1MM in 2Q14 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.“
Non GAAP Adjusted EBITDA Reconciliation can be found on the Oasis website at www.oasispetroleum.com.
Excludes capital for acquisitions in 2013 of $1,563MM.
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 6/30/13)
101.3 MM
Share Price (close on 8/29/14)
$49.19 per share
Approximate Equity Market Capitalization
$4.9BN
External Support
25
Independent Financial/Tax Auditor
PricewaterhouseCoopers
Legal Advisors
DLA Piper LLP / Vinson & Elkins, LLP
Reserves Engineers
DeGolyer and MacNaughton

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