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RSP Permian Investor Presentation
October 2015
2
Forward-Looking Information
Certain statements and information in this presentation may constitute “forward-looking statements” within the meaning of the Private
Securities Litigation Reform Act of 1995. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or
other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-
looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While
management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future
developments affecting us will be those that we anticipate. Our forward-looking statements involve significant risks and uncertainties (some
of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our
present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking
statements include, but are not limited to, the volatility of commodity prices, product supply and demand, competition, access to and cost of
capital, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions
underlying production forecasts, our hedging strategy and results, the quality of technical data, environmental and weather risks, the ability to
obtain environmental and other permits and the timing thereof, other government regulation or action, the costs and results of drilling and
operations, the availability of equipment, services, resources and personnel required to complete RSP’s operating activities, access to and
availability of transportation, processing and refining facilities, the financial strength of counterparties to the Company’s credit facility and
derivative contracts and the purchasers of RSP’s production and third parties providing services to RSP and acts of war or terrorism.
For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see
our filings with the United States Securities and Exchange Commisson (SEC), including our Annual Report on Form 10-K and Quarterly
Reports on Form 10-Q.
Existing and prospective investors are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date
hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a
result of new information, future events or otherwise.
TX
Focus Areas
Dawson Area
RSP Existing Acreage
Potential WPR Acq. Acreage
3
RSP Permian Overview (NYSE: RSPP)
Concentrated Acreage Position in the Core of the Midland Basin Large, contiguous, core acreage blocks in the Midland Basin
~225,000 net “effective horizontal acres” (1) and ~63,000 net surface acres (96% operated)
~2,400 horizontal and ~1,700 vertical drilling locations
Average horizontal lateral length of ~7,100’
Efficient operator – focused on execution
Drilled wells in five different horizontal benches
Peer-leading F&D costs, cash operating costs per Boe and cash margins per Boe
___________________________Note: All acreage and location totals pro forma for acquisitions closed in August/September 2015 and potential acquisition announced October 2015.(1) Combined horizontal acreage position that management believes is prospective for hydrocarbon production across each target horizontal zone.(2) Based on pro forma Q2 2015 net debt and Adjusted EBITDAX annualized. Please see reconciliation of Adjusted EBITDAX in Appendix. (3) Includes the effect of the August/September acquisitions, the potential October acquisition (the WPR Acquisition) and the related financings.
Key Statistics
Market Capitalization (10/8/15):
3Q 2015 Production:
YE 2014 Proved Reserves:
Net Debt / Annualized EBITDAX(2)(3):
Current Liquidity(3):
$2.7 billion
23.5 - 24.0 MBoe/d
106.4 MMBoe
1.7x
>$700 million
Clearfork 15,956
Middle Spraberry 45,171
Lower Spraberry 52,618
Wolfcamp A 34,030
Wolfcamp B 36,313
Wolfcamp D 38,686
Total 222,774
Net Effective Horizontal Acres
4
Another Accretive Potential Acquisition in the Core of the Midland Basin
In October, announced LOI to acquire ~4,100 net acres in the Midland Basin for ~$137 million (the potential WPR Acquisition)
~1.9 MBoe/d of existing production (August 2015)
86 net horizontal locations in five zones with average lateral length of ~8,100’
~15,000 net effective horizontal acres
Upon closing, 100% RSP-operated (currently operated by High Sky Partners)
Map of Acreage to Be Potentially Acquired
RSP Existing Acreage
Potential WPR Acq. Acreage
Inventory Detail
Net Hz Lateral Net Hz
Locations Length (ft) Acres
Clearfork – – 2,202
Middle Spraberry 21 8,448 2,202
Lower Spraberry 34 7,555 4,097
Wolfcamp A 10 8,571 2,202
Wolfcamp B 10 8,571 2,202
Wolfcamp D 11 8,333 2,202
Total 86 8,109 15,107
5
Key Horizontal Activity and Completions
___________________________Source: Texas Railroad Commission and investor presentations. 3-stream data. 30-day IP rates noted where available.
Midland County Potential WPR Acquisition Offset Activity
OXY
“Curtis Ranch So 2344SH” (Lower Spraberry)
24-hr IP: 1,040 Boe/d – 5,605’ lateral length
“Curtis Ranch So #2341MH” (Middle Spraberry)
24-hr IP: 752 Boe/d – 5,284’ lateral length
OXY
“Curtis Ranch So 2823AH” (Wolfcamp A)
24-hr IP: 1,079 Boe/d - 6,355’ lateral length
“Curtis Ranch 2828H” (Wolfcamp B)
24-hr IP: 1,089 Boe/d – 5,704’ lateral length
OXY
“Curtis Ranch So 3521H” (Lower Spraberry)
24-hr IP: 1,206 Boe/d - 6,142’ lateral length
“Curtis Ranch 3519H” (Wolfcamp A)
24-hr IP: 841 Boe/d – 5,892’ lateral length
“Curtis Ranch So 3517H” (Wolfcamp B)
24-hr IP: 909 Boe/d – 4,368’ lateral length
MIDLAND CO
MARTIN CO
OXY
“Curtis Ranch South”
Mid / Lower Spraberry Drilling / Permitted
RSP / Callon
“Pecan Acres 23-1 1H” (Wolfcamp B)
“Pecan acres 23-1 2H” (Lower Spraberry)
10,000’ lateral lengths - WOC
Diamondback
“Gridiron N 1H” (Wolfcamp B)
24-hr IP: 2,757 Boe/d - 8,785’ lateral length
“Gridiron So 17LS” (Lower Spraberry)
24-hr IP: 1,768 Boe/d – 9,154’ lateral length
Diamondback
“Oaktree / Mockingbird Leases”
Lower Spraberry / WA / WB
Drilling / Permitted
High Sky (RSP)
“Isbell HU 104WB” (Wolfcamp B)
IP 30: 718 Boe/d
<5,000’ lateral length
“Isbell HU 105LS” (Lower Spraberry
IP 30: 765 Boe/d
<5,000’ lateral length
“Isbell HU 106 MS” (Middle Spraberry)
IP 30: 674 Boe/d
<5,000’ lateral length
“Isbell HU 107WA” (Wolfcamp A)
IP 30: 803 Boe/d
<5,000’ lateral length
OXY
“Mabee 139 #412H” (Clearfork)
~7500 lateral length
Completing
RSP
Spanish Trail 11,000’ laterals on Flowback
4717WA” (Wolfcamp A)
Pumping 1,886 Boe/d
4717WB (Wolfcamp B)
Flowing 1,625 Boe/d
4719WA (Wolfcamp A)
Flowing 1,946 Boe/d
4719WB (Wolfcamp B)
Flowing 1,643 Boe/d
6
LS
MS
DEAN
WA
WB
CLINE
WC
Martin County Potential WPR Acquisition Offset by Significant Activity Area Type Log
W&T
“Pinot 65 15H” (Lower Spraberry)
24-hr IP: 917 Boe/d – 6,769’ lateral length
Diamondback
“Mabee BL 2301LS” (Lower Spraberry)
24-hr IP: 1,145 Boe/d - 6,454’ lateral length
“Mabee BL 2201H” (Wolfcamp B)
24-hr IP: 1.029 Boe/d – 8,296 lateral length
“Mabee BL 4004H” (Wolfcamp B)
24-hr IP: 910 Boe/d – 8,263 lateral length
ENERGEN
“Campbell #101H” (Wolfcamp A)
24-hr IP: 792 Boe/d - 6,725’ lateral length
“Campbell #501H” (Lower Spraberry)
24-hr IP: 1,007 Boe/d - 6,628’ lateral length
ENERGEN
“Holton 101H” (Wolfcamp A)
24-hr IP: 1,171 Boe/d - 6,675’ lateral length
“Holton #210H” (Wolfcamp B)
24-hr IP: 1,172 Boe/d - 6,825’ lateral length
“Holton #401H” (Cline)
24-hr IP: 2,425 Boe/d - 7,185’ lateral length
ENERGEN
Holton / Kitta Belle Leases
Multiple Permitted Locations
Diamondback
“Estes #1602H” (Lower Spraberry)
24-hr IP: 1067 Boe/d - 7,559’ lateral length
ENCANA
“Holt Ranch 101H” (Wolfcamp B)
24-hr IP: 1.022 Boe/d – 7,304’ lateral length
7
Recent Acquisitions and Potential WPR Acquisition Add Significant Scale to Core Acreage Since August 2015, RSP has announced the acquisition
or intention to acquire ~10,700 net acres for ~$450 million(1)
~3,500 Boe/d of net production(2)
277 net horizontal locations(2)
~47,000 net effective horizontal acres(2)
All acquisitions reflect high-quality inventory in RSP’s Focus Area
Would increase Focus Area net locations by 26% and Focus Area net acreage by 27%
Map of Recent Acquisitions and Potential Acquisitions
RSP Existing AcreageNew Acreage or Potential WPR Acq. Acreage
Additional Interests Acq.
Recent Acquisitions Additions and Potential Additions
20,000
30,000
40,000
6/30/15 Pro Forma
27%
Net Focus Area Acreage Net Focus Area Hz Locations
600
1,000
1,400
6/30/15 Pro Forma
26%
___________________________(1) Includes ~$39 million of subsequent acquisitions of acreage and production from non-operated partners on the acquisition properties announced in August 2015 and the potential WPR Acquisition.(2) Each combined metric represents (a) sum of production rates as disclosed for each of the August/Sept. 2015 acquisitions and October 2015 potential WPR Acquisition (1.6 Mboe/d Q2 2015 production and 1.9 Mboe/d August 2015
production, respectively), (b) 191 net horizontal locations for the August/Sept. 2015 acquisitions and 86 net horizontal locations for the October 2015 potential WPR Acquisition and (c) ~32,000 net effective horizontal acres for the August/Sept. 2015 acquisitions and ~15,000 net effective horizontal acres for the October 2015 potential WPR Acquisition .
8
Track Record of Production Growth
___________________________1) Forecasted oil production based on assumed 75% oil mix for estimated Q3 2015 production.
Strong Total Production Growth Since Inception
2,8005,089
7,293
11,868
19,802
23,50019,971
24,000
–
5,000
10,000
15,000
20,000
25,000
2011 2012 2013 2014 YTD2015 Q32015E
+43%
+63%Bo
e/d
+82%
3,4925,115
8,490
14,932
17,62515,059
18,000
60%
65%
70%
75%
–
5,000
10,000
15,000
20,000
2012 2013 2014 YTD2015 Q3 2015E
Oil Mix
Even Faster Oil Production Growth since 2012 (1)
+66%
+47%B
bl/
d
Strong quarter of production growth for RSP, with 23.5 - 24.0 MBoe/d of estimated Q3 2015 production, or ~20% over Q2 2015 volumes at the midpoint
9
Decreasing Cash Operating Costs
Historical Cash Operating Costs (per Boe)
$9.52
$6.92 $7.55 $8.78 $8.12
$3.66
$3.19 $4.21
$2.95 $2.47
$6.12
$4.98 $3.22 $2.92
$2.99
$19.30
$15.09 $14.98 $14.65 $13.58
–
$5.00
$10.00
$15.00
$20.00
Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015
LOE, Gathering & Transporation, & Workovers Cash G&A Prod. & Ad Val
___________________________Note: Periods prior to Q4 2013 reflect Predecessor per unit metrics, as pro forma numbers reflecting the combinations at the IPO were not available.
–
25%
50%
75%
100%
A B C D E F G H IR
SPP J K L M N O P Q R S T U V W X Y Z
AA
AB
AC
AD AE
AF
AG
AH AI
AJ
AK AL
AM AN
AO AP
AQ AR
AS
AT
AU
AV
AW AX
AY
AZ
BA
BB
BC
BD BE
BF
BG
BH BI
BJ
BK BL
BM BN
BO BP
BQ BR
10
Low Costs and High Oil Mix Generate Strong Cash Margins…
Domestic E&P Universe 2015 Estimated Oil Mix as a Percent of Total Production (1)
___________________________Note: Company data, Bloomberg, FactSet, Global Hunter Securities (“GHS”) estimates. Letters correspond to the same companies in the top and bottom charts.1) 2015 estimated oil production estimates and Q2 2015 operating margin per GHS. 2) Permian peers include CPE, CXO, FANG, LPI, PE, and PXD.
RSPP
Domestic E&P Universe Q2 2015 Unhedged Cash Operating Margin per Boe (1)
Median: 47%
–
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
I
RSP
P O R B F E G C L
AB H S U A
AA W AE V AF K T
AG M Z AJ
AM AD X AI
AS
AT
AC AL
AP Y
AH Q
AU
AO AR
AW
J
AN BC
AK
AQ BA BJ
BK
BB
AV
BH BE
BG
BM AX
RSPP U.S. E&P Company
Permian Peer (2)
Median: $17.16
U.S. E&P Company
Permian Peer (2)
(50%)
(25%)
–
25%
50%
75%
100%
A B C D E FR
SPP G H I J K L M N O P Q R S T U V W X Y Z
AA
AB
AC
AD AE
AF
AG
AH AI
AJ
AK AL
AM AN
AO AP
AQ AR
AS
AT
AU
AV
AW AX
AY
AZ
BA
BB
BC
BD BE
BF
BG
BH BI
BJ
BK BL
BM BN
BO BP
BQ
11
... And Strong Margins Plus Well Performance Lead to Capital Efficiency
Domestic E&P Universe Q2 2014 – Q2 2015 Production Growth per Debt-Adjusted Share (1)
___________________________Note: Company data, Bloomberg, FactSet, Global Hunter Securities (“GHS”) estimates. Letters correspond to the same companies in the top and bottom charts.1) Production growth per debt-adjusted share per GHS calculations. Q2 2015 Recycle Ratio calculated as unhedged Q2 2015 cash operating margin per Boe divided by last two year average PDP F&D cost per Boe as calculated by GHS.2) Permian peers include CPE, CXO, FANG, LPI, PE, and PXD.
Best-in-class in the Permian and the broader domestic E&P universe in both efficient production growth and cash returns
U.S. E&P Company
Permian Peer (2)
RSPP
Domestic E&P Universe Q2 2015 Unhedged Recycle Ratios (1)
Median: 6%
–
0.25x
0.50x
0.75x
1.00x
1.25x
GA
HR
SPP
AM
AW Z L U O AB
AE
BB P Y
AA
AY
AD
AK
BM XA
T AJ
AN
AU BI J
BJ D
AO I
BH R
BD AZ N
AV
AR BF T
BE
AG AP
BA Q B
AS C W AF M B
QA
Q AI
AX S
BG
BN F
BC AL H A BL E K
BK
BP
AC
RSPPU.S. E&P Company
Permian Peer (2)
Median: 0.6x
RSP is one of the very few companies near the top in both debt-adjusted production growth and recycle ratios
12
Permian Leader in Efficiencies
2014 Production & Capex per Average Headcount (1)
2014 Finding & Development Costs (per Boe)
2014 Reserve Replacement Ratios
Strong production and reserve growth with low corporate overhead
Peer-leading F&D costs and reserve replacement
76
38
-
10
20
30
40
50
60
70
80
Production perHeadcount (MBoe)
$10.59
$13.88
$18.21
$23.28
$0.00
$5.00
$10.00
$15.00
$20.00
$25.00
Drillbit F&D Total F&D
RSPP Permian Peer Average
RSPP Rank:
#1
RSPP Rank:
#1
1140%
1406%
493% 616%
–
500%
1000%
1500%
Organic ReserveReplacement
Reserve Replacement
RSPP Permian Peer Average___________________________Permian peers include CPE, CXO, FANG, LPI, PE, and PXD. Information based on public filings.(1) 2014 total production (MBoe) and total capital spent ($MM) divided by the average of the employee count at YE 2013 & YE 2014.(2) Defined as exploration and development costs divided by the sum of extensions and discoveries and non-price revisions.(3) Defined as the sum of extensions, discoveries, and non-price revisions, divided by annual production.
RSPP Rank:
#1
RSPP Rank:
#1
(2)
(3)
$8.5
$3.2
–
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
$8.0
$9.0
Capex per Headcount($MM)
RSPP Rank:
#1
RSPP Rank:
#2
RSPP Permian Peer Average
13
Wolfcamp A/B Overview
Performance of Wolfcamp A wells to date has exceeded the performance of the Wolfcamp B
RSP now has 12 Wolfcamp A wells with production history
RSP’s plan is to simultaneously develop the Wolfcamp A and Wolfcamp B to maximize recovery from the zones
Location Summary(1)
Midland / Martin / Andrews
70%
Glasscock24%
Ector6%
Focus Area Locations by County
Johnson Ranch
Cross Bar Ranch
Spanish Trail
1717
1017
2017
3027
4820
4717
1021
1017
1019
1018
4827
1719
4719
217
Map of Wolfcamp A Wells Drilled
___________________________1) As of June 2015. Pro forma acquisitions announced and closed August/Sept. 2015 and Oct. 2015 potential WPR Acquisition.
Gross Net
Wolfcamp A 323 188
Wolfcamp B 298 194
Total 621 382
Average Length (ft) 7,097
14
Increasing Wolfcamp A Type Curves Due to Outperformance
Wolfcamp A/B Type Curve and Operated Well Production in Core Counties since Mid-2014 (Normalized to 7,500’)
–
50.0
100.0
150.0
200.0
0 30 60 90 120 150 180 210 240 270 300 330 360800 MBoe Wolfcamp A Type Curve Average Wolfcamp A wells
715 MBoe Wolfcamp B Type Curve Average Wolfcamp B wells
Cu
mu
lati
ve M
Bo
e
___________________________Note: Updated curves based on cumulative production to date for wells drilled in the applicable zone.
Average Midland Basin peer type curve derived from CPE, FANG, PE, and PXD public investor presentations and RSP estimates. Core Counties are defined as Midland, Martin, and Andrews. Production data normalized for operational downtime. As of September 2015. Previously disclosed type curves of 665 MBoe reflected a 7,000’ lateral.
12 Wolfcamp A wells
11 Wolfcamp B wells
Improved completion techniques and strong well results in core counties driving outperformance
Management increasing the core county 7,500’ type curve for the Wolfcamp A and keeping the core county Wolfcamp B 7,500’ typecurve unchanged
More production history will help clarify the estimated ultimate recovery over the 50+ year life of the well, but RSP believes the early time forecasts of these type curves determine a substantial portion of the single-well economics
EURs: ~75% Oil360-Day Cum: ~80% Oil
New Prior Basin Peer
(MBoe) Curve Curve % Inc. Curve
EUR 800 715 12% 1,000
90-Day Cum 81 64 28% 75
180-Day Cum 122 101 20% 120
360-Day Cum 173 149 16% 182
Wolfcamp A (7,500’ lateral)
New Prior Basin Peer
(MBoe) Curve Curve % Inc. Curve
EUR 715 800
90-Day Cum 64 64
180-Day Cum 101 101
360-Day Cum 149 152
no change
Wolfcamp B (7,500’ lateral)
Upper Wolfcamp Full Development Test
15
300’
E
200’
250’
250’595’ 825’ 1650’ 790’ 810’
920’20
0’
Gun Barrel View
800’1130’1460’
375’
1000’
1000’
22
5’
20
0’
1 Mile
W
Wolfcamp A
Wolfcamp B
Dean
Lower Spraberry
At Johnson Ranch, RSP has completed 10 Wolfcamp A / Wolfcamp B wells across a mile on a 960-acre tract
Average production for the 10 wells is trending at or above the type curve in the first six months
“Proposed Pattern”
“As Drilled”
100
1,000
0 30 60 90 120 150 180
Average Wolfcamp B Wells Wolfcamp B Type Curve
Average Wolfcamp A Wells Wolfcamp A Type Curve
Wells outperforming the 7,500’ core type curves (average 7,300’ lateral)
Bo
e/d
___________________________Note: Production plot normalized for operational downtime. As of September 2015.
1018 WA
1019 WA
1021 WA
1023 WB1022 WB
1021 WB1019 WB
1018 WB
N1017 (WD) WA
1017 (WB) WA
Average Daily Production (Boe/d)
16
Lower Spraberry Overview
Lower Spraberry remains the top performing zone in RSP’s inventory
The majority of RSP’s activity continues to target the Lower Spraberry
Multiple sections have Lower Spraberry wells drilled to 500’ or closer spacing
Evaluations are ongoing but early results are promising
Location Summary(1)
Midland / Martin / Andrews
64%
Glasscock22%
Ector14%
Focus Area Locations by County
Map of Recent Lower Spraberry Activity
1719
1717
1717
218217
4818 4820
48174827
20173025 3026
Gross Net
Focus Area 668 413
Dawson 92 67
Total 760 480
Average Length (ft) 7,073
___________________________1) As of June 2015. Pro forma acquisitions announced and closed August/Sept. 2015 and Oct. 2015 potential WPR Acquisition.
17
Middle Spraberry Overview
Location Summary(1)
Middle Spraberry results continue to improve
Sufficient tests across Focus Area acreage position to derisk zone
Midland / Martin / Andrews
77%
Glasscock5%
Ector18%
Focus Area Locations by County
Johnson Ranch
Cross Bar Ranch
Spanish Trail
Fendley
Sarah Ann
Headlee
Parks Bell
1811
912
2017
3025
2184817
3814
405
404
3911
3909
Map of Producing Middle Spraberry Wells
Gross Net
Focus Area 557 338
Dawson 92 67
Total 649 405
Average Length (ft) 7,091
___________________________1) As of October 2015. Pro forma acquisitions announced and closed August/Sept. 2015 and Oct. 2015 potential WPR Acquisition.
–
50.0
100.0
150.0
200.0
0 30 60 90 120 150 180 210 240 270 300 330 360830 MBoe Wolfcamp A Type Curve Average Lower Spraberry wells
715 MBoe Middle Spraberry Type Curve Average Middle Spraberry wells
New Prior Basin Peer
(MBoe) Curve Curve % Inc. Curve
EUR 715 650 10% 800
90-Day Cum 63 38 68% 64
180-Day Cum 104 71 46% 101
360-Day Cum 156 116 35% 152
New Prior Basin Peer
(MBoe) Curve Curve % Inc. Curve
EUR 830 715 16% 1,000
90-Day Cum 72 65 12% 75
180-Day Cum 118 103 15% 120
360-Day Cum 177 152 16% 182
18
Increasing Both Lower Spraberry and Middle Spraberry Type Curves
Spraberry Type Curve and Operated Well Production in Core Counties since Mid-2014 (Normalized to 7,500’)
Cu
mu
lati
ve M
Bo
e
___________________________Note: Updated curves based on cumulative production to date for wells drilled in the applicable zone.
Average Midland Basin peer type curve derived from CPE, FANG, PE, and PXD public investor presentations and RSP estimates. Core Counties are defined as Midland, Martin, and Andrews. Production data normalized for operational downtime. As of September 2015. Previously disclosed type curves of 665 MBoe and 615 MBoe reflected a 7,000’ lateral.
15 Lower Spraberry wells
6 Middle Spraberry wells
Substantial outperformance in both the Lower Spraberry and Middle Spraberry led us to increase the 7,500’ lateral type curves for the zones in our core counties, which comprise ~85% of our Focus Area inventory
The largest increase is the first year production estimates for the Middle Spraberry, which increased substantially more than the overall EUR and will have a large impact on a well’s returns and payback period
RSP’s new type curves in both zones reflect strong economic potential in the current oil price environment
EURs: ~75% Oil360-Day Cum: ~80% Oil
Lower Spraberry (7,500’ lateral)
Middle Spraberry (7,500’ lateral)
–
20
40
60
80
100
120
140
0 30 60 90 120 150 180All Core Lower Spraberry Wells
Average Tightly Spaced Lower Spraberry Wells
19
Preliminary Lower Spraberry Spacing Results
Average Core Lower Spraberry Cumulative Production
Cu
mu
lati
ve M
Bo
e
___________________________Note: Core Counties are defined as Midland, Martin, and Andrews. Production data normalized for operational downtime. As of September 2015.
While RSP has not completed a full Lower Spraberry development test on a single section, there are 5 producing Lower Spraberry wells spaced ~500’ apart on two different leases
These wells are producing from the same stratigraphic interval in a lower landing zone within the Lower Spraberry, testing 500’ spacing without a chevron development pattern
Subsequent development will incorporate an upper landing target to maximize recovery
Early production data indicates the wells are ahead of type curve and comparable to RSP’s recent Lower Spraberry wells
Normalized to 7,500’ lateral
Average of 5 wells spaced ~500’ apart in the same
landing zone
~500’ ~500’“Lower Landing Target” (Producing)
Cross Bar Ranch
Spanish Trail
MIDLAND CO
Lower Spraberry Gun Barrel View
MARTIN CO
20
Core Acreage is Well-Suited for Development
Core of the Midland Basin
Operating areas in a concentrated proximity
Shared infrastructure
Consistent geology
Blocked up, contiguous acreage allows for longer laterals on average
Average Lateral Length across entire inventory: ~7,100 feet, with less than 1/3 of locations “short” laterals
The majority of Focus Area net acreage is held by production
All of acreage position has opportunity for stacked pay with the vast majority with the right to all depths
Minimal acreage expirations in the next two years
Advantages for Contiguous RSP’s Acreage Positions in Focus Area
Focus Area:~1,350 Net Locations
~200,000 Net Effective Horizontal Acres (5 Target Zones)
~12% of Hz Loc.
~70% of Hz Loc.
Over 90% of RSP’s total booked horizontal locations are in concentrated operating areas in the core of the Midland Basin that are situated for full development with primarily longer laterals
~18% of Hz Loc.
RSP Existing Acreage
Potential Acreage Acquisition
<1% of Hz Loc.
___________________________Note: All metrics pro forma for October 2015 potential acquisition.
21
2016 Rig Operating Scenarios
RSP has flexibility to operate two, three, or four horizontal rigs in 2016
2016 completions will primarily be in our highest-return operating areas, similar to 2015
RSP anticipates carrying over a larger than normal backlog of wells waiting on completion to 2016, which would enable us to complete more wells and potentially add incremental production with fewer operated rigs
We anticipate double-digit year-over-year growth in 2016 under all contemplated rig scenarios
Illustrative 2016 Rig Operating Scenarios at Various Commodity Prices
0
1
2
3
4
$40 Oil $50 Oil $60 Oil
# o
f H
Z R
igs
Operated Horizontal Rigs
$200-250mm Capex
35-40 Op. Hz. Completions
$275-325mm Capex
45-50 Op. Hz. Completions
$350-400mm Capex
55-60 Op. Hz. Completions
22
RSP is in a Strong Financial Position
___________________________(1) Capitalization table reflects the closing of the $274 million of acquisitions announced in August, plus $39 million of acquis itions of non-operated partner interests made subsequent to the acquisitions. Includes closing of potential
transactions announced in October. Includes proceeds from August and October equity offerings and August senior notes offering. Does not reflect incremental production or EBITDAX from acquired properties in leverage metrics.(2) Q2 2015 Annualized Adjusted EBITDAX represents Adjusted EBITDAX for the quarter ended June 30, 2015 of $72.55 multiplied by four. Comparatively, first half 2015 Annualized Adjusted EBITDAX would be $264.72 million, with the
improvement in the annualized figure driven primarily by the continued increase in production. Further, the annualized amounts shown in this presentation may not be reflective of our actual results for 2015.
Capitalization Table (1)
Selective use of capital markets to maintain strong balance sheet and liquidity
$181 million equity offering and $200 million senior notes offering in August 2015
$223 million equity offering in October 2015
Increased borrowing base from $500 million to $600 million in August 2015
Earliest debt maturity is Revolving Credit Facility in 2019; and Senior Unsecured Notes mature in 2022
S&P upgraded RSPP’s unsecured notes to “B” from “B-” in September 2015
6/30/2015
($ in millions) PF Transactions
Cash $200
Revolving Credit Facility 0
6.625% Senior Unsecured Notes Due 2022 700
Total Debt $700
Net Debt $500
Liquidity
Borrowing Base $600
Less: Borrowings & LCs (1)
Plus: Cash 200
Liquidity $799
Financial & Operating Statistics
Q2 2015 Annualized Adjusted EBITDAX (2) $290.2
Q2 2015 Daily Production (MBoe/d) 19.9
Credit Metrics
Net Debt / Annualized Adjusted EBITDAX 1.7x
Net Debt / Latest Daily Production ($/Boe/d) $20,833
23
RSP Permian – Positioned for Growth
High Quality Assets
Strong Financial Position
Concentrated asset base in the core of Northern Midland Basin
Multiple quality reservoirs
Lowest F&D cost in the Basin
Multi-well pad development drives efficiency
>25 years of high quality drilling inventory
Focused on Costs and Execution
Undrawn revolver borrowing base increased to $600 million
~$800 million of pro forma liquidity as of Q2 2015
Flexibility to increase or decrease capex
Ability to capitalize on opportunistic acquisitions
Low cost, high margin producer
Low G&A, lean organization
Highly productive wells and low costs lead to superior shareholder returns
24
Appendix
25
Concentration of Core Acreage Provides Attractive Assets with Upside
Despite acreage adjacent to many peers and a high percentage of core acreage, RSP remains conservative on its stated inventory
RSP books only horizontal zones in which it has a producing well in its inventory
RSP has booked the least amount of zones and locations per section in its stated ~1,400 net horizontal locations of the Midland Basin peers
___________________________1) Excludes potential acquisition announced October 2015. 2) Midland Basin Peers include CPE, EGN, FANG, LPI, PE, and PXD.
5751 51
40 40 3835
5753
94
40
64
4640
0
10
20
30
40
50
60
70
80
90
100
Peer 1 Peer 5 Peer 6 Peer 2 Peer 4 Peer 3 RSPP
Stated Locations Stated Upside
Wells per Section Booked for Midland Basin Peers (1)(2)
Booked Zones
Upside Zones
8 7 6 5 5 7 5
8 7 10 5 8 7 6
26
RSP Development Plan to Maximize Efficiency
Well performance improves with lateral length, but the relationship is not linear across all metrics
Capital efficiency increases with lateral length, although there is a point of diminishing returns related to steering and time to clean out
Lateral lengths of 7,000’ – 8,000’ are well-suited to realize the benefits of timing, capital and production
The average lateral length of RSP’s inventory is 7,100’, with few “short” laterals
Illustrative Capex per Foot by Lateral Length
Illustrative EUR by Lateral Length
~5,000' ~7,500' ~10,000'
~50% increase
~5,000' ~7,500' ~10,000'
~75% increase
~25% decrease
~40% decrease
Illustrative 30-Day IP by Lateral Length
~5,000' ~7,500' ~10,000'
~25% Increase
~30% increase
Shorter laterals tend to have higher IPs per foot than longer laterals Longer laterals tend to have higher EURs per dollar of capex and higher IRRs
___________________________Note: Illustrative metrics by lateral length based on actual RSP results on a single lease with wells of each lateral length.
Wolfcamp A
Wolfcamp B
NE
Gun Barrel View
SW
175’
280’
320’1200’ 940’
1060’
375’
1000’
500’
13
0’
25
0’
1/2 Mile
Dean
27
Spanish Trail Extended Reach Laterals
Lower Spraberry
Currently Drilling
On Flowback110’
N
Spanish Trail - Upper Wolfcamp A/B & Spraberry Development
2016 Spud
RSP is currently developing the Company’s longest laterals drilled to date on the Spanish Trail lease (>11,000’)
1st four Upper Wolfcamp laterals are on initial flowback and cleaning up
4717 WA – Pumping 1,886 Boepd 4717 WB – Flowing 1,625 Boepd
4719 WA – Flowing 1,946 Boepd 4719 WB - Flowing 1,643 Boepd
SW
Lower Spraberry development began late Q3 2015
Glasscock County Activity Update
28
2015 Drilling Program Testing Multiple
Horizons
GLASSCOCK CO
MIDLAND CO
RSP Acreage
2015 Acquisitions
#1H (WA) – Completing#2H (Upper WB) – Completing#3H (Lo Spraberry) – Permitted
#4H (Lower WB) - Drilling
XTO
“Zant Lease”
Lower Spraberry, Wolfcamp A, Wolfcamp B
8 wells permitted / drilling
Diamondback
“Saxon / Riley B Leases”
Lower Spraberry, Wolfcamp A, B
6 wells permitted / drilling
Lower Spraberry, Wolfcamp A, Wolfcamp B
Woody 1H WAWoody 2H WB
Completing
Apache – ShackeltonWB/WA Spacing Test
#3H (WB) Cum: 149 Mboe / 9 mo’s
HUNT
“Harris-Hutchinson Lease” (Wolfcamp B)
#1HB - 24-hr IP 820 Boe/d - flowing
#2HB – 24-hr IP: 692 Boe/d – flowing
2 additional wells permitted
HUNT
“Boone - Coffee Lease” (Wolfcamp B)
#1HB - 24-hr IP 820 Boe/d - flowing
#2HB – 24-hr IP: 1,270 Boe/d – flowing
2 additional wells permitted / drilling
Pioneer
“Flanagan Leases”
Lower Spraberry, Wolfcamp A, B, Cline
#21H (Lower Spraberry) – 24 hr IP: 940 Boe/d
#5H (Cline) - 24 hr IP: 1,610 Boe/d
#4H (Wolfcamp A) – 24 hr IP: 1,129 Boe/d
#8H (Wolfcamp B) – 24 hr IP: 1,466 Boe/d
Pioneer
“O Daniel Leases”
Wolfcamp A, B, Cline
#2H (Cline) - 24 hr IP: 2,729 Boe/d
#27H (Wolfcamp A) – 24 hr IP: 2,145 Boe/d
#1H (Wolfcamp B) – 24 hr IP: 2,491 Boe/d
27
___________________________Source: TX RRC and other public sources
29
Adjusted EBITDAX, Adjusted Net Income and Net Income Reconciliation
___________________________Note: 2014 results adjust for the combinations that occurred in connection with our IPO in January 2014. Please see 10-K and 10-Q for more information.
($ in thousands, except per unit amounts) Quarter Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 Pro Forma
RevenuesOil sales $73,917 $66,134 $121,222 $122,065Natural gas sales 2,028 3,117 4,261 5,514NGL sales 2,520 4,811 4,356 9,228
Total revenues $78,465 $74,062 $129,839 $136,807
Net cash from derivative instruments 18,646 (2,161) 48,117 (2,766)
Adjusted Total Revenues $97,111 $71,901 $177,956 $134,041
Operating Expenses
Lease operating expenses $14,693 $9,279 $27,304 $17,036Production and ad valorem taxes 5,402 5,964 9,599 10,091General and administrative expenses 4,464 3,573 8,693 5,344
Total operating costs and expenses $24,559 $18,816 $45,596 $32,471
Adjusted EBITDAX, as defined $72,552 $53,085 $132,360 $101,570
Depreciation, depletion, and amortization $39,620 $21,734 $71,121 $41,728Asset retirement obligation accretion 84 38 168 76Exploration 889 1,233 2,067 1,989Interest expense 9,367 1,142 18,683 2,272Stock-based compensation, net 2,401 1,665 4,543 952
Adjusted income before income taxes $20,191 $27,273 $35,778 $54,553
Adjusted income tax expense 7,145 10,244 12,697 19,639
Adjusted net income, as defined $13,046 $17,029 $23,081 $34,914
Adjusted net income per common share - Basic $0.16 $0.23 $0.28 $0.48Adjusted net income per common share - Diluted $0.16 $0.23 $0.28 $0.48
Other items included in income before taxesNon-cash (loss) on derivatives, netOther income
($31,608) ($13,797) ($48,748) ($17,345)
(37) (302) 161 8
Income (loss) before income taxes ($18,599) $2,930 ($25,506) $17,577
Income tax (benefit) expense ($13,146) ($5,296) ($19,028) ($6,241)
Net Income (loss) ($5,453) $8,226 ($6,478) $23,818
Net income (loss) per common share - Basic ($0.07) $0.11 ($0.08) $0.33
Net income (loss) per common share - Diluted ($0.07) $0.11 ($0.08) $0.33
30
Hedging Program Summary
Oil Hedge Summary
RSP has hedged ~35% of its remaining 2015 oil production at a floor price of ~$86
RSP has begun to layer on hedges for 2016 and will continue to opportunistically add hedges
Q3 2015 Q4 2015 2015 2016
Swaps
Volumes (MBbls) 30 30 60
Average Swap Price ($/Bbl) $92.60 $92.60 $92.60
Collars
Volumes (MBbls) 498 498 996 555
Average Floor ($/Bbl) $85.57 $85.57 $85.57 $55.00
Average Ceiling ($/Bbl) $94.33 $94.28 $94.30 $74.08
Average Short Put Price ($/Bbl) $45.00
Total Volumes Hedged (MBbls) 528 528 1,056 555
Total Blended Floor $85.97 $85.97 $85.97 $55.00
Daily Volumes (Bbls/day) 5,739 5,739 5,739 1,516
% Future Oil Production Hedged ~35%
2,378
4,077
557
668
323 298
348
92
92
622
1,077
0250500750
1,0001,2501,5001,7502,0002,2502,5002,7503,0003,2503,5003,7504,0004,2504,500
MiddleSpraberry
LowerSpraberry
Wolfcamp A Wolfcamp B Wolfcamp D Total TargetHorizontalLocations
Vertical 40-Acre Spacing
Vertical 20-Acre Spacing
TotalLocations
___________________________Note: As of June 30, 2015. Includes locations from acquisitions subsequent to June 30, 2015, including the potential acquisition announced October 2015. Excludes Clearfork, Jo Mill, Strawn, Atoka, and any other horizontal zones.
31
Extensive Multi-Year Drilling Inventory with Strong Rates of Return
Identified Horizontal Locations Identified Vertical Locations
Focus Areas Dawson Area
Operated horizontal locations booked as 5 wells across a section in Wolfcamp (~1,100’ spacing) and 10 wells across a
section in Spraberry (~500’ spacing) in Focus Area
Clearfork, Jo Mill, Strawn, Atoka, and other formations are potential future upside
Net Locations:
Focus Area 338 413 188 194 224 1,357 451 711 2,519
Dawson 67 67 0 0 0 134 - - 134
Total Net Locations: 405 480 188 194 224 1,492 451 711 2,654
Avg. Lat. Length 7,091' 7,073' 7,076' 7,116' 6,909' 7,059'
% Booked as PUDs 2% 4% 2% 18% 1% 5%
32
Proved Reserves Doubled in 2014
Proved Reserves Growth
Gross Horizontal PUD Count
Proved Reserve Summary
PD39%PUD
61%Oil
65%
Gas15%
NGLs20%
106.4 MMBoe
21.4 41.9
32.5
64.5 53.9
106.4
–
20
40
60
80
100
YE 2013 YE 2014PD PUD
MM
BO
E
9
30 2
14
14
60
5
25
109
–
20
40
60
80
100
YE 2013 YE 2014 % of Locations
Lower Spraberry Middle Spraberry
Wolfcamp A / B Wolfcamp D
Approximately doubled both Proved Developed and Proved Undeveloped Reserves year over year
Only 5% of RSP’s horizontal locations are booked as PUDs
Reserve life of more than 18 years (1)
Drillbit F&D of $10.59 (2) and Total F&D of $13.88
Reserve Replacement Ratio of 1,406% and Organic Reserve Replacement Ratio of >1,100% (3)
___________________________(1) Based on Q4 2014 production. (2) Defined as exploration and development costs divided by the sum of extensions and discoveries and non-price revisions.(3) Defined as the sum of extensions, discoveries, and non-price revisions, divided by annual production.
10%(621 Locations)
1%(348 Locations)
2%(649 Locations)
4%(760 Locations)
Cross Bar Microseismic – Conclusions and Implications
33
Middle Spraberry – Micro Seismic indicates 10 wells across one mile
Wolfcamp A – Micro Seismic indicates correct spacing of 5 wells across one mile
Wolfcamp D (Cline) – No data available for verification of spacing
Wolfcamp B – Micro Seismic indicates correct spacing of 5 wells across one mile
Wolfcamp A
Wolfcamp B
Dean
Lower Spraberry
575’
375’
350’
Middle Spraberry
275’
200’
1 Mile
Wolfcamp C
Wolfcamp D (Cline)
Jo Mill 80’
275’
325’
Dean – Micro Seismic indicates Dean is covered by LS and WA stimulation
Jo Mill – Micro Seismic indicates undeveloped gap between MS and LS
Lower Spraberry – Micro Seismic indicates 10 wells across one mile
10
5
10
5
5
5
Potential for 40 horizontal wells across 1 mile section
Hypothetical Development Scheme Implied by Cross Bar Ranch Microseismic Study
Preliminary Microseismic Conclusions:
34
Additional Disclosures
Supplemental Non-GAAP Financial Measures
We define Adjusted EBITDAX as oil and gas revenues including net cash receipts (payments) on settled derivative instruments and premiums paid on put options
that settled during the period, less lease operating expenses, production and ad valorem taxes, and general and administrative expenses excluding stock based
compensation. Adjusted net income deducts from Adjusted EBITDAX depreciation, depletion, and amortization, accretion on asset retirement obligations,
exploration expenses, interest expense, stock-based compensation and adjusted income tax expense.
Management believes Adjusted EBITDAX and adjusted net income are useful because they allow us to more effectively evaluate our operating performance and
compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above in arriving
at Adjusted EBITDAX and adjusted net income because these amounts can vary substantially from company to company within our industry depending upon
accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX and adjusted net income
should not be considered as an alternative to, or more meaningful than, net income as determined in accordance with GAAP or as an indicator of our operating
performance or liquidity. Certain items excluded from Adjusted EBITDAX and adjusted net income are significant components in understanding and assessing a
company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are
components of Adjusted EBITDAX. Our computations of Adjusted EBITDAX and adjusted net income may not be comparable to other similarly titled measures of
other companies.
Certain Reserve Information
Cautionary Note to U.S. Investors: The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other
than “reserves,” as that term is defined by the SEC. This presentation discloses estimates of quantities of oil and gas using certain terms, such as “resource
potential,” “net recoverable resource potential,” “resource base,” “estimated ultimate recovery,” “EUR” or other descriptions of volumes of reserves, which terms
include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC’s guidelines strictly prohibit
the Company from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are
subject to substantially greater risk of being recovered by the Company. U.S. investors are urged to consider closely the disclosures in the Company’s periodic
filings with the SEC. Such filings are available from the Company at 3141 Hood Street, Suite 500, Dallas, Texas 75219, Attention: Investor Relations, and the
Company’s website at www.rsppermian.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.