RSP Permian Q1 2015 Results
May 2015
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.
2
RSP Permian Overview
 Large, contiguous, core acreage blocks in the Midland Basin
Contiguous Acreage in the Core of the Midland Basin
 ~188,000 net “effective horizontal acres” and ~47,000 net
surface acres (95% operated, >99% rights to all depths)
(1)
 More than 2,000 horizontal and 1,200 vertical drilling locations
 Low-risk, oil-rich base with rapid growth potential
Dawson Area
 Leader in Northern Midland Basin horizontal development
 Drilled wells in five different horizontal benches
 First operator to drill horizontal well in Spraberry Shale (Lower &
Middle)
 Spent 2014 doing technical pilots to design and execute
development program
Focus Areas
 Strong balance sheet & liquidity position
 Over $600 million of liquidity at 3/31/15 and 1.6x net debt /
Adjusted EBITDAX (2)
 Optionality to change drilling pace or make opportunistic
acquisitions
Effective Horizontal Acres
 Key Statistics:
 Market capitalization of ~$2.3 billion (3)
RSP Acreage
 Q1 2015 Average Production: 15.9 MBoe/d
 Q1 2015 Exit Rate Production: 17.7 MBoe/d (4)
 Proved Reserves as of 12/31/14: 106 MMBoe (65% Oil, 20% NGL,
15% Natural Gas), 42 MMBoe of which is proved developed
TX
Gross
Middle Spraberry 55,256
Lower Spraberry 60,996
Wolfcamp A
39,651
Wolfcamp B
56,403
Wolfcamp D
45,176
Total
257,482
Net
40,200
45,864
27,383
41,958
32,193
187,598
___________________________
(1)
Combined horizontal acreage position that management believes is prospective for hydrocarbon production across each target horizontal zone.
(2)
Based on 1Q 2015 Adjusted EBITDAX annualized. Please see reconciliation of Adjusted EBITDAX in Appendix.
(3)
Market data as of May 12, 2015.
(4)
Reflects average daily production for the last week of March 2015.
3
First Quarter 2015 Highlights
 Q1 2015 production averaged 15.9 MBoe/d (75% Oil, 14% NGLs, 11% Natural Gas)
 Increase of 86% compared to Q1 2014
Q1 Financial
Results
 Q1 2015 exit rate production of 17.7 MBoe/d (1)
 Excluding weather impact at the beginning of the year, production averaged ~17
MBoe/d during the quarter
 Adjusted EBITDAX of $59.8 million in Q1 2015, an increase of 45% compared to Q1 2014
 Adjusted Net Income of $10.3 million, or $0.13 per diluted share
 Completed follow-on equity offering, selling 5.0 million primary shares, resulting in
approximately $127.9 million of net proceeds to the Company
Capital Markets
& Balance Sheet
 In April 2015, the underwriter fully exercised its option to purchase an additional .75
million shares which provided additional proceeds of $19.2 million to the Company
 Ended quarter with conservative leverage, with 1.6x Debt / Annualized Adjusted EBITDAX (2)
 Over $600 million of available liquidity as of 12/31/14, including $500 million on an undrawn
borrowing base. On May 1, our lenders reaffirmed our $500 million borrowing base
 Spent $78 million on drilling and completion and $6 million on infrastructure
Operational
Activity
 $7 million of this capital was attributable to non-operated properties
 Completed 8 operated horizontal wells and 3 operated vertical wells during the quarter
 Completed 11 non-operated horizontal wells and 2 non-operated vertical wells
 Built additional inventory of wells waiting on completion: 16 horizontal wells and 15 vertical
wells at the end of the quarter
___________________________
Please see reconciliation of Adjusted EBITDAX in Appendix. Pro forma statistics assume combination of interests at IPO had occurred prior to 2013.
(1) Reflects average daily production for the last week of March 2015.
(2) Based on Q1 2015 Adjusted EBITDAX annualized.
4
Historically Low Cost Structure and Strong Margins
Our operations and commodity mix allow us to generate healthy cash margins in a challenging environment
Historical Cash Margins and Costs (per Boe)
$63.22
Realized Price per Boe (Excluding Hedges)
$85.13
$74.64
$74.65
$75.96
$68.45
$67.24
$30.00
78%
$25.00
78%
78%
$14.21
$4.19
$10.00
$5.00
72%
$5.01
$1.42
$2.86
$8.60
$7.63
$16.73
$5.57
$2.42
$8.74
$16.75
$6.31
$1.60
$8.74
$16.24
$6.12
60%
$15.09
$4.91
$2.10
$4.98
$3.67
$3.19
$9.23
75%
59%
$19.31
$20.00
$15.00
78%
75%
#2 among Peers
for 2014
$15.50
$35.80
90%
80%
77%
$53.51
$9.52
$6.92
$14.98
$14.65
$3.22
$2.92
$4.21
$2.95
$7.55
$8.78
–
45%
30%
15%
–
Q1 2013
Q2 2013
Q3 2013
Q4 2013
LOE, Gathering & Transporation, & Workovers
Q1 2014
Cash G&A
Q2 2014
Q3 2014
Prod. & Ad Val
Q4 2014
Q1 2015
Cash Margin (Excluding Hedges)
(1)
___________________________
Note: Periods prior to Q4 2013 reflect Predecessor per unit metrics, as pro forma numbers reflecting the combinations at the IPO were not available. Permian peers include CPE, CXO, FANG, LPI, PE, and PXD. Based on public filings.
1)
Cash Margin (Excluding Hedges) is calculated as the Realized Price per Boe (Excluding Hedges) less the cash costs listed in the chart, divided by the Realized Price per Boe (Excluding Hedges) .
5
RSP in a Strong Financial Position to Execute its Strategy
Pro Forma Capitalization Table (1)
Financial Strategy
 Following its equity offering in Q1 2015, RSP
has over $600 million of liquidity
 Ensures capital to execute drilling
program into 2016
 Allows RSP to take advantage of future
acquisition opportunities
 Maintain conservative balance sheet and
financial flexibility
 Currently ~45% hedged on remaining expected
2015 oil production, with the majority of PDP
oil production hedged
 Earliest debt maturity is Revolving Credit
Facility in 2019; and Senior Unsecured Notes
mature in 2022
($ in millions)
3/31/2015
Cash
$122
Revolving Credit Facility
6.625% Senior Unsecured Notes Due 2022
Total Debt
0
500
$500
Net Debt
$378
Liquidity
Borrowing Base
Less: Borrowings & LCs
Plus: Cash
$500
(0)
122
Liquidity
$622
Financial & Operating Statistics
Q1 2015 Annualized Adjusted EBITDAX (2)
Q1 2015 Daily Production (MBoe/d)
Credit Metrics
Net Debt / Annualized Adjusted EBITDAX
Net Debt / Latest Daily Production ($/Boe/d)
$239.2
15.9
1.6x
$23,707
___________________________
(1) Adjusted for the April 2015 exercise of the overallotment option by the underwriter related to RSP’s March 2015 equity offering, which resulted in $19.2 million of additional net proceeds.
(2) Based on 4Q 2014 Adjusted EBITDAX annualized. Please see reconciliation of Adjusted EBITDAX in Appendix.
6
RSP Deferred Completion Activity During the Quarter
Q1 Drilling & Completion Activity Summary
Drilled
Completed
WOF
Operated Wells
Horizontal
Vertical
Total
14
9
23
8
3
11
16
15
31
Non-Operated Wells
Horizontal
Vertical
10
1
11
2
9
–
 During the first quarter, RSP completed 8 horizontal wells as
an operator (2 Middle Spraberry, 4 Lower Spraberry and 2
Wolfcamp B wells) & 3 operated vertical wells
 During the quarter, RSP’s drilling activity added to its
inventory of wells waiting on completion
 Deliberate delay of completion activity while awaiting
cost reductions
 16 operated horizontal wells and 15 vertical wells at
quarter-end
Progression of 2015 Net Production
Weekly Boe/d
20,000
15,000
1Q Exit Rate:
17.7 MBoe/d
1Q Average: 15,944 Boe/d
Weather
Impact
10,000
12/31
Q1 Q2
3 Hz Completions
1/31
3 Hz Completions 2 Hz Completions
2/28
 Following the weather-impact early in
the quarter, RSP produced ~17 MBoe/d
on average for the remainder of the
quarter
 The majority of Q1 horizontal
completions finished between late
February and late March and did not
contribute materially to the first quarter
average production
3/31
7
Recent Operational Highlights
Notable Recent Operational Highlights
Spanish Trail 4817
 Three-well pad: Lower Spraberry,
Wolfcamp B and Middle Spraberry
 Average lateral length of 7,400’, and
average 30 day IP of 1,143 Boe/d after
cleaning up and average 90-day
cumulative production of 82 MBoe
Cross Bar Ranch 3025
Q1 Operated Horizontal Completions
Cross Bar
Ranch
Johnson
Ranch
 Two-well Lower Spraberry and Middle
Spraberry pad
 Average lateral length of ~9,400’ and
average 30 day IP of 1,128 Boe/d
Cross Bar Ranch 1811
 Two-well Lower Spraberry and Middle
Spraberry pad
Section
47
 Average lateral length of ~7,350’ and an
average 30 day IP of 834 Boe/d (still
cleaning up)
Spanish Trail
Section 47
 Drilled longest lateral in RSP history
(Wolfcamp A well, 11,400’)
 Simultaneous development of four
WA/WB wells followed by four Lower
Spraberry wells
Spanish
Trail
Wolfcamp A/B
Lower Spraberry
Mid. Spraberry
8
Leader in Multi-Zone Horizontal Development in the Midland Basin
 As on operator, RSP has tested at least 7 different combinations of multi-zone, multi-well pad
development
 RSP expects strong results as it develops across all areas of its horizontal inventory and has seen
overall results continue to improve
 RSP’s production mix reflected in the results below is 80-90% oil (three-stream basis)
Program Average – Operated Focus Area Wells with Production History (1)
# of Wells
Average
Lateral
Length (ft)
Average
30-Day IP
(Boe/d)
Average
30-Day IP /
1,000'
Average
Average 9090-Day Cum Day Cum /
(MBoe)
1,000'
Average
Average 180180-Day Cum Day Cum /
(MBoe)
1,000'
Middle
Spraberry
11
7,582
790
104
54
7.2
88
11.6
Lower
Spraberry
15
7,148
898
128
60
8.4
101
14.1
Wolfcamp
A/B
20
6,537
846
132
55
8.5
84
12.8
Total
46
6,986
850
124
57
8.1
90
12.9
___________________________
(1) Excludes two wells in Dawson County and Wolfcamp D wells with mechanical issues.
9
RSP Full Development Test on Johnson Ranch
Johnson Ranch Full 960-Acre Development
1021 WA
1019 WA
 At Johnson Ranch, RSP has completed 10 Wolfcamp A /
Wolfcamp B wells across a mile on a 960-acre tract and wells
are flowing back
1017 (WD) WA
N
1017 (WB) WA
 Late in 2015 or early in 2016, RSP will begin a Lower Spraberry
pilot in the same section, in which it will eventually drill 10
wells across the section
1018 WA
Gun
Barrel View
1023 WB
W
E
110’
Potential of 20 wells across this section by end of 2016
1018 WB
1021 WB 1022 WB
1019 WB
300’
Gun Barrel View
Lower
Spraberry
“Proposed Pattern”
1000’
225’
1000’
375’
Producing
1018 WA / WB
On Flow Back
1022 WB
1021 WA
1019 WA / WB 1017 WA
1021 WB
1017 WA
1023 WB
200’
Dean
200’
“As Drilled”
Wolfcamp A
1460’
1130’
250’
800’
200’
Wolfcamp B
920’
595’
825’
1650’
1 Mile
790’
810’
250’
Tank Battery for Johnson Ranch Pilot
10
Continued Success and Development at Spanish Trail Lease
RSP Spanish Trail Development
N
 RSP now has 9 horizontal wells on production and 5
horizontal wells waiting on completion on its Spanish
Trail lease
 Results remain among the strongest in RSP’s operating
areas
 Section 47 – Longest lateral to date in Spanish Trail
4717WA (~11,400’)
 Wolfcamp B well will be drilled on the same pad
to an equal length
 Half-mile wide section will ultimately be fully
developed with Wolfcamp A/B wells and Lower
Spraberry wells of the same length
Spanish Trail Results
Well Name
Avg 30
Average Average 90Lateral Avg 30 day Day IP / 90-Day Cum Day Cum /
Zone Length IP (Boe/d) 1000'
(MBoe)
1,000'
Spanish Trail 217
LS
WB
6,853
6,860
1,217
1,211
178
177
93
79
13.6
11.6
Spanish Trail 218
LS
MS
9,947
9,947
1,301
1,082
131
109
88
78
8.8
7.8
LS
Spanish Trail 4817 WB
MS
7,352
7,454
7,352
1,229
1,268
931
167
170
127
95
85
64
13.0
11.5
8.7
LS
WB
7,352
7,250
1,256
1,342
171
185
NA
NA
NA
NA
7,819
1,204
157
83
10.7
Spanish Trail 4818
Average of Wells
11
Recent Middle Spraberry Results Significantly Outperforming Type Curve
Recent Middle Spraberry Well Results
Johnson Ranch
912
Cross Bar Ranch
Well Name
2017
3025
9,172
7,352
9,947
7,454
1,190
931
1,082
878
130
127
109
118
82
64
78
NA
8.9
8.7
7.8
NA
Average of Wells
8,481
1,020
121
75
8.5
Lower Spraberry Average
Wolfcamp A/B Average
7,148
6,537
898
846
126
129
60
55
8.4
8.5
Cumulative Production Normalized to 7,000’
70
Cross Bar Ranch 3025 MS
Spanish Trail 4817 MS
Headlee
Spanish Trail
218
4817
3814
Parks Bell
3909
Spanish Trail 218 MS
Cross Bar Ranch 1811 MS
50
Middle Spraberry Type Curve
40
Lower Spraberry Type Curve
30
20
404
10
405
Fendley
Cumulative MBoe
60
Sarah Ann
Avg 30
Average Average 90Avg 30 day Day IP / 90-Day Cum Day Cum /
IP (Boe/d)
1000'
(MBoe)
1,000'
Cross Bar Ranch 3025 MS
Spanish Trail 4817 MS
Spanish Trail 218 MS
Cross Bar Ranch 1811 MS
471 Middle Spraberry
Locations in Focus Area
3911
Lateral
Length
1811
Middle Spraberry Completions
0
0
30
60
90
12
Leading Wolfcamp A Development in this Area of the Midland Basin
1019
 Wolfcamp A wells have outperformed Wolfcamp B type
curve, and zone will be included in initial development
1017
1717
1017
1018
Cross Bar Ranch
1021
2017
 4 additional wells starting flowback and 5 additional
wells either drilling or waiting on completion
Johnson Ranch
3027
Wolfcamp A Well Results
Remaining Wolfcamp A
wells flowing back
Lateral
Length
Well Name
258 Wolfcamp A
Locations in Focus Area
Avg 30
Avg 30 day Day IP /
IP (Boe/d)
1000'
Average Average 9090-Day Cum Day Cum /
(MBoe)
1,000'
Cross Bar Ranch 1717 WA*
Johnson Ranch 1018 WA*
Cross Bar Ranch 2017 WA
7,107
7,392
7,074
928
1,050
887
131
142
125
75
74
59
10.5
10.0
8.3
Average of Wolfcamp A
7,191
955
133
69
9.6
Wolfcamp B Average
6,377
812
127
53
8.3
* Wells were completed simultaneously with a Wolfcamp B well
Cumulative Production Normalized to 7,000’
4717
Spanish Trail
4820
4827
Wolfcamp A Wells Drilled
Cumulative MBoe
80
Cross Bar Ranch 2017 WA
Johnson Ranch 1018 WA
60
Cross Bar Ranch 1717H WA
Wolfcamp A/B Type Curve
40
20
0
0
30
60
90
13
LS
Glasscock County Update
2015 Drilling Program – Testing Multiple Horizons
N
DEAN
GLASSCOCK CO.
WC A
520’
“WOODY”
WC B
544’
“BRUNSON”
LS
DEAN
WC A
U WC B
655’
“CALVERLEY”
L WC B
RSP Acreage
14
Update on Horizontal Well Costs
 Target well costs have decreased by ~30% since peak levels in Q4 2014, ~20% due to lower service
costs and another ~10% due to increased efficiencies
 The illustration below depicts a 7,500’ lateral well at peak costs in Q4 2014 compared to current
target well costs
Illustrative Decrease in Service Costs from Peak Costs in 2014 to Current Target (7,500’ lateral)
~7,500’
~$9.0mm
$1,200 / ft
% of D&C
42%
% Reduction
(30%)
26%
(32%)
~7,500’
~$6.3mm
$840 / ft
Frac/Stim, Water, Log/Perf
Other Drilling & Completion &
Contingent Costs
Mud
Rental
9%
(34%)
10%
(31%)
10%
(27%)
2014 Peak Cost
Current Target
Casing/Tubing
Contract Drilling & Directional
15
Appendix
16
Adjusted EBITDAX and Adjusted Net Income Reconciliation
Adjusted EBITDAX and Adjusted Net Income Reconciliation
($ in thousands, except per unit amounts)
2015
Actual
Revenues
Oil sales
Natural gas sales
NGL sales
Total revenues
Net cash from derivative instruments
Adjusted Total Revenues
Quarter Ended March 31,
2014
Pro Forma
Actual
$47,305
2,233
1,837
$51,375
$55,930
2,397
4,417
$62,744
$51,471
2,206
4,081
$57,758
29,471
(606)
(606)
$80,846
$62,138
$57,152
Operating Expenses
Lease operating expenses
Production and ad valorem taxes
General and administrative expenses
Total operating costs and expenses
$12,611
4,197
4,229
$21,037
$7,757
4,127
1,771
$13,655
$7,063
3,876
5,001
$15,940
Adjusted EBITDAX, as defined
$59,809
$48,483
$41,212
$31,502
84
1,178
9,316
2,142
$19,994
38
756
1,131
294
$16,361
29
756
1,131
12,015
$15,587
$26,270
$10,920
5,557
9,457
4,637
$10,030
$16,813
$6,283
$0.13
$0.13
$0.23
$0.23
$0.10
$0.10
Depreciation, depletion, and amortization
Asset retirement obligation accretion
Exploration
Interest expense
Stock-based compensation, net
Adjusted income before income taxes
Adjusted income tax expense
Adjusted net income, as defined
Adjusted net income per common share - Basic
Adjusted net income per common share - Diluted
___________________________
Note: Pro forma results adjust for the combinations that occurred in connection with our IPO in January 2014. Please 10-K and 10-Q for more information.
17
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.
18