40
SCOTIA HOWARD WEIL 2017 ENERGY CONFERENCE March 27, 2017
SCOTIA HOWARD WEIL2017 ENERGY CONFERENCE
March 27, 2017
FORWARD-LOOKING STATEMENTS
2
Certain statements and information in this presentation may constitute “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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 anduncertainties (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 ability to assimilate acquisitions into our operations, 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 RSP’s credit facility and derivative contracts and the purchasers of RSP’s production and third parties providing services to RSP, acts of war or terrorism and the fact that our capital program may exceed budgeted amounts.
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 Commission (SEC), including our Annual Reports 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.
RSP PERMIAN INVESTMENT HIGHLIGHTS
3
Prime Permian
Position
Focused asset base with balanced exposure to the core of the Midland and Delaware
Basins. Blocky, contiguous acreage footprint enabling peer leading efficiencies and long
lateral horizontal development
Strong Growth
Profile
Superior
Execution
Focus on Capital
Efficiency
Technical
Leader
Oil-Weighted
Production and
Reserve Base
Experienced
Permian Team
Massive inventory of high-return horizontal drilling locations in multiple stacked horizons
driving substantial, multi-year production growth profile while achieving cash flow
neutrality at $55 oil in 2018
Track record of driving down costs and achieving low cost operations, yielding strong
and resilient cash operating margins throughout the commodity price cycle
Rate of return driven capital program generating attractive finding and development
costs leading to strong recycle ratio when combined with high cash margins
At the forefront of horizontal drilling technology using advanced completion techniques
and spacing designs, leading to resource expansion and operating efficiencies
Assets located in oily and liquids-rich areas of the Midland and Delaware Basins, leading
to higher revenue per boe and superior well economics
Management and senior operating team has over 30 years of average experience in the
Permian Basin, operating through multiple cycles
RSP PERMIAN OVERVIEW
~160,000 gross / 100,000 net acres across highly
contiguous acreage blocks in the core of the Midland and
Delaware Basins
~5,900 gross (3,700 net) horizontal locations in
drilling inventory
Significant 2017 production ramp with visibility to 30%+
annual production growth in 2018-2019
Cash flow neutral beginning in 2018 at ~$55 oil
Organizational focus on efficiency and execution
Leading drill-bit F&D costs, reserve replacement
ratios and cash operating margins
4
CONTIGUOUS ACREAGE POSITION IN CORE OF PERMIAN BASIN(1)RSP OVERVIEW
Key Statistics (Pro Forma for Silver Hill Acquisition)
NYSE Symbol RSPP
Shares Outstanding 157.9 MM
Market Capitalization (3/23/17) $6.1 B
Enterprise Value $7.1 B
Net Debt / LQA EBITDAX 2.4x
YE 2016 Proved Reserves 283 MMBoe
(1) Combined horizontal acreage position that Management believes is prospective for hydrocarbon production across each target horizontal zone.
Delaware
Basin
Midland
Basin
Net
Surface
Acres
Net
Effective
Hz Acres(1)
Gross
Locations
Net
Locations
%
Operated
Midland 57,400 257,368 2,700 1,750 95%
Delaware 40,100 244,538 3,200 1,950 80%
STRONG TRACK RECORD OF GROWTH
5
ANNUAL RESERVE GROWTH (MMBOE)ANNUAL PRODUCTION GROWTH (MBOE/D)
54
106
159
202
YE 2013 YE 2014 YE 2015 YE 2016
SHEP II
SHEP I
Midland Basin
7
12
21
29
53
2013 2014 2015 2016 2017E
237
283
57(1)
(1)
(1) First part of Silver Hill acquisition (SHEP I) closed 11/28/16; second part (SHEP II) closed 03/01/17.
(1)
Achieved most efficient quarter to date in Q4 2016, with cash operating costs of $9.11/Boe and cash margin of 76%(1)
Experienced Permian operations team
Highly contiguous acreage footprint
Crude price realization ranks amongst highest in basin
DURABLE MARGINS THROUGHOUT THE COMMODITY PRICE CYCLE
6
HISTORICAL CASH MARGINS AND COSTS (PER BOE)
$8.14$6.92
$5.41 $4.99
$4.25
$2.33
$2.10 $2.11
$4.63
$2.60
$2.03 $2.01
$17.02
$11.85
$9.54$9.11
74%
68%
71%
76%
50%
60%
70%
80%
–
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
2014 2015 2016 Q4 2016
LOE, Gathering & Transporation, & Workovers Cash G&A Prod. & Ad Val Cash Margin (Excluding Hedges)
(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).
(2) Peers include: CPE, CXO, FANG, LPI, PE, PXD.
(1)
Peer(2) Avg:
70%
Peer(2) Avg:
$10.67
Premier acreage position yielding consistent, strong results
Focused R&D effort to determine optimal drilling and completion techniques by area and reservoir
Significant year-over-year improvement with potential for further optimization
WELL PERFORMANCE LEADING THE PACK
7
MIDLAND BASIN 180D OIL IPS (BO/D)(1)
Note: Peers include APA, CPE, CVX, CXO, ECA, EGN, EPE, FANG, LPI, OXY, PE, PXD, QEP, SM, and XOM.
Source: Drillinginfo, J.P.Morgan estimates.
732
594 587
514 512 512 501
466 462444
415380
360336
309 302
0
100
200
300
400
500
600
700
800
RSPP Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14 Peer 15
2016 2015 2014
DRILLING & COMPLETION EFFICIENCY IMPROVEMENTS
8
0
2
4
6
8
10
12
14
16
18
20
0 5 10 15 20 25 30 35 40
Dep
th (
‘00
0 f
t)
Days
2013 2014 2015 2016
4.45.2
7.8 7.5
0.0
0.5
1.0
1.5
2.0
2.5
3.0
2013 2014 2015 2016
0
1
2
3
4
5
6
7
8
9
Po
un
ds o
f Sand
Pu
mp
ed
/Day (m
illion
s)
Stag
es/D
ay
Avg. Stages/Day # Sand/Day
MIDLAND BASIN - RATE OF PENETRATION EVOLUTION(1) MIDLAND BASIN – COMPLETION EFFICIENCY
RSP drilling HZ wells in less than half the time as HZ wells drilled in 2013
RSP is completing over 7 stages per day (sand pounds/day increased ~15% over 2015)
Opportunities for additional improvement in both the Midland Basin and Delaware Basin
>60% Reduction
(1) Based on all wells drilled with a lateral length of ~7,500’.
SUPERIOR CAPITAL EFFICIENCY
9
TOP DRILLING TARGETS – SINGLE WELL IRRDRILLBIT F&D (EXCL. PRICE REVISIONS)(1)
$5.77
$4.05
$10.13
$8.25
2015 2016
RSPP Permian Peers Avg
ReservoirLateral
LengthIRR @ $55
Glasscock Upper Wolfcamp 7,500’ +
>70%Wolfcamp A 7,500’ +
Lower Wolfcamp A 4,500’ +
Upper Wolfcamp (XY) 4,500’ +
Lower Spraberry 7,500’ +
40-70%
Middle Spraberry 7,500’ +
2nd Bone Spring 4,500’ +
Avalon 4,500’ +
Wolfcamp B 7,500’ +
Wolfcamp B 4,500’ +
30-40%3rd Bone Spring 4,500’ +
West Side 7,500’ +
Midland
Delaware
RSP ranks amongst the most capital efficient operators in the
industry
Focus on maximizing well performance, reducing D&C
costs and maintaining high cash operating margins
(1) Exploration & development expense divided by extensions plus non-price related reserve revisions. Peer numbers include all revisions when price revisions are not disclosed. RSP 2016 excludes
impact of removing remaining vertical PUDs from reserve base.
(2) Peers include: CPE, CXO, FANG, LPI, PE, PXD.
#2
85% of 2017E
D&C CAPEX
#1
Deep inventory of high rate of return drilling opportunities
Wells with IRRs >40% represent 85% of 2017E D&C
capex
Delaware Basin returns based on 4,500’ lateral wells, expect
uplift from drilling longer laterals
Midland Basin well returns based on 7,500’ LL despite a
meaningful portion of 2017 inventory planned for 10,000’
(2)
STRONG FINANCIAL POSITION WITH AMPLE LIQUIDITY
10
CAPITALIZATION TABLEEntered into amended and restated credit facility with $1.1B
borrowing base, $900MM elected commitment and $2.5B
maximum lender commitments
Key financial covenants:
Maximum of 4.25x Total Debt / TTM EBITDAX
Minimum current ratio of 1.0x
DEBT MATURITIES ($MM)
$0
$200
$400
$600
$800
$1,000
$1,200
2017 2018 2019 2020 2021 2022 2023 2024 2025
Credit Facility Senior Notes
6.625%
5.25%
Elected Commitment
Borrowing Base
(1) Pro forma for SHEP II, closed 3/01/17.
($ in millions) 12/31/2016 PF SHEP II
Cash $691 $109
Revolving Credit Facility – –
6.625% Senior Unsecured Notes Due 2022 700 700
5.25% Senior Unsecured Notes Due 2025 450 450
Total Debt $1,150 $1,150
Net Debt $459 $1,041
Liquidity
Elected Commitment $900 $900
Less: Borrowings & LCs (1) (1)
Plus: Cash 691 109
Liquidity $1,590 $1,008
Financial & Operating Statistics
Annualized PF Q4 2016 Adjusted EBITDAX (1) $434.3
PF Proved Reserves (MMBoe) (1)
Credit Metrics
Net Debt / Adjusted EBITDAX 2.4x
Net Debt / Proved Reserves ($/Boe) $3.67
283.3
INCREASING HEDGE PROFILE
11
Crude Oil (Bbl, $/Bbl) 1Q’ 17 2Q’ 17 3Q’ 17 4Q’ 17 2017 2018
Three-Way Collars (1) 675,000 675,000 3,160,000
Ceiling
Floor
Short Put
$54.25
$45.00
$35.00
$54.25
$45.00
$35.00
$65.06
$50.00
$40.00
Costless Collars (1) 450,000 1,137,500 1,150,000 1,150,000 3,887,500
Ceiling
Floor
$59.75
$45.00
$60.05
$45.00
$60.05
$45.00
$60.05
$45.00
$60.02
$45.00
Deferred Premium Puts (1) 910,000 920,000 920,000 2,750,000
Floor
Deferred Premium (2)
$48.50
($4.00)
$48.50
($4.00)
$48.50
($4.00)
$48.50
($4.00)
Put Spreads (1) 675,000 675,000
Floor
Short Put
Premium
$45.00
$35.00
($2.32)
$45.00
$35.00
($2.32)
Total Hedge
Weighted Average Floor (3)
1,800,000
$44.13
2,047,500
$44.78
2,070,000
$44.78
2,070,000
$44.78
7,987,500
$44.63
3,160,000
$50.00
% Hedged on Midpoint Oil Volume Guidance(5) 55%
Mid-Cush Differential Swaps (6) 1,881,000 2,548,000 920,000 276,000 5,625,000
Weighted Average Swap ($0.14) ($0.11) ($0.38) ($0.50) ($0.18)
Natural Gas (MMBtu, $/MMBtu) 1Q’ 17 2Q’ 17 3Q’ 17 4Q’ 17 2017
Costless Collars (4) 1,955,000 2,366,000 2,422,000 2,545,000 9,288,000
Ceiling
Floor
$3.83
$3.00
$3.86
$3.00
$3.86
$3.00
$3.86
$3.00
$3.85
$3.00___________________________(1) The crude oil derivative contracts are settled based on the arithmetic average of the closing settlement price for the front month contract NYMEX price of West Texas Intermediate Light Sweet Crude.(2) The deferred premium is not paid until expiration date, aligning cash inflows and outflows with the settlement of the derivative contract.(3) Weighted average floor assumes the long put in three way collars and put spreads and reflects the impact of premiums paid.(4) The natural gas derivative contracts are settled based on the last trading day’s closing price for the front month contract relevant to each period.(5) Utilizing 2017 midpoint oil volume guidance.(6) The Mid-Cush oil derivative contracts are settled based on the arithmetic average of the Argus daily price for WTI Midland and the arithmetic average of the Argus daily price for WTI Formula Basis.
HEDGE CONTRACT DETAIL
RSP opportunistically layers on hedges to protect returns and support planned capital expenditures
FULL YEAR 2017 GUIDANCE
12
COMMENTARYFULL YEAR 2017 GUIDANCE SUMMARY
2017E CAPEX SUMMARY
61%
4%
30%
5% Midland D&C
Midland Infrastructure
Delaware D&C
Delaware Infrastructure
2017 Guidance Range
Production
Avg. Daily Production (Boe/d) 53,000 - 57,000
% Oil 71% - 73%
% Natural Gas 11% - 13%
% NGLs 15% - 17%
Income Statement ($/Boe)
LOE (incl. workovers) $4.50 - $5.50
Gathering & Transportation $1.10 - $1.40
Exploration Expenses $0.40 - $0.60
Cash G&A $1.25 - $1.75
Non-Cash G&A $0.70 - $0.90
DD&A $14.00 - $16.00
Prod. & Ad Val. (% Rev.) 6.0% - 8.0%
Capital Expenditures ($MM)
Drilling & Completion $575 - $625
Infrastructure & Other $50 - $75
Total Development Capital $625 - $700
Non-Operated (%) 5% - 10%
Operated Completions
Gross Hz 85 - 95
Operated WI 88%
Avg. LL (Midland / Delaware) 8,500’ / 6,250’
6 operated rigs currently (4 Midland, 2 Delaware)
Plan to exit year with 8 operated rigs
Capex budget range includes:
Latest estimate of well costs
Greater proportion of longer lateral wells in the Delaware
Reduction in average drilling days; more wells drilled &
completed (same rig cadence)
$35MM of infrastructure spend in Delaware
Upgraded tank batteries, salt water disposal wells, frac pits /
fresh water sourcing, power generation facilities, artificial lift
Excludes recent $18MM acquisition of Lone Wolf SWD business
RSP STRATEGY: RATE-OF-RETURN DRIVEN GROWTH
13
Emphasis on high rate of return vs. achieving growth objective
During 2015 – 2016 oil price downturn RSP slowed drilling and opportunistically made acquisitions
Operated rigs dropped from 5 in 1Q15 to 2 in 1Q16, acquired $3.0B in high return Hz inventory
3 57
12
21
29
53
57
'11 '12 '13 '14 '15 '16 '17E '18E '19E
ROBUST 3-YEAR PRODUCTION GROWTH (MBOE/D)
Prelim
2018-
2019E
2017E
Ramping to 8 Hz rigs from current count of 6
Production growth (82% – 95%) over 2016
Slight cash flow outspend at $55.00
Leverage <2.0x at $55.00
Plan to add 2 HZ rigs per year
30%+ production growth per year
Cash flow neutral at $55.00
Leverage <2.0x at $55.00
MIDLAND BASIN UPDATE
MIDLAND BASIN ACTIVITY UPDATE
15
MIDLAND BASIN ACTIVITY
Note: Results reflect aggregate production for 2-well pads.
6 7
1
4 5
2 38
9
# Well Name
Compl.
Date Formation
Lateral
Length
(Feet)
IP30
(BOED) % Oil
1 Mask 1004/5H 10/18/16 LS,WB 9,500 2,932 73%
2 Spanish Trail
341
12/9/16 WA,WB 6,500 2,910 80%
3 Spanish Trail
344
12/9/16 WA,WB 6,500 3,302 78%
4 Spanish Trail
228
8/25/16 LS,WA 6,500 2,907 80%
5 Spanish Trail
229
8/13/16 LS,WB 6,500 2,514 76%
6 Johnson
Ranch 1019
11/20/16 LS, LS 7,000 2,177 85%
7 Johnson
Ranch 1020
11/20/16 LS, LS 7,000 2,101 79%
8 Woody 3-46 1/25/17 WA, WB 7,500 2,436 86%
9 Calverley 9-4 1/10/17 WA, LWB 9,500 2,146 76%
10 Parks Bell 3923 2/15/17 LS, WA 7,000 2,243(1) 80%
WELL RESULT UPDATE (TWO-WELL PADS)
Strong well results confirming enhanced completion design and asset quality
(1) 7-day average, well still cleaning up.
10
Furthest West Wolfcamp Well
MIDLAND BASIN WELL PERFORMANCE
16
Substantial year over year well productivity
improvement since commencing horizontal drilling in
2012
2016 performance 13% above 2014 & 2015 avg.
despite shorter avg. lateral length
Updated type curves to reflect expected performance
from current generation well design
2017 Average Midland Basin Type Curve(1):
~8,500’ lateral length
1-year cuml: 205 MBoe
2-year cuml: 285 Mboe
0
50
100
150
200
250
300
0 90 180 270 360 450 540 630 720
Cum
l. M
Bo
e
Days
2012 & 2013 Avg. 2014 & 2015 Avg.
2016 Avg. 2017 Completions Weighted Avg
MIDLAND BASIN WELL PERFORMANCE BY VINTAGE
13%
54%
Avg. LL: 5,694’
Avg. LL: 7,089’
Avg. LL: 7,416’
LL: ~8,500’
Note: 2016 avg. LL
shorter than 2014 &
2015 avg. LL
(1) Represents average type curve of expected 2017 completions. Includes several Middle Spraberry wells and West Side wells which have more conservative type curves due to less data available
from recent completion designs.
(1)
SIGNIFICANT REDUCTION IN TIME TO WELL PAYOUT
17
At $55/bbl flat, and using conservative capex and well performance assumptions, 155MBo approximates well payout
To date, over 55% of wells completed in 2015 have reached payout in less than a year’s time
0
5
10
15
20
25
30
35
2013 2014 2015
Mo
nth
s
AVERAGE MONTHS TO PAYOUT (155MBO), BY YEAR DRILLED AREAS WITH 2015 WELLS THAT REACHED PAYOUT (155MBO)
MS
LS
WA
WB
Note: Stars represent areas (potentially more than 1 well) with 2015 wells
that have reached payout
MIDLAND BASIN TYPE CURVE INCREASES
18
RSP increased average type curve for aggregate Midland Basin position
Adjusted IP and initial decline / slope of RSP type curves to match early time outperformance
Type curves prepared by RSP third party engineers, Netherland Sewell & Associates, Inc.
Across the 45 type curves RSP carries internally, range increases on a Boe basis are as follows (vs. prior year levels):
1st Year Cuml: (0 – 60%) increase
2nd Year Cuml: (0 – 60%) increase
EUR: (0 – 35%) increase
Early production is the most important driver of a well’s value (NPV / IRR); EURs are less impactful to well value and rate of return
Certain areas and zones had more dramatic increases than the average
RSP YOY TYPE CURVE INCREASES – BY AREA, ZONE AND LATERAL LENGTH (BOE BASIS)
0%
10%
20%
30%
40%
50%
60%
70%1st Year Cuml Change
2nd Year Cuml Change
EUR Change
MIDLAND BASIN WELL COST UPDATE
19
HISTORICAL WELL COST PER LATERAL FOOT (OP. WELLS)(1)CURRENT MIDLAND DC&E COST (8,500’ LATERAL)
44%
47%
9%
Drilling Completion Equipping
$1,232
$1,086
$933
$828$775
$741 $760$715 $709
$0
$250
$500
$750
$1,000
$1,250
$1,500
4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16
Drill Complete & Equip
Current DC&E: $6.2MM
Increased R&D Spending
(1) Includes wells with lateral lengths of 7,000 – 8,000’.
MIDLAND BASIN INVENTORY
20
CURRENT SPACING ASSUMPTIONS
Base Spacing Upside Spacing
Formation Avg. Wells/Section Wells/Section
Clearfork 5 6 – 7
Middle Spraberry 11 14 – 16
Jo Mill 5 6 – 7
Lower Spraberry 11 14 – 20
Wolfcamp A 6 7 – 10
Wolfcamp B 6 7 – 9
Wolfcamp C 5 6 – 7
Wolfcamp D 5 6 – 7
BASE SPACING LOCATIONS UPSIDE SPACING LOCATIONS
2,700 Gross Locations
1,750 Net Locations
3,550 – 4,540 Gross Locations
2,260 – 2,890 Net Locations
Numerous spacing pilots ongoing
Base Spacing assumptions updated
Optimal well placement will evolve with more data
Spacing assumptions vary by area and formation
Increased well density as much as 20% over YE 2015 levels
in select areas based on performance to date
Remain conservative but optimistic across other areas where
Base Spacing maintained
Clear Fork4%
Middle Spraberry
22%
Jo Mill10%
Lower Spraberry
30%
Wolfcamp A11%
Wolfcamp B11%
Wolfcamp D11%
Clear Fork5%
Middle Spraberry
24%
Jo Mill11%
Lower Spraberry
25%
Wolfcamp A12%
Wolfcamp B11%
Wolfcamp D12%
DELAWARE BASIN UPDATE
DELAWARE BASIN INITIATIVES
Initiating acreage trades with offset operators to enhance operations and drill longer laterals
Recently completed trade increased lateral length of 4 drilling units in Loving County from 5,000’ to 7,500’
22
Blocking Up Acreage Position
Acquired Water Disposal Operations and Infrastructure
At the time of acquisition, SWD facilities maxed out
Silver Hill trucking ~15,000 Bbls water/day to 3rd party facilities
Acquired Lone Wolf SWD wells and related infrastructure system in 1Q17
Expansion of existing facilities in progress
All water disposal on pipe and disposed in company-owned facilities within two quarters
Upgrading Field Power
Switching field power from diesel fired generators to raw field natural gas fired generators, reducing operating costs
Longer-term, working to build-out electrical grid
Enhancing Natural Gas Gathering Infrastructure
System currently being upgraded to handle additional natural gas volumes
Midstream provider (Outrigger) to be acquired by Targa
Initiating Workovers on Existing Producers
Majority of producing horizontal wells still flowing naturally (many over 1-year old)
Installing production tubing and ESPs to enhance existing production
Early results above expectations with significant uplift above prior rates
Acquiring 3-D Seismic over Delaware Position
Purchased 2 recent seismic surveys covering western 2/3rds of acreage position; shooting 3-D seismic over eastern 1/3rd of block
Will enhance capability to select optimum landing targets and drill longer laterals
# Well Name Zone
Total
Prod.
Days
Lateral
Length
(Feet) Action
Previous
Rate
(BOED)
Post
Change
(BOED) % Oil
Cuml
Prod
(MBOE)
12 Brunson 1111H Avalon 206 8,000ESP
Install460 1,035 68% 126
13 Ludeman 505H2nd
Bone174 4,400
ESP
Install337 1,033 71% 87
14Hughes Talbot
75 22 1HLWA 234 4,100 Tube Up 283 445 76% 99
DELAWARE BASIN ACTIVITY UDPATE
23
DELAWARE BASIN ACTIVITY
Recent Well Results
RSP Prod. Enhancements
LWA WC XY WB 2nd Bone Avalon
1
5
8
6
7
2
3
4
9
12
13
14
(1) Pistol 25 8 2H well IP rate represents 14-day average.
(2) Italics indicates non-operated well. Totum well IP rate represents 24-hour average.
(3) Offset operator wells, IP rates represent 24-hour average.
ROBUST RESULTS DESPITE SHORT LATERALS & RESTRICTIVE CHOKES
INITIAL WORKOVERS PROVIDING SUBSTANTIAL UPLIFT
# Well Name Zone
Total
Prod.
Days
Lateral
Length
(Feet)
IP 30
(BOED) % Oil
IP Choke
Size
IP
FTP
(PSI)
Cuml
Prod
(MBOE)
1 Pistol 25 8 2H(1) Avalon 40 4,500 827 67% 48/64 415 14
2 Pistol 24 20 1H LWA 640 4,200 1,006 75% 16/64 2,550 266
3Corsair C26 20
1H(2)LWA 210 4,100 1,787 70% 31/64 915 191
4State Rudd Draw
26 25 1HWC XY 101 4,100 1,086 73% 21/64 2,600 89
5 Ludeman 1302H LWA 139 6,500 1,111 71% 22/64 2,950 129
6 Bullet 27 11 2H WC B 153 4,400 898 69% 22/64 1,400 90
7Hughes Talbot
75 24 2H(2)LWA 334 4,600 1,545 78% 31/64 2,168 189
8 Totum #211H(2) LWA 22 4,400 2,247 72% 22/64 3,400 34
9Rudd Draw 75
10 2HWC XY 246 4,600 804 72% 21/64 2,820 153
Recent Offset Operator Wells
10 Bison #1H(3) WC B 64 6,897 2,375 NA NA 1,800 NA
11 Grizzly #1H(3) WC B 43 4,103 1,666 NA NA 1,850 NA
Substantial stacked resource potential with 7 currently producing zones and strong recent results across 5 highlighted below
10
11
DELAWARE BASIN WORKOVER CASE STUDY
24
PRODUCTION UPLIFT FROM RECENT WORKOVERS
RSP recently directed workovers of several wells with excellent results
Wells have been online ~170 – 200 days total and current rates are substantially above IPs
Installed ESP in Brunson 1111H 8,000’ Avalon well on January 20th
Installed ESP in Ludeman 505H 4,400’ 2nd Bone Spring well on February 5th
Additional workovers ongoing
200
2,000
20 40 60 80 100 120 140 160 180
Boe
/d
Days
Brunson 1111H (Avalon) Ludeman 505H (2nd BS)
ESP Install
Substantial year over year well productivity improvement
on the Silver Hill properties
Improvements in drilling and completion techniques
Switch in primary drilling target to Wolfcamp
Recent LWA (Corsair C26 20 1H), Silver Hill non-
operated well plotted at right is flowing on a more
conventional 31/64 choke setting (FTP of 915 PSI) as
compared to recent operated Silver Hill wells flowing on
~20/64 choke (FTP’s range from ~2,200 to 3,000 PSI)(1)
~4,100’ lateral length
180-day cuml: 182 MBoe
Est. 1-year cuml: 315 MBoe
Est. 2-year cuml: 425 MBoe
DELAWARE BASIN WELL PERFORMANCE
25
0
50
100
150
200
250
300
0 90 180 270 360 450 540 630 720
Cu
ml. M
Bo
e
Days
2015 2016 Corsair C26 20 1H
DELAWARE BASIN WELL PERFORMANCE BY VINTAGE
Corsair C26 20 1H 22%
(1) Wolfcamp A wells.
RSP PERMIAN INVESTMENT HIGHLIGHTS
26
Prime Permian Position
Strong Growth Profile
Focus on Capital Efficiency
Superior Execution
Technical Leader
Oil-Weighted Production and Reserve Base
Experienced Permian Team
DELIVERING VALUE
27
HIGH QUALITY
ASSETS
FOCUS ON RETURNS
& EXECUTION
STRONG FINANCIAL
POSITION
EXPERIENCED
MANAGEMENT
APPENDIX
2016 ACHIEVEMENTS
Entry into Delaware Basin with $2.4B acquisition of Silver Hill Energy Partners(1)
Blocked up core Midland leasehold position with $69MM in acquisitions
Increased drilling inventory by 127% from 2,600 gross locations at YE15 to 5,900 gross locations(2) at YE16
29
(1) First part of Silver Hill acquisition (SHEP I) closed 11/28/16; second part (SHEP II) closed on 03/01/17.
(2) Pro forma for SHEP I and SHEP II.
(3) Reserve report prepared by Netherland Sewell & Associates, Inc.
(4) Includes non-price related revisions, excludes price related revisions, excludes impact of removing remaining vertical PUDs from reserve base.
(5) Pro forma for SHEP I and SHEP II, leverage based on 4Q16 annualized EBITDA and net debt outstanding as of 12/31/16.
Expanded Core Permian Position
Focused on Returns-Driven Growth
Increased average production 39% from 21.0 MBoe/d in 2015 to 29.2 MBoe/d in 2016
Strong growth despite moderating operated rig pace
FY 2016 development capex of $294MM, slightly below the revised budget of $295-$315MM
Increased proved reserves by 78% from 159 MMBoe at YE15 to 283 MMBoe(2)(3) at YE16
Continued to Achieve Low Cost Operations and Efficiency Gains
Decreased cash operating expenses 23% to $9.11/Boe in 4Q16 from 2015 average of $11.85/Boe
Achieved low drill-bit finding and development cost of $4.05/Boe(4)
Maintained Financial Strength
Strong balance sheet and liquidity position with 2.4x leverage, $109MM of cash and no borrowings on our
revolving credit facility which has a $1.1 billion borrowing base and a $900MM company elected commitment(5)
Expanded oil hedge profile, covering 55% of expected 2017 oil production, entered into basis swaps to protect
mid-cush differential, and began layering in 2018 oil hedges
4Q16 AND FY16 DRILLING & COMPLETION ACTIVITY OVERVIEW
30
During 2016, RSP drilled 46 and completed 53 operated
HZ wells
During 4Q16, RSP drilled 13 and completed 14 operated
HZ wells
2 drilled and 1 completed (Avalon) in the Delaware Basin in
4Q16, post close of SHEP I(1)
FY16 / 4Q16 Midland Basin completions:
35 / 7 in the Lower Spraberry
8 / 3 in the Wolfcamp A
8 / 3 in the Wolfcamp B
1 / 0 in the Middle Spraberry
MIDLAND OPERATED HZ D&C SUMMARYACTIVITY OVERVIEW
18
1310 10 11 11 11
17
1310
2015YE
1Q16 2Q16 3Q16 4Q16 1Q16 2Q16 3Q16 4Q16 2016YE
DUCs Drill Complete DUCs
PROGRESSION OF 2016 NET PRODUCTION (WEEKLY BASIS)
0
5
10
15
20
25
30
35
40
45
1/16 2/16 3/16 4/16 5/16 6/16 7/16 8/16 9/16 10/16 11/16 12/16
MB
oe
/d
Note: Excludes Delaware
DRILLING & COMPLETION ACTIVITY
Drilled Completed Drilled Completed
Operated
Horizontal 46 53 13 14
Vertical 4 6 - 2
Total 50 59 13 16
Non-Operated
Horizontal 35 37 6 13
Vertical 1 1 - -
FY16 4Q16
44 52
(1) First part of Silver Hill acquisition (SHEP I) closed 11/28/16 and activity only includes D&C on acquired properties from closing date. Second part of Silver Hill (SHEP II) closed on 3/1/17.
2Q16
26.4 Boe/d3Q16
29.8 Boe/d
4Q16
35.8 Boe/d1Q16
24.6 Boe/d
4Q16 4Q15 FY ’ 16 FY ’ 15 4Q16 4Q15 FY ’ 16 FY ’ 15
Avg. Daily Production Cash Op. Exp. ($/Boe)
Oil (MBbl/d) 25.4 18.3 21.3 15.9 LOE $4.41 $4.76 $4.93 $6.46
Gas (MMcf/d) 24.8 16.9 19.6 13.7 G&T 0.57 0.42 0.48 0.46
NGL (MBbl/d) 6.3 3.1 4.6 2.9 Prod. Taxes 2.01 2.56 2.03 2.60
Total (MBoe/d) 35.8 24.3 29.2 21.0 Cash G&A 2.11 2.24 2.10 2.33
Total Cash Expenses $9.11 $9.98 $9.54 $11.85
Pricing Non-Cash/Other Exp. ($/Boe)
Average NYMEX Oil ($/Bbl) $49.29 $42.18 $43.32 $48.80 Recurring Stock Comp $0.98 $0.93 $1.23 $1.03
Realized Price (Incl. Hedges) Non-recurring Stock Comp - 0.15 0.06 0.19
Oil ($/Bbl) 46.20 53.74 41.06 61.22 DD&A 15.94 17.88 18.21 20.05
Gas ($/Mcf) 2.24 1.91 1.94 2.11 Exploration 0.08 0.04 0.10 0.31
NGL ($/Bbl) 12.94 11.13 10.87 9.75
Total ($/Boe) $36.60 $43.31 $32.99 $48.96
Financial Results ($MM) Capital Expenditures ($MM)
Adj. EBITDAX $90.5 $74.4 $250.3 $285.1 D&C $88.1 $54.8 $275.5 $354.0
Adj. Net Income (Loss) $13.4 $12.1 ($7.4) $48.6 Infrastructure 7.4 9.4 18.7 37.0
Total Development Capex $95.5 $64.1 $294.2 $391.0
4Q16 AND FY16 FINANCIAL RESULTS
31
Production growth and cost structure improvements helped support cash flow during oil price downturn
~40% production growth YOY with 25% less development capex
4Q16 development capex ~50% above 4Q15, building momentum into 2017
EXECUTING BOLT-ON ACQUISITIONS IN CORE MIDLAND
32
During 2016, RSP acquired ~$69 million of bolt-on oil and gas properties:
~2,800 net acres located in core Midland, Martin, and Glasscock Counties
~$7 million of acquisitions in 4Q16
LOCATOR MAP OF 2016 ACQUISITIONS
RSP Existing Acreage
New Acreage Acquired
Additional Interest Acq.
0
100
200
300
400
500
600
700
800
0 5 10 15 20 25 30
Cum
lM
Bo
Years
b=1.8
b=1.7
b=1.6
b=1.5
b=1.4
b=1.3-$8
-$6
-$4
-$2
$0
$2
$4
$6
$8
0
100
200
300
400
500
600
700
0 10 20 30 40 50
Net P
resent V
alu
e ($
MM
)
Cum
lM
Bo
Years
Well 1 Cuml Oil
Well 2 Cuml Oil
Well 1 NPV
Well 2 NPV
EARLY PRODUCTION HAS GREATEST INFLUENCE ON WELL VALUE
33
A well’s value is determined relatively early in its life
~85% of a well’s NPV is achieved in first ~10 years
Despite a 10% uplift in EUR from a 33% reduction in terminal
decline, the NPV of Well #2 is less than 2% greater than Well #1
ILLUSTRATION: TERMINAL DECLINE IMPACT ON EUR / NPV
Illustration: EUR/NPV Sensitivity to Terminal Decline
Terminal Decline EUR (MBoe) NPV 10% ($M)
Well #1 6% 827 $6,980
Well #2 4% 920 $7,103
ILLUSTRATION: B-FACTOR IMPACT ON EUR
Changing assumed B-factor results in materially different EURs
In illustration above, production profiles in the first few years are
nearly identical while outer years vary more dramatically
15%
VALUE
85%
VALUE
15%
VALUE
85%
VALUE
RSP Avg.
B-Factor
35%
diff
RSP PERMIAN 3RD PARTY 1MMBOE EUR WELLS
34
AREAS WITH 3RD PARTY PROJECTED EUR OVER 1MMBOEStars represent areas where
Netherland Sewell & Associates, Inc.
projected at least one producing well
to have an EUR over 1MMBOE
All four primary targets in the Midland
Basin have 1MMBoe wells
To date, two target intervals in
Delaware Basin have 1MMBoe wells
despite majority of wells with lateral
lengths under 5,000’
MS
LS
WA
WB
WC XY
LWA
MIDLAND BASIN
DELAWARE BASIN
Stars represent areas (potentially more than 1 well) with EURs >1MMBoe
JOHNSON RANCH LOWER SPRABERRY DOWNSPACING PILOT
35
JOHNSON RANCH SPACING PILOT CUMULATIVE AVERAGE PRODUCTION PLOT
0
20
40
60
80
100
120
140
160
0 50 100 150 200 250
Cum
lM
Boe
Days
1st 4 Well Pad
2nd 4 Well Pad
In 4Q16, RSP completed 4 additional LS wells in the Johnson Ranch spacing pilot with the latest generation frac design
Of the 4 new wells, 1 was drilled at an equivalent of 10 wells/section and 3 initiated the equivalent of a 14 well/section pattern
Average of the new 4 wells compares favorably to the previous 4 wells in the section
Plan to drill final 4 wells in the pattern at an equivalent of 14 wells per section during 2H17
More conclusive production results not expected until the remaining four wells have been producing for 6 months to a year (late 2018)
Producing Well
DELAWARE CRUDE OIL GATHERING AND TRANSPORTATION OVERVIEW
36
DELAWARE CRUDE OIL INFRASTRUCTURECrude oil gathering provided by
Outrigger (Targa)
Targa (NYSE: TRGP), one of the
largest midstream providers in
North America, acquiring Outrigger
Volumes transported to Wink with
multiple basin outlets
Average oil price realization is ~$0.40
lower than Midland properties, under
existing arrangements
Significant crude oil gathering and
transportation optionality with
multiple inter/intrastate pipelines
proximate to RSP acreage position
DELAWARE GAS GATHERING AND TRANSPORTATION OVERVIEW
37
DELAWARE GAS GATHERING SYSTEMGas gathering provided by Outrigger
(Targa)
Processing provided by Outrigger
(Targa) and Energy Transfer
70 MMcf/d cryogenic processing plant
on acreage position
Expandable to accommodate expected
growth
Gathering system
Loving Gas Plant
Diamondhead
Compressor
DELAWARE WATER INFRASTRUCTURE OVERVIEW
38
DELAWARE WATER DISPOSAL SYSTEMRecently acquired water gathering and
disposal infrastructure assets that
serviced Silver Hill
Post acquisition RSP controls:
4 operated SWD wells
Each well disposes 15-20,000
bbls/day
Right to drill 5 additional SWD wells
3 permitted/permitting
~100-mile network of water gathering
pipelines
Significant exclusive surface-use
agreements
All disposed water in RSP-owned
disposal wells within 6 months
Ample water supply available to support
planned drilling
Gathering system
SWD well
Planned SWD
Potential SWD
ADJUSTED EBITDAX AND ADJUSTED NET INCOME RECONCILIATION
39
Reconciliation of Net Income (Loss) to Adjusted EBITDAX
(in thousands)
Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss)
(in thousands)
-
6,374 -
- 306
(14,659) (38,434)
(7,358)$ 48,630$
6,374 -
- -
682 -
(1,833) (469)
(24,851)$ (18,254)$
4,901 34,269
22,028 71,212
Twelve Months Ended December 31,
2016 2015
- 306
285,058$ 250,326$
(1,732) 92,118
13,764 9,384
472 336
(20,906)
52,724 43,538
(18,706) (11,683)
194,360 154,039
(1,833) (469)
23,122
2,409
1,381$
13,683
265
(10,307)(1,464)
Twelve Months Ended December 31,
2016 2015
(24,851)$ (18,254)$ (20,751)$
13,175
2015
4,901 34,269
1,093 2,380
6,374 -
23,760
Loss (gain) on asset sale 302
(1,246)
52,484
579
17,538
6,374
(2,398)
3,215
Acquisition Costs
39,887
30,031
(3,439)
(242)
118 84Asset Retirement Accretion
Other income, net
Net Cash Payments on Settled Derivative Instruments
Exploration Expense
Loss (Gain) on Derivative Instruments
Non-Cash Equity Based Compensation
96
-
- -
(1,246) (242)
15,140 19,683
- -
Stock-based compensation - non-recurring
Other income, net
Income tax expense (benefit) for above items (8,833) (16,949)
Acquisition Costs
Adjusted Net Income (Loss) 13,395$ 12,074$
302
Net income (loss) 1,381$ (20,751)$
Impairments 579 30,031
Net cash payments on settled derivative instruments
2016 2015
Three Months Ended December 31,
2016
Loss (gain) on derivative instruments
Interest Expense
Income Tax Expense (Benefit)
DD&A
Impairments
Net Income (Loss)
Three Months Ended December 31,
-
Adjusted EBITDAX 74,367$
Loss (gain) on Sale of Assets
90,529$
ADDITIONAL DISCLOSURES
40
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.
