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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


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)


OXY

“Curtis Ranch So 3521H” (Lower Spraberry)


“Curtis Ranch 3519H” (Wolfcamp A)


“Curtis Ranch So 3517H” (Wolfcamp B)


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)


“Gridiron So 17LS” (Lower Spraberry)


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


“Isbell HU 106 MS” (Middle Spraberry)

IP 30: 674 Boe/d


“Isbell HU 107WA” (Wolfcamp A)

IP 30: 803 Boe/d


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)


Diamondback

“Mabee BL 2301LS” (Lower Spraberry)


“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)


ENERGEN

“Holton 101H” (Wolfcamp A)


“Holton #210H” (Wolfcamp B)


“Holton #401H” (Cline)


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)



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)


64%

Glasscock22%

Ector14%


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


___________________________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


77%

Glasscock5%

Ector18%


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


___________________________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



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



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.


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


$350-400mm Capex


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.

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