GOLDMAN SACHS GLOBAL ENERGY CONFERENCE 2018

January 9, 2018

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 for RSP’s operating activities, access to and availability of transportation, processing and refining facilities, the financial strength of counterparties to 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 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.

RSP PERMIAN OVERVIEW

~92,000 net acres across highly contiguous acreage

blocks in the core of the Midland and Delaware Basins

~6,000 net royalty acres in the Delaware Basin(1)

4,200+ net horizontal locations in drilling inventory

Current production of 65 MBoe/d(2)

Expect 2017 YoY production growth of 89% at mid-

point of guidance

Organizational focus on returns, efficiency and execution

Leading drill-bit F&D costs, reserve replacement

ratios and cash operating margins

Positive adj. net income at sub-$50 oil prices

3

CONTIGUOUS ACREAGE POSITION IN CORE OF PERMIAN BASIN(1)RSP OVERVIEW

(1) Net royalty acre defined as one surface acre leased at a 1/8th royalty.

(2) As of November 3, 2017.

(3) Based on Annualized 3Q17 Adjusted EBITDAX.

(4) Midland Basin locations based on range of base to upside case well spacing.

(5) As of 1/1/17, pro forma Silver Hill closing on 3/1/17.

Net

Acres

Net

Locations(4)

Proved

Reserves

(MMBoe)(5)

Resource

Potential

(BBoe)

Midland 46,700 1,750 - 2,890 200 1.0 - 1.6

Delaware 45,600 2,410 80 1.8

Total 92,300 4,200 - 5,300 280 2.8 - 3.4

Key Statistics (as of 9/30/17)

NYSE Symbol RSPP

Shares Outstanding 158.6 MM

Market Capitalization (share price as of 1/4/18)

$6.5 B

Enterprise Value $8.0 B

Net Debt / Adj. EBITDAX(3) 2.5x

CORPORATE UPDATE

RSP BUILDING SHAREHOLDER VALUE THROUGH THE CYCLES

5

HORIZONTAL INVENTORY EXPANSION SINCE IPO (GROSS LOCATIONS)

GROWTH IN SHAREHOLDER VALUE SINCE IPO

Production

(MBoe/d)

Quarterly

Annualized

EBITDAX

HZ Drilling

Locations

(Base Spacing)

Proved Reserves

(MMBoe)

Net Surface

Acreage

Enterprise Value

($ Billions)

Market Cap

($ Billions)

8.2

$194.8 (2)

1,169

52.2

~34,000

$1.4

$1.4

IPO

(Jan 2014)

58.9

$578.6

5,930 (3)

283.3 (3)

~92,300

$8.0 (4)

$6.5 (4)

Current (1)

(1) As of 3Q17, except where otherwise noted.

(2) 1Q14 annualized EBITDAX.

(3) As of YE 2016, pro forma for Silver Hill acquisition.

(4) Share price as of 1/4/18.

$0

$20

$40

$60

$80

$100

$120

$0

$10

$20

$30

$40

$50

Jan 14 Jan 15 Jan 16 Jan 17 Jan 18

Oil P

rice

RS

PP

Sto

ck P

rice

RSPP WTI Oil

-35%

+111%

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

IPO YE 2014 YE 2015 YE 2016

Silver Hill Acquisition

PEER-LEADING PROFITABILITY

6

High quality assets + low cost operations = excellent corporate returns & profitability

Durability in periods of commodity price lows as well as significant leverage to commodity price upside

3Q17 OPERATING PROFIT PER BARREL (DEFINED BELOW)

$(15.00)

$(10.00)

$(5.00)

$-

$5.00

$10.00

$15.00

$20.00

$25.00Note: Average WTI crude oil price of $48.20 for 3Q17

Unhedged Revenue2-YR AVG.

PDP F&D (1) Operating Costs G&AOperating Profit

Better, more comparable

metric than DD&A which is

influenced by accounting

methodology and

write-downs

LOE

Production Taxes

Cash G&A

Non-Cash G&A

Source: Public filings.

Peer companies include: APA, APC, CDEV, CLR, CPE, CXO, DVN, EGN, EOG, FANG, HES, JAG, LPI, MRO, MTDR, MUR, NBL, NFX, OAS, PDCE, PE, PXD, WPX, XEC, XOG.

(1) 2015 and 2016 average PDP F&D Cost per Boe, as calculated by Seaport Global Securities.

TRACK RECORD OF DELIVERING SUPERIOR DEBT-ADJUSTED GROWTH

7

PRODUCTION GROWTH PER DEBT-ADJUSTED SHARE

Rank #2 amongst Permian-focused peer group for production growth per DAS from 2Q14 (PE IPO) to 3Q17

Source: Public filings.

Note: Peers include Callon, Cimarex, Concho, Diamondback, Energen, EOG, Laredo, Parsley, and Pioneer. Indexed to Q2 2014 (Parsley IPO).

207%

238%

161%

135% 140%

104%

129% 135%

109%

95%

0%

50%

100%

150%

200%

250%

Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017

RSPP Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9

CAPITALIZATION AND LIQUIDITY SUMMARY

8

CAPITALIZATION TABLERecently increased borrowing base to $1.5 B from $1.1 B,

reiterating $900 MM Company-elected commitment under the

amended and restated credit facility ($2.5 B maximum lender

commitments)

Key financial covenants:

Maximum of 4.25x Total Debt / TTM EBITDAX

Minimum current ratio of 1.0x

Next redetermination April 2018

DEBT MATURITIES ($MM)

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2017 2018 2019 2020 2021 2022 2023 2024 2025

9/30/17 Balance Elected Commitment Borrowing Base Senior Notes

6.625%

5.25%

Elected Commitment

Borrowing Base

9/30/17 Balance

($ in millions) 9/30/2017

Cash $46

Revolving Credit Facility $345

6.625% Senior Unsecured Notes Due 2022 700

5.25% Senior Unsecured Notes Due 2025 450

Total Debt $1,495

Net Debt $1,449

Liquidity

Elected Commitment $900

Less: Borrowings & LCs (345)

Plus: Cash 46

Liquidity $601

Financial & Operating Statistics

Annualized 3Q17 Adjusted EBITDAX $578.6

3Q17 Avg. Daily Production (MBoe/d) 58.9

Credit Metrics

Net Debt / Adjusted EBITDAX 2.5x

Net Debt / Daily Production ($/Boe/d) $24,580

FULL YEAR 2017 GUIDANCE

9

COMMENTARYFULL YEAR 2017 GUIDANCE SUMMARY

2017E CAPEX SUMMARY

62%

4%

29%

5%

Midland D&C

Midland Infrastructure

Delaware D&C

Delaware Infrastructure

3Q17 YTD

Actuals2017 Guidance Range

Production

Avg. Daily Production (Boe/d) 52,864 53,000 - 57,000

% Oil 72% 71% - 73%

% Natural Gas 12% 11% - 13%

% NGLs 16% 15% - 17%

Income Statement ($/Boe)

LOE (incl. workovers) $5.09 $4.50 - $5.50

Gathering & Transportation $0.99 $1.10 - $1.40

Exploration Expenses $0.48 $0.40 - $0.60

Cash G&A $1.62 $1.25 - $1.75

Non-Cash G&A $0.88 $0.70 - $0.90

DD&A $14.03 $14.00 - $16.00

Prod. & Ad Val. (% Rev.) 5.9% 6.0% - 8.0%

Capital Expenditures ($MM)

Drilling & Completion $448.1 $575 - $625

Infrastructure & Other $38.7 $50 - $75

Total Development Capital $486.8 $625 - $700

Non-Operated (%) 10% 8% - 12%

Operated Completions

Gross Hz 54 70 - 74

Operated WI 91% 92%

Avg. LL (Midland / Delaware) 8,300’ / 5,600’ 8,500’ / 6,250’

Reiterated full year 2017 guidance ranges for production, unit

costs and capex

Revised completion guidance to 70-74 gross operated

horizontal completions, as compared to previous guidance of

80-85

Originally budgeted to run 3 frac crews for a portion of 2H17, instead elected to run 2 crews

Revised average operated working interest to 92% from 88%

Currently running 7 operated rigs (4 Midland, 3 Delaware)

Currently running 2 completion crews

RSP STRATEGY: RATE-OF-RETURN DRIVEN GROWTH

10

Emphasis on high rate of return, rather than growth for growth’s sake

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

ROBUST PRODUCTION GROWTH (MBOE/D)

Prelim

2018E

2017E

Increased to 7 Hz rigs from 6, averaged 2 full-time frac crews

Production growth (82% – 95%) over 2016

Slight cash flow outspend

Leverage ~2.5x(1)

Assuming $50+ oil price

Plan to add 1 completion crew and likely 1 Hz rig next year

30%+ production growth

Operating Cash Flow > Capex by YE 2018 at $50+

Leverage ~2.0x(1) by YE 2018 at $50+

(1) Leverage calculated as Total Debt / LQA EBITDAX.

SERVICES, SAND & WATER NEEDS SECURED THROUGH 2018+

11

Services

2018 pricing agreement in place with Halliburton for 2 dedicated frac crews

Entered into contract for 3rd full-time frac crew, to arrive mid-2Q18

Crews are flexible to move between basins

Currently evaluating addition of 8th drilling rig, foresee no issue procuring a high spec rig with a couple of

months notice

Sand

12-month contract secures sand required to execute 2018 development program

Expect to pump 75-100% regional sand from 2Q18 through end of year

Diversified exposure to multiple local mines, logistics/last mile delivery handled by third party

Significant cost savings vs. northern white sand

Water

Currently building out Delaware Basin fresh water sourcing system, which will pipe fresh water from

adjacent aquifer directly to RSP well sites, expect in-service in 2H18

All produced water in the Delaware Basin currently on pipe to company-owned disposal wells, sufficient

capacity to accommodate 2018 drilling program and beyond

ACTIVELY BUILDING HEDGE POSITION INTO 2018 AND 2019

12

Crude Oil (Bbl, $/Bbl) 1Q18 2Q18 3Q18 4Q18 2018 1Q19 2Q19 3Q19 4Q19 2019

Three-Way Collars (1) 2,219,000 1,941,000 1,319,000 1,227,000 6,706,000

Ceiling

Floor

Short Put

$58.81

$46.96

$36.96

$59.07

$47.11

$37.11

$60.56

$47.79

$37.79

$60.96

$48.00

$38.00

$59.62

$47.36

$37.36

Costless Collars (1) 571,000 516,000 1,212,000 1,058,000 3,357,000 315,000 318,500 322,000 322,000 1,227,500

Ceiling

Floor

$60.19

$45.00

$60.20

$45.00

$60.10

$46.33

$60.11

$46.52

$60.13

$45.96

$55.99

$50.00

$55.99

$50.00

$55.99

$50.00

$55.99

$50.00

$55.99

$50.00

Swaps (1) 322,000 322,000 644,000 315,000 318,500 322,000 322,000 1,277,500

Swap Price $55.77 $55.77 $55.77 $53.42 $53.42 $53.42 $53.42 $53.42

Total Hedge

Weighted Average Floor (2)

2,790,000

$46.56

2,457,000

$46.67

2,853,000

$48.07

2,607,000

$48.36

10,707,000

$47.42

630,000

$51.71

637,000

$51.71

644,000

$51.71

644,000

$51.71

2,555,000

$51.71

Mid-Cush Differential Swaps (3) 1,918,000 2,002,000 2,024,000 2,024,000 7,968,000 270,000 273,000 276,000 276,000 1,095,000

Weighted Average Swap ($0.58) ($0.57) ($0.57) ($0.57) ($0.57) ($0.27) ($0.27) ($0.27) ($0.27) ($0.27)

___________________________(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 during the relevant period.(2) Weighted average floor assumes the long put in three way collars and reflects the impact of premiums paid.(3) 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 continuing to protect > $45 floor into 2018 & 2019

RSP OWNERSHIP UPDATE

13

Management and Board hold ~14% of outstanding

shares (>$750 MM of value) compared to <5% average

insider ownership of E&P SMID-Caps

Management compensation is heavily weighted (>2/3rds)

towards stock, further aligning objectives

½ of stock awards are performance shares earned based

on relative total shareholder return

Cash bonus amounts are tied to metrics that measure

overall financial performance of the Company, not

absolute growth metrics, M&A success etc.

(1) As of form 13-G filed on 10/2/17.

Upon closing of the Silver Hill transaction, Silver Hill owners

received 31 MM shares of RSP stock, subject to certain

escrow holdbacks

Kayne Anderson, Silver Hill’s largest shareholder, became

RSP’s largest shareholder

Through a block trade executed in May 2017 and

subsequent open market sales and distributions, Kayne

Anderson’s beneficial ownership has dropped from 18%

to ~1% of outstanding shares(1)

Cash Bonus Metrics

2016 2017

LOE / Boe LOE / Boe

Cash G&A / Boe Cash G&A / Boe

F&D Cost / Boe F&D Cost / Boe

Leverage Multiple Capex / Production Added

Recycle Ratio Production per Debt-Adjusted

Share Growth

RSP MANAGEMENT AND BOARD ARE STRONGLY ALIGNED WITH SHAREHOLDERS

KAYNE ANDERSON AND OTHER SILVER HILL SHAREHOLDERS’ OWNERSHIP IN RSP HAS BEEN DRAMATICALLY REDUCED

OPERATIONS UPDATE

DRILLING & COMPLETIONS UPDATE

15

During 3Q17, RSP drilled 26 and completed 22

operated HZ wells

18 Midland, 4 Delaware completions

Expect to drill 26-28 and complete 16-20 in

4Q17

26 operated DUCs as of 9/30/17, estimate 32-

38 as of YE 2017

2017 OPERATED DRILLING & COMPLETION ACTIVITY

2017 PLANNED COMPLETION ACTIVITY BY HORIZON

WA

WBLS

MS

WA

WXYWB

BSMidland

Delaware

11

69

26

54

16

32

28

20

38

YE 2016ADUCs

YTD 4Q YTD 4Q YE 2017EDUCsDrilling Completions

PRODUCTION PROFILE

28

33

38

43

48

53

58

63

68

MB

oe/d

MBoe/d Q1 Q2 Q3 Current

Avg. Daily Production 45.2 54.3 58.9 ~65

Closing of

SHEP II

transaction

MIDLAND BASIN WELL PERFORMANCE IMPROVEMENT

MIDLAND BASIN WELL PERFORMANCE BY VINTAGE

2017 wells drilled (through October) outperforming 2014 / 2015 / 2016 vintage wells

16

0

30

60

90

120

150

180

210

0 30 60 90 120 150 180 210 240 270 300 330 360

Cum

l. M

Boe

Days

2014 & 2015 Avg. 2016 Avg. 2017 Avg.

Avg. LL: 7,400’

Avg. LL: 7,100’

Avg. LL: 8,300’

0

100

200

300

400

500

600

700

2014 2015 2016 2017

AVG. WELL SPACING (FEET) @ FIRST PRODUCTION

Avg. distance

decreased >28%

Note: Includes all zones.

MIDLAND BASIN UPDATE

17

With addition of 2nd Halliburton frac crew in 3Q17, able to

simultaneously frac 2, 2-well pads

Reduced downtime for offset producers

Increased complexity/efficiency of stimulations

Completed several wells in 3Q17 with higher percentage of

100 mesh sand

Early results are outstanding (ST 347 WA wells, Woody 3-

46 WB well, Keystone WA and LS wells)

Keystone West Side area wells continue to impress

Average cumulative production for 3 well pad is ~100

MBoe in less than 90 days (WA well produced 125 MBoe in

same time period)

Next two wells in Spanish Trail WA pattern with 8 wells drilled

across the section have average cumulative production of 100

MBoe in 75 days (100% 100 mesh)

Implemented several gas lift pilots, testing application in

different areas/reservoirs

Strong results; plan to increase usage, benefiting LOE

MIDLAND BASIN LOCATOR MAP

Keystone 1007 WA (LL: 9,800’)IP30: 2,220 Boe/d (227 Boe/d / 1k’), 90% oil

Keystone 1006 LLS (LL: 9,800’)IP30: 1,600 Boe/d (163 Boe/d / 1k’), 88% oil

Keystone 1005 ULS (LL: 9,750’)IP30: 1,270 Boe/d (130 Boe/d / 1k’), 85% oil

Woody 3-46 WB (LL: 7,600’) IP30:

1,520 Boe/d (200 Boe/d / 1k’), 80% oil

Spanish Trail 347 01 WA (LL: 6,500’) IP30: 1,400 Boe/d (215 Boe/d / 1k’), 72% oil

Spanish Trail 347 02 WA (LL: 6,500’) IP30: 1,850 Boe/d (285 Boe/d / 1k’), 82% oil

Calverley 22 27 UWA (LL: 10,250’)170 Day Cuml: 175 MBoe, 72% oil

Calverley 22 27 LWA (LL: 10,250’) 170 Day Cuml: 170 MBoe, 71% oil

Calverley 22 27 UWB (LL: 7,630’) 170 Day Cuml: 135 MBoe, 60% oil

Calverley 22 27 LWB (LL: 7,630’) 170 Day Cuml: 125 MBoe, 61% oil

MIDLAND BASIN 2018 PLANS

18

Run 4 rigs on average, drilling almost entirely in full

development mode

Focus on highest return leases

Initiate development of Glass Ranch leases where RSP

has higher net revenue interest

Continue with full development sequence across West Side

area based on excellent recent step-out results in the WA

Continue to pair 2-well pads and complete 4 wells at once

when possible

Limited additional infrastructure requirements

MIDLAND BASIN LOCATOR MAP

Denotes area with significant 2018 drilling activity

DELAWARE BASIN WELL PERFORMANCE IMPROVEMENT

DELAWARE BASIN WELL PERFORMANCE BY VINTAGE

2017 wells drilled (through October) outperforming 2015 / 2016 vintage wells

19

0

30

60

90

120

150

180

210

240

270

300

0 30 60 90 120 150 180 210 240 270 300 330 360

Cum

l. M

Boe

2015 Avg. 2016 Avg. 2017 Avg.

Avg. LL: 4,700’

Avg. LL: 5,100’

Avg. LL: 6,100’

Note: Includes all zones.

DELAWARE BASIN UPDATE

20

First 3BS well, Rudd Draw 29 03 01H, completed on southern

end of acreage with excellent early results

7-day IP: 1,428 Boe/d (79% oil)

Current rate: 1,822 Boe/d (73% oil), still cleaning up at

>2,500 psi

8 other operated 3BS HZ wells across acreage

First RSP drilled & completed WB well brought online during

3Q17, strong results with flat decline profile

First well completed with 100% regional sand

Now have WB well results on far east and far west side of

acreage block

Recently returned Bullet well to production; came back

on with an initial flush rate of >1,000 Bo/d, has since

declined but is stabilizing after ~30 days around 560

Boe/d (64% oil)

First pass of Delaware 3D looks very high quality, showing

consistent presence of thick Wolfcamp and Bone Spring

section throughout eastern portion of acreage position

Continuing to test variations to stimulation design and flowback

methods

In early stages of data gathering, will likely result in

different optimized designs for different geographic areas

and formations

Modified Delaware casing design, evaluating from cost/benefit

perspective

Build-out of fresh water distribution system underway

DELAWARE BASIN LOCATOR MAP

Rudd Draw 26 21 XY (LL: 6,700’)

275 Day Cuml: 450 MBoe, 73% oil

Ludeman D 2105 LWA (LL: 4,750’)

170 Day Cuml: 200 MBoe, 72% oil

Ludeman A 603 WB (LL: 4,830’)IP30: 935 Boe/d (194 Boe/d / 1k’), 77% oil

Bullet 27 11 2H WB

Rudd Draw 29 03 01H 3BS (LL: 4,440’)IP7: 1,428 Boe/d (322 Boe/d / 1k’), 79% oil

DELAWARE BASIN 2018 PLANS

21

Run 3 rigs minimum, with likelihood of 4th

Move majority of drilling to multi-well pads, reducing well

costs

Previously ~40%, going forward ~85%

Focus will remain in Wolfcamp A, pending additional

results could see increasing allocation to Bone Spring

intervals and Wolfcamp B

Dedicate one rig to Rudd Draw area - highly prolific well

results to date and above average net revenue interest

Continue to test a couple of additional targets within pay

column

With likely 4th rig, drill delineation and extension wells on

east side where new 3D seismic (and offset wells) shows

promising potential – pending full interpretation of 3D

Continue science projects to further refine landing targets,

flowback methodology and completion designs

Implement new fresh water distribution system which will

provide surety of supply, on-time delivery and reduced D&C

costs Denotes areas with significant 2018 drilling activity

DELAWARE BASIN LOCATOR MAP

DELAWARE BASIN CROSS-SECTION (LOVING & WINKLER COUNTIES)

22

West-to-east seismic cross-section across RSP’s acreage position based on newly acquired 3D data

Confirms Central Basin Platform is well East of RSP’s Winkler County position

Avalon / 1st Bone Springs

2nd/3rd Bone Springs

T/Wolfcamp

WC A

WC D

WC C

WC B X/Y SAND

WINKLERLOVING

Atoka High

Carbonate % Increases

W

E

T/ATOKA

1,700’

1,300’

550’

475’

500’

2,700’

1,700’

1,400’

400’

450’

400’

1,400’

W E

23

• Continued focus on corporate-level returns and capital efficiency, not growth for growth’s sake

• Ability to achieve 30%+ production growth in 2018 in $50+ oil price environment, reaching cash flow neutrality by end of year

• Maintain strong balance sheet and liquidity through periods of commodity price volatility

• RSP flexible to accelerate or decelerate in response to commodity prices & service costs

FUTURE OUTLOOK

APPENDIX

MIDLAND BASIN INVENTORY

25

CURRENT SPACING ASSUMPTIONS

Base Spacing Mid - 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

~60% of drilling in 2018 targeting “platinum” inventory with

expected IRR > 50% at $50 oil

50% estimated weighted average return for 2018 drilling

program

Numerous spacing pilots ongoing

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%

CURRENT SPACING ASSUMPTIONS

Base Spacing (Avg. Wells/Section)

Formation West / Central East

Avalon 8 6

1st Bone Spring 3 0

2nd Bone Spring 8 0

3rd Bone Spring 3 0

Wolfcamp XY 6 0

Wolfcamp A 6 6

Wolfcamp B 6 6

Wolfcamp C 6 6

Wolfcamp D 6 6

26

DELAWARE BASIN INVENTORY

WEST & CENTRAL BASE SPACING LOCATIONS EAST BASE SPACING LOCATIONS

3,580 Gross Locations

1,860 Net Locations

1,010 Gross Locations

550 Net Locations

~65% of drilling in 2018 targeting “platinum” inventory with

expected IRR > 50% at $50 oil

65% estimated weighted average return for 2018 drilling

program

Significant upside to inventory pending results of future spacing

tests

Avalon16%

1st BS6%

2nd BS16%

3rd BS6%Wolfcamp

XY11%

Wolfcamp A11%

Wolfcamp B12%

Wolfcamp C12%

Wolfcamp D12%

Avalon20%

Wolfcamp A20%

Wolfcamp B20%

Wolfcamp C20%

Wolfcamp D20%

3Q17 FINANCIAL RESULTS

27

3Q17 3Q16 2Q17 3Q17 3Q16 2Q17

Avg. Daily Production Cash Op. Exp. ($/Boe)

Oil (MBbl/d) 41.4 21.6 38.8 LOE $5.18 $4.67 $4.72

Gas (MMcf/d) 47.2 18.7 40.1 G&T 0.98 0.51 1.12

NGL (MBbl/d) 9.7 5.0 8.9 Prod. Taxes 2.45 2.14 2.05

Total (MBoe/d) 58.9 29.8 54.3 Cash G&A 1.43 2.04 1.60

Total Cash Operating Exp. $10.04 $9.36 $9.49

Pricing Non-Cash/Other Exp. ($/Boe)

Average NYMEX Oil ($/Bbl) $48.20 $44.94 $48.28 Stock Comp G&A $0.81 $1.20 $0.90

Realized Price (Incl. Hedges) DD&A 13.54 18.27 13.77

Oil ($/Bbl) $45.16 $41.46 $45.27 Exploration 0.28 0.13 0.58

Gas ($/Mcf) 2.24 2.27 2.70 Interest Expense 3.98 4.80 3.94

NGL ($/Bbl) 19.52 10.82 15.88 Other (1) (0.18) (0.07) (0.09)

Total ($/Boe) $36.72 $33.37 $36.88 Total Non-Cash / Other Exp.(2) $18.43 $24.33 $19.10

Financial Results ($MM) Capital Expenditures ($MM)

Total Revenues $201.7 $93.6 $183.1 D&C $168.9 $65.3 $168.7

Net Income $21.3 $1.0 $31.1 Infrastructure and Other 22.7 7.9 10.9

Adj. EBITDAX $144.7 $65.7 $135.5 Total Development Capex $191.6 $73.2 179.6

Adj. Net Income (Loss) $28.2 ($0.8) $26.0

(1) Includes Other income net of Asset retirement obligation accretion expense.

(2) Excludes non-recurring non-cash expenses.

ADJUSTED EBITDAX AND ADJUSTED NET INCOME RECONCILIATION

28

Reconciliation of Net Income to Adjusted EBITDAX

(in thousands)

Net income

Interest expense

Income tax expense (benefit)

Depreciation, depletion, and amortization

Asset retirement obligation accretion

Exploration

Acquisition costs

Impairments

(Gain) loss on derivative instruments

Stock-based compensation, net

Other income, net

Reconciliation of Net Income to Adjusted Net Income (Loss)

(in thousands)

Net income

Acquisition costs

Impairments

(Gain) loss on derivative instruments

Other income, net

Income tax expense (benefit) for above items

Adjusted Net Income (Loss) 28,187$ (764)$ 26,048$

(11,827) (3,086) 2,744

(1,106) (310) (589)

705 971 5,312

19,059 676 (12,910)

21,326$ 985$ 31,090$

30 - 401

2017 2016 2017

Three Months Ended September 30,

Adjusted EBITDAX 144,662$ 65,732$ 135,450$

Three Months Ended June 30,

4,361 3,272 4,443

(1,106) (310) (589)

19,059 676 (12,910)

30 - 401

705 971 5,312

151 118 150

1,497 359 2,869

3,678 (3,507) 17,072

73,408 50,022 68,104

21,326$ 985$ 31,090$

21,553 13,146 19,508

Three Months Ended September 30,

2017 2016 2017

Three Months Ended June 30,

ADDITIONAL DISCLOSURES

29

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.