2Q 2017 FINANCIAL & OPERATING RESULTS August 7, 2017 - - PowerPoint PPT Presentation

2Q 2017 FINANCIAL & OPERATING RESULTS

August 7, 2017

FORWARD-LOOKING STATEMENTS

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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

• ther 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 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.

2Q RESULTS AND 2H UPDATE

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• 1. 2Q highlights
• 2. Infrastructure update
• 3. A&D update
• 4. Hedge Profile
• 5. Outlook for 2H17 and beyond
• 6. 2Q financial update
• 7. 2Q operational update
• 8. Appendix

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Production

20%↑

LOE/BOE

13%↓ 7% ↓

Cash G&A/BOE

16%↓

EBITDAX

9%↑

Strong second quarter results attributable to organic growth in the Midland Basin, full contribution of Delaware Basin acquisition volumes and operational improvements in both basins Positive net income with average realized oil price less than $50 per barrel over past four quarters, underscoring RSP’s ability to deliver profitable growth in lower oil price environment Execution of Delaware Basin infrastructure build-out on schedule, 3rd Delaware rig added during 2Q and 2017 Delaware wells performing materially better than 2015/2016 vintage wells

More than tripled water disposal capacity, with over 120,000 BWPD of capacity expected by mid-August LOE expected to trend further down in 2H17 with decreasing trucked water volumes Targa gas gathering and processing plant additions on schedule, addressing previous system limitations

Acquired bolt-on assets in the Delaware Basin, bolstering highly attractive footprint for $228 MM(1)

Acquired mineral interests underlying RSP acreage position (~4,500 net royalty acres(2)) Acquired working interests in the heart of RSP’s acreage position and added offset acreage (~6,000 net leasehold acres)

Enhanced hedge profile

Opportunistically added hedges in recent crude rally to protect $45+ floor in 4Q17 and 2018(3)

2Q HIGHLIGHTS

(1) Transactions closed in July, subsequent to 2Q17. (2) Net royalty acre defined as one surface acre leased at a 1/8th royalty. (3) Closed subsequent to 2Q17.

2Q17 vs. 1Q17

Excluding G&T Including G&T

DELAWARE BASIN WATER INFRASTRUCTURE UPDATE

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DELAWARE WATER DISPOSAL SYSTEM

Salt Water Disposal RSP owns 8 operated SWD wells with ~120,000 BWPD capacity expected as

• f mid-August 2017

Newly drilled wells permitted up to 25,000 BWPD each

~100-mile network of water gathering pipelines Significant exclusive surface-use agreements Nearly all disposed water currently piped to RSP-owned disposal wells

Currently injecting ~60,000 BWPD, leaving ample capacity for growth

Fresh Water Sourcing Currently buying water from commercially available sources Finalizing long-term water sourcing agreement and designing a water distribution system that will service RSP’s entire asset base

Estimate in-service in first half of 2018, resulting in D&C cost savings and secure source for future development

Gathering system SWD well

DELAWARE BASIN GAS GATHERING AND TRANSPORTATION UPDATE

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DELAWARE GAS GATHERING SYSTEM

Gas gathering provided by Targa (NYSE: TRGP) Processing provided by Targa and Energy Transfer Partners Targa’s Loving plant: ~60 MMcf/d cryogenic processing plant on RSP acreage position

Targa connecting Loving plant to their Delaware Basin system

Targa’s new Wildcat plant: ~250 MMcf/d cryogenic processing plant, in service ~2Q 2018 Targa expanding field compression and looping gathering lines ahead of RSP development plans

Gathering system Gas Plant Compressor

Wildcat Plant Loving Plant

ACQUISITIONS & DIVESTITURES UPDATE

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Acquired leasehold and mineral interests in the Delaware Basin

Total aggregate purchase price of $228 MM, closed 3Q ~6,000 net leasehold acres and 4,500 net royalty acres(1) ~500 Boe/d of production

Accretive bolt-ons to existing footprint, augment working interest (WI) and extend lateral length of near-term drilling locations

Converted ~14 sections from minority to majority WI

Mineral interest acquisition increases net revenue interest (NRI) and enhances drilling economics, increasing rate of return on each dollar of capital spent

LOCATOR MAP OF 2Q17 ACQUISITIONS & TRADES

RSP Existing Acreage New WI / NRI Acquired Additional WI / NRI Acquired

MINERAL INTEREST ACQUISITION: ILLUSTRATIVE UPLIFT TO ECONOMICS

+ 5% + 10-15% Net Boe IRR / NPV

Impact of 3% incremental NRI on single well economics

Note: Pro forma for acquisitions closed in July 2017. (1) Net royalty acre defined as one surface acre leased at a 1/8th royalty.

HEDGE PROFILE

8 Crude Oil (Bbl, $/Bbl) 3Q17 4Q17 3Q17 – 4Q17 1Q18 2Q18 3Q18 4Q18 2018 Three-Way Collars (1) 552,000 552,000 2,219,000 1,941,000 1,319,000 1,227,000 6,706,000 Ceiling Floor Short Put $54.10 $45.00 $35.00 $54.10 $45.00 $35.00 $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) 1,150,000 1,150,000 2,300,000 Ceiling Floor $60.05 $45.00 $60.05 $45.00 $60.05 $45.00 Deferred Premium Puts (1) 920,000 920,000 1,840,000 Floor Deferred Premium (2) $48.50 ($4.00) $48.50 ($4.00) $48.50 ($4.00) Swaps (1) 552,000 552,000 Swap Price $48.95 $48.95 Total Hedge Weighted Average Floor (3) 2,070,000 $44.78 3,174,000 $45.54 5,244,000 $45.24 2,219,000 $46.96 1,941,000 $47.11 1,319,000 $47.79 1,227,000 $48.00 6,706,000 $47.36 % Hedged on Midpoint Oil Volume Guidance(4) 66% Mid-Cush Differential Swaps (5) 920,000 276,000 1,196,000 Weighted Average Swap ($0.38) ($0.50) ($0.41) Natural Gas (MMBtu, $/MMBtu) 3Q17 4Q17 3Q17 – 4Q17 1Q18 2Q18 3Q18 4Q18 2018 Costless Collars (6) 2,422,000 2,545,000 4,967,000 Ceiling Floor $3.86 $3.00 $3.86 $3.00 $3.86 $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) Utilizing 2017 midpoint oil volume guidance. (5) 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. (6) 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.

HEDGE CONTRACT DETAIL

RSP continuing to protect $45+ floor into 4Q17 and 2018

Opportunistically added ~12 MBo/d and ~10 MBo/d, respectively, in recent crude rally

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• Continued focus on corporate-level returns and capital efficiency, not growth for growth’s sake
• Strong execution YTD, reiterate 2017 production, unit cost, and capex guidance
• Look to closely balance capex with cash flow in 2018-2019, while still achieving double-digit

production growth in $40-$50 oil price environment

• 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

OUTLOOK FOR 2H17 AND BEYOND

2Q FINANCIAL UPDATE

2Q17 ACTIVITY OVERVIEW

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During 2Q17, RSP drilled 22 and completed 18 operated HZ wells 10 Midland, 8 Delaware completions Expect to drill 52-56 and complete 48-53 in 2H17 Deferring 6-8 2H17 completions and increasing DUC inventory to capture expected well cost reductions in early 2018 (sand deal, water sourcing deal, efficiencies) 22 operated DUCs as of 6/30/17, estimate 21-30 as of YE 2017

GROSS OPERATED ACTIVITY 2H17 PLANNED COMPLETION ACTIVITY 1H17 COMPLETION ACTIVITY WA LS WB MS WA WXY WB 3BS2BS WA 31% WB 25% LS 13% WA 22% WXY 6% 2BS 3%

Midland Delaware Midland Delaware

11 43 52 32 48 21 56 53 30 YE 2016A DUCs 1HA 2HE 1HA 2HE YE 2017E DUCs Drilling Completions

2Q17 2Q16 1Q17 2Q17 2Q16 1Q17

• Avg. Daily Production

Cash Op. Exp. ($/Boe) Oil (MBbl/d) 38.8 19.3 33.7 LOE $4.72 $5.37 $5.40 Gas (MMcf/d) 40.1 19.0 32.5 G&T 1.12 0.49 0.85 NGL (MBbl/d) 8.9 3.9 6.1

• Prod. Taxes

2.05 2.06 2.33 Total (MBoe/d) 54.3 26.4 45.2 Cash G&A 1.60 2.06 1.91 Total Cash Expenses $9.49 $9.99 $10.49 Pricing Non-Cash/Other Exp. ($/Boe) Average NYMEX Oil ($/Bbl) $48.28 $45.59 $51.91 Recurring Stock Comp $0.90 $1.46 $0.96 Realized Price (Incl. Hedges) Non-recurring Stock Comp

• 0.28
• Oil ($/Bbl)

45.27 43.05 49.02 DD&A 13.77 19.68 15.01 Gas ($/Mcf) 2.70 1.47 2.59 Exploration 0.58 0.17 0.63 NGL ($/Bbl) 15.88 11.69 19.96 Total ($/Boe) $36.88 $34.32 $41.09 Financial Results ($MM) Capital Expenditures ($MM) Net Income $31.1 ($9.8) $38.9 D&C $168.7 $56.5 $110.5

• Adj. EBITDAX

$135.5 $58.5 $124.5 Infrastructure and Other 10.9 1.1 5.1

• Adj. Net Income (Loss)

$26.0 ($3.8) $24.2 Total Development Capex $179.6 $57.6 $115.6

2Q17 FINANCIAL RESULTS

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Production growth of 20% and EBITDAX growth of 9% over prior quarter despite lower oil prices LOE/Boe (excl. G&T) 13% lower than prior quarter, driven by Midland Basin efficiency gains and infrastructure gains D&C capex 53% higher than prior quarter, reflecting an accelerated drilling & completion pace

CAPITALIZATION AND LIQUIDITY SUMMARY

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CAPITALIZATION TABLE

$900MM elected commitment under the Company’s revolving credit facility with $1.1B borrowing base and $2.5B maximum lender commitments Key financial covenants: Maximum of 4.25x Total Debt / TTM EBITDAX Minimum current ratio of 1.0x Next redetermination November 2017

DEBT MATURITIES ($MM)

$0 $200 $400 $600 $800 $1,000 $1,200

2017 2018 2019 2020 2021 2022 2023 2024 2025

6/30/17 Credit Facility Balance Credit Facility Availability Senior Notes 6.625% 5.25%

Elected Commitment Borrowing Base

(1) $228 MM of acquisitions closed subsequent to 6/30/17, in July 2017 (including $25 MM of deposits paid 2Q17).

6/30/17 Balance

(1)

($ in millions) 6/30/2017 Cash $34 Revolving Credit Facility 58 6.625% Senior Unsecured Notes Due 2022 700 5.25% Senior Unsecured Notes Due 2025 450 Total Debt $1,208 Net Debt $1,174 Liquidity Elected Commitment $900 Less: Borrowings & LCs (58) Plus: Cash 34 Liquidity $876 Financial & Operating Statistics Annualized 2Q17 Adjusted EBITDAX $541.8 2Q17 Avg. Daily Production (MBoe/d) 54.3 Credit Metrics Net Debt / 2Q17A Adjusted EBITDAX 2.2x Net Debt / Daily Production ($/Boe/d) $21,608

(1)

FULL YEAR 2017 GUIDANCE

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COMMENTARY FULL YEAR 2017 GUIDANCE SUMMARY 2017E CAPEX SUMMARY

61% 4% 30% 5% Midland D&C Midland Infrastructure Delaware D&C Delaware Infrastructure

1H17 Actuals 2017 Guidance Range Production

• Avg. Daily Production (Boe/d)

49,779 53,000 - 57,000 % Oil 73% 71% - 73% % Natural Gas 12% 11% - 13% % NGLs 15% 15% - 17% Income Statement ($/Boe) LOE (incl. workovers) $5.03 $4.50 - $5.50 Gathering & Transportation $1.00 $1.10 - $1.40 Exploration Expenses $0.60 $0.40 - $0.60 Cash G&A $1.74 $1.25 - $1.75 Non-Cash G&A $0.93 $0.70 - $0.90 DD&A $14.33 $14.00 - $16.00

• Prod. & Ad Val. (% Rev.)

5.6% 6.0% - 8.0% Capital Expenditures ($MM) Drilling & Completion $279.2 $575 - $625 Infrastructure & Other $16.0 $50 - $75 Total Development Capital $295.2 $625 - $700 Non-Operated (%) 12% 8% - 12% Operated Completions Gross Hz 32 80 - 85 Operated WI 89% 88%

• Avg. LL (Midland / Delaware)

8,300’ / 5,700’ 8,500’ / 6,250’

Reiterate full year 2017 production, unit cost and capex guidance ranges Revised completion guidance to 80-85 gross operated horizontal completions, as compared to original guidance of 85- 95

Deferring completions from 2H17 to early 2018, to capture lower expected well cost

Revised non-operated development capital (increased percentage of total) Currently running 7 operated rigs (4 Midland, 3 Delaware) Running 2 completion crews

PRODUCTION PER DEBT-ADJUSTED SHARE GROWTH (THROUGH FY17E)

Note: Peers include Callon, Cimarex, Concho, Diamondback, Energen, EOG, Laredo, Parsley, and Pioneer. Indexed to Q2 2014 (Parsley IPO). Bloomberg consensus estimates used for FY 2017E production and cash flow outspend. FY 2017E shares outstanding based on current count on the most recent quarterly filing. Share price as of 7/11/2017.

RSP consistently ranks #1 or #2 in production per debt-adjusted share growth FY 2017E based on consensus research estimates for RSP and peers as of July 31

15 203% 209% 143% 133% 143% 115% 126% 129% 93% 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 FY 2017E RSP Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 10

2Q OPERATIONAL UPDATE

CONTIGUOUS FOOTPRINT + STACKED RESOURCE

MIDLAND BASIN POSITION

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46,500

net acres

1,750 – 2,890

net drilling locations(1)

200 MMBoe

Proved Reserves(2)

1.0 – 1.6 BBoe

Total Resource Potential(1)

(1) Based on range from base to upside case well spacing. 80% of total resource potential from most delineated zones – Middle Spraberry, Lower Spraberry, Wolfcamp A and Wolfcamp B. (2) As of 1/1/17.

3,400’

MIDLAND BASIN INVENTORY

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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 Fork 4% Middle Spraberry 22% Jo Mill 10% Lower Spraberry 30% Wolfcamp A 11% Wolfcamp B 11% Wolfcamp D 11% Clear Fork 5% Middle Spraberry 24% Jo Mill 11% Lower Spraberry 25% Wolfcamp A 12% Wolfcamp B 11% Wolfcamp D 12%

# Well Name Zone Lateral Length (Feet) IP30 (BOED) IP30 / 1,000’ % Oil

1 Spanish Trail 4826 MS 7,000 1,167(1) 168(1) 77% 2 MCC 1104H WA 9,500 1,066 112 74% 3 MCC 1103H LS 9,500 1,495 157 82% 4 MCC 1102H WA 9,500 1,316 139 83% 5 MCC 1101H LS 9,400 996 105 82% 6 Calverley 22 27 104H WB 7,600 1,215 159 69% 7 Calverley 22 27 103H WA 10,300 1,337 130 77% 8 Calverley 22 27 102H WB 7,600 1,597 209 68% 9 Calverley 22 27 101H WA 10,300 1,184 115 77% 10 Cross Bar Ranch 1722 WA 7,000 1,162 167 79%

MIDLAND BASIN ACTIVITY UPDATE

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MIDLAND BASIN ACTIVITY RECENT WELL RESULTS

Excellent and consistent well results confirming enhanced completion design and asset quality

LS WA WB

2 4

3 5

6 7 9

8

EXTENDED PRODUCTION DATA

# Well Name Zone Lateral Length (Feet) IP 30 (BOED) % Oil Prod. Days Cuml Prod (MBOE)

11 Mask 1004 WB 9,500 1,617 71% 279 274 12 Mask 1005 LS 9,500 1,538 74% 279 351

(1) 10-day IP.

MS

1

10 11 12

MICROSEISMIC CASE STUDY: CONFIRMING NEAR-WELLBORE STIMULATION

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Note: Results colored by stage.

Grid Size X: 500’ Y: 500’ Grid Size X: 500’ Y: 500’

*Surface Array *Surface Array

2014 / 2015 COMPLETION DESIGN CURRENT COMPLETION DESIGN Northern Midland Basin Wolfcamp A Glasscock County Wolfcamp A Event Cloud 1,000’ Radius Event Cloud 600’ Radius

DELAWARE BASIN POSITION

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(1) Net royalty acre defined as one surface acre leased at a 1/8th royalty. (2) Based on base case well spacing. 70% of total resource potential from most delineated zones – Avalon, 2nd Bone Spring, 3rd Bone Spring, Wolfcamp XY, Wolfcamp A, and Wolfcamp B. (3) As of 1/1/17. (4) Wells / section for West and Central operating areas.

CONTIGUOUS FOOTPRINT + STACKED RESOURCE

47,100

net leasehold acres

4,500

net royalty acres(1)

2,410

net drilling locations(2)

80 MMBoe

Proved Reserves(3)

1.8 BBoe

Total Resource Potential(2)

5,700’ Lea Winkler Loving

New Mexico Texas

CURRENT SPACING ASSUMPTIONS

Base Spacing (Avg. Wells/Section) Formation West / Central East

Avalon 8 6 1st Bone Spring 3 2nd Bone Spring 8 3rd Bone Spring 3 Wolfcamp XY 6 Wolfcamp A 6 6 Wolfcamp B 6 6 Wolfcamp C 6 6 Wolfcamp D 6 6

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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

Avalon 16% 1st BS 6% 2nd BS 16% 3rd BS 6% Wolfcamp XY 11% Wolfcamp A 11% Wolfcamp B 12% Wolfcamp C 12% Wolfcamp D 12% Avalon 20% Wolfcamp A 20% Wolfcamp B 20% Wolfcamp C 20% Wolfcamp D 20%

DELAWARE BASIN ACTIVITY UDPATE

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DELAWARE BASIN ACTIVITY

LWA 1

2 5 3 4

WELL RESULTS

# Well Name Zone Lateral Length (Feet) IP 30 (BOED) IP30 / 1,000’ % Oil

1 Ludeman 1408H 2BS 6,400 915(1) 143(1) 84% 2 Ludeman 1407H LWA 6,900 1,029(2) 149(2) 72% 3 Pistol 25-09 3H LWA 4,600 1,026(2) 225 76% 4 Rudd Draw 26-18 04H LWA 5,200 1,193 228 77% 5 Ludeman K 2105H LWA 4,750 1,905 401 73% 6 Ludeman 1303H LWA 7,300 822(3) 113 72%

Excellent well results reflecting improvements in drilling and completion designs

(1) Rate presented is IP24, still cleaning up (awaiting ESP install). (2) 10-day IP. (3) Has been on restricted choke for entirety of well life due to facility constraints. (4) Set new IP30 at day 189. (5) Non-operated well.

1

2BS WC XY

10 7 6 9

RECENT WELL RESULTS EXTENDED PRODUCTION DATA

# Well Name Zone Lateral Length (Feet) IP 30 (BOED) % Oil Prod. Days Cuml Prod (MBOE)

7 Crockett Reese St B 2403H LWA 6,900 1,706 73% 115 147 8 Brunson 1111H Avalon 8,000 1,053 67% 340 216 9 Ludeman 1406H LWA 6,900 1,027 73% 164 146 10 Rudd Draw 26-21 01H WC XY 6,700 2,020(4) 74% 189 300 11 Hughes Talbot 75 23 2H(5) WC XY 4,800 2,068 75% 156 212 12 Ludeman F 505H 2BS 4,400 952 67% 291 147 11 12

Avalon

8

LWA 2

OFFSET OPERATORS CONTINUE TO DE-RISK EASTERN EDGE

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Solid results from offset operators along eastern edge of Delaware Basin further de-risk RSP’s Winkler County acreage

WELL RESULTS EASTERN DELAWARE BASIN ACTIVITY

Deepest Shallowest

# Operator Name Well Name IP24 (BOE) IP24 / 1000' Lateral Length

1 Lilis Grizzly #1H 1,323 322 4,100 2 Lilis Hippo #1H 1,917 467 4,100 3 Lilis Bison #1H 2,014 292 6,900 4 Felix Falcon State 28-36 #1H 941 215 4,400 5 Felix UL 4-21 #1H 1,302 307 4,200 6 Forge UL 21 Pahaska #1H 748 174 4,300 7 Felix UL 20 #1311H 1,376 142 9,700 8 Felix UL Elk Park 21-21 #1H 768 168 4,600 9 Felix UL Sunshine Mesa 29-21 #1H 1,330 272 4,900 10 Forge UL 21 Bighorn #1H 1,621 172 9,400 11 Jagged Peak UL 4344-21 #1H 1,761 176 10,000 12 Jagged Peak UL 3031A-17 #1H 1,548 162 9,500 13 Jagged Peak UL 3031B-17 #1H 1,439 143 10,000 14 Jagged Peak UL 2932-17 #1H 1,175 113 10,400 15 Jagged Peak UL 28-17 #1H 2,272 236 9,600 16 Jagged Peak UL Beldin L J 1211-17 #2HX 1,978 173 11,400 3 1 2 6 10 8 9 11 12 13 14 16 15

Lower Wolfcamp A Wolfcamp B

5 4 7

ONGOING DELINEATION OF MULTIPLE ZONES

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NON-WOLFCAMP A DELAWARE BASIN ACTIVITY 1st Bone

2 7 3 6

WELL RESULTS

# Well Name Zone Lateral Length (Feet) Cuml Prod (MBOE) Frac Comments

1 Jackson Trust C 12 121H 1st Bone 4,900 144 350’ stages, x-link 2 Pistol 25 8 2H Avalon 4,200 80 2,300#/ft - slickwtr 3 Rippin Wrangler #1H WB 4,600 155 1,400#/ft -100 mesh 4 Brunson 1111H Avalon 8,100 204 1,700#/ft -slickwtr 5 Ludeman 1402H 1st Bone 6,700 160 1,000#/ft -gel 6 Ludeman 505H 2nd Bone 4,400 140 2,500#/ft - slickwtr 7 Ludeman 703H 3rd Bone 3,900 208 1,900#/ft - gel 8 Brunson B 1501H 3rd Bone 4,100 172 2,000#/ft - gel 9 Bison 1H WB 6,900 159 2,200#/ft – slickwtr 10 Kerr State 28-35 1H 3rd Bone 5,100 275 431#/ft – gel 11 UL Block 20 1304H 3rd Bone 6,900 310 984#/ft – gel 12 UL 4-21 1H WB 4,200 168 1,160#/ft – gel 13 Mitchell 28-38 1H 3rd Bone 2,700 300 530#/ft – gel

In addition to industry focus on Wolfcamp A zone, strong results from 5 other target horizons across RSP position

1

3rd Bone 2nd Bone

4 5 9 8 10 11

Avalon WB

12

Note: Italics denote non-operated well.

13

2ND BONE SPRING UPDATE: 2 DISTINCT LANDING ZONES

26

2ND BONE WELLS ON RSP FOOTPRINT 2ND BONE COMPARISON TO MIDLAND LOWER SPRABERRY Ludeman 1408H Ludeman 202H Ludeman 505H

PRODUCING 2ND BONE WELL PLANNED 2H17 2ND BONE WELL

Lower Spraberry Dean

Ludeman 505H Ludeman 1407H 2nd BS 3rd BS

750’ between landing zones

DELAWARE MIDLAND

Ludeman 505H (4,400’ LL) has produced 147 MBoe in <10 months of production from Upper 2nd Bone Spring landing zone IP30 (952 Boe/d) was established after nearly 6 months of production and 95 MBoe of cumulative production New Ludeman 1408H (6,400’ LL) is landed 750’ deeper than 505H in RSP Lower 2nd Bone Spring landing zone Similar production profile in early flowback (IP24 of 915 Boe/d) Waiting on ESP installation

500’ total section height 1000’ total section height

Purchased 108 sq mi 3D data set from Fairfield Nodal (at time of Silver Hill acquisition) Acquiring new 137 sq mi 3D data set from TGS (Oct. 2017 delivery) Monitoring Brunson D 3 well pad with surface microseismic (Q4 2017 delivery)

DELAWARE BASIN 3D & SURFACE MICROSEISMIC

Winkler Loving Lea 3D SEISMIC COVERAGE BRUNSON D MICROSEISMIC

Brunson D Gun Barrel 27

DELAWARE BASIN WELL PERFORMANCE IMPROVEMENT

UPPER WOLFCAMP WELL PERFORMANCE BY VINTAGE

10 20 30 40 50 60 70 80 90 100

• 20,000

40,000 60,000 80,000 100,000 120,000 140,000 160,000 180,000 30 60 90 120 150 180 210 240 270 300 330 360

Cum'l Oil (bbls)

2015 AVG 2016 AVG YTD 2017 AVG 2015 Well Count 2016 Well Count 2017 Well Count

*Results normalized to 7,500'

2017 wells drilled to date outperforming 2015 / 2016 vintage wells

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APPENDIX

DELAWARE BASIN WOLFCAMP C & D ACTIVITY

Wolfcamp C&D have been drilled by WPX, EOG, Concho, Devon & Cimarex Comparable log response on RSP leasehold

Similar to other Wolfcamp zones, expect trend of increasing oil percentage as you move east across the basin

C A B

WC A WC B WC C WC D 3 BS

Potential Target Zones 14 MMBO/SEC 89 MMBO/SEC

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B A C

WPX Energy E Pecos Fed Com 22-14H IP30: 1,736 Boe/D (30% Oil) 4,678’ lateral length 09/2016; WC D EOG State Harrison Ranch 1502H IP24: 1,881 Boe/D (51% Oil) 5,551’ lateral length 11/2014; WC C Cimarex Searls 34-115 2H IP30: 543 Boe/D (82% Oil) 4,566’ lateral length 09/2014; WC C WPX Energy Pecos State 46-5H IP30: 1,628 Boe/D (22% Oil) 4,481’ lateral length 05/2017; WC D WPX Energy Lindsay 16-6H IP30: 1,434 Boe/D (18% Oil) 4,474’ lateral length 08/2016; WC D

Lower Spraberry WA WB E 200’ ½ Mile W

Dean Middle Spraberry

Q4 Frac Future Development

FULL DEVELOPMENT UNDERWAY ACROSS MIDLAND BASIN ACREAGE

31

SPANISH TRAIL SECTION 47 CROSS BAR RANCH SECTION 17 JOHNSON RANCH SECTION 10 CALVERLEY SECTION 9 1st Prod Start Date: 04/2014 Cum Prod: 2,200 MBoe Lateral Length: 7,500’ 1st Prod Start Date: 10/2014 Cum Prod: 3,200 MBoe Lateral Length: 7,500’ 1st Prod Start Date: 08/2015 Cum Prod: 2,800 MBoe Lateral Length: 10,000’ 1st Prod Start Date: 10/2015 Cum Prod: 2,100 MBoe Lateral Length: 10,000’

RSP has several units approaching full development of primary zones across breadth of acreage position

ADJUSTED EBITDAX AND ADJUSTED NET INCOME RECONCILIATION

32 Reconciliation of Net Income (Loss) to Adjusted EBITDAX

(in thousands) Net income (loss) 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 (Loss) to Adjusted Net Income (Loss)

(in thousands) Net income (loss) Acquisition costs Impairments (Gain) loss on derivative instruments Stock-based compensation - non-recurring Other income, net Income tax expense (benefit) for above items Adjusted Net Income (Loss) 26,048 $ (3,758) $ 24,212 $ 2,744 (2,370) 1,754 (589) (104) (720)

• 682
• 5,312

3,177 125 (12,910) 4,658 (19,933) 31,090 $ (9,801) $ 38,934 $ 401

• 4,052

2017 2016 2017 Three Months Ended June 30, Adjusted EBITDAX 135,450 $ 58,453 $ 124,451 $ Three Months Ended March 31, 4,443 4,183 3,924 (589) (104) (720) (12,910) 4,658 (19,933) 401

• 4,052

5,312 3,177 125 150 123 153 2,869 405 2,580 17,072 (4,438) 15,072 68,104 47,296 61,040 31,090 $ (9,801) $ 38,934 $ 19,508 12,954 19,224 Three Months Ended June 30, 2017 2016 2017 Three Months Ended March 31,

ADDITIONAL DISCLOSURES

33 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

• ther 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.