RSP Permian Howard Weil Conference March 2016

RSP Permian Howard Weil Conference March 2016

Forward-Looking Information Certain statements and information in this presentation may constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words believe, expect, anticipate, plan, intend, foresee, should, would, could or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, the volatility of commodity prices, product supply and demand, competition, access to and cost of capital, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, our hedging strategy and results, the quality of technical data, environmental and weather risks, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the costs and results of drilling and operations, the availability of equipment, services, resources and personnel required to complete RSP s operating activities, access to and availability of transportation, processing and refining facilities, the financial strength of counterparties to the Company s credit facility and derivative contracts and the purchasers of RSP s production and third parties providing services to RSP and acts of war or terrorism. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see our filings with the United States Securities and Exchange Commisson (SEC), including our Annual Report on Form 10-K and Quarterly Reports on Form 10-Q. Existing and prospective investors are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. 2

RSP Permian Overview (NYSE: RSPP) Large, contiguous, core acreage blocks in the Midland Basin ~280,000 net effective horizontal acres (1) and ~64,000 net surface acres (96% operated) ~2,600 horizontal locations in inventory with significant upside of an additional ~1,750 horizontal locations at tighter spacing Average horizontal lateral length >7,000 Efficient operator focused on execution Peer-leading F&D costs, cash operating costs per Boe and cash margins per Boe Drilled wells in five different horizontal benches Key Statistics Market Capitalization (3/17/16): 2015 Production: YE 2015 Proved Reserves: Net Debt / Annualized EBITDAX (2)(3) : Current Liquidity (3) : $2.9 billion 21.0 MBoe/d 159.2 MMBoe Concentrated Acreage Position in the Core of the Midland Basin RSP Acreage Note: All acreage and location totals pro forma for acquisitions subsequent to December 31, 2015. Focus Area defined as adjacent counties of Midland, Martin, Andrews, Ector, and Glasscock. (1) Combined horizontal acreage position that management believes is prospective for hydrocarbon production across each target horizontal zone. (2) Based on pro forma Q4 2015 net debt and Adjusted EBITDAX annualized. Please see reconciliation of Adjusted EBITDAX in Appendix. (3) Includes acquisitions of additional working interests subsequent to 12/31/15. 2.0x $714 million TX Focus Area 3

Recent Company Highlights Strong financial and operational performance in 2015 Grew production by 77% and proved reserves by ~50% over 2014 Spent ~$20 million less capital than the midpoint of the revised capital budget of $400 - $420 million Cash operating costs per Boe down 27% ($11.85 / Boe) and drilling F&D costs ($5.77 / Boe) down 46% in 2015 Record cash operating costs per Boe of $9.98 in Q4 2015 ($4.76 / Boe of LOE, excluding gathering and transportation) 2016 AFEs of $5.5 million for a 7,500 lateral, a 13% decrease from 2015 target and ~40% decrease from 2014 peak Western Glasscock County results confirm new core area for RSP Results in Glasscock to date reflect the most prolific wells in RSP s history Decades of horizontal inventory with compelling single-well returns ~2,600 horizontal locations in the highest-return areas of the Midland Basin within delineated zones Potential to increase inventory by 67% at higher densities on existing footprint Continuing to bolt-on additional core acreage at attractive prices Ample liquidity in 2016 & beyond Currently over $100 million of cash on hand and an undrawn $600 million revolving credit facility Forecasting ~20% production growth at the midpoint in 2016 while budgeting ~41% less capex at the midpoint To keep 2017 production volumes ~20% higher than 2015 levels, RSP will require minimal to no funding beyond cash on hand and operating cash flow Selective use of capital markets Capital markets were utilized to fund all significant acquisitions in 2015 Clear use of proceeds important to ensure return on capital objectives and minimize dilution Shareholders positioned to benefit from future improvement in oil prices 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. 4

Q4 and Full Year 2015 Financial Results 4Q15 & 2015 Financial Highlights Acquisitions & Capital Markets 4Q production averaged 24.3 MBoe/d (75% oil, 13% NGL, 12% Natural Gas) Increase of 50% compared to 4Q14 ~1.4 MBoe/d offline due to Crossbar Ranch fire and winter weather 2015 production averaged 21.0 MBoe/d (75% Oil, 14% NGLs, 11% Natural Gas) Increase of 77% compared to 2014 Adjusted EBITDAX of $74.4 million in 4Q15 and $285.1 million in 2015 Adjusted Net Income of $12.1 million, or $0.12 per diluted share in 4Q15 and $48.6 million, or $0.56 per diluted share in 2015 Cash flow neutral in Q4 2015, excluding acquisitions Since mid-2015, RSP acquired ~11,900 net acres in the Midland Basin Focus Area RSP completed three equity offerings totaling $557 million and issued an additional $200 million in senior notes S&P upgraded RSP s notes from B to B+ and Moody s affirmed notes at B3 in February 2016 Exited year with strong liquidity position, with $143 million of cash and a $600 million undrawn revolver Operational Activity Invested $64 million in Q4 2015 and $391 million in 2015 on drilling, completion, infrastructure and other Completed 8 operated horizontal wells during 4Q 18 additional operated horizontal wells waiting on completion at the end of the year In 2015 completed 45 operated horizontal wells and 19 operated vertical wells Completed 46 non-operated horizontal wells and 5 non-operated vertical wells Note: Please see reconciliation of Adjusted EBITDAX and Adjusted Net Income in Appendix. 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. 5

2015 Drilling & Completion Activity Q4 Drilling & Completion Activity Summary Drilled Completed DUCs (1) Operated Wells Horizontal 10 8 18 Vertical 1 2 Total 11 8 20 Non-Operated Wells Horizontal 15 8 13 Vertical In Q4 2015, RSP completed 8 operated horizontal wells (1 Lower Spraberry, 4 Wolfcamp A wells and 3 Wolfcamp B wells) During the quarter, RSP increased its inventory of operated horizontal wells waiting on completion (DUCs) while operating three horizontal rigs 2015 Drilling & Completion Summary 2015 Operated Completion Summary 2015 Operated Horizontal Drilling & Completions (1) LS 33% WB 31% WA 31% 60 50 40 30 20 10 0 10 2014 YE DUC Wells (1) DUCs are drilled but uncompleted wells. (2) Denotes only horizontal well drilling and completion activity. Two vertical wells were drilled during 2015 that will be completed in 2016. MS 5% 43 YTD Drilled 10 Q4 Drilled 53 2015 Drilled 8 45 37 YTD Q4 2015 Compl. Compl. Compl. 18 2015 YE DUC Wells 6

Boe/d MMBOE Track Record of Production and Proved Reserve Growth RSP had a strong year of growth, increasing production by ~77% and growing proved reserves by ~50% RSP has roughly tripled production and proved reserves in the last two years Annual Production Growth Since Inception Proved Reserve Growth 25,000 175 159.2 20,000 15,000 +63% +77% 21,047 150 125 100 106.4 94.6 10,000 5,000 +43% +82% 11,868 7,293 5,089 2,800 2011 2012 2013 2014 2015 75 50 25 64.5 53.9 32.5 64.6 41.9 21.4 YE 2013 YE 2014 YE 2015 PD PUD 7

Continuing to Drive Down Costs Production growth, efficiency gains and cost improvements driving meaningful reduction in per unit costs $20.00 $15.00 $10.00 $5.00 $0.00 $18.21 Drill bit F&D Costs $10.59 $10.87 2014 2015 Permian Peer Average RSPP $5.77 LOE and Gathering & Transportation per Boe $25.00 $20.00 $15.00 $10.00 $5.00 $0.00 PDP F&D Costs (1) $21.31 $21.45 $16.32 $17.04 $14.96 $9.77 $11.28 RSPP Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Cash G&A per Boe $10.00 $8.00 $6.00 $4.00 $2.00 $8.93 $8.17 $7.52 $7.83 $6.92 $6.46 $0.00 2014 2015 Permian Peer Average RSPP LOE RSPP LOE w/ G&T $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 $5.47 $3.44 Note: Permian peers include CPE, CXO, FANG, LPI, PE, and PXD. (1) Defined as exploration and development costs divided by the sum of PDP extensions and PUD-to-PDP conversions. FANG calculation excludes PDP additions related to VNOM. $3.92 2014 2015 Permian Peer Average RSPP $2.33 8

Peer Leading Reserve Replacement Ratio and F&D Costs Drill-bit success and capital efficiency driving reserve growth Proved Developed and Proved Undeveloped Reserves grew by ~50% and ~83%, respectively, year over year Less than 8% of RSP s current horizontal locations are booked as PUDs Reserve life of ~18 years (1) Drillbit F&D of $5.77 (2) and Total F&D of $10.43 Reserve Replacement Ratio of 1,042% and Organic Reserve Replacement Ratio of 855% (4) Proved Reserve Summary Reserve Replacement and F&D Costs 2015 Drillbit F&D ($ / Boe) (2) $5.77 RSP Peer Rank (5) #2 PDP F&D ($ / Boe) (3) $9.77 RSP Peer Rank (5) #1 Reserve Replacement 1,042% RSP Peer Rank (5) #1 Organic Reserve Replacement (4) 855% RSP Peer Rank (5) #1 Gross Horizontal PUD Count PUD 59% PD 41% Gas 14% 159.2 MMBoe NGLs 16% Oil 70% (1) Based on Q4 2015 production. (2) Defined as exploration and development costs divided by the sum of extensions and discoveries and non-price revisions. (3) Defined as exploration and development costs divided by the sum of PDP extensions and PUD-to-PDP conversions. (4) Defined as the sum of extensions, discoveries, and non-price revisions, divided by annual production. (5) Permian peers include CPE, CXO, FANG, LPI, PE, and PXD. 225 200 175 150 125 100 75 50 25 109 60 14 30 202 4 86 28 84 YE 2014 YE 2015 % of Locations LS MS WA/WB WD 1% (359 Locations) 16% (554 Locations) 5% (570 Locations) 13% (650 Locations) 9

Low Cost Structure and Strong Margins Six straight quarters of declining cash costs and high oil mix allow us to maintain healthy cash margins in a challenging environment Historical Cash Margins and Costs (per Boe) $96.26 Realized Oil Price Excluding Hedges (per Bbl) $86.88 $66.34 $43.88 $53.68 $44.84 $40.00 $30.00 $25.00 75% 78% 72% 69% 71% 70% 90% 75% $20.00 $15.00 $10.00 $5.00 $19.30 $6.12 $3.66 $9.52 $15.09 $14.98 $14.65 $4.98 $3.19 $4.21 $6.92 $7.55 $3.22 $2.92 $8.78 $8.12 1) Cash Margin (Excluding Hedges) is calculated as the Realized Price per Boe (Excluding Hedges) less the cash costs listed in the chart, divided by the Realized Price per Boe (Excluding Hedges). 59% $2.95 $13.58 $2.99 $2.47 $10.50 $9.98 $2.12 $1.92 $6.46 Record low LOE & Cash Costs Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 LOE, Gathering & Transporation, & Workovers Cash G&A Prod. & Ad Val Cash Margin (Excluding Hedges) $2.56 $2.24 $5.18 60% 45% 30% 15% (1) 10

Continuously Improving Drilling Efficiencies Drilling costs have declined by over 50% per foot since 2014, a substantial portion of which is due to increased efficiencies Drilling Cost Reductions (2014 to 2015) Feet drilled per Day (Operated Wells) 0% Rentals Surface Cement Daywork Fuel Casing Directional Drilling Mud 1,000 60% more feet drilled per day since 2014 (10%) (20%) (30%) (40%) (34%) (29%) (22%) (21%) 750 500 (50%) (60%) (61%) (52%) 250 (70%) (80%) (90%) (79%) Q3 2013 Q4 2013 Q1 2014 Q2 2014 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 11

Well Costs Continue to Decline Lower D&C Target Both drilling and completion costs on a per lateral foot basis have declined for six straight quarters 2016 AFE well costs of $5.5 million for a 7,500 lateral have already been achieved Potential for further well cost decreases based on realized Q4 capital costs Actual Well Cost per Lateral Foot (Operated Wells) AFEs for 7,500 Lateral ($MM) $1,500 $1,250 ~40% decrease from peak $9.0 $8.0 $7.0 $8.0 $6.3 Already achieving 2016 AFE target with potential for further reduction $1,000 $6.0 $5.0 $5.5 $5.5 $5.0 $750 $4.0 $500 $3.0 $2.0 $250 $1.0 $0 Q3 2014 Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Drilling Cost per Foot Completion Cost per Foot $0.0 2014 AFE 2015 AFE 2016 AFE Average Q4 Record Performance in Q415 Note: As of Q4 2015. Cost per lateral foot analysis includes all operated horizontal wells longer than 6,500. Record Performance column reflects best completion and drilling costs achieved in Q4 2015. 12

Well Results Continue to Improve RSP s operated horizontal well results continue to improve Completing more wells in areas with better geology and more representative of RSP s overall leasehold Ongoing improvements in completion techniques, with meaningful improvements occurring since mid-2014 As RSP has transitioned to a longer lateral drilling program, we have continued to increase efficiency on a per lateral foot basis Increasing IPs per Foot with Longer Laterals Increasing IP Rates and Average Lateral Lengths 1,200 8,500 1,000 8,000 7,500 800 7,000 600 6,500 400 6,000 5,500 200 5,000-4,500 1H14 2H14 1H15 2H15 IP-30 (Boe/d) Average Lateral Length (ft) 180-Day Cumulative Production per Foot 170 15 +41% +32% 50 1H14 2H14 1H15 2H15 IP-30 / 1,000 ft (Boe/d) Note: As of February 2016. Reflects all RSP operated horizontal wells. 0 2014 2015 180-Day Cum / ft (MBoe) 13

Western Glasscock County Update Initial Glasscock Results Similar to Spanish Trail Glasscock Well Results to Date MIDLAND CO GLASSCOCK CO Woody 1H WA: 946 Boe/d (191 per 1000 ) Woody 2H WB: 1,027 Boe/d (207 per 1000 ) Well Name Lat IP30 % IP 30 per 60 day cum Formation Length (Boe/d) Oil 1,000' (Mboe) Calverley #1H WA 9,968 1,757 83% 179 88.6 Calverley #2H Upper WB 9,830 1,877 83% 191 96.9 Woody 4-1H WA 4,954 946 83% 191 48.4 Woody 4-2H WB 4,954 1,027 83% 207 53.4 Calverley 3H LS 9,590 Calverley 4H Lower WB 9,378 Starting Flowback Calverley 1H WA: 1,757 Boe/d (179 per 1000 ) Calverley 2H UWB: 1,877 Boe/d (191 per 1000 ) Glasscock Calverley Area Development Calverley Gun Barrel View RSP s 1 st Wolfcamp B Dual Bench Test LS Q1 SPUD 3H 544 WC A 1H WC B U 2H 655 L 4H 1 Mile * All Boe figures are 3 stream Current Well Spacing WC A/Up B/Lo B - 5 wells/mile Final Spacing TBD 14

MBoe MBoe Early Production Results Demonstrate Prolific Glasscock Potential Results from the Wolfcamp A and Wolfcamp B have significantly outperformed the type curves utilized at the time of the Glasscock acquisition in 2014 as well as RSP s best current core type curves Early production is over 80% oil, compared to 70% oil forecasted in the type curves at the time of the acquisition Two Calverley long lateral horizontal wells represent the best-performing horizontal wells in RSP s history Glasscock Long Lateral Wells Glasscock Short Lateral Wells 160 140 120 +46% above Current Core Wolfcamp A Type Curve 100 90 80 70 +25% above Current Core Wolfcamp A Type Curve 100 60 80 50 60 40 20 +75% above Wolfcamp Type Curve from 2014 Acquisition 40 30 20 10 +85% above Wolfcamp Type Curve from 2014 Acquisition 0 30 60 90 120 150 180 0 30 60 90 120 150 180 2014 Acquisition 10,000' Type Curve Current WA 10,000' Type Curve 2014 Acquisition 5,000' Type Curve Current WA 5,000' Type Curve Calverley 09-04 2H WB Calverley 09-04 1H WA Note: Production data normalized for operational downtime. As of February 2016. Woody 4-1H WA Woody 4-2H WB 15

Footprint & Inventory Growth Since IPO Since the IPO in January 2014, RSP has more than doubled acreage and horizontal inventory in its Focus Area Increase in Focus Area Net Locations Focus Area Acquisitions Since IPO 1,750 1,500 1,250 1,000 750 500 250 At IPO YE 2014 YE 2015 Increase in Focus Area Acreage 50,000 40,000 30,000 20,000 10,000 At IPO YE 2014 YE 2015 Note: Statistics at IPO reflect numbers used in prospectus and marketing materials for IPO in January 2014. Acreage at IPO Acreage Acquired Post-IPO 16

Continuing Bolt-on Acreage Acquisitions in Core Areas Subsequent to the third quarter of 2015, RSP acquired ~$29 million of bolt-on interests in properties we acquired during 2015 (1) Map of Recent Acquisitions ~1,250 net acres ~115 Boe/d of net production 36 net horizontal locations Acquired additional interests in 2015 acquisition properties for ~$29 million All acquisitions reflect top-tier horizontal inventory in Midland, Martin, and Glasscock Counties Acquisitions funded with cash on the balance sheet RSP continues to selectively review opportunities to acquire core acreage in RSP s operating areas RSP Acreage 2015 Acreage Acquired 2015 Working Interests Acquired (1) Of the $29.4 million of acquisitions, $28.6 million was closed after year-end 2015. 17

Significant Upside to Focus Area Inventory from Further Downspacing RSP believes spacing tests may show significant upside to current spacing assumptions Higher density spacing cases based on RSP evaluation of original oil in place and estimated recovery factors Spacing tests to further validate higher density cases is in process Spacing Assumptions (Wells per 1-Mile Section) Current Spacing Increased Density High Density Middle Spraberry 10 12-16 14-18 Lower Spraberry 10 12-16 14-20 Wolfcamp A 5 5-8 8-10 Wolfcamp B 5-10 6-10 8-12 Wolfcamp D 5 6 7 Jo Mill 5 6 7 Clearfork 5 6 7 Wolfcamp C 5 6 7 Current Spacing Increased Density High Density Target Recovery Factor: <8% Target Recovery Factor: 8-10% Target Recovery Factor: 10-12% Gross Locations 2,591 Net Locations 1,684 Gross Locations 3,392 Net Locations 2,210 + 31% + 28% Gross Locations 4,328 Net Locations 2,813 Clearfork 5% Jo Mill 11% Wolfcamp C 2% Middle Spraberry 22% Identified 67% upside to current spacing assumptions Clearfork 4% Jo Mill Wolfcamp C 10% 1% Middle Spraberry 21% Wolfcamp D 14% Wolfcamp D 12% Wolfcamp B 11% Wolfcamp A 10% Lower Spraberry 25% Additional locations add to inventory in RSP s best zones Wolfcamp B 11% Wolfcamp A 11% Lower Spraberry 30% 18

MBoe MBoe Early Spacing Test Results are Encouraging In the Wolfcamp A & Wolfcamp B, RSP has several data points verifying the current spacing of ~1,000 on the core type curve RSP will continue to test higher densities in the Wolfcamp In the Lower Spraberry, RSP has tested both current spacing (~1,000 at same depth) and higher density wells (<500 at same depth), with encouraging results Wolfcamp Spacing Tests Lower Spraberry Spacing Tests 200 180 160 140 120 200 180 160 140 120 100 80 60 40 20 0 0 60 120 180 240 300 360 Days Note: Production data normalized to 7,500 lateral and adjusted for operational downtime. As of February 2016. 100 80 60 40 20 0 0 60 120 180 240 300 360 Days 19

2016 Operational Focus Dropped to 2 operated horizontal rigs in February Continue cost reduction program 2016 Planned Operated Horizontal Completions ANDREWS CO 20% MARTIN CO Continue increased spacing density review ECTOR CO 15% GLASSCOCK CO Continue frac design tests 20% 30% MIDLAND CO 15% 20

Boe/d RSP Permian 2016 Guidance 28,000 23,000 18,000 13,000 8,000 % Oil % Gas % NGL 21,047 Production Unit Costs (per Boe) 23,000 2015 2016E 75% 11% 14% 27,000 75% - 76% 10% - 11% 13% - 14% 2015 2016E LOE (Including Workovers) * $6.46 $5.00 - $6.00 Gathering & Transportation * $0.46 $0.45 - $0.50 Exploration Expenses $0.31 $0.25 - $0.30 Cash G&A $2.33 $2.00 $2.50 Recurring Non-Cash G&A $1.03 $1.25 $1.50 DD&A $20.05 $18.00 $20.00 Production & Ad Valorem (% of Revenue) 7.0% 7.0% - 8.0% * LOE above excludes Gathering & Transportation. However, Gathering & Transportation expenses are reported within Lease Operating Expenses on Income Statement Capital Program Overview ($ in millions) 2015 2016E Drilling & Completion $354 $185 - $235 Infrastructure & Other $37 $15 - $25 Total Capital $391 $200 - $260 (~10% Non-Operated) Operated Gross Hz Completions 45 36-48 Estimated Average Lateral Length ~7,500' Operated Gross Vt Completions 19 5 Estimated Average Operated WI 80% - 90% Operated Drilling & Completion Capital Breakdown WA MS WB Vert. LS 21

Ability to Self-Fund Drilling & Completion Through 2017 RSP currently has over $100 million in cash and an undrawn $600 million revolving credit facility Despite a challenging commodity price environment, RSP can keep 2017 production levels ~20% higher than 2015 levels with minimal borrowings and no need for capital markets activities 2017 estimates reflect capex required to maintain 2016 guidance level of 23.0 27.0 MBoe/d At strip pricing (1), maintaining 2016 production rates in 2017 could be achieved with minimal funding needs RSP expects to maintain ample liquidity, providing flexibility in determining future development pace At consensus pricing (2), maintaining 2016 production rates in 2017 could be achieved while generating a ~$100 million cash surplus In an improving oil price outlook, RSP would likely resume growth profile rather than maintain production rate 2016 2017 at Strip Pricing (1) 2016 2017 at Consensus Pricing (2) $500 $400 $300 $200 Funding needs: ~3% of current undrawn borrowing base $600 $500 $400 $300 Cash surplus would allow for acceleration with no incremental leverage $100 $200 $100 ($100) Cash Available 2016 Capex + 2017 Maintenance Capex Pro Forma 2015 Cash Balance Operating Cash Flow After Interest 2016-2017 Funding Needs Cash Available 2016 Capex + 2017 Maintenance Capex Pro Forma 2015 Cash Balance Operating Cash Flow After Interest 2016-2017 Operating Cash Surplus (1) Strip pricing as of February 17, 2016. First two months of 2016 reflect actual settlements. Average oil prices used for 2016 and 2017, respectively, are $35.63 and $42.64. (2) Broker consensus pricing as of February 17, 2016. First two months of 2016 reflect actual settlements. Average oil prices used for 2016 and 2017, respectively, are $41.63 and $53.09. 22

RSP is in a Strong Liquidity Position Selective use of capital markets to maintain strong balance sheet and liquidity Equity and debt offerings during 2015: $148 million equity offering in March 2015 $181 million equity offering and $200 million senior notes offering in August 2015 $223 million equity offering in October 2015 Undrawn borrowing base of $600 million February Ratings Agencies review: $800 $600 $400 $200 $0 S&P upgraded unsecured senior notes to B+ from B and affirmed corporate rating Moody s affirmed unsecured senior notes at B3 and corporate rating at B2 Debt Maturities ($MM) 2016 2017 2018 2019 2020 2021 2022 Senior Notes Unused Borrowing Base 6.625% Pro forma Capitalization Table (1) 12/31/2015 ($ in millions) Pro forma Cash $114 (1) Revolving Credit Facility 6.625% Senior Unsecured Notes Due 2022 700 Total Debt $700 Net Debt $586 Liquidity Borrowing Base $600 Less: Borrowings & LCs (1) Plus: Cash 114 Liquidity $714 Financial & Operating Statistics Q4 2015 Annualized Adjusted EBITDAX (2) $297.5 Q4 2015 Daily Production (MBoe/d) 24.3 Credit Metrics Net Debt / Annualized Adjusted EBITDAX 2.0x Net Debt / Latest Daily Production ($/Boe/d) $24,158 (1) Capitalization table reflects the acquisition of $28.6 million of additional working interests subsequent to December 31, 2015. Does not reflect incremental production or EBITDAX from acquired properties in leverage metrics. (2) Q4 2015 Annualized Adjusted EBITDAX represents Adjusted EBITDAX for the quarter ended December 31, 2015 multiplied by four. 23

RSP Permian Delivering Value in a Challenging Environment High Quality Assets Focused on Returns and Execution Strong Financial Position Experienced Management 24

Appendix 25

4Q15 and Year-End 2015 Financial Results 2015 2014 Change Q4 2015 Q4 2014 Change Avg Daily Production (Boe/d) 21,047 11,868 77% 24,250 16,141 50% % Oil 75% 72% 3% 75% 73% 3% Average NYMEX Oil Price $48.80 $93.00 (48%) $42.18 $73.15 (42%) Avg Realized Prices (Incl. Hedges) Oil (per Bbl) $61.22 $85.08 (28%) $53.74 $74.97 (28%) Natural Gas (per Mcf) 2.11 3.60 (41%) 1.91 3.20 (40%) NGLs (per Bbl) 9.75 25.13 (61%) 11.13 19.60 (43%) Total (per Boe) $48.96 $67.60 (28%) $43.31 $59.82 (28%) Total Revenues + Realized Hedges ($MM) $376.1 $292.9 28% $96.6 $88.8 9% Adjusted EBITDAX ($MM) 285.1 222.6 28% 74.4 66.6 12% Adjusted Net Income ($MM) 48.6 70.6 (31%) 12.1 12.6 (4%) Cash Expenses (per Boe) LOE $6.46 $7.52 (14%) $4.76 $7.01 (32%) Gathering & Transportation 0.46 0.65 (29%) 0.42 0.54 (22%) Production & Ad Valorem 2.60 4.62 (44%) 2.56 3.22 (20%) Cash G&A 2.33 3.44 (32%) 2.24 4.21 (47%) Total Cash Expenses $11.85 $16.23 (27%) $9.98 $14.98 (33%) Non-Cash Expenses (per Boe) Recurring Non-Cash G&A 1.03 0.63 63% 0.93 0.58 60% Non-Recurring IPO Stock Comp 0.19 4.04 (95%) 0.15 2.54 (94%) DD&A 20.05 21.12 (5%) 17.88 20.71 (14%) Capital Expenditures Drilling & Completion $354.0 $442.0 (20%) $54.8 $161.0 (66%) Infrastructure & Other 37.0 41.5 (11%) 9.4 29.5 (68%) Total Capital Expenditures $391.0 $483.5 (19%) $64.1 $190.5 (66%) Note: Please see reconciliation of Adjusted EBITDAX and Adjusted Net Income in Appendix. 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. 26

Adjusted EBITDAX and Adjusted Net Income Reconciliation Quarter Ended December 31, 12 Months Ended December 31, ($ in thousands, except per unit amounts) 2015 2014 2015 2014 Revenues Oil sales $67,318 $71,646 $263,286 $257,830 Natural gas sales 2,973 2,951 10,517 10,762 NGL sales 3,217 4,861 10,189 18,317 Total revenues $73,508 $79,458 $283,992 $286,909 Net cash from derivative instruments 23,122 9,379 92,118 5,943 Adjusted Total Revenues $96,630 $88,837 $376,110 $292,852 Operating Expenses Lease operating expenses $11,546 $11,222 $53,124 $35,398 Production and ad valorem taxes 5,722 4,781 19,995 20,009 General and administrative expenses 4,995 6,255 17,933 14,893 Total operating costs and expenses $22,263 $22,258 $91,052 $70,300 Adjusted EBITDAX, as defined $74,367 $66,579 $285,058 $222,552 Depreciation, depletion, and amortization $39,887 $30,758 $154,039 $91,477 Asset retirement obligation accretion 84 38 336 151 Exploration 96 899 2,380 3,854 Interest expense 13,175 9,517 43,538 14,031 Stock-based compensation, net 2,409 862 9,384 2,726 Adjusted income before income taxes $18,716 $24,505 $75,381 $110,313 Adjusted income tax expense 6,642 8,822 26,751 39,713 Adjusted net income, as defined $12,074 $15,683 $48,630 $70,600 Adjusted net income per common share - Basic $0.12 $0.20 $0.56 $0.94 Adjusted net income per common share - Diluted $0.12 $0.20 $0.56 $0.94 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. 27

Extensive Multi-Year Drilling Inventory with Strong Rates of Return Gross Focus Area Horizontal Inventory Net Focus Area Horizontal Inventory 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 <8% booked as PUDs 2,591 120 293 359 283 271 650 <6% booked as PUDs 3,392 144 359 437 333 324 957 4,328 175 431 523 459 465 1,285 Current Spacing Net Locations Increased Density High Density ~286,000 Net Effective Horizontal Acres (1) Lateral Length Middle Spraberry 357 494 590 6,911 Lower Spraberry 425 621 831 7,029 Wolfcamp A 164 203 284 7,096 Wolfcamp B 201 236 315 6,959 Wolfcamp D 231 283 342 7,029 Jo Mill 185 229 274 6,911 Clearfork 78 93 116 7,410 Wolfcamp C 42 52 61 7,750 Total 1,684 2,210 2,813 7,025 500 570 Excludes locations in Dawson County, additional zones (Strawn, Atoka, etc.) and more than 1,500 vertical locations on 40- and 20-acre spacing 782 924 Current Spacing Increased Density High Density Middle Spraberry Wolfcamp A Wolfcamp D Clearfork Lower Spraberry Wolfcamp B Jo Mill Wolfcamp C 5180 18,229 16,350 36,058 36,058 44,054 45,355 37,592 46,997 Middle Spraberry Lower Spraberry Wolfcamp A Wolfcamp B Wolfcamp D Jo Mill Clearfork Wolfcamp C Dawson / New Ventures Note: As of February 2015. Includes locations from acquisitions subsequent to December 31, 2015. (1) Combined horizontal acreage position that management believes is prospective for hydrocarbon production across each target horizontal zone. 28

IRR IRR Wolfcamp A & B Overview Performance of Wolfcamp A wells to date is as strong as any zone in RSP s inventory RSP now has 16 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 150% 100% 50% 0% Single Well Economics Wolfcamp A (1) 100% of WA Inventory on this type curve $40 $50 $60 $5.0mm D&C $5.5mm D&C $6.0mm D&C Focus Area Location Summary Single Well Economics Wolfcamp B (1) Focus Area Locations by County Ector 2% Glasscock 31% Midland / Martin / Andrews 67% Gross Net Wolfcamp A 271 164 Wolfcamp B 283 201 Total 554 366 Average Length (ft) 7,026 60% 50% 40% 30% 20% 10% 0% 95% of WB Inventory on this type curve $40 $50 $60 $5.0mm D&C $5.5mm D&C $6.0mm D&C (1) Assumes 7 500 lateral type curve in Core Counties. Core Counties defined as Midland, Martin, Andrews and Glasscock. 29

IRR IRR Lower & Middle Spraberry Overview Lower Spraberry remains the top performing zone in RSP s inventory, but Middle Spraberry economics also reflect robust potential 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 Focus Area Location Summary 150% 100% 50% 0% Single Well Economics Lower Spraberry (1) 85% of LS Inventory on this type curve $40 $50 $60 $5.0mm D&C $5.5mm D&C $6.0mm D&C Single Well Economics Middle Spraberry (1) Focus Area Locations by County Glasscock 10% Ector 17% Midland / Martin / Andrews 73% Gross Net Middle Spra. 570 357 Lower Spra. 650 425 Total 1,220 783 Average Length (ft) 6,975 100% 80% 60% 40% 20% 0% 82% of MS Inventory on this type curve $40 $50 $60 $5.0mm D&C $5.5mm D&C $6.0mm D&C (1) Assumes 7 500 lateral type curve in Core Counties. Core Counties defined as Midland, Martin, Andrews and Glasscock. 30

Cumulative MBoe Lower Spraberry and Middle Spraberry Type Curves Spraberry Type Curve and Operated Wells in Core Counties since Mid-2014 (Normalized to 7,500 ) 200 16 Lower Spraberry wells 150 100 6 Middle Spraberry wells 50 EURs: ~75% Oil 360-Day Cum: ~80% Oil 0 0 30 60 90 120 150 180 210 240 270 300 330 360 830 MBoe Wolfcamp A Type Curve Average Lower Spraberry wells 715 MBoe Middle Spraberry Type Curve Average Middle Spraberry wells Note: Core Counties are defined as Midland, Martin, Andrews, and Glasscock. Production data normalized for operational downtime. As of February 2016. 31

Cumulative MBoe Wolfcamp A and Wolfcamp B Type Curves Wolfcamp A/B Type Curves and Operated Wells in Core Counties since Mid-2014 (Normalized to 7,500 ) 200 150 16 Wolfcamp A wells 100 17 Wolfcamp B wells 50 EURs: ~75% Oil 360-Day Cum: ~80% Oil 0 0 30 60 90 120 150 180 210 240 270 300 330 360 800 MBoe Wolfcamp A Type Curve Average Wolfcamp A wells 715 MBoe Wolfcamp B Type Curve Average Wolfcamp B wells Note: Core Counties are defined as Midland, Martin, Andrews, and Glasscock. Production data normalized for operational downtime. As of February 2016. 32

Boe/d Spanish Trail Extended Reach Laterals RSP is currently developing the Company s longest laterals drilled to date on the Spanish Trail lease (>11,000 ) Two Wolfcamp B wells and two Wolfcamp A wells on production with strong results Production has averaged over 1,100 Boe/d since IP Lower Spraberry development began late Q3 2015 Average Cum. Production of ~146 MBoe Through 130 Days Spanish Trail Long Lateral Development 4717 WA 4719 WA 4717 WB 4719 WB Peak 24-Hour IP (Boe/d) 1,886 1,946 1,625 1,643 30-Day IP (Boe/d) 1,594 1,321 1,442 1,313 N 1,000 110 100 0 10 20 30 40 50 60 70 80 90 100 110 120 130 Average of Four Upper Wolfcamp Wells Note: Production data normalized for operational downtime. As of February 2016. 33

Eagle Ford Comparison to RSP s Midland Basin Acreage Eagle Ford development originally targeted the lower unit (150 thick) and is now expanding into the upper unit (150 ) Well spacing has evolved from 5 wells/section down to 14-16 wells/section, with chevron pattern testing including the upper unit RSP s targets in the Wolfcamp and Lower Spraberry have a combined thickness 3x that of the Eagle Ford RSP is currently testing and evaluating down spacing options in each of the target intervals RSP Well Density Optimization (Current Targets) Initial Development High Density Lower Spraberry 500 ~1000 ~500 ~1000 ~500 10 wells/ section 20 wells/ section Dean 400 175 Initial Development Eagle Ford Development Progression Current Testing Wolfcamp A ~1150 ~660 250 Upper Eagle Ford 150 1155 5 wells/ section 8 wells/ section Wolfcamp B Lower Eagle Ford ~1150 ~660 250 150 5 wells/ section 16+ wells/ section 5 wells/ section 8 wells/ 8 wells/ section section RSP believes that downspacing opportunities exist in the Middle Spraberry as well, but are currently focusing efforts on the Upper Wolfcamp and Lower Spraberry. 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. 35