Forward-Looking Statements

Transcription

1 RSP Permian Bank of America Merrill Lynch 2016 Global Energy Conference November 17, 2016

2 Forward-Looking Statements Certain statements and information in this presentation may constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 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 ability to assimilate acquisitions into our operations, the assumptions underlying production forecasts, our hedging strategy and results, the quality of technical data, environmental and weather risks, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the costs and results of drilling and operations, the availability of equipment, services, resources and personnel required to complete RSP s operating activities, access to and availability of transportation, processing and refining facilities, the financial strength of counterparties to the 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 Reports on Form 10-K and Quarterly Reports on Form 10-Q. Existing and prospective investors are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. 2

3 RSP Permian Overview (NYSE: RSPP) Large, contiguous acreage blocks in the core of the Midland and Delaware Basins (1) Midland: ~60,700 net surface acres and ~270,000 net effective horizontal acres (2) ~96% operated Delaware: ~41,000 net surface acres and ~250,000 net effective horizontal acres ~80% operated Current run rate production of ~50 MBoe/d ~5,800 horizontal locations in inventory with significant upside Efficient operator focused on execution Leading F&D costs, reserve replacement ratios and operating costs Drilled wells in five different horizontal benches in Midland Basin Q Key Statistics Market Capitalization (11/15/16): 3Q16 Average Production: YE 2015 Proved Reserves: Net Debt / TTM EBITDAX (3)(4) : Liquidity as of 9/30/16: $5.1 billion 29.8 MBoe/d MMBoe 3.0x $587 million (1) Silver Hill acquisition pending, expected close in Q and Q (2) Combined horizontal acreage position that Management believes is prospective for hydrocarbon production across each target horizontal zone. (3) Please see reconciliation of Adjusted EBITDAX in Appendix. (4) Based on Q net debt and TTM Adjusted EBITDAX. Contiguous Acreage Position in Core of Permian Basin Delaware Basin Acquisition (1) ~41,000 net acres ~3,200 gross locations Midland Basin ~60,700 net acres ~2,600 gross locations in focus area >100,000 largely contiguous net surface acres and >500,000 net effective horizontal acres in the core of each basin 3

4 Financial and Operating Highlights 3Q Results 4Q Midland Basin Operating Plans Silver Hill Acquisition & Financing 2016 Guidance & 2017 Outlook Average daily production of 29.8 MBoe/d (73% oil), up 13% from 2Q16 Completed 17 operated Hz wells, 1 operated Vt well and 13 non-op Hz wells Adjusted EBITDAX of $65.7MM with $73.2MM of 3Q16 development Capex Record low cash operating expenses of $9.36/Boe, 6% lower than 2Q16 3 rigs running, with 1 full-time completion crew Plan to complete operated wells in 4Q 40-50% focused in the Lower Spraberry zone Expect to end 2016 with 8-12 DUCs (1) Entering into 6 month contract for 4th Hz rig in Midland Basin, expected to arrive in January 2017 On October 13, 2016, announced acquisition of Silver Hill for approximately $2.4 billion Consideration includes $1.25 billion in cash and 31.0 million shares of RSP common stock On track to close SHEP I by the end of November 2016; SHEP II expected to close in Q On October 19, 2016, completed underwritten public offering of 25.3MM shares of common stock for total net proceeds of approximately $1.0 billion Expected full-year production range increased to MBoe/d Development capital expenditure budget narrowed to $295 - $315 million Preliminary full-year 2017 production range of MBoe/d with development capex of $570 - $630 million (1) DUC is a drilled but uncompleted well. 4

5 2016 Horizontal Well Performance Exceeding Type Curves The average of all operated horizontal wells brought online in 2016 YTD is outperforming the weighted average internal type curve by ~25% This group of wells includes, among others, R&D wells testing high density stimulation, increased density spacing and alternate landing zone tests All Hz Wells Completed YTD vs. Weighted Avg. Type Curve (Boe) ~25% Outperformance through 230 Days Days Avg. Cum. Production Weighted Avg. Type Curve 5

6 Low Cost Structure and Strong Margins Operating margins remain strong despite drop in realized oil prices due to cost controls and prolific wells Historical Cash Margins and Costs (per Boe) $ % $ % 72% 69% 71% 70% 71% 73% 75% $ % 60% Peer Mean (1) 67% 60% $15.00 $10.00 $5.00 $15.09 $14.98 $14.65 $13.58 $3.22 $4.98 $2.92 $2.99 $2.95 $4.21 $2.47 $3.19 $8.78 $6.92 $7.55 $8.12 $10.50 $9.98 $9.88 $9.99 $2.12 $1.92 $6.46 $2.56 $1.85 $2.06 $2.24 $2.19 $2.06 Peer Mean (1) $10.30 $9.36 $2.14 $2.04 $5.18 $5.84 $5.87 $ % 30% 15% Q Q Q Q Q Q Q Q Q LOE, Gathering & Transporation, & Workovers Cash G&A Prod. & Ad Val Cash Margin (Excluding Hedges) (1) Permian peers include CPE, CXO, FANG, LPI, PE, and PXD. (2) Cash Margin (Excluding Hedges) is calculated as the Realized Price per Boe (Excluding Hedges) less the cash costs listed in the chart, divided by the Realized Price per Boe (Excluding Hedges) (2) 6

7 A RSPP C D E F G H I J K L M N O P Q R S T U V W X Y Z AA AB AC AD AE AF AG AH AI AJ AK AL AM AN AO AP AQ AR AS AT AU AV AW AX AY AZ BA BB BC Superior Recycle Ratio Premier assets and operational expertise leading to one of highest recycle ratios in the E&P industry Leading cash flow margin/boe and low F&D cost/boe High cash margins driven by low cost operations and strong well performance Low PDP F&D costs (1) a result of intense focus on maximizing EURs and reducing D&C costs 3Q16 Cash Margin / Boe $25.00 $23.64 $20.00 $15.00 $12.73 $10.00 $5.00 $0.00 RSPP E&P Universe Median 2015 PDP F&D Cost (1) / Boe $20.00 $18.07 $15.00 $9.77 $10.00 $5.00 $0.00 RSPP E&P Universe Median 2.75x 2.50x 2.25x 2.00x 1.75x 1.50x 1.25x 1.00x 0.75x 0.50x 0.25x E&P Universe Q Recycle Ratio (2) RSPP U.S. E&P Company Permian Peer (3) Cash Flow per Boe > PDP F&D Cost per Boe Mean: 0.76x Note: Per Seaport Global Securities ( SGS ) estimates. 1) Defined as exploration and development costs divided by PDP reserve additions as calculated by SGS. 2) Q Recycle Ratio calculated as unhedged Q cash operating margin per Boe divided by PDP F&D cost per Boe as calculated by SGS. 3) Permian peers include CPE, CXO, FANG, LPI, PE, and PXD. 7

8 Updated 2016 Guidance and Preliminary 2017 Outlook YTD 2016 Actuals and Revised Full Year Guidance Aug. Revised Oct. Revised YTD Production Actual Guidance (1) Guidance Average Daily Production (Boe/d) 26,931 26,500-28,500 28,500-29,500 % Oil 74% 75% - 76% 73% - 75% % Natural Gas 11% 10% - 11% 10% - 11% % NGLs 15% 13% - 14% 14% - 15% Income Statement ($/Boe) LOE (Including Workovers) $5.16 $ $6.00 $ $6.00 Gathering & Transportation $0.44 $ $0.50 $ $0.50 Exploration Expenses $0.11 $ $0.15 $ $0.15 Cash G&A $2.09 $ $2.25 $ $2.25 Recurring Non-Cash G&A $1.34 $ $1.50 $ $1.50 DD&A $19.23 $ $21.00 $ $21.00 Prod. & Ad Val. (% of Rev.) 6.5% 6.0% - 7.0% 6.0% - 7.0% Capital Expenditures ($MM) Drilling & Completion $187.4 $270 - $290 $280 - $290 Infrastructure & Other $11.3 $15 - $25 $15 - $25 Total Development Capital $198.7 $285 - $315 $295 - $315 % Non-Operated 16% 10% - 15% 10% - 15% Completions Operated Gross Hz Operated Gross Vt Midland Basin: 4 rigs Guidance Update Production guidance increased by 5% at the midpoint based on well results exceeding expectations, including shallower decline profiles Narrowed capex range Guidance now incorporates flexibility for two Delaware Basin operated Hz completions in late 4Q16 Preliminary 2017 Outlook Delaware Basin: 2 rigs ramping to 4 by YE 2017 Production: 52,000-56,000 Boe/d Oil: 72% - 74% Natural Gas: 11% - 12% NGLs: 14% - 15% Total Development Capital: $570 - $630 million Drilling & Completion: Infrastructure & Other: $520 - $560MM $50 - $70MM % Non-Operated: 10% - 15% (1) Reflects guidance previously published by RSP in August

9 RSP is in a Strong Financial Position With strong liquidity, no near-term maturities, an improved hedge position and attractive returns on our drilling, RSP is well positioned to accelerate activity beyond current levels $600MM borrowing base Anticipate borrowing base will be increased upon closing SHEP I and SHEP II transactions During 1Q16, Moody s confirmed RSP s B3 rating on its senior notes and S&P upgraded the senior notes a notch to B+ $800 $600 $400 $200 $0 Debt Maturities ($MM) (1) Please see reconciliation of Adjusted EBITDAX in Appendix % Unused Borrowing Base Revolving Credit Facility Borrowings Senior Notes Capitalization Table ($ in millions) Q Cash $22 Revolving Credit Facility % Senior Unsecured Notes Due Total Debt $735 Net Debt $713 Liquidity Borrowing Base $600 Less: Borrowings & LCs (36) Plus: Cash 22 Liquidity $587 Financial & Operating Statistics Q TTM Adjusted EBITDAX (1) $234.2 Q Daily Production (MBoe/d) 29.8 Credit Metrics Net Debt / TTM Adjusted EBITDAX 3.0x Net Debt / Latest Daily Production ($/Boe/d) $23,945 9

10 Hedging Program Summary RSP opportunistically layers on hedges to protect returns and support planned capital expenditures Recently executed additional hedging arrangements to protect remaining 2016 and 2017 volumes Deferred premium put structure allows RSP to retain upside to future oil price increases Hedge Contract Detail Crude Oil (Bbl, $/Bbl) 4Q 16 1Q 17 2Q 17 3Q 17 4Q Three-Way Collars (1) 120, , ,000 Ceiling Floor Short Put $74.41 $55.00 $45.00 $54.25 $45.00 $35.00 Costless Collars (1) 450,000 1,137,500 1,150,000 1,150,000 3,887,500 Ceiling Floor $59.75 $45.00 Deferred Premium Puts / Put Spreads (1) 1,125, , , , ,000 3,425,000 Floor Short Put Deferred Premium (2) $45.00 ($2.74) Total Hedge 1,245,000 Weighted Average Floor (3) $43.49 $45.00 $35.00 ($2.32) 1,800,000 $44.13 $60.05 $45.00 $48.50 ($4.00) 2,047,500 $44.78 $60.05 $45.00 $48.50 ($4.00) 2,070,000 $44.78 $60.05 $45.00 $48.50 ($4.00) 2,070,000 $44.78 % Hedged on Midpoint Oil Volume Guidance (5) 53% 56% Natural Gas (MMBtu, $/MMBtu) 4Q 16 1Q 17 2Q 17 3Q 17 4Q (1) The crude oil derivative contracts are settled based on the arithmetic average of the closing settlement price for the front month contract NYMEX price of West Texas Intermediate Light Sweet Crude. (2) The deferred premium is not paid until expiration date, aligning cash inflows and outflows with the settlement of the derivative contract. (3) Weighted average floor assumes the long put in three way collars and put spreads and reflects the impact of premiums paid. (4) The natural gas derivative contracts are settled based on the last trading day s closing price for the front month contract relevant to each period. (5) Utilizing 4Q16 and 2017 midpoint oil volume guidance. $54.25 $45.00 $35.00 $60.02 $45.00 $47.81 NM ($3.67) 7,987,500 $44.63 Costless Collars (4) 900, , , ,000 3,650,000 Ceiling Floor $3.64 $3.00 $3.64 $3.00 $3.64 $3.00 $3.64 $3.00 $3.64 $

11 Midland Basin Operational Update 11

12 Well Cost Update After declining for six straight quarters, drilling, completion & equipping costs have increased modestly Increase was in line with expectations based on significant increase in frac density employed vs. beginning of year Latest vintage completion design includes more than 1,900 lbs/ft of proppant, +/-14 perf clusters per stage and diverter agents Expect enhanced well performance to more than offset incremental cost, resulting in a net positive impact on per well and per section NPVs Two of three RSP rigs currently running have day rates of more than $25,000/d As two older rigs roll off contract in January and April of 2017, RSP will transition average day rate towards current market levels Drilling, Completion & Equip. Cost (7,500 lateral) $5.5-$5.9 MM $5.2-$5.6 MM Contingency Spanish Trail Avg. 100 Day Cum. Production (MBoe) 160 +$250k +$250k Equip 120 Decreased day rate: -$350k Enhanced Compl Base Compl Drill Old Old Rig Rig Rate New New Rig Rig Rate Spanish Trail Old Vintage Completion Spanish Trail New Vintage Completion Avg. 12

13 Density Pilots Spanning Acreage Position In multiple spacing pilots across our core acreage position, RSP has successfully completed wells at or above our type curve using 3 different landing targets RSP believes vertical separation (staggering) between landing targets allows for more dense drilling Potential for simultaneous development of 3 landing intervals within the Lower Spraberry exists in some areas Spacing Pilots Delineate Core Position Spanish Trail Johnson Ranch Lower Spraberry 400 Producing Producing Dean 1 Mile (5280 ) Upper Landing Target Intermediate Landing Target Lower Landing Target 13

14 MBoe Strong and Consistent Wolfcamp A Performance Across Position RSP has tested the Wolfcamp A zone across its core acreage position with excellent results to date (20 operated Hz Wolfcamp A wells) The Kemmer 4217 WA represents RSP s westernmost Wolfcamp A well to date and also its strongest performer on a per foot basis Implies an increase to Wolfcamp A inventory (currently not carried along western edge of acreage) Selected Top Wolfcamp A Wells Across Position total operated Hz Wolfcamp A wells 5 Select West & East Side Wolfcamp A Wells Days 1MMBOE Peer Type Curve Kemmer 4217 WA Woody 1H WA Wolfcamp A Well Performance Well Name Lateral Length IP30/1,000 (Boe/d) 1 Kemmer 4217 WA 4, Cross Bar Ranch 3027 WA 6, Spanish Trail 228 WA 6, Johnson Ranch 1021 WA 7, Woody WA 4, Calverley WA 9, Latest vintage completion design 14

15 MBoe Spanish Trail Long Laterals Exceeding Expectations RSP s longest LS laterals to date completed in Spanish Trail Section 47 (10,500 +) On average, wells have produced over 100MBoe in first 90 days Full half-section developed on base spacing; all producing wells performing above peer 1MMBoe type curve with no observable degradation Results to date strengthen case for increased well density Spanish Trail Section 47 Update Spanish Trail Performance Days 1MMBOE Peer Type Curve WA Avg. WB Avg. LS Avg. 15

16 MBoe Cross Bar Ranch Lower Spraberry Increased Density Pilot RSP s 500 spacing test at Cross Bar Ranch has performed above expectations despite relatively less oil in place vs. other RSP core acreage Original 3 wells of pattern completed during July 2015 with prior frac design; next 3 wells completed during August 2016 with latest vintage frac design Performance to date strongly supportive of high density frac design paired with downspacing Cross Bar Ranch Section 17 Update Cross Bar Ranch LS Performance Days 7,500' LS Type Curve (~830MBoe) Original 3 Well Avg. (prior frac design) Next 3 Well Avg. (latest vintage frac design) 16

17 MBoe MBoe Western Glasscock Generating Strongest Economics Across Leasehold Calverley Area Update RSP s two initial Calverley wells continue to outperform peer 1MMBOE type curve MIDLAND CO GLASSCOCK CO Two test wells, 3H LS and 4H LWB, are now producing in line with peer 1MMBOE type curve after R&D efforts reduced upfront well results Calverley Wells Two recently completed LS wells were placed on ESP, have been producing for ~60 days and are tracking peer 1MMBOE type curve Two additional Upper Wolfcamp wells scheduled to be completed during 4Q16 or 1Q17 LS WA WB U L 5H 6H DUCs 4H 2H 3H 1H 3H 1H 2H Calverley LS Performance ESP Gas Lift Days 1MMBOE Peer Type Curve 3H LS 5H LS & 6H LS Avg Calverley WC Performance Days 1MMBOE Peer Type Curve 2H UWB First 60 days restricted for R&D 1H WA 4H LWB 17

18 Acquisition Overview 18

19 Silver Hill Acquisition Overview Silver Hill Acquisition Highlights Highly contiguous operated position in the core of the Delaware Basin ~68,000 gross / ~41,000 net acres ~80% operated with over 80% working interest in operated properties (acreage held by one operated rig) Conducive to efficient long lateral development Meaningful current production base of ~15 MBoe/d 69% oil and 86% liquids 2 operated horizontal rigs currently running 49 producing Hz wells and 9 producing Vt wells Over 4,500 ft. of stacked pay with 7 producing, horizontal zones ~250,000 net effective horizontal acres Includes the Wolfcamp B, Lower and Upper (XY) Wolfcamp A, 3 rd Bone Spring, 2 nd Bone Spring, 1 st Bone Spring and Avalon Key offset operators include EOG, Anadarko, Shell, Matador and Devon, among others Decades of highly economic horizontal drilling inventory ~3,200 gross / ~1,950 net drilling locations, largely operated Accretive to cash flow, production and NAV at current strip prices NEW MEXICO TEXAS Wolfcamp Structure Map (Subsea Depths) Culberson Eddy Reeves SILVER HILL ACREAGE Loving WOLFCAMP STRUCTURE (TVDSS) CONTOUR INTERVAL = 500 Lea Ward Winkler Pecos Gaines Andrews 19

20 RSP is a Selective Acquirer: Why Silver Hill? RSP has taken a measured approach to acquisitions successfully growing asset base without sacrificing quality Silver Hill Meets All Key Acquisition Criteria Rock Quality: Silver Hill located in the deepest, thickest over-pressured portion of the Delaware Basin characterized by low GOR Drives higher IPs, EURs and economics as well as higher density development across multiple zones Inventory includes horizontal wells with EURs of ~1.0 MMBoe and single well IRRs over 70% (1) at current strip pricing Delineated: high number of producing, de-risked zones Horizontals producing in 7 zones, including multiple Wolfcamp and Bone Spring targets as well as Avalon Affords meaningful long-term scale and enhanced NAV Contiguous: blocky acreage position Allows for efficient development with enhanced economics from the use of long-laterals Scale: meaningful existing base of production and cash flow 15 MBoe/d (69% oil, 86% liquids) as of October 2016 Significantly larger production base than the majority of recently evaluated opportunities (1) Based on Management estimates. 20

21 Strategic Combination Substantially Increases Scale Gross Horizontal Drilling Locations Net Surface Acreage Current Production (MBoe/d) (1) +123% +68% +43% ~5,800 ~101,700 ~50 ~2,600 ~60,700 ~35 RSP PF RSP RSP PF RSP RSP PF RSP Net Horizontal Drilling Locations Net Effective Horizontal Acreage Current Rigs Running +115% ~3, % ~512, % 5 ~1,700 ~262,000 3 RSP PF RSP RSP (1) Represents RSP current 3-week run-rate production and Silver Hill production as of October PF RSP RSP PF RSP 21

22 Penn Wolfcamp Leonard Guadalupe Delaware Group Superior Delineation Drives Acreage Value Selected Delaware Basin Operator Development Targets Silver hill Cimarex MTDR Enduranc e CXO EOG Shell Brigham FANG PDCE WPX Lamar Bell Canyon Cherry Canyon Brushy Canyon t t t Avalon Shale t t t t t 1 st Bone Spring t t t t t t t t t 2 nd Bone Spring t t t t t t t t t 3 rd Bone Spring t t t t t t t t t t t Upper (XY) / Lower Wolfcamp A t t t t t t t t t t t t t t Wolfcamp B t t t t t t t t t t t t Wolfcamp C t t t t t Wolfcamp D / Cline t t Strawn Atoka TOTAL Note: Latest investor presentations, Wall Street research and Texas Railroad Commission. Disclosed Horizontal Penetration t 22

23 Economics of Delaware Basin Provide Compelling Opportunity Delaware Basin Technical Highlights Thick, oil saturated section within the over-pressured Wolfcamp and Bone Spring Wolfcamp and Bone Spring thicker in the Delaware Basin due to the more protracted subsidence history Delaware / Midland Geologic Comparison Silver Hill Type Log Top 10 Inventory Overview (1) Core Midland Basin Type Log Reservoir Glasscock Upper Wolfcamp LL (ft.) EUR (MBOE) EUR / 1,000 Strip (2) 7, >70% Wolfcamp A 7, >70% Upper Wolfcamp (XY) 4, >70% Lower Spraberry 7, % Lower Wolfcamp A 4, % 2 nd Bone Spring 4, % Wolfcamp B 7, % Middle Spraberry 7, % Wolfcamp B 4, % 3 rd Bone Spring 4, % Midland Basin Delaware Basin (1) Based on Management estimates. (2) Based on Midland Basin D&C cost of $5.5 MM (7,500 lateral) and Delaware Basin D&C costs of $5.7-$6.1 MM (4,500 lateral), depending on zone. 23

24 Silver Hill Properties Stack Up Well with Our Current Inventory Silver Hill short lateral well performance competes with and in some cases exceeds Midland basin long lateral well performance Potential for uplift in upfront deliverability and increasing ultimate recoveries from drilling longer laterals Upper Wolfcamp Cumulative Production (Boe) Bone Spring / Lower Spraberry Cumulative Production (Boe) 600, , , , , , , , , , , , Days (1) Midland Peer 1 MMBoe Type Curve Silver Hill 4,500' Upper Wolfcamp A (XY) RSP 7,500' Avg. Glasscock Upper Wolfcamp (2) Silver Hill 7,500' Upper Wolfcamp A (XY) Source: Management estimates. (1) Based on peer public filings. (2) Normalized to 7,500 based on ratio of lateral lengths Days (1) Midland Peer 1 MMBoe Type Curve Silver Hill 4,500' Bone Spring RSP 7,500' Core County Lower Spraberry Type Curve (2) Silver Hill 7,500' Bone Spring 24

25 Multi-Zone Potential Across Silver Hill Assets White Falcon 16 #1H 1 Endurance IP30: 1,813 Boepd 2 Gunner Fed 5H Concho IP30: 1,306 Boepd Rudd Draw 3H John James 1H Brunson 47 1H Brunson 38 1H 26 Silver Hill 25 Concho 24 EOG 23 EOG IP30: 1,084 Boepd IP30: 1,306 Boepd IP30: 1,635 Boepd IP30: 1,870 Boepd Brunson A 803H Silver Hill IP30: 1,027 Boepd Brunson 1121H Silver Hill IP30: 1,025 Boepd 3 Brunson 1111H Silver Hill IP30: 840 Boepd 20 University B201 Mewbourne IP30: 850 Boepd 4 Brunson C 1002H Concho IP30: 837 Boepd NEW MEXICO TEXAS 19 Rippin Wrangler 1 Anadarko IP30: 845 Boepd 5 Ragin Cajun 2H Devon IP30: 898 Boepd 18 Bullet H (1) Silver Hill IP30: 940 Boepd State Galileo 6H EOG IP30: 2,252 Boepd Coachman Fee 4H Concho IP24: 1,142 Boepd Ludeman 1404H Silver Hill IP30: 659 Boepd Univ. Block H 9 XTO IP30: 890 Boepd Ragin Cajun 2H Excelsior 7 #7H Ludeman D 302H Ludeman D 102H H&T H Devon 10 EOG 11 Silver Hill 12 Silver Hill 13 Anadarko IP30: 898 Boepd (85% IP30: 2,003 Boepd IP30: 1,335 Boepd IP30: 1,361 Boepd IP30: 1,148 Boepd oil) Source: Silver Hill data. Note: Well results not intended to be representative across all Silver Hill assets or an indication of future well results. (1) Estimated 3 stream with well still on a restricted choke Whitney Brunson EOG IP30: 1,398 Boepd Harrison 43 W102 Mewbourne IP30: 977 Boepd Falcon State #1H Energen IP30: 818 Boepd Corsair H Anadarko IP24: 2,253 Boepd 25

26 RSP Permian Delivering Value High Quality Assets Focused on Returns and Execution Strong Financial Position Experienced Management 26

27 Appendix 27

28 Boe/d 3Q16 Activity Summary DUC inventory approaching normalized levels, distributed across core position In 3Q16, RSP completed 17 operated Hz wells (11 LS, 3 WA, 3 WB) and 1 Vt well Ended 3Q16 with 12 operated Hz DUCs (18 nonoperated DUCs) Production averaged 29,761 Boe/d during 3Q16, up from 26,407 Boe/d during 2Q16 3Q16 Drilling & Completion Activity Summary 2Q16 DUCs Progression of YTD Net Production (Weekly Basis) Drilled Completed 3Q16 DUCs Operated Horizontal Vertical Total Non-Operated Horizontal Vertical ,000 34,000 Q1 Q2 Q2 Q3 32,000 30,000 28,000 26,000 1Q16 Avg. Production of 24,615 Boe/d 2Q16 Avg. Production of 26,407 Boe/d 3Q16 Avg. Production of 29,761 Boe/d 24,000 22,000 1/1/16 2/1/16 3/1/16 4/1/16 5/1/16 6/1/16 7/1/16 8/1/16 9/1/16 10/1/16 28

29 2016 Drilling & Completion Activity Update In 4Q16, RSP expects to complete operated wells in the Midland Basin 40-50% focused in the Lower Spraberry zone 4Q16 drilling and completion activity contemplates: 3 existing rigs 1 full-time frac crew Expect to end 2016 with 8-12 DUCs in the Midland Basin YTD Operated Completions by Zone WA 22% WB 13% LS 64% MS 2% 2016 Midland Basin Operated Horizontal Drilling & Completion Summary YE 1Q16 2Q16 3Q16 4Q16 1Q16 2Q16 3Q16 4Q YE DUCs Drill Complete DUCs 29

30 Executing Accretive Bolt-on Acquisitions in Core Midland Areas YTD 2016 (through September), RSP has acquired ~$62 million of bolt-on oil and gas properties: Locator Map of 2016 YTD Acquisitions ~2,500 net acres located in core Midland, Martin, and Glasscock Counties ~$19 million of acquisitions in 3Q16 Acquisitions funded with cash on the balance sheet ~$62MM in 2016 acquisitions 30

31 3Q16 Financial Results 3Q16 3Q15 % Change 2Q16 % Change Avg Daily Production (Boe/d) 29,761 24,000 24% 26,407 13% % Oil 73% 75% (3%) 73% Average NYMEX Oil Price $44.94 $46.43 (3%) $45.59 (1%) Avg Realized Prices (Incl. Hedges) Oil (per Bbl) $41.46 $57.36 (28%) $43.05 (4%) Natural Gas (per Mcf) % NGLs (per Bbl) % (7%) Total (per Boe) $33.37 $45.98 (27%) $34.32 (3%) Total Revenues + Realized Hedges ($MM) $91.4 $101.5 (10%) $ % Adjusted EBITDAX ($MM) (16%) % Adjusted Net Income (Loss) ($MM) (0.8) 13.5 (106%) (3.8) 80% Cash Expenses (per Boe) LOE $4.67 $6.08 (23%) $5.37 (13%) Gathering & Transportation % % Production & Ad Valorem % % Cash G&A % 2.06 (1%) Total Cash Expenses $9.36 $10.50 (11%) $9.99 (6%) Non-Cash Expenses (per Boe) Recurring Stock Comp % 1.46 (18%) Non-Recurring Stock Comp 0.15 (100%) 0.28 (100%) DD&A (6%) (7%) Capital Expenditures Drilling & Completion $65.3 $86.0 (24%) $ % Infrastructure & Other (16%) % Total Capital Expenditures $73.2 $95.3 (23%) $ % Note: Please see reconciliation of Adjusted EBITDAX and Adjusted Net Income in Appendix. 31

32 Adjusted EBITDAX and Adjusted Net Income Reconciliation Reconciliation of Net Income (Loss) to Adjusted EBITDAX (in thousands) Three Months Ended September 30, Three Months Ended June 30, Net Income (Loss) $ 985 $ 8,974 $ (9,801) Interest Expense Income Tax Expense (Benefit) DD&A Impairments Exploration Expense Loss (Gain) on Derivative Instruments 13,146 11,680 12,954 (3,507) 4,953 (4,438) 50,022 43,031 47, ,238 3, ,934 (18,098) 3,684 Net Cash Payments on Settled Derivative Instruments (2,258) 20, Non-Cash Equity Based Compensation Asset Retirement Accretion Other income, net Loss (gain) on Sale of Assets 3,272 2,432 4, (310) (66) (104) Adjusted EBITDAX $ 65,732 $ 78,329 $ 58, Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss) (in thousands) Three Months Ended Three Months Ended September 30, June 30, Net income (loss) $ 985 $ 8,974 $ (9,801) Impairments 971 4,238 3,177 Loss (gain) on derivative instruments Net cash payments on settled derivative instruments Stock-based compensation - non-recurring Other income, net 2,934 (18,098) 3,684 (2,258) 20, (310) (66) (104) Loss (gain) on asset sale Income tax expense (benefit) for above items (3,086) (2,458) (2,370) Adjusted Net Income (Loss) $ (764) $ 13,473 $ (3,758) 32

33 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 These filings also can be obtained from the SEC by calling SEC