RSP Permian Investor Presentation January 2016

Transcription

1 RSP Permian Investor Presentation January 2016

2 Forward-Looking Information Certain statements and information in this presentation may constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 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 forwardlooking 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

3 RSP Permian Overview (NYSE: RSPP) Large, contiguous, core acreage blocks in the Midland Basin Concentrated Acreage Position in the Core of the Midland Basin ~225,000 net effective horizontal acres (1) and ~63,000 net surface acres (96% operated) ~2,400 horizontal and ~1,700 vertical drilling locations Dawson Area Average horizontal lateral length of ~7,100 Efficient operator focused on execution Drilled wells in five different horizontal benches Focus Areas Peer-leading F&D costs, cash operating costs per Boe and cash margins per Boe Key Statistics Market Capitalization (1/4/16): 3Q 2015 Production: YE 2014 Proved Reserves: Net Debt / Annualized EBITDAX (2)(3) : Current Liquidity (3) : $2.5 billion 24.0 MBoe/d MMBoe 1.8x $738 million Note: All acreage and location totals pro forma for acquisitions closed in (1) Combined horizontal acreage position that management believes is prospective for hydrocarbon production across each target horizontal zone. (2) Based on pro forma Q net debt and Adjusted EBITDAX annualized. Please see reconciliation of Adjusted EBITDAX in Appendix. (3) Includes the November closing of the Wolfberry Partners Resources, LLC acquisition (WPR Acquisition) and the October financings. RSP Acreage TX Net Effective Horizontal Acres Clearfork 15,956 Middle Spraberry 45,171 Lower Spraberry 52,618 Wolfcamp A 34,030 Wolfcamp B 36,313 Wolfcamp D 38,686 Total 222,774 3

4 Recent Acquisitions Add Significant Scale to Core Acreage Since August 2015, RSP has acquired ~10,700 net acres for ~$450 million (1) Map of Recent Acquisitions ~3,500 Boe/d of net production 277 net horizontal locations ~47,000 net effective horizontal acres All acquisitions reflect high-quality inventory in RSP s Focus Area (2) Increased Focus Area (2) net locations by 26% and Focus Area (2) net acreage by 27% Recent Acquisitions Additions Net Focus Area Horizontal Locations % +28% % +33% +23% MS LS WA WB WD RSP Existing Acreage New Acreage Additional Interests Acquired 6/30/2015 Pro Forma (1) Includes ~$39 million of subsequent acquisitions of acreage and production from non-operated partners on the acquisition properties announced in August (2) Focus Area defined as adjacent counties of Midland, Martin, Andrews, Ector, and Glasscock. 4

5 Low Cost Structure and Strong Margins High oil mix and five straight quarters of declining operating costs result in strong cash margins despite low oil price 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 $30.00 $ % 78% 72% 69% 71% 90% 75% $20.00 $ % 60% $15.00 $10.00 $6.12 $3.66 $15.09 $14.98 $14.65 $3.22 $4.98 $2.92 $4.21 $2.95 $3.19 $13.58 $2.99 $2.47 $10.50 $2.12 $ % 30% $5.00 $9.52 $6.92 $7.55 $8.78 $8.12 $ % Q Q Q Q Q Q LOE, Gathering & Transporation, & Workovers Cash G&A Prod. & Ad Val Cash Margin (Excluding Hedges) 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). (1) 5

6 Boe/d Boe/d Track Record of Production Growth Strong quarter of production growth for RSP in Q3, with 21% production growth over Q and 114% production growth over Q Annual Production Growth Since Inception Quarterly Production Growth Since IPO 25,000 20,000 15, % 21,250 20, % - +79% 21,000 16,000 More than doubled production in last year 16,141 15, % 19, % 24,000 10,000 5, % +82% 11,868 7,293 5,089 2, YTD ,000 6,000 IPO January ,837 Q ,339 Q ,714 Q ,217 Q Q Q Q Q

7 RSPP A B 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 BD Industry-Leading Margins, Cost Structure & Growth RSP leads the U.S. E&P industry in both profitability and growth of production per debt-adjusted share E&P Universe Q Unhedged Cash Operating Margin per Boe (1) RSPP $25.00 U.S. E&P Company $20.00 G ALV AFIP $15.00 $10.00 Permian Peer (2) Median: $11.44 $5.00 $0.00 Oily E&P Q Operating Costs per Boe (1)(3) $40.00 $30.00 $20.00 $10.00 $0.00 D EC RSPP AM RSPP J A Y S H Q BC AL D AC M BK AD R N F AF I L AW K E C O P B U G AE AQ V BC BK Oily E&P Q3 14 Q3 15 Growth per Debt-Adjusted Share (1)(3) RSPP L JH Median: $15.55 O B AD % Oil AC AE SK F YN AQ Q 100% Note: Company data, Bloomberg, FactSet, Seaport Global Securities ( SGS ) estimates. Letters correspond to the same companies in the top and bottom charts. 1) Q operating margin per Boe, Q operating costs per Boe and Q Q production growth per debt-adjusted share per Seaport Global Securities. 2) Permian peers include CPE, CXO, FANG, LPI, PE, and PXD. 3) Oil-weighted peers include companies with >50% expected 2015 oil mix per GHS. AW UR 85% 70% 55% 40% 80% 60% 40% 20% (20%) (40%) RSPP U.S. E&P Company Permian Peer (2) Median: 3% 7

8 RSP is in a Strong Financial Position Selective use of capital markets to maintain strong balance sheet and liquidity Equity and debt offerings in conjunction with 2015 acquisitions: $223 million equity offering in October 2015 $181 million equity offering and $200 million senior notes offering in August 2015 Increased borrowing base from $500 million to $600 million in August 2015 S&P upgraded RSPP s unsecured notes to B from B- in September 2015 Capitalization Table (1) 9/30/2015 ($ in millions) Pro Forma Cash $138 Revolving Credit Facility % Senior Unsecured Notes Due Total Debt $700 Net Debt $562 Liquidity Borrowing Base $600 Less: Borrowings & LCs (1) Plus: Cash 138 Liquidity $738 $800 $600 $400 $200 $0 Debt Maturities ($MM) Senior Notes Unused Borrowing Base Financial & Operating Statistics Q Annualized Adjusted EBITDAX (2) $313.3 Q Daily Production (MBoe/d) 24.0 Credit Metrics Net Debt / Annualized Adjusted EBITDAX 1.8x Net Debt / Latest Daily Production ($/Boe/d) $23,402 (1) Capitalization table reflects the closing of the WPR Acquisition and proceeds of $218.1 million from October equity offering. Does not reflect incremental production or EBITDAX from acquired properties in leverage metrics. (2) Q Annualized Adjusted EBITDAX represents Adjusted EBITDAX for the quarter ended September 30, 2015 multiplied by four. 8

9 # of HZ Rigs 2016 Rig Operating Scenarios RSP has flexibility to operate two, three or four horizontal rigs in completions will primarily be in our highest-return operating areas, similar to 2015 RSP will carry over Hz wells waiting on completion ( DUC ) into 2016 (~75% of DUCs are targeting Lower Spraberry), which will enable us to complete more wells and add production with fewer operated rigs We anticipate double-digit year-over-year growth in 2016 under all contemplated rig scenarios Illustrative 2016 Rig Operating Scenarios at Various Commodity Prices $ mm Capex Op. Hz. Completions $ mm Capex Op. Hz. Completions $40 Oil $50 Oil $60 Oil Operated Horizontal Rigs $ mm Capex Op. Hz. Completions 9

10 Well Results Continue to Improve RSP s 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 7,500 1,000 7, , , , ,000 4,500 2H13 1H14 2H14 1H15 2H15 IP-30 (Boe/d) Average Lateral Length (ft) 180-Day Cumulative Production per Foot % +39% H13 1H14 2H14 1H15 2H15 IP-30 / 1,000 ft (Boe/d) Note: As of December Reflects all RSP operated horizontal wells. 0 2H13 1H14 2H14 1H Day Cum / ft (MBoe) 10

11 Declining Drilling & Completion Costs Both drilling and completion costs have steadily declined for three straight quarters on a per lateral foot basis A substantial portion of both drilling and completion cost savings is driven by increased efficiency Feet drilled per Day (Operated Wells) Total Well Cost per Lateral Foot (Operated Wells) 1, % $1,500 $1,250 Target well Costs: $6.3mm $10.0 $ $1,000 $ $750 $4.0 $ $250 $2.0 Q Q Q Q Q Q Q Q Note: As of Q Cost per lateral foot analysis includes all operated horizontal wells longer than 6,500. Q $0 Q Q Q Q Q Q Q Completion Cost per Foot Drilling Cost per Foot Cost per 7,500' Lateral ($MM) $0.0 11

12 Cumulative MBoe Preliminary Lower Spraberry Spacing Results While RSP has not completed a full Lower Spraberry development test on a single section, there are 5 producing Lower Spraberry wells spaced ~500 apart on two different leases These wells are producing from the same stratigraphic interval in a lower landing zone within the Lower Spraberry, testing 500 spacing without a chevron development pattern Subsequent development will incorporate an upper landing target to maximize recovery Early production data indicates the wells are ahead of type curve and comparable to RSP s recent Lower Spraberry wells Average Core Lower Spraberry Cumulative Production Lower Spraberry Gun Barrel View Cross Bar Ranch Lower Landing Target (Producing) ~500 ~ Average of 15 Lower Spraberry wells drilled in the same counties MARTIN CO Average of 5 wells spaced ~500 apart in the same landing zone All Core Lower Spraberry Wells Average Tightly Spaced Lower Spraberry Wells Normalized to 7,500 lateral Note: Core Lower Spraberry counties are defined as Midland, Martin and Andrews. Production data normalized for operational downtime. As of December Spanish Trail WPR Acquisition MIDLAND CO 12

13 Glasscock County Activity Update Pioneer Flanagan Leases Lower Spraberry, Wolfcamp A, B, Cline MIDLAND CO #21H (Lower Spraberry) 24 hr IP: 940 Boe/d #5H (Cline) - 24 hr IP: 1,610 Boe/d #4H (Wolfcamp A) 24 hr IP: 1,129 Boe/d #8H (Wolfcamp B) 24 hr IP: 1,466 Boe/d 13 XTO Zant Lease Lower Spraberry, Wolfcamp A, Wolfcamp B 8 wells permitted / drilling Pioneer O Daniel Leases Wolfcamp A, B, Cline #2H (Cline) - 24 hr IP: 2,729 Boe/d #27H (Wolfcamp A) 24 hr IP: 2,145 Boe/d #1H (Wolfcamp B) 24 hr IP: 2,491 Boe/d HUNT Boone - Coffee Lease (Wolfcamp B) #1HB - 24-hr IP 820 Boe/d - flowing #2HB 24-hr IP: 1,270 Boe/d flowing #3HB, #4HB Completing 3 additional wells drilling 2015 Drilling Program Testing Multiple Horizons Woody 1H WA Woody 2H WB On Flowback Apache Shackelton WB/WA Spacing Test #3H (WB) Cum: 163 Mboe / 12 mo s Diamondback Saxon / Riley B Leases Lower Spraberry, Wolfcamp A, B 6 wells permitted / drilling Lower Spraberry, Wolfcamp A, Wolfcamp B HUNT Harris-Hutchinson Lease (Wolfcamp B) 4 well producing ~625 inter-well spacing Source: TX RRC and other public sources RSP Acreage 2015 Acquisitions GLASSCOCK CO #1H (WA) 10,106 LL Producing #2H (Upper WB) 9,830 LL Producing #3H (Lo Spraberry) Awaiting Completion #4H (Lower WB) - Awaiting Completion 13

14 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 Lower Spraberry development began late Q Average Cum Production of ~120 MBoe Through 100 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, Day IP (Boe/d) 1,594 1,321 1,442 1,313 N 1,000 Still over 1,000 Boe/d after 100 days Average of Four Upper Wolfcamp Wells Note: Production data normalized for operational downtime. As of December

15 Cumulative MBoe Increased Wolfcamp Type Curves Due to Outperformance Improved completion techniques and strong well results in core counties driving outperformance Increased core county 7,500 type curve for the Wolfcamp A and keeping the core county Wolfcamp B 7,500 type curve unchanged Permian peer type curves shown for reference; more history will help clarify the estimated ultimate recovery over the 50+ year life of the well, but RSP believes the early time forecasts of these type curves determine a substantial portion of the single-well economics Wolfcamp A/B Type Curve and Operated Well Production in Core Counties since Mid-2014 (Normalized to 7,500 ) Wolfcamp A (7,500 lateral) New Basin Peer (MBoe) Curve Actual Curve EUR 800 1, Day Cum Day Cum Day Cum Wolfcamp A wells Wolfcamp B (7,500 lateral) 50.0 EURs: ~75% Oil 360-Day Cum: ~80% Oil 13 Wolfcamp B wells MBoe Wolfcamp A Type Curve Average Wolfcamp A wells 715 MBoe Wolfcamp B Type Curve Average Wolfcamp B wells New Basin Peer (MBoe) Curve Actual Curve EUR Day Cum Day Cum Day Cum Note: Updated curves based on cumulative production to date for wells drilled in the applicable zone. Average Midland Basin peer type curve derived from CPE, FANG, PE, and PXD public investor presentations and RSP estimates. Core Wolfcamp counties are defined as Midland, Martin and Andrews. Production data normalized for operational downtime. As of December

16 Cumulative MBoe Increased Both Lower Spraberry and Middle Spraberry Type Curves Substantial outperformance in both the Lower Spraberry and Middle Spraberry led us to increase the 7,500 lateral type curves for the zones in our core counties, which comprise ~85% of our Focus Area inventory The largest increase was the first year production estimates for the Middle Spraberry, which increased substantially more than the overall EUR and will have a large impact on a well s returns and payback period RSP s new type curves in both zones reflect strong economic potential in the current oil price environment Spraberry Type Curve and Operated Well Production in Core Counties since Mid-2014 (Normalized to 7,500 ) Lower Spraberry (7,500 lateral) New Basin Peer (MBoe) Curve Actual Curve EUR 830 1, Day Cum Day Cum Day Cum Lower Spraberry wells Middle Spraberry (7,500 lateral) 50.0 EURs: ~75% Oil 360-Day Cum: ~80% Oil 6 Middle Spraberry wells MBoe Wolfcamp A Type Curve Average Lower Spraberry wells 715 MBoe Middle Spraberry Type Curve Average Middle Spraberry wells New Basin Peer (MBoe) Curve Actual Curve EUR Day Cum Day Cum Day Cum Note: Updated curves based on cumulative production to date for wells drilled in the applicable zone. Average Midland Basin peer type curve derived from CPE, FANG, PE, and PXD public investor presentations and RSP estimates. Core Middle and Lower Spraberry counties are defined as Midland, Martin and Andrews. Production data normalized for operational downtime. As of December

17 RSP Permian Delivering Value in a Challenging Environment High Quality Assets Premier asset base in the core of Northern Midland Basin Multiple stacked quality reservoirs Multi-well pad development and blocked up acreage drives efficiency >25 years of high return drilling inventory 2015 acquisitions expanded top tier Hz inventory Focused on Returns and Execution Strong Financial Position Experienced Management Industry-leading margins Low G&A, lean organization Lowest F&D cost in the Basin Highly productive wells and low costs lead to superior margins & growth Undrawn revolver borrowing base increased to $600 million ~$740 million of pro forma liquidity as of Q (pro forma acquisitions and capital markets activities) Flexibility to increase or decrease capex Ability to capitalize on opportunistic acquisitions Management has over 25 years average experience in the Permian Basin Founding management backed by private equity, significant returns on multiple exits Highly technical team, implementing leading edge technology to optimize resource Substantial transaction experience, over $3 billion of deals since RSP founded 17

18 Appendix 18

19 Adjusted EBITDAX, Adjusted Net Income and Net Income Reconciliation ($ in thousands, except per unit amounts) Quarter Ended September 30, Nine Months Ended September 30, Revenues Oil sales $74,746 $64,119 $195,968 $186,184 Natural gas sales 3,283 2,297 7,544 7,811 NGL sales 2,615 4,229 6,972 13,456 Total revenues $80,644 $70,645 $210,484 $207,451 Net cash from derivative instruments 20,879 (669) 68,996 (3,436) Adjusted Total Revenues $101,523 $69,976 $279,480 $204,015 Operating Expenses Lease operating expenses $14,274 $7,140 $41,578 $24,176 Production and ad valorem taxes 4,674 5,137 14,273 15,228 General and administrative expenses 4,246 3,295 12,938 8,637 Total operating costs and expenses $23,194 $15,572 $68,789 $48,041 Adjusted EBITDAX, as defined $78,329 $54,404 $210,691 $155,974 Depreciation, depletion, and amortization $43,031 $18,991 $114,152 $60,719 Asset retirement obligation accretion Exploration ,285 2,955 Interest expense 11,680 2,241 30,363 4,513 Stock-based compensation, net 2,432 1,919 6,975 1,864 Adjusted income before income taxes $20,884 $30,248 $56,664 $85,810 Adjusted income tax expense 7,411 11,816 20,109 30,892 Adjusted net income, as defined $13,473 $18,432 $36,555 $54,918 Adjusted net income per common share - Basic $0.15 $0.24 $0.44 $0.75 Adjusted net income per common share - Diluted $0.15 $0.24 $0.44 $0.75 Note: 2014 results adjust for the combinations that occurred in connection with our IPO in January Please see 10-K and 10-Q for more information. 19

20 Extensive Multi-Year Drilling Inventory with Strong Rates of Return 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, Net Locations: Middle Spraberry Lower Spraberry Identified Horizontal Locations Operated horizontal locations booked as 5 wells across a section in Wolfcamp (~1,100 spacing) and 10 wells across a section in Spraberry (~500 spacing) in Focus Area Focus Areas 348 Dawson Area 2,378 Wolfcamp A Wolfcamp B Wolfcamp D Total Target Horizontal Locations Identified Vertical Locations 622 Vertical 40- Acre Spacing 1,077 Vertical 20- Acre Spacing 4,077 Total Locations Focus Area , ,519 Dawson Total Net Locations: , ,654 Avg. Lat. Length 7,157' 7,064' 7,051' 7,091' 6,991' 7,063' % Booked as PUDs 2% 4% 2% 18% 1% 5% Clearfork, Jo Mill, Strawn, Atoka, and other formations are potential future upside Note: As of June Includes locations from acquisitions subsequent to June Excludes Clearfork, Jo Mill, Strawn, Atoka, and any other horizontal zones. 20

21 Midland County WPR Acquisition Offset Activity Key Horizontal Activity and Completions OXY Mabee 139 #412H (Clearfork) ~7500 lateral length Completing OXY Curtis Ranch South Mid / Lower Spraberry Drilling / Permitted Diamondback Oaktree / Mockingbird Leases Lower Spraberry / WA / WB Drilling / Permitted MARTIN CO OXY Curtis Ranch So 2344SH (Lower Spraberry) 24-hr IP: 1,040 Boe/d 5,605 lateral length Curtis Ranch So #2341MH (Middle Spraberry) 24-hr IP: 752 Boe/d 5,284 lateral length OXY Curtis Ranch So 2823AH (Wolfcamp A) 24-hr IP: 1,079 Boe/d - 6,355 lateral length Curtis Ranch 2828H (Wolfcamp B) 24-hr IP: 1,089 Boe/d 5,704 lateral length RSP / Callon Pecan Acres H (Wolfcamp B) Pecan acres H (Lower Spraberry) 10,000 lateral lengths - WOC RSP Spanish Trail 11,000 laterals on Flowback 4717WA (Wolfcamp A) Pumping 1,886 Boe/d 4717WB (Wolfcamp B) Flowing 1,625 Boe/d 4719WA (Wolfcamp A) Flowing 1,946 Boe/d 4719WB (Wolfcamp B) Flowing 1,643 Boe/d Diamondback Gridiron N 1H (Wolfcamp B) 24-hr IP: 2,757 Boe/d - 8,785 lateral length Gridiron So 17LS (Lower Spraberry) 24-hr IP: 1,768 Boe/d 9,154 lateral length Source: Texas Railroad Commission and investor presentations. 3-stream data. 30-day IP rates noted where available. MIDLAND CO OXY Curtis Ranch So 3521H (Lower Spraberry) 24-hr IP: 1,206 Boe/d - 6,142 lateral length Curtis Ranch 3519H (Wolfcamp A) 24-hr IP: 841 Boe/d 5,892 lateral length Curtis Ranch So 3517H (Wolfcamp B) 24-hr IP: 909 Boe/d 4,368 lateral length High Sky (RSP) Isbell HU 104WB (Wolfcamp B) IP 30: 718 Boe/d <5,000 lateral length Isbell HU 105LS (Lower Spraberry IP 30: 765 Boe/d <5,000 lateral length Isbell HU 106 MS (Middle Spraberry) IP 30: 674 Boe/d <5,000 lateral length Isbell HU 107WA (Wolfcamp A) IP 30: 803 Boe/d <5,000 lateral length 21

22 Martin County WPR Acquisition Offset by Significant Activity Area Type Log Diamondback Estes #1602H (Lower Spraberry) 24-hr IP: 1067 Boe/d - 7,559 lateral length MS W&T Pinot 65 15H (Lower Spraberry) 24-hr IP: 917 Boe/d 6,769 lateral length Diamondback Mabee BL 2301LS (Lower Spraberry) 24-hr IP: 1,145 Boe/d - 6,454 lateral length Mabee BL 2201H (Wolfcamp B) 24-hr IP: Boe/d 8,296 lateral length Mabee BL 4004H (Wolfcamp B) 24-hr IP: 910 Boe/d 8,263 lateral length LS DEAN ENCANA Holt Ranch 101H (Wolfcamp B) 24-hr IP: Boe/d 7,304 lateral length WA ENERGEN Holton / Kitta Belle Leases Multiple Permitted Locations WB ENERGEN Holton 101H (Wolfcamp A) 24-hr IP: 1,171 Boe/d - 6,675 lateral length Holton #210H (Wolfcamp B) 24-hr IP: 1,172 Boe/d - 6,825 lateral length WC Holton #401H (Cline) 24-hr IP: 2,425 Boe/d - 7,185 lateral length ENERGEN Campbell #101H (Wolfcamp A) 24-hr IP: 792 Boe/d - 6,725 lateral length CLINE Campbell #501H (Lower Spraberry) 24-hr IP: 1,007 Boe/d - 6,628 lateral length 22

23 Increased 2015 Production Guidance and Decreasing Capex & Cost Guidance Q marked the second straight quarter in which RSP increased production guidance Due to cost savings and a moderated Q4 completion pace, RSP expects to spend $400 $420 million of capital expenditures during 2015, at the low end of the previous guidance range of $400 - $450 million As a result of increased operating efficiency and production growth, RSP decreased its cost per unit guidance Comparison of 2015 Production Guidance (1) 2015 Actuals and Guidance % Oil % 75% Oil % +17% 75% Oil % % +22% YTD 2015 Full Year 2015 Change Since Actual Guidance August 2015 (1) Operated Horizontal Completions Average Daily Production (Boe/d) 19,967 20,750-21,250 +6% Capital Expenditures ($MM) $327 $400 - $420 (4%) Unit Costs (per Boe) LOE (Including Workovers) $7.16 $ $7.15 (6%) Gathering & Transportation $0.47 $ $0.50 (10%) Exploration Expenses $0.42 $ $0.40 (22%) Cash G&A $2.37 $ $2.45 (7%) Recurring Non-Cash G&A $1.07 $ $1.10 (4%) Non-Recurring IPO Stock Comp $0.21 $ $0.20 (5%) DD&A $20.94 $ $22.00 (3%) Production & Ad Valorem (% of Rev) 6.8% 6.6% - 6.8% (7%) 10.0 Total Production Oil Production (MBbls/d) (MBoe/d) January Midpoint August Midpoint Current Midpoint 1) Reflects the midpoint of guidance range. Prior Guidance reflects guidance published by RSP in January 2015 and August Differences calculated based on the midpoint of guidance. 23

24 Permian Leader in Efficiencies Strong production and reserve growth with low corporate overhead Peer-leading F&D costs and reserve replacement Production & Capex per Average Headcount (1) 76 RSPP Rank: #2 38 Production per Headcount (MBoe) RSPP $9.0 $8.0 $7.0 $6.0 $5.0 $4.0 $3.0 $2.0 $1.0 $8.5 RSPP Rank: #1 $3.2 Capex per Headcount ($MM) Permian Peer Average $25.00 $20.00 $15.00 $10.00 $5.00 $ % 1000% 500% Permian peers include CPE, CXO, FANG, LPI, PE, and PXD. Information based on public filings. (1) 2014 total production (MBoe) and total capital spent ($MM) divided by the average of the employee count at YE 2013 & YE (2) Defined as exploration and development costs divided by the sum of extensions and discoveries and non-price revisions. (3) Defined as the sum of extensions, discoveries, and non-price revisions, divided by annual production Finding & Development Costs (per Boe) $10.59 RSPP Rank: #1 $18.21 $13.88 RSPP Rank: # Reserve Replacement Ratios $23.28 Drillbit F&D Total F&D RSPP Permian Peer Average 1140% RSPP Rank: #1 493% (2) 1406% RSPP Rank: #1 616% Organic Reserve Reserve Replacement (3) Replacement RSPP Permian Peer Average 24

25 RSP Development Plan to Maximize Efficiency Well performance improves with lateral length, but the relationship is not linear across all metrics Illustrative Capex per Foot by Lateral Length Capital efficiency increases with lateral length, although there is a point of diminishing returns related to steering and time to clean out Lateral lengths of 7,000 8,000 are well-suited to realize the benefits of timing, capital and production ~25% decrease ~40% decrease The average lateral length of RSP s inventory is 7,100, with few short laterals Illustrative 30-Day IP by Lateral Length Shorter laterals tend to have higher IPs per foot than longer laterals ~5,000' ~7,500' ~10,000' Illustrative IRR by Lateral Length Longer laterals tend to have higher IRRs despite lower initial IP ~25% Increase ~30% increase ~5,000' ~7,500' ~10,000' Note: Illustrative metrics by lateral length based on actual RSP results on a single lease with wells of each lateral length. ~5,000' ~7,500' ~10,000' 25

26 Concentration of Core Acreage Provides Attractive Assets with Upside We believe that the vast majority of our inventory can generate sufficient returns in a challenging environment Upside continues to exist in the form of downspacing, additional zones, cost reductions, and enhanced completion techniques Booked Zones Upside Zones Peer 1 Peer 5 Peer 6 Peer 2 Peer 4 Peer 3 RSPP Stated Locations Wells per Section Booked for Midland Basin Peers (1)(2) ) Per Keybanc Capital Markets, Inc. estimates. Strip pricing as of September Inventory years based on estimate of average completion pace 2) Midland Basin Peers include CPE, EGN, FANG, LPI, PE, and PXD Stated Upside 5 Years of Inventory with 20%+ IRR at Strip (1) RSPP Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Despite acreage adjacent to many peers and a high percentage of core acreage, RSP remains conservative on its stated inventory RSP books only horizontal zones in which it has a producing well in its inventory RSP has booked the least amount of zones and locations per section in its stated ~1,400 net horizontal locations of the Midland Basin peers 26

27 MMBOE Proved Reserves Doubled in PUD 61% Proved Reserves Growth Proved Reserve Summary PD 39% MMBoe Gas 15% NGLs 20% YE 2013 YE 2014 PD PUD Oil 65% (1) Based on Q production. (2) Defined as exploration and development costs divided by the sum of extensions and discoveries and non-price revisions. (3) Defined as the sum of extensions, discoveries, and non-price revisions, divided by annual production. Approximately doubled both Proved Developed and Proved Undeveloped Reserves year over year Only 5% of RSP s horizontal locations are booked as PUDs Reserve life of more than 18 years (1) Drillbit F&D of $10.59 (2) and Total F&D of $13.88 Reserve Replacement Ratio of 1,406% and Organic Reserve Replacement Ratio of >1,100% (3) Gross Horizontal PUD Count YE 2013 YE 2014 % of Locations Lower Spraberry Wolfcamp A / B Middle Spraberry Wolfcamp D 1% (348 Locations) 10% (621 Locations) 2% (649 Locations) 4% (760 Locations) 27

28 Cross Bar Microseismic Conclusions and Implications Hypothetical Development Scheme Implied by Cross Bar Ranch Microseismic Study Preliminary Microseismic Conclusions: Middle Spraberry Lower Spraberry 10 5 Jo Mill Middle Spraberry Micro Seismic indicates 10 wells across one mile Jo Mill Micro Seismic indicates undeveloped gap between MS and LS Lower Spraberry Micro Seismic indicates 10 wells across one mile Dean 200 Dean Micro Seismic indicates Dean is covered by LS and WA stimulation Wolfcamp A Wolfcamp A Micro Seismic indicates correct spacing of 5 wells across one mile Wolfcamp B Wolfcamp B Micro Seismic indicates correct spacing of 5 wells across one mile Wolfcamp C 325 Wolfcamp D (Cline) Wolfcamp D (Cline) No data available for verification of spacing 1 Mile Potential for 40 horizontal wells across 1 mile section 28

29 Optimizing Wellbore Placement 3D Inversion Attribution RSP continues to see improving well results using technology to optimize wellbore placement Geosteering Microseismic Geochem 29

30 Hedging Program Summary Oil Hedge Summary Swaps Volumes (MBbls) 30 Average Swap Price ($/Bbl) $92.60 Q Collars Volumes (MBbls) Average Floor ($/Bbl) $85.57 $55.00 Average Ceiling ($/Bbl) $94.28 $74.08 Average Short Put Price ($/Bbl) $45.00 Total Volumes Hedged (MBbls) Total Blended Floor $85.97 $55.00 Daily Volumes (Bbls/day) 5,739 1,516 30

31 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