RSP Permian Investor Presentation September 2014
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 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, the quality of technical data, environmental and weather risks, including the possible impacts of climate change, 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 the Company 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 the Company s production, 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 SEC, including our Annual Report on Form 10-K for the year ended December 31, 2013 and our Quarterly Report on Form 10-Q for the quarter ended June 30, 2014. 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
Corporate Overview 3
RSP Overview Market Snapshot Permian Basin Pure Play NYSE Symbol: Market Cap (1) : Net Debt (2) : Enterprise Value: RSPP ~$2.2 billion ~$0.3 billion ~$2.4 billion Pro Forma Production and Reserves (3) Average Daily Production (4) Acreage Summary 10.7 MBoe/d Proved Reserves 76.1 MMBoe % Oil 59% % NGL 21% % Natural Gas 20% % Proved Developed 31% Effective Horizontal Acreage Gross Net Middle Spraberry 53,306 38,370 Lower Spraberry 59,824 44,242 Wolfcamp A 40,015 26,834 Wolfcamp B 53,404 38,314 Wolfcamp D 44,077 30,691 Total Horizontal Acreage 250,626 178,450 Surface Acreage 63,035 46,738 (1) As of August 29, 2014. (2) Balance as of June 30, 2014, adjusted for primary equity offering closed in August 2014 and acquisitions closed on August 29, 2014. (3) Pro forma reserves give effect to the formation transactions described in 10-K and 10-Q. Reserves per independent reserve report prepared by Ryder Scott as of 12/31/13, plus management s estimate of reserves for the acquisitions closed August 29, 2014. (4) Average daily production for quarter ended June 30, 2014. 4
Contiguous Acreage in the Core of the Midland Basin Boe/d 12,000 10,000 8,000 6,000 4,000 2,000 2,807 5,089 1% Overview Large, contiguous, core acreage in the Midland Basin (1) Permian pure-play with 63,035 gross (46,738 net) acres Over 178,000 net effective horizontal acres (2) Low-risk, oil-rich base with rapid growth potential Proved reserves: 76.1 MMBoe; 59% oil, 21% NGLs, 20% natural gas (3) Focus on horizontal drilling to maximize returns Four current horizontal rigs going to five in late Q4 2014 and six during Q1 2015 RSP has participated in more than 75 horizontal wells (>35 operated) Large inventory of identified drilling locations (1) 1,760 horizontal and 1,241 vertical drilling locations Track Record of Production Growth 99% 7,293 15% 85% 7,837 9,339 10,714 0 2011 2012 2013 Q4 2013 Q1 2014 Q2 2014 Vertical Production Horizontal Production Acquired Production (1) Includes Midland Basin acquisitions closed on August 29, 2014. (2) Combined horizontal acreage position that management believes is prospective for hydrocarbon production across each target horizontal zone. (3) 12/31/2013 Ryder Scott reserve report, plus management s reserve estimates for acquisitions closed August 29, 2014. (4) Based on Q2 2014 production of 10,714 Boe/d. 21% 79% 32% 68% 11,820 (1) 46% 54% TX RSP s Acreage in the Midland Basin Dawson Area Focus Areas Glasscock Acquisitions 5
Acquisitions Increase RSP s Drilling Inventory in Core of Midland Basin Midland Basin Acquisitions Acquisitions Map In Q1 2014, RSP completed $79 million of acquisitions adding 5,316 net acres On August 29, 2014, RSP closed on multiple acquisitions in Glasscock County for a total of ~$257 million 7,680 gross / 6,652 net surface acres 100% Operated 21,440 gross / 19,367 net effective horizontal acres 188 horizontal locations with average lateral length >6,500 316 vertical locations on 20-acre spacing Production of ~1,300 Boe/d (~75% liquids) from 13 vertical wells Net proved reserves of 22 MMBoe (9% developed) (1) Adds another primary operating area for RSP in the core of the Midland Basin Significant Undeveloped Inventory Glasscock Acquisitions Focus Areas Dawson Area Surface Horizontal Locations Acreage Acreage LS WA WB WD Total Hz 40-acre 20-acre Total Vt Gross 7,680 21,440 63 41 38 46 188 158 158 316 Net 6,652 19,367 52 34 33 37 156 132 132 264 Net Acreage (Focus Areas) 40,000 35,000 30,000 25,000 20,000 Glasscock Acq. RSPP Prior to Acq. +23% Net Hz Locations (Focus Areas) 1,000 900 800 700 600 500 Glasscock Acq. RSPP Prior to Acq. +20% Net Vertical Locations (1) Proved reserves of the assets acquired in the acquisitions closed during August 2014 is based solely on our internal evaluation and interpretation of reserve and other information provided to us by the sellers of those assets in the course of our due diligence with respect to the acquisitions and have not been independently verified or estimated by our independent petroleum engineers or any other party. 1,000 800 600 400 200 Glasscock Acq. RSPP Prior to Acq. +47% TX Recently Closed Acquisitions of 6,652 Net Acres Glasscock Acquisitions Acreage 1Q 2014 Acquisitions Acreage In 7 months since IPO, RSP has closed ~$340 million of acquisitions, increasing locations and net acres by ~50% and ~38%, respectively 6
Recent Acquisitions Create Another Primary Operating Area for RSP Acquisition Acreage Offset by Significant Industry Activity Pioneer Houston Ranch 1H,2H,10H,11H Permitted Locations Existing RSP Permian acreage Glasscock Acquisitions acreage OXY Powell Ranch 151HC Permitted Location 4,888 Planned Lateral Length Pioneer Flanagan 14 Lloyd A #21H (Lower Spraberry) 24-hr IP: 1,010 Boe/d Cum: 88 MBoe 7,212 lateral length Pioneer Flanagan 14 Lloyd B #1H (Wolfcamp B) 24-hr IP: 1,460 Boe/d 9,542 lateral length Midland Glasscock BTA Cox Unit 4 Permitted Locations ~6,900 Planned Lateral Lengths Apache Shackelton (Wolfcamp) 6 Permitted Locations ~4,900 Lateral Length Pioneer E.T. O Daniel #1H (Wolfcamp B) 24-hr IP: 2,801 Boe/d Cum: 165 Mboe 9,229 lateral length E.T. O Daniel #2H (Wolfcamp D / Cline) 24-hr IP: 3,156 Boe/d Cum: 128 MBoe 9,112 lateral length Apache Cleveland Lease 2 Permitted Locations Energen Llano Lease Permitted Locations Hunt Boone-Coffee 1HB, 2HB Permitted Locations Athlon Wilkinson 31 #8H (Wolfcamp A) 30-day IP: 1,562 Boe/d 69% Oil 7,132 Lateral Length Pioneer Shackleford Unit Permitted Locations Apache Schrock Unit 10 Permitted Locations Athlon Buckner 9H/10H (Wolfcamp) Permitted Locations Energen Daniel Lease 11 Permitted Locations Source: Texas Railroad Commission and investor presentations. Athlon Lawson 2703H (Wolfcamp A) 30-day IP: 983 Boe/d 76% Oil 7,618 Lateral Length Laredo Lane Trust C/E 42-2HL (Wolfcamp C) 30-day IP: 1,406 Boe/d 79% Oil 7,571 Lateral Length Lane Trust C/E 421HU (Wolfcamp A) 30-day IP: 1,391 Boe/d 76% oil 7,185 Lateral Length 7
Asset Overview 8
RSP s Focus Areas Are in the Most Prolific Areas of the Midland Basin RSP s Acreage Midland Basin Historical Oil Production Heat Map Borden Dawson Area Dawson Area Focus Areas Focus Areas Best-month oil production (bbl) >6,000 4,000-6,000 3,000-4,000 2,000-3,000 1,000-2,000 <1,000 TX TX Red dots indicate the most prolific oil production in the basin Source: IHS Enerdeq, best-month oil production for wells completed between 1/1/2008 and 5/1/2014. 9
Leader in Multiple Pay Zones in the Midland Basin RSP Permian and other industry players have unlocked multiple target zones for horizontal drilling RSP Success / Industry Commentary Industry Horizontal Drilling Targets Formations highlighted in blue are RSP Target Horizontal Zones Midland Basin Clearfork RSP successfully drilled and completed the first horizontal well targeting the Middle Spraberry RSP successfully drilled and completed the first horizontal well targeting the Lower Spraberry RSP recently drilled its first Wolfcamp A well with 30-day IP of 928 Boe/d RSP was among the first operators in the core of the Midland Basin to successfully drill and complete a horizontal well targeting the Wolfcamp B RSP is currently evaluating two recent 3D seismic acquisitions and will implement the data to optimize future drilling in the Wolfcamp D Upper Spraberry Middle Spraberry Jo Mill Lower Spraberry Dean Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D (Cline) Strawn Atoka Mississippian Source: Texas Railroad Commission and investor presentations. 10
Current Activity Focused on Capital Efficiency Operations Update Activity Map Operating four horizontal rigs Andrews Cross Bar Ranch 1717 Cross Bar Ranch 1811 Johnson Ranch 912 5th horizontal rig to arrive in December 2014 and 6th horizontal rig in 2Q 2015 Operating three vertical rigs, with an additional vertical rig setting intermediate in front of a horizontal rig Seven dual well/dual zone pads on production Dawson Cross Bar Ranch 2017 Johnson Ranch 1018 Martin Four dual/dual pads currently completing and three dual well/dual zone pads currently drilling Cross Bar Ranch 3025 Midland First true triple well/triple zone pad currently fracing in Cross Bar Ranch; Second triple/triple pad currently drilling in Spanish Trail 4817 WB-MS-LS During remainder of 2014, six dual/dual pads and two triple/triple pads will be drilled Ector Morgan 3601 Headlee 3505 Headlee 3911 Parks Bell 3909 Kemmer 4210 Spanish Trail 217 Spanish Trail 4817 Lower Spraberry wells and short (~5,000 ) lateral Wolfcamp B wells significantly outperforming expectations Fendley 404 Spanish Trail 218 Two pilot wells in Dawson flowing back Lower Spraberry and Wolfcamp B wells are in early flowback stage Wolfcamp B Wolfcamp A Lower Spraberry Middle Spraberry Hz Rig Location Currently Drilling / Completing TX Wolfcamp D (Cline) 11
Extensive Multi-Year Drilling Inventory with Strong Rates of Return 8 6 4 2 7 Highlights Multi-year inventory of horizontal and vertical drilling projects Multiple stacked pay zones beneath concentrated acreage position 8 6 4 2 0 Peak Operated Horizontal Rigs Currently running 4 rigs; Adding 5 th rig in late Q4 2014 2 2 2012 2013 2014 2015 Peak Operated Vertical Rigs Shift from Vertical Drilling to Horizontal Development 6 5 1 4 3 7 3 rd rig operating on acquired Glasscock acreage 3 1 2 Net Locations: 3,250 3,000 2,750 2,500 2,250 2,000 1,750 1,500 1,250 1,000 750 500 250 0 92 320 Middle Spraberry Identified Horizontal Locations Operated horizontal locations booked as 5 wells across a section in Wolfcamp (~1,100 spacing) and 7 wells across a section in Spraberry (~750 spacing) 91 373 Lower Spraberry 267 Focus Areas (1) 92 227 298 Dawson Area WC-A WC-B WC-D (Cline) 0 2011 2012 2013 2014 Note: As of June 30, 2014. Dawson area Wolfcamp locations categorized as Wolfcamp A/B and included in Wolfcamp B locations. Excludes Clearfork, Strawn, Atoka, and any other horizontal zones. 1) Focus Areas Includes locations from Midland Basin acquisitions closed in August 2014. 1,760 Total Target Horizontal Locations 2) EUR reflects 7,000 lateral type curve. Lack of production history in the Wolfcamp D (Cline) horizontal wells on RSP acreage. RSP will continue to monitor well results in assessing the Company s EURs and resource potential. Identified Vertical Locations 438 Vertical 40- Acre Spacing 803 Vertical 20- Acre Spacing 3,001 Total Locations Focus Areas (1) 202 248 159 145 191 946 333 509 1,788 Dawson 67 66-67 - 201 - - 201 Total Net Locations: 270 315 159 212 191 1,147 333 509 1,989 EUR (2) 615 665 665 665 NA Avg. Lat. Length 6,748' 6,722' 6,627' 6,738' 6,727' 6,719' 12
Large, Concentrated Acreage Blocks Provide Operating Advantages Large, Concentrated Acreage Blocks RSP leasehold positioned for horizontal development North to South blocked-up position, which lays out ideally for horizontal drilling, given desired frac planes Ability to drill long horizontal wells without having to rely on participation by industry players Ability to drive down costs: Sharing infrastructure and other critical drilling resources (water, disposal) across leasehold Rig efficiencies of staying in one location to execute pad drilling on multi-zone horizontal development Map of Focus Areas Average lateral length of our target horizontal locations is ~6,700 ft (>70% will be long laterals) Vast majority of operated horizontal wells to date have been drilled on multi-well pads 13
150 Boe/d Wolfcamp A/B Spacing Pilot Encouraging Early Results Cross Bar Ranch 1717H Wolfcamp A/B Pilot 1717WA 30-day IP: 928 Boe/d (~84% oil) 1717WB 30-day IP: 867 Boe/d (~88% oil) Treating pressures during zipper frac indicated wells are not in communication Strong early results point to tighter spacing potential leading to higher cash flows per acre Cross Bar Ranch 1717H Production History (1) Map of Cross Bar Ranch 1717 1,000 6,955 7,107 100 665 MBOE (7,000 lateral) 0 30 60 90 120 150 180 Gun Barrel View WA WB 1717 WA 1717 WB Wolfcamp A Wolfcamp B Wolfcamp A/B 7,000' Type Curve (1) As estimated by Ryder Scott, our estimated average EURs from our Wolfcamp B PUD horizontal drilling locations as of 12/31/13 average 524 MBoe (approximately 70% oil, 16% NGLs and 14% natural gas) and have an average assumed lateral length of approximately 6,000 feet. 325 14
Boe/d Boe Wolfcamp A/B Horizontals Continue to Exceed Expectations RSP Activity Wolfcamp A/B Cumulative Production (1) 12 operated Wolfcamp A/B wells with production history; average lateral length of ~6,000 Average 30-Day IPs of ~740 Boe/d 128 Boe/d per 1,000 of lateral Average 180-day Cumulative Production of ~74 MBoe ~12 MBoe per 1,000 of lateral RSP s first Wolfcamp A well continues to outperform 140,000 120,000 100,000 80,000 60,000 40,000 20,000 Average Wolfcamp wells tracking higher than RSP projected type curves Wolfcamp A/B 7,000' Lateral Type Curve Average Operated Wolfcamp Wells Cross Bar Ranch 1717 WA 0 0 30 60 90 120 150 180 210 240 270 300 Wolfcamp A/B Type Curve and Operated Well Production (1) 665 MBOE 1000 First Wolfcamp A Well Crossbar Ranch 1717WA: Drilled on a Wolfcamp A/B Pad (~7,100 lateral) W.C. A/B 7,000' Lateral Per 1,000' MBOE ~665 ~95 MBO ~475 ~68 100 0 30 60 90 120 150 180 210 240 270 300 Wolfcamp A/B 7,000' Lateral Type Curve Average Operated Wolfcamp Wells Cross Bar Ranch 1717 WA Note: Production data normalized for a 7,000 lateral and operational downtime. As of August 2014. (1) As estimated by Ryder Scott, our estimated average EURs from our Wolfcamp B PUD horizontal drilling locations as of 12/31/13 average 524 MBoe (approximately 70% oil, 16% NGLs and 14% natural gas) and have an average assumed lateral length of approximately 6,000 feet. 15
Boe/d Boe Lower Spraberry Results Also Exceeding Expectations RSP Activity Lower Spraberry Cumulative Production (1) 7 operated Lower Spraberry wells with production history; average lateral length of ~6,000 Average 30-Day IPs of ~690 Boe/d 119 Boe/d per 1,000 of lateral Average 180-day Cumulative Production of ~75 MBoe ~13 MBoe per 1,000 of lateral Results from the Lower Spraberry have exceeded RSP s type curve estimates on both long and short laterals 140,000 120,000 100,000 80,000 60,000 40,000 20,000 Lower Spraberry Type Curve and Operated Well Production (1) 0 Lower Spraberry wells performing well above the type curve 665 MBOE Lower Spraberry 7,000' Lateral Type Curve Average Operated Lower Spraberry Wells 0 30 60 90 120 150 180 1000 L.S. 7,000' Lateral Per 1,000' MBOE ~665 ~95 MBO ~475 ~68 100 0 30 60 90 120 150 180 Lower Spraberry 7,000' Lateral Type Curve Average Operated Lower Spraberry Wells Note: Production data normalized for a 7,000 lateral and operational downtime. As of August 2014. (1) As estimated by Ryder Scott, our estimated average EURs from our Lower Spraberry PUD horizontal drilling locations as of 12/31/13 average 652 MBoe (approximately 65% oil, 19% NGLs and 16% natural gas) and have an average assumed lateral length of approximately 6,400 feet. 16
Boe/d Boe Initial Middle Spraberry Results Reflect Potential RSP Activity Middle Spraberry Cumulative Production (1) 3 operated Middle Spraberry wells with production history; average lateral length of ~5,900 Average 30-Day IPs of ~540 Boe/d 91 Boe/d per 1,000 of lateral Average 180-day Cumulative Production of ~65 MBoe ~11 MBoe per 1,000 of lateral RSP s early Middle Spraberry results exceed expectations and reflect strong single-well economics 140,000 120,000 100,000 80,000 60,000 40,000 20,000 Middle Spraberry Type Curve and Operated Well Production (1) Early Middle Spraberry results trending stronger than forecasted 615 MBOE Middle Spraberry 7,000' Lateral Type Curve Average Operated Middle Spraberry Wells 0 30 60 90 120 150 180 1000 M.S. 7,000' Lateral Per 1,000' MBOE ~615 ~88 MBO ~455 ~65 100 0 30 60 90 120 150 180 Middle Spraberry 7,000' Lateral Type Curve Average Operated Middle Spraberry Wells Note: Production data normalized for a 7,000 lateral and operational downtime. As of August 2014. (1) As estimated by Ryder Scott, our estimated average EURs from our Middle Spraberry PUD horizontal drilling locations as of 12/31/13 average 428 MBoe (approximately 65% oil, 18% NGLs and 17% natural gas) and have an average assumed lateral length of approximately 5,000 feet. 17
Boe Spraberry Potential Provides Additional Upside Leader in the Spraberry RSP was the first operator to drill horizontal Lower Spraberry and horizontal Middle Spraberry Initial results point to economics as strong as Wolfcamp B Lower D&C costs Lower IP rates offset by shallower declines Approximately 1/2 of RSP s capex budget directed at horizontal Spraberry development (Middle Spraberry, Lower Spraberry) 140,000 Substantial Horizontal Spraberry Inventory - Net Locations Comparable Average Cumulative Production (Normalized to 7,000 Lateral Length) 600 500 400 300 200 100 315 270 315 Lower Spraberry Middle Spraberry 585 270 Middle + Lower Spraberry 371 212 159 WC-A + WC-B 120,000 100,000 80,000 Reflects RSP Operated Middle Spraberry, Lower Spraberry & Wolfcamp wells with at least 90 days of production history D&C: $7.5mm Long Lateral / $6.3mm Short Lateral 60,000 40,000 20,000 - D&C: $7.0mm Long Lateral / $6.0mm Short Lateral 0 15 30 45 60 75 90 105 120 135 150 165 180 Average of Middle Spraberry Wells Average of Wolfcamp Wells Average of Lower Spraberry Wells Note: Production data normalized for a 7,000 lateral and operational downtime. As of August 2014. 18
RSP s Operating Areas in the Core of Successful Industry Activity Map of Activity Midland / Martin / Andrews / Ector RSP s primary operating area to date Productive horizontal wells in at least six zones Some of the highest performing wells in the Midland Basin Majority of Midland Basin horizontal Spraberry activity RSP s 20+ producing operated wells across MS, LS, WA, and WB zones have averaged 30- Day IP s of ~120 Boe/d per 1,000 of lateral Represents FANG s core horizontal operating area and some of PXD s highest-performing horizontal wells Source: Texas Railroad Commission and investor presentations. Dawson Activity still early Nearby results in the Wolfcamp suggest economic viability Dawson: FANG, SM, W&T N. Martin / N.E. Howard: FANG, PXD, ATHL First two RSP wells in early flowback (WB / LS) Glasscock Offset by strong industry results and permitting activity PXD: Avg 24-IPs of >2,000 Boe/d on WB, WD, and LS ATHL and LPI: Avg 30-day IPs of ~1,300 Boe/d in Wolfcamp A and ~1,400 in Wolfcamp C Others: FANG, APA RSP intends to build infrastructure to support a horizontal program 19
RSP s Remaining Multi-Zone Development Projects For 2014 Commentary 2014 Planned Horizontal Wells 1. Johnson Ranch 1018 & 1019-2-well stacked offsetting pads for Wolfcamp B Wolfcamp A spacing pattern test. Project on production by end of Q4 2014 6 3D Shoot 1 2. Cross Bar Ranch 2017-4 well stacked pad Wolfcamp B is currently producing, and Wolfcamp A (offset 440 from Wolfcamp B), Lower Spraberry & Middle Spraberry are drilled and waiting on completion. Micro-seismic will be acquired to study interaction during completion between the 4 zones. Project on production in Q3 2014 2 3 3. Cross Bar Ranch 3025-4 well stacked pad Wolfcamp D, Wolfcamp B, Lower Spraberry & Middle Spraberry. Project on production with all 4 wells in Q4 2014 4. Spanish Trail 217-2 well stacked pad Lower Spraberry and Wolfcamp B in early flowback production. First operated RSP horizontal wells on Spanish Trail 5. Spanish Trail 4817-3 well stacked pad Wolfcamp B, Lower Spraberry and Middle Spraberry. Project on production late 2014 4 5 6. 3D Shoot - RSP has acquired 3D seismic with partners that will cover the key northern core acreage blocks 20
Cost per Lateral Foot Horizontal Well Costs Trending Down Efficiencies due to experience, completion / well design optimization, and pad development more than offsetting oilfield service cost inflation Operated Horizontal Drilling & Completion Costs Per Lateral Foot (by Spud Date) $2,200 $2,000 $1,800 $1,600 $1,400 $1,200 $1,000 Short Lateral Target Long Lateral Target Recent well costs trending below budget for both drilling and completion, and closer to RSP s longer term cost targets $800 Jun-12 Oct-12 Feb-13 Jul-13 Nov-13 Mar-14 Short Laterals Long Laterals $750 $500 $250 40 30 20 10 0 $750 $500 $250 Average Operated Drilling Costs Per Lateral Foot $0 $0 (26%) Spud Prior to 6/30/13 Spud After 6/30/13 Average Operated Spud to Rig Release (Days) (28%) Spud Prior to 6/30/13 Spud After 6/30/13 Average Operated Completion Costs Per Lateral Foot (24%) Spud Prior to 6/30/13 Spud After 6/30/13 Note: Data excludes one sidetracked horizontal well. 21
Low-Cost Operator with Strong Margins Pre-G&A Cash Margin (Six Months Ended 6/30/2014) $ / boe $80.00 $67.16 $60.00 $60.48 $58.23 $57.15 $56.76 $46.94 $44.07 $40.00 $20.00 $0.00 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 100% 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% 17% 20% 20% 15% 68% 21% 22% 59% 58% Source: Company filings. Permian Basin Peers include AREX, ATHL, CXO, FANG, LPI, PXD. (1) As of 12/31/2013 pro forma for Midland Basin acquisitions announced in July 2014. (2) NGL percentage not disclosed. (1) Commodity Mix (Proved Reserves) % Oil % NGL % Gas 31% 28% 22% 40% 40% 38% 39% Peer 1 Peer 3 Peer 5 Peer 6 Peer 2 Peer 4 61% (2) 45% 55% (2) 22
Financial Overview 23
RSP s Financial Strategy and Capitalization Financial Strategy Preserve financial strength In August 2014, amended credit facility to: Increase borrowing base to $500 million from $375 million Increase the lenders' maximum facility commitments to $1.0 billion from $500 Extended maturity date two years to August 2019 Allow RSP the ability to issue senior notes Ensures capital to execute drilling program Keeps strong balance sheet to take advantage of acquisition opportunities Evaluating notes offering to preserve liquidity Maintain conservative balance sheet Target long-term Debt / EBITDAX at or less than 2.0x Protect Cash Flows with Active Hedging Program Provides certainty around executing drilling program and maintains strong financial position Target 65% - 85% of production hedged on a rolling 2-year basis (1) 6/30/14 balances adjusted to reflect net proceeds from RSP s August 2014 offering of 4.8 million primary shares and the closing of acquisitions on August 29, 2014. (2) Based on 2Q 2014 Adjusted EBITDAX annualized. Please see reconciliation of Adjusted EBITDAX in Appendix. (3) Q2 2014 average daily production, plus estimated production acquired in acquisitions closed in August 2014. Pro Forma Capitalization ($ in millions) 6/30/2014 As Adjusted (1) Cash $15 $15 Revolving Credit Facility 140 281 Total Debt $140 $281 Net Debt $125 $266 Credit Metrics (2) Net Debt / Annualized Adjusted EBITDAX 0.6x Net Debt / Latest Daily Production ($/Boe/d) (3) $11,692 $22,538 Liquidity Borrowing Base $375 $500 Less: Borrowings (140) (281) Plus: Cash 15 15 Liquidity $250 $234 $500 $400 $300 $200 $100 $0 $250 Liquidity Bridge ($MM) $118 $259 6/30/2014 Equity Offering Acquisition Closing $125 $234 Borrowing Base Upsize (1) As Adjusted 24
Capital Budget and Hedging Detail All production inputs are engineered Drilling program modified as needed to re-focus on most attractive opportunities within portfolio Middle Spraberry Lower Spraberry 2014 Capital Budget Total Drilling & Completion Vertical 25% $400 million $300 million Horizontal 75% Horizontal Drilling & Completion 2014 Capital Budget ($mm) Drilling & Completion $400 Infrastructure & Other 25 Total $425 Wolfcamp A/B ~90% expected to be long lateral horizontal wells Does not include capital spend attributable to recently closed acquisitions acreage Hedging Detail Crude Oil Q3 2014 Q4 2014 2015 Swaps Volumes (Bbls) 60,000 60,000 120,000 Average Swap Price ($/Bbl) $94.50 $94.50 $92.60 Collars Volumes (Bbls) 414,000 561,000 2,067,000 Average Floor ($/Bbl) $86.56 $87.49 $86.60 Average Ceiling ($/Bbl) $100.77 $100.73 $94.87 Total Volumes Hedged (Bbls) 474,000 621,000 2,187,000 Total Blended Floor $87.56 $88.16 $86.93 Daily Volumes (Bbls/day) 5,152 6,750 5,992 % Future Oil Production Hedged ~60% ~50% Natural Gas Q3 2014 Q4 2014 2015 Collars Volumes (MMBtu) 450,000 450,000 Average Floor ($/MMBtu) $4.00 $4.00 NA Average Ceiling ($/MMBtu) $4.78 $4.78 NA 25
Adjusted EBITDAX and Adjusted Net Income Reconciliation Adjusted EBITDAX and Adjusted Net Income Reconciliation ($ in thousands, except per unit amounts) RSP Permian, Inc. Pro Forma Actual & Predecessor Quarter Ended Quarter Ended Quarter Ended Quarter Ended June 30, 2014 March 31, 2014 June 30, 2014 June 30, 2013 Revenues Oil sales $66,134 $55,930 $66,134 $22,442 Natural gas sales 3,117 2,397 3,117 1,397 NGL sales 4,811 4,417 4,811 1,309 Total revenues $74,062 $62,744 $74,062 $25,148 Net cash from derivative instruments (1,517) (380) (1,517) (1,342) Adjusted Total Revenues $72,545 $62,364 $72,545 $23,806 Operating Expenses Lease operating expenses $9,279 $7,757 $9,279 $3,944 Production and ad valorem taxes 5,964 4,127 5,964 783 General and administrative expenses 3,573 1,771 3,573 1,069 Total operating costs and expenses $18,816 $13,654 $18,816 $5,796 Adjusted EBITDAX $53,729 $48,709 $53,729 $18,010 Depreciation, depletion, and amortization $21,734 $19,994 $21,734 $12,032 Asset retirement obligation accretion 38 38 38 26 Exploration 1,233 756 1,233 94 Interest expense 1,142 1,131 1,142 477 Stock-based compensation, net 658 294 1,665 Adjusted income before income taxes $28,924 $26,497 $27,917 $5,381 Adjusted income tax expense 10,413 9,539 10,486 Adjusted net income, as defined $18,511 $16,958 $17,431 $5,381 Adjusted net income per common share - Basic $0.25 $0.23 $0.24 N/A Adjusted net income per common share - Diluted $0.25 $0.23 $0.24 N/A 26
Additional Disclosures Supplemental Non-GAAP Financial Measures Adjusted EBITDAX is a supplemental non-gaap financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We define Adjusted EBITDAX as net income (loss) before interest expense, income taxes, depreciation, depletion and amortization, exploration expense, (gains) losses on derivative instruments excluding net cash receipts (payments) on settled derivative instruments and premiums paid for put options that settled during the period, impairment of oil and natural gas properties, non-cash equity based compensation, asset retirement obligation accretion expense, other income, gains and losses from the sale of assets and other non-cash operating items. Adjusted EBITDAX is not a measure of net income as determined by United States generally accepted accounting principles ( GAAP ). Management believes Adjusted EBITDAX is useful because it allows it to more effectively evaluate our operating performance and compare the results of our operations from period to period and against our peers without regard to our financing methods or capital structure. We exclude the items listed above from net income in arriving at Adjusted EBITDAX 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 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 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 presentation of Adjusted EBITDAX should not be construed as an inference that our results will be unaffected by unusual or non-recurring items. Our computations of Adjusted EBITDAX 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. 27