YEAR-END 2016 UPDATE. February 27, 2017

Transcription

1 YEAR-END 2016 UPDATE February 27, 2017

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 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The words believe, expect, anticipate, plan, intend, foresee, should, would, could or 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 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 RSP 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. Furthermore, we may not be able to close the Silver Hill E&P II, LLC (SHEP II) transaction in a timely manner or at all, the ultimate funding sources for the SHEP II transaction may differ from our current expectations, we may not be able to recognize the expected benefits from the Silver Hill Energy Partners, LLC and SHEP II transactions (including our expectations for production growth) and our capital program may exceed budgeted amounts. For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see our filings with the United States Securities and Exchange Commission (SEC), including our Annual 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 INVESTMENT HIGHLIGHTS Prime Permian Position Strong Growth Profile Focused asset base with balanced exposure to the core of the Midland and Delaware Basins. Blocky, contiguous acreage footprint enabling peer leading efficiencies and long lateral horizontal development Massive inventory of high-return horizontal drilling locations in multiple stacked horizons driving substantial, multi-year production growth profile while achieving cash flow neutrality at $55 oil in 2018 Superior Execution Track record of driving down costs and achieving low cost operations, yielding strong and resilient cash operating margins throughout the commodity price cycle Focus on Capital Efficiency Rate of return driven capital program generating attractive finding and development costs leading to strong recycle ratio when combined with high cash margins Technical Leader At the forefront of horizontal drilling technology using advanced completion techniques and spacing designs, leading to resource expansion and operating efficiencies Oil-Weighted Production and Reserve Base Assets located in oily and liquids-rich areas of the Midland and Delaware Basins, generating higher revenue per boe and superior well economics Experienced Permian Team Management and senior operating team has over 30 years of average experience in the Permian Basin, operating through multiple cycles 3

4 2016 ACHIEVEMENTS Expanded Core Permian Position Entry into Delaware Basin with $2.4B acquisition of Silver Hill Energy Partners (1) Blocked up core Midland leasehold position with $69MM in acquisitions Increased drilling inventory by 127% from 2,600 gross locations at YE15 to 5,900 gross locations (2) at YE16 Focused on Returns-Driven Growth Increased average production 39% from 21.0 MBoe/d in 2015 to 29.2 MBoe/d in 2016 Strong growth despite moderating operated rig pace FY 2016 development capex of $294MM, slightly below the revised budget of $295-$315MM Increased proved reserves by 78% from 159 MMBoe at YE15 to 283 MMBoe (2)(3) at YE16 Continued to Achieve Low Cost Operations and Efficiency Gains Decreased cash operating expenses 23% to $9.11/Boe in 4Q16 from 2015 average of $11.85/Boe Achieved low drill-bit finding and development cost of $4.05/Boe (4) Maintained Financial Strength Strong balance sheet and liquidity position with 2.4x leverage, $109MM of cash and no borrowings on our revolving credit facility which has a $1.1 billion borrowing base and a $900MM company elected commitment (5) Expanded oil hedge profile, covering 55% of expected 2017 oil production, entered into basis swaps to protect mid-cush differential, and began layering in 2018 oil hedges (1) First part of Silver Hill acquisition (SHEP I) closed 11/28/16; second part (SHEP II) expected to close on 03/01/17. (2) Pro forma for SHEP I and SHEP II. (3) Reserve report prepared by Netherland Sewell & Associates, Inc. (4) Includes non-price related revisions, excludes price related revisions, excludes impact of removing remaining vertical PUDs from reserve base. (5) Pro forma for SHEP I and SHEP II, leverage based on 4Q16 annualized EBITDA and net debt outstanding as of 12/31/16. 4

5 RSP PERMIAN OVERVIEW RSP OVERVIEW CONTIGUOUS ACREAGE POSITION IN CORE OF PERMIAN BASIN (1) ~160,000 gross / 100,000 net acres across highly contiguous acreage blocks in the core of the Midland and Delaware Basins (1) ~5,900 gross (3,700 net) horizontal locations in drilling inventory Significant 2017 production ramp with visibility to 30%+ annual production growth in Cash flow neutral beginning in 2018 at ~$55 oil Organizational focus on efficiency and execution Leading drill-bit F&D costs, reserve replacement ratios and cash operating margins Key Statistics (Pro Forma for Silver Hill Acquisition) NYSE Symbol RSPP Delaware Basin Midland Basin Shares Outstanding MM Market Capitalization (2/24/17) $6.3 B Enterprise Value $7.3 B Net Debt / LQA EBITDAX 2.4x YE 2016 Proved Reserves 283 MMBoe Net Surface Acres Net Effective Hz Acres (2) Gross Locations Net Locations % Operated Midland 57, ,368 2,700 1,750 95% Delaware 40, ,538 3,200 1,950 80% (1) First part of Silver Hill acquisition (SHEP I) closed 11/28/16; second part (SHEP II) expected to close on 03/01/17. (2) Combined horizontal acreage position that Management believes is prospective for hydrocarbon production across each target horizontal zone. 5

6 STRONG TRACK RECORD OF GROWTH ANNUAL PRODUCTION GROWTH (MBOE/D) ANNUAL RESERVE GROWTH (MMBOE) SHEP II SHEP I (1) (1) Midland Basin E YE 2013 YE 2014 YE 2015 YE 2016 (1) (1) First part of Silver Hill acquisition (SHEP I) closed 11/28/16; second part (SHEP II) expected to close on 03/01/17. 6

7 DURABLE MARGINS THROUGHOUT THE COMMODITY PRICE CYCLE Achieved most efficient quarter to date in Q4 2016, with cash operating costs of $9.11/Boe and cash margin of 76% (1) Experienced Permian operations team Highly contiguous acreage footprint Crude price realization ranks amongst highest in basin HISTORICAL CASH MARGINS AND COSTS (PER BOE) $ % 80% $ % 71% Peer (2) Avg: 71% $20.00 $ % 70% $15.00 $10.00 $4.63 $4.25 $11.85 $2.60 $2.33 $9.54 Peer (2) Avg: $10.02 $9.11 $2.03 $ % $5.00 $8.14 $6.92 $2.10 $2.11 $5.41 $ % Q LOE, Gathering & Transporation, & Workovers Cash G&A Prod. & Ad Val Cash Margin (Excluding Hedges) (1) (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). (2) Peers include: CXO, FANG, LPI, PE, PXD. 7

8 SUPERIOR CAPITAL EFFICIENCY DRILLBIT F&D (EXCL. PRICE REVISIONS) (1) TOP DRILLING TARGETS SINGLE WELL IRR $10.13 Reservoir Lateral Length Glasscock Upper Wolfcamp 7,500 + $55 $5.77 $4.05 $7.49 Wolfcamp A 7,500 + Lower Wolfcamp A 4,500 + Upper Wolfcamp (XY) 4,500 + Lower Spraberry 7,500 + Middle Spraberry 7,500 + >70% 85% of 2017E D&C CAPEX 2 nd Bone Spring 4,500 + Avalon 4, % #1 Wolfcamp B 7, RSPP Permian Peers Avg (2) Wolfcamp B 4, rd Bone Spring 4,500 + West Side 7, % Midland Delaware RSP ranks amongst the most capital efficient operators in the industry Focus on maximizing well performance, reducing D&C costs and maintaining high cash operating margins Deep inventory of high rate of return drilling opportunities Wells with IRRs >40% represent 85% of 2017E D&C capex #2 Delaware Basin returns based on 4,500 lateral wells, expect uplift from drilling longer laterals Midland Basin well returns based on 7,500 LL despite a meaningful portion of 2017 inventory planned for 10,000 (1) Exploration & development expense divided by extensions plus non-price related reserve revisions. Peer numbers include all revisions when price revisions are not disclosed. RSP 2016 excludes impact of removing remaining vertical PUDs from reserve base. (2) Peers include: CPE, CXO, FANG, LPI, PE, PXD (CPE and PE have not yet reported 2016). 8

9 4Q16 AND FY16 DRILLING & COMPLETION ACTIVITY OVERVIEW ACTIVITY OVERVIEW During 2016, RSP drilled 46 and completed 53 operated HZ wells MIDLAND OPERATED HZ D&C SUMMARY During 4Q16, RSP drilled 13 and completed 14 operated HZ wells 2 drilled and 1 completed (Avalon) in the Delaware Basin in 4Q16, post close of SHEP I (1) FY16 / 4Q16 Midland Basin completions: / 7 in the Lower Spraberry 8 / 3 in the Wolfcamp A 8 / 3 in the Wolfcamp B 1 / 0 in the Middle Spraberry DRILLING & COMPLETION ACTIVITY FY16 4Q16 Drilled Completed Drilled Completed Operated Horizontal Vertical Total Non-Operated Horizontal Vertical YE 1Q16 2Q16 3Q16 4Q16 1Q16 2Q16 3Q16 4Q YE DUCs Drill Complete DUCs Note: Excludes Delaware MBoe/d PROGRESSION OF 2016 NET PRODUCTION (WEEKLY BASIS) 1Q Boe/d 2Q Boe/d 3Q Boe/d 4Q Boe/d 0 1/16 2/16 3/16 4/16 5/16 6/16 7/16 8/16 9/16 10/16 11/16 12/16 (1) First part of Silver Hill acquisition (SHEP I) closed 11/28/16 and activity only includes D&C on acquired properties from closing date. Second part of Silver Hill (SHEP II) expected to close on 3/1/17. 9

10 4Q16 AND FY16 FINANCIAL RESULTS Production growth and cost structure improvements helped support cash flow during oil price downturn ~40% production growth YOY with 25% less development capex 4Q16 development capex ~50% above 4Q15, building momentum into Q16 4Q15 FY 16 FY 15 4Q16 4Q15 FY 16 FY 15 Avg. Daily Production Cash Op. Exp. ($/Boe) Oil (MBbl/d) LOE $4.41 $4.76 $4.93 $6.46 Gas (MMcf/d) G&T NGL (MBbl/d) Prod. Taxes Total (MBoe/d) Cash G&A Total Cash Expenses $9.11 $9.98 $9.54 $11.85 Pricing Non-Cash/Other Exp. ($/Boe) Average NYMEX Oil ($/Bbl) $49.29 $42.18 $43.32 $48.80 Recurring Stock Comp $0.98 $0.93 $1.23 $1.03 Realized Price (Incl. Hedges) Non-recurring Stock Comp Oil ($/Bbl) DD&A Gas ($/Mcf) Exploration NGL ($/Bbl) Total ($/Boe) $36.60 $43.31 $32.99 $48.96 Financial Results ($MM) Capital Expenditures ($MM) Adj. EBITDAX $90.5 $74.4 $250.3 $285.1 D&C $88.1 $54.8 $275.5 $354.0 Adj. Net Income (Loss) $13.4 $12.1 ($7.4) $48.6 Infrastructure Total Development Capex $95.5 $64.1 $294.2 $

11 STRONG FINANCIAL POSITION WITH AMPLE LIQUIDITY Entered into amended and restated credit facility with $950MM borrowing base, $900MM elected commitment and $2.5B maximum lender commitments Key financial covenants: Maximum of 4.25x Total Debt / TTM EBITDAX Minimum current ratio of 1.0x Borrowing base automatically increases upon closing of SHEP II transaction to $1.1B, with elected commitment of $900MM DEBT MATURITIES ($MM) CAPITALIZATION TABLE ($ in millions) 12/31/2016 PF SHEP II Cash $691 $109 Revolving Credit Facility 6.625% Senior Unsecured Notes Due % Senior Unsecured Notes Due Total Debt $1,150 $1,150 Net Debt $459 $1,041 $1,200 $1,000 $800 $600 $400 $200 PF Borrowing Base (1) Elected Commitment (1) 6.625% 5.25% Liquidity Elected Commitment (1) $900 $900 Less: Borrowings & LCs (1) (1) Plus: Cash Liquidity $1,590 $1,008 Financial & Operating Statistics Annualized PF Q Adjusted EBITDAX (2) $434.3 PF Proved Reserves (MMBoe) (2) $ Credit Facility Senior Notes Credit Metrics Net Debt / Adjusted EBITDAX 2.4x Net Debt / Proved Reserves ($/Boe) $3.67 (1) Borrowing Base will be $1.1B pro forma for SHEP II. Elected commitment will remain $900MM. (2) Pro forma for SHEP II. 11

12 FULL YEAR 2017 GUIDANCE FULL YEAR 2017 GUIDANCE SUMMARY 2017 Guidance Range Production Avg. Daily Production (Boe/d) 53,000-57,000 % Oil 71% - 73% % Natural Gas 11% - 13% % NGLs 15% - 17% Income Statement ($/Boe) LOE (incl. workovers) $ $5.50 Gathering & Transportation $ $1.40 Exploration Expenses $ $0.60 Cash G&A $ $1.75 Non-Cash G&A $ $0.90 DD&A $ $16.00 Prod. & Ad Val. (% Rev.) 6.0% - 8.0% COMMENTARY 5 operated rigs currently (4 Midland, 1 Delaware), 1 Delaware rig added upon close of SHEP II Plan to exit year with 8 operated rigs Capex budget range includes: Latest estimate of well costs Greater proportion of longer lateral wells in the Delaware Reduction in average drilling days; more wells drilled & completed (same rig cadence) $35MM of infrastructure spend in Delaware Upgraded tank batteries, salt water disposal wells, frac pits / fresh water sourcing, power generation facilities, artificial lift Excludes recent $18MM acquisition of Lone Wolf SWD business 2017E CAPEX SUMMARY Capital Expenditures ($MM) Drilling & Completion $575 - $625 Infrastructure & Other $50 - $75 Total Development Capital $625 - $700 Non-Operated (%) 5% - 10% Operated Completions Gross Hz Operated WI 88% Avg. LL (Midland / Delaware) 8,500 / 6,250 30% 4% 5% Midland D&C Midland Infrastructure Delaware D&C Delaware Infrastructure 61% 12

13 RSP STRATEGY: RATE-OF-RETURN DRIVEN GROWTH Emphasis on high rate of return vs. achieving growth objective During oil price downturn RSP slowed drilling and opportunistically made acquisitions Operated rigs dropped from 5 in 1Q15 to 2 in 1Q16, acquired $3.0B in high return Hz inventory ROBUST 3-YEAR PRODUCTION GROWTH (MBOE/D) 2017E Ramping to 8 Hz rigs from current count of 6 (1) Production growth (82% 95%) over 2016 Slight cash flow outspend at $55.00 Leverage <2.0x at $55.00 Prelim E Plan to add 2 HZ rigs per year 30%+ production growth per year Cash flow neutral at $55.00 Leverage <2.0x at $ '11 '12 '13 '14 '15 '16 '17E '18E '19E (1) Pro forma for SHEP II acquisition (+1 rig). 13

14 DRILLING & COMPLETION EFFICIENCY IMPROVEMENTS RSP drilling HZ wells in less than half the time as HZ wells drilled in 2013 RSP is completing over 7 stages per day (sand pounds/day increased ~15% over 2015) Opportunities for additional improvement on both the Midland Basin and Delaware Basin sides MIDLAND BASIN - RATE OF PENETRATION EVOLUTION (1) MIDLAND BASIN COMPLETION EFFICIENCY Depth ( 000 ft) Days Stages/Day Pounds of Sand Pumped/Day (millions) >60% Reduction Avg. Stages/Day # Sand/Day 0.0 (1) Based on wells with a lateral length of ~7,

15 MIDLAND BASIN UPDATE

16 MIDLAND BASIN ACTIVITY UPDATE Strong well results confirming enhanced completion design and asset quality WELL RESULT UPDATE (TWO-WELL PADS) MIDLAND BASIN ACTIVITY # Well Name Compl. Date Formation Lateral Length (Feet) IP30 (BOED) % Oil 1 Mask 1004/5H 2 Spanish Trail Spanish Trail Spanish Trail /18/16 LS,WB 9,500 2,932 73% 12/9/16 WA,WB 6,500 2,910 80% 12/9/16 WA,WB 6,500 3,302 78% 8/25/16 LS,WA 6,500 2,907 80% Spanish Trail Johnson Ranch /13/16 LS,WB 6,500 2,514 76% 11/20/16 LS, LS 7,000 2,177 85% Johnson Ranch /20/16 LS, LS 7,000 2,101 79% 8 Woody /25/17 WA, WB 7,500 2,519 (1) 86% 9 9 Calverley 9-4 1/10/17 WA, LWB 9,500 2,327 (1) 76% Note: Results reflect aggregate production for 2-well pads.. (1) 14-day average, still cleaning up. 16

17 JOHNSON RANCH LOWER SPRABERRY DOWNSPACING PILOT In 4Q16, RSP completed 4 additional LS wells in the Johnson Ranch spacing pilot with the latest generation frac design Of the 4 new wells, 1 was drilled at an equivalent of 10 wells/section and 3 initiated the equivalent of a 14 well/section pattern Average of the new 4 wells compares favorably to the previous 4 wells in the section Plan to drill final 4 wells in the pattern at an equivalent of 14 wells per section during 2H17 More conclusive production results not expected until the remaining four wells have been producing for 6 months to a year (late 2018) JOHNSON RANCH SPACING PILOT CUMULATIVE AVERAGE PRODUCTION PLOT st 4 Well Pad 2nd 4 Well Pad Cuml MBoe Producing Well Days 17

18 MIDLAND BASIN WELL PERFORMANCE Substantial year over year well productivity improvement since commencing horizontal drilling in performance 13% above 2014 & 2015 avg. despite shorter avg. lateral length Updated type curves to reflect expected performance from current generation well design 2017 Average Midland Basin Type Curve: ~8,500 lateral length 1-year cuml: 205 MBoe 2-year cuml: 285 MBoe Cuml. MBoe MIDLAND BASIN WELL PERFORMANCE BY VINTAGE Note: 2016 avg. LL shorter than 2014 & 2015 avg. LL Avg. LL: 7,089 13% 54% LL: ~8,500 Avg. LL: 7,416 Avg. LL: 5, Days 2012 & 2013 Avg & 2015 Avg Avg. Weighted Avg 2017 Type Curve 18

19 SIGNIFICANT REDUCTION IN TIME TO WELL PAYOUT At $55/bbl flat, and using conservative capex and well performance assumptions, 155MBo approximates well payout To date, over 55% of wells completed in 2015 have reached payout in less than a year s time AVERAGE MONTHS TO PAYOUT (155MBO), BY YEAR DRILLED AREAS WITH 2015 WELLS THAT REACHED PAYOUT (155MBO) Months MS LS WA WB Note: Stars represent areas (potentially more than 1 well) with 2015 wells that have reached payout 19

20 MIDLAND BASIN TYPE CURVE INCREASES RSP increased average type curve for aggregate Midland Basin position Adjusted IP and initial decline / slope of RSP type curves to match early time outperformance Type curves prepared by RSP third party engineers, Netherland Sewell & Associates, Inc. Across the 45 type curves RSP carries internally, range increases on a Boe basis are as follows (vs. prior year levels): 1st Year Cuml: (0 60%) increase 2nd Year Cuml: (0 60%) increase EUR: (0 35%) increase Early production is the most important driver of a well s value (NPV / IRR); EURs are less impactful to well value and rate of return Certain areas and zones had more dramatic increases than the average RSP YOY TYPE CURVE INCREASES BY AREA, ZONE AND LATERAL LENGTH (BOE BASIS) 70% 60% 50% 40% 30% 20% 10% 0% 1st Year Cuml Change 2nd Year Cuml Change EUR Change 20

21 EARLY PRODUCTION HAS GREATEST INFLUENCE ON WELL VALUE Cuml MBo ILLUSTRATION: TERMINAL DECLINE IMPACT ON EUR / NPV % VALUE 15% VALUE Well 1 Cuml Oil Well 2 Cuml Oil 100 Well 1 NPV Well 2 NPV -$6 0 -$ Years Illustration: EUR/NPV Sensitivity to Terminal Decline $8 $6 $4 $2 $0 -$2 -$4 Terminal Decline EUR (MBoe) NPV 10% ($M) Well #1 6% 827 $6,980 Well #2 4% 920 $7,103 Net Present Value ($MM) Cuml MBo ILLUSTRATION: B-FACTOR IMPACT ON EUR 85% VALUE 15% VALUE RSP Avg. B-Factor 400 b= b= b=1.6 b= b=1.4 0 b= Years Changing assumed B-factor results in materially different EURs In illustration above, production profiles in the first few years are nearly identical while outer years vary more dramatically 35% diff A well s value is determined relatively early in its life ~85% of a well s NPV is achieved in first ~10 years Despite a 10% uplift in EUR from a 33% reduction in terminal decline, the NPV of Well #2 is less than 2% greater than Well #1 21

22 MIDLAND BASIN WELL COST UPDATE CURRENT MIDLAND DC&E COST (8,500 LATERAL) HISTORICAL WELL COST PER LATERAL FOOT (OP. WELLS) (1) Current DC&E: $6.2MM $1,500 9% $1,250 $1,000 $1,232 $1,086 $933 Increased R&D Spending 44% $750 $828 $775 $741 $760 $715 $709 47% $500 $250 Drilling Completion Equipping $0 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 4Q16 Drill Complete & Equip (1) Includes wells with lateral lengths of 7,000 8,

23 MIDLAND BASIN INVENTORY Numerous spacing pilots ongoing Base Spacing assumptions updated Optimal well placement will evolve with more data Spacing assumptions vary by area and formation Increased well density as much as 20% over YE 2015 levels in select areas based on performance to date Remain conservative but optimistic across other areas where Base Spacing maintained CURRENT SPACING ASSUMPTIONS Base Spacing Upside Spacing Formation Avg. Wells/Section Wells/Section Clearfork Middle Spraberry Jo Mill Lower Spraberry Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D BASE SPACING LOCATIONS 2,700 Gross Locations 1,750 Net Locations UPSIDE SPACING LOCATIONS 3,550 4,540 Gross Locations 2,260 2,890 Net Locations Wolfcamp B 11% Wolfcamp D 12% Clear Fork 5% Middle Spraberry 24% Wolfcamp B 11% Wolfcamp D 11% Clear Fork 4% Middle Spraberry 22% Wolfcamp A 12% Jo Mill 11% Wolfcamp A 11% Jo Mill 10% Lower Spraberry 25% Lower Spraberry 30% 23

24 DELAWARE BASIN UPDATE

25 DELAWARE BASIN INITIATIVES Blocking Up Acreage Position Initiating acreage trades with offset operators to enhance operations and drill longer laterals Recently completed trade increased lateral length of 4 drilling units in Loving County from 5,000 to 7,500 Acquired Water Disposal Operations and Infrastructure At the time of acquisition, SWD facilities maxed out Silver Hill hauling ~15,000 Bbls water/day to 3rd party facilities Acquired Lone Wolf SWD wells and related infrastructure system in 1Q17 Expansion of existing facilities in progress All water disposal in company-owned facilities within two quarters Upgrading Field Power Switching field power from diesel fired generators to raw field natural gas fired generators, reducing operating costs Longer-term, working to build-out electrical grid Enhancing Natural Gas Gathering Infrastructure System currently being upgraded to handle additional natural gas volumes Midstream provider (Outrigger) to be acquired by Targa Initiating Workovers on Existing Producers Majority of producing horizontal wells still flowing naturally (many over 1-year old) Installing production tubing and ESPs to enhance existing production Early results above expectations with significant uplift above prior rates Acquiring 3-D Seismic over Delaware Position Purchased 2 recent seismic surveys covering western 2/3rds of acreage position; shooting 3 -D seismic over eastern 1/3rd of block Will enhance capability to select optimum landing targets and drill longer laterals 25

26 DELAWARE BASIN ACTIVITY UDPATE Substantial stacked resource potential with 7 currently producing zones and strong recent results across 5 highlighted below ROBUST WELL RESULTS DESPITE SHORTER LATERALS AND RESTRICTIVE CHOKES (1) DELAWARE BASIN ACTIVITY # Well Name Zone Total Prod. Days Lateral Length (Feet) IP 30 (BOED) % Oil IP Choke Size IP FTP (PSI) Cuml Prod (MBOE) 1 Pistol H (2) Avalon 40 4, % 48/ Pistol H LWA 640 4,200 1,006 75% 16/64 2, LWA WC XY WB 2nd Bone Avalon 3 4 Corsair C H (1) LWA 210 4,100 1,787 70% 31/ State Rudd Draw H WC XY 101 4,100 1,086 73% 21/64 2, Ludeman 1302H LWA 139 6,500 1,111 71% 22/64 2, Bullet H WC B 153 4, % 22/64 1, Hughes Talbot H (1) LWA 334 4,600 1,545 78% 31/64 2, Totum #211H (1) LWA 22 4,400 2,247 72% 22/64 3, Rudd Draw H WC XY 246 4, % 21/64 2, INITIAL WORKOVERS PROVIDING SUBSTANTIAL UPLIFT 3 # Well Name 10 Brunson 1111H Zone Total Prod. Days Avalon 206 8,000 Lateral Length (Feet) Action ESP Install Previous Rate (BOED) Post Change (BOED) % Oil Cuml Prod (MBOE) 460 1,035 68% Ludeman 505H 2nd Bone 174 4,400 ESP Install 337 1,033 71% 87 Recent Well Results 12 Hughes Talbot H LWA 234 4,100 Tube Up % 99 RSP Prod. Enhancements Note: Well # s 5, 10, & 11 are located on SHEP II acreage, expected to close on March 1, (1) Italics indicates non-operated well. Totum well IP represents 24-hour average. (2) Pistol H well IP represents 14-day average. 26

27 DELAWARE BASIN WORKOVER CASE STUDY RSP recently directed workovers of several wells with excellent results Wells have been online ~ days total and current rates are substantially above IPs Installed ESP in Brunson 1111H 8,000 Avalon well on January 20th Installed ESP in Ludeman 505H 4,400 2 nd Bone Spring well on February 5th Additional workovers ongoing PRODUCTION UPLIFT FROM RECENT WORKOVERS 2,000 ESP Install Mboe/d Days Brunson 1111H (Avalon) Ludeman 505H (2nd BS) Note: Brunson and Ludeman wells are located on SHEP II acreage, expected to close on March 1,

28 DELAWARE BASIN WELL PERFORMANCE Substantial year over year well productivity improvement on the Silver Hill properties Improvements in drilling and completion techniques Switch in primary drilling target to Wolfcamp 300 DELAWARE BASIN WELL PERFORMANCE BY VINTAGE Recent LWA (Corsair C H), Silver Hill nonoperated well plotted at right is flowing on a more conventional 31/64 choke setting (FTP of 915 PSI) as compared to recent operated Silver Hill wells flowing on ~20/64 choke (FTP s range from ~2,200 to 3,000 PSI) (1) ~4,100 lateral length 180-day cuml: 182 MBoe Est. 1-year cuml: 315 MBoe Est. 2-year cuml: 425 MBoe Cuml. MBoe Corsair C H 22% Days Corsair C H (1) Wolfcamp A wells. 28

29 DELAWARE CRUDE OIL GATHERING AND TRANSPORTATION OVERVIEW Crude oil gathering provided by Outrigger (Targa) DELAWARE CRUDE OIL INFRASTRUCTURE Targa (NYSE: TRGP), one of the largest midstream providers in North America, acquiring Outrigger Volumes transported to Wink with multiple basin outlets Average oil price realization is ~$0.40 lower than Midland properties, under existing arrangements Significant crude oil gathering and transportation optionality with multiple inter/intrastate pipelines proximate to RSP acreage position 29

30 DELAWARE GAS GATHERING AND TRANSPORTATION OVERVIEW Gas gathering provided by Outrigger (Targa) DELAWARE GAS GATHERING SYSTEM Processing provided by Outrigger (Targa) and Energy Transfer 70 MMcf/d cryogenic processing plant on acreage position Gathering system Loving Gas Plant Diamondhead Compressor Expandable to accommodate expected growth 30

31 DELAWARE WATER INFRASTRUCTURE OVERVIEW Recently acquired water gathering and disposal infrastructure assets that serviced Silver Hill DELAWARE WATER DISPOSAL SYSTEM Post acquisition RSP controls: 4 operated SWD wells Each well disposes 15-20,000 bbls/day Gathering system SWD well Planned SWD Potential SWD Right to drill 5 additional SWD wells 3 permitted/permitting ~100-mile network of water gathering pipelines Significant exclusive surface-use agreements All disposed water in RSP-owned disposal wells within 6 months Ample water supply available to support planned drilling 31

32 RSP PERMIAN INVESTMENT HIGHLIGHTS Prime Permian Position Strong Growth Profile Superior Execution Focus on Capital Efficiency Technical Leader Oil-Weighted Production and Reserve Base Experienced Permian Team 32

33 DELIVERING VALUE HIGH QUALITY ASSETS FOCUS ON RETURNS & EXECUTION STRONG FINANCIAL POSITION EXPERIENCED MANAGEMENT 33

34 APPENDIX

35 INCREASING HEDGE PROFILE RSP opportunistically layers on hedges to protect returns and support planned capital expenditures HEDGE CONTRACT DETAIL Crude Oil (Bbl, $/Bbl) 1Q 17 2Q 17 3Q 17 4Q Three-Way Collars (1) 675, ,000 3,160,000 Ceiling Floor Short Put $54.25 $45.00 $35.00 $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 $60.05 $45.00 $60.05 $45.00 $60.05 $45.00 $60.02 $45.00 Deferred Premium Puts (1) 910, , ,000 2,750,000 Floor Deferred Premium (2) $48.50 ($4.00) $48.50 ($4.00) $48.50 ($4.00) $48.50 ($4.00) Put Spreads (1) 675, ,000 Floor Short Put Premium $45.00 $35.00 ($2.32) Total Hedge 1,800,000 Weighted Average Floor (3) $ ,047,500 $ ,070,000 $ ,070,000 $44.78 $45.00 $35.00 ($2.32) 7,987,500 $44.63 % Hedged on Midpoint Oil Volume Guidance (5) 55% Mid-Cush Differential Swaps (6) 1,881,000 2,548, , ,000 5,625,000 Weighted Average Swap ($0.14) ($0.11) ($0.38) ($0.50) ($0.18) Natural Gas (MMBtu, $/MMBtu) 1Q 17 2Q 17 3Q 17 4Q Costless Collars (4) 1,955,000 2,366,000 2,422,000 2,545,000 9,288,000 Ceiling $3.83 $3.86 $3.86 $3.86 $3.85 Floor $3.00 $3.00 $3.00 $3.00 $3.00 (1) The crude oil derivative contracts are settled based on the arithmetic average of the closing settlement price for the front month contract NYMEX price of West Texas Intermediate Light Sweet Crude. (2) The deferred premium is not paid until expiration date, aligning cash inflows and outflows with the settlement of the derivative contract. (3) Weighted average floor assumes the long put in three way collars and put spreads and reflects the impact of premiums paid. (4) 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 2017 midpoint oil volume guidance. (6) The Mid-Cush oil derivative contracts are settled based on the arithmetic average of the Argus daily price for WTI Midland and the arithmetic average of the Argus daily price for WTI Formula Basis. $65.06 $50.00 $ ,160,000 $

36 EXECUTING BOLT-ON ACQUISITIONS IN CORE MIDLAND During 2016, RSP acquired ~$69 million of bolt-on oil and gas properties: ~2,800 net acres located in core Midland, Martin, and Glasscock Counties ~$7 million of acquisitions in 4Q16 LOCATOR MAP OF 2016 ACQUISITIONS RSP Existing Acreage New Acreage Acquired Additional Interest Acq. 36

37 RSP PERMIAN 3 RD PARTY 1MMBOE EUR WELLS Stars represent areas where Netherland Sewell & Associates, Inc. projected at least one producing well to have an EUR over 1MMBOE All four primary targets in the Midland Basin have 1MMBoe wells To date, two target intervals in Delaware Basin have 1MMBoe wells despite majority of wells with lateral lengths under 5,000 AREAS WITH 3 RD PARTY PROJECTED EUR OVER 1MMBOE DELAWARE BASIN WC XY LWA MIDLAND BASIN MS LS WA WB Stars represent areas (potentially more than 1 well) with EURs >1MMBoe 37

38 ADJUSTED EBITDAX AND ADJUSTED NET INCOME RECONCILIATION Reconciliation of Net Income (Loss) to Adjusted EBITDAX (in thousands) Three Months Ended December 31, Twelve Months Ended December 31, Net Income (Loss) $ 1,381 $ (20,751) $ (24,851) $ (18,254) Interest Expense 13,683 13,175 52,724 43,538 Income Tax Expense (Benefit) (1,464) (10,307) (18,706) (11,683) DD&A 52,484 39, , ,039 Impairments ,031 4,901 34,269 Exploration Expense ,093 2,380 Acquisition Costs 6,374-6,374 - Loss (Gain) on Derivative Instruments 17,538 (3,439) 23,760 (20,906) Net Cash Payments on Settled Derivative Instruments (2,398) 23,122 (1,732) 92,118 Non-Cash Equity Based Compensation 3,215 2,409 13,764 9,384 Asset Retirement Accretion Other income, net (1,246) (242) (1,833) (469) Loss (gain) on Sale of Assets Adjusted EBITDAX $ 90,529 $ 74,367 $ 250,326 $ 285,058 Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss) (in thousands) Net income (loss) $ 1,381 $ (20,751) Impairments ,031 Loss (gain) on derivative instruments 15,140 19,683 Net cash payments on settled derivative instruments - - Stock-based compensation - non-recurring Other income, net - - (1,246) (242) Loss (gain) on asset sale Income tax expense (benefit) for above items (8,833) (16,949) Acquisition Costs Three Months Ended December 31, ,374 - Adjusted Net Income (Loss) $ 13,395 $ 12,074 Twelve Months Ended December 31, $ (24,851) $ (18,254) 4,901 34,269 22,028 71, (1,833) (469) (14,659) (38,434) 6,374 - $ (7,358) $ 48,630 38

39 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