RSP Permian Investor Presentation November 2014

Transcription

1 RSP Permian Investor Presentation November 2014

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, 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 September 30, 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 Overview Market Snapshot Permian Basin Pure Play NYSE Symbol: Market Cap (1) : Net Debt (2) : Enterprise Value: RSPP ~$1.9 billion ~$0.4 billion ~$2.3 billion Pro Forma Production and Reserves (3) Average Daily Production (4) Acreage Summary 14.6 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, ,450 Surface Acreage 63,035 46,738 (1) As of November 6, (2) Balance as of September 30, (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, (4) Average daily production rate for the seven days ending October 1,

4 Contiguous Acreage in the Core of the Midland Basin Overview RSP s Acreage in the Midland Basin Large, contiguous, core acreage in the Midland Basin Permian pure-play with Over 178,000 net effective horizontal acres (1) Low-risk, oil-rich base with rapid growth potential Substantial liquidity to develop asset base Focus on horizontal drilling to maximize returns Four current horizontal rigs going to five in late Q and six during Q Large inventory of identified drilling locations (1) 1,760 horizontal and 1,241 vertical drilling locations Track Record of Production Growth Focus Areas Dawson Area Boe/d 15,000 10,000 5, ,807 5,089 7,293 9,339 10,714 11,217 14, Q Q Q Q3 Exit Rate (1) Combined horizontal acreage position that management believes is prospective for hydrocarbon production across each target horizontal zone. (2) Average daily production rate for the seven days ending October 1, (2) TX Glasscock Acquisitions 4

5 Third Quarter 2014 Highlights Q3 Financial Results Average daily production during the Q of 11,217 Boe/d Q3 Exit Rate of ~14.6 MBoe/d (1) On track to meet 2014 stated production and capex guidance ~$650 million of available liquidity as of 9/30/14 Capital Markets and Acquisitions Closed on acquisitions totaling ~$257 million Completed a $295 million follow-on equity offering Completed inaugural issuance of $500 million of Senior Notes Increased borrowing base from $375 million to $500 million Operational Highlights Completed 11 operated horizontal wells in the Middle Spraberry, Lower Spraberry, Wolfcamp A, and Wolfcamp B target zones Concluded the majority of planned multi-well, multi-zone test pilots First horizontal wells drilled on Spanish Trail prospect with strong results Completed Microseismic and 3D surveys evaluating results (1) Average daily production rate for the seven days ending October 1,

6 Boe/d RSP Reaffirms Production & Capex Guidance 2014 Production Guidance Summary Total Boe/d 11,500 12,000 % Oil 70% 72% % Natural Gas 11% 13% % NGLs 16% 18% 2014 Capex Budget ($MM) RSP has spent ~$293 million year to date through Q3 2014, excluding acquisitions $400 $425 $400 16,000 14,000 12,000 10,000 8,000 9,339 10,714 11,217 ~14,600 11,500-12,000 $300 $200 $100 Q3 Q2 Q1 Total Capex Q3 Q2 Q1 Drilling & Completion Capex 6,000 4,000 2,000 Infrastructure & Other $25 Vertical 25% Q Q Q Q3 Exit Rate (1) 2014 Guidance Drilling & Completion $400 Horizontal 75% (1) Average daily production rate for the seven days ending October 1,

7 Weekly Boe/d Pad Development Leads to Lumpy Production Completions occur 2+ at a time and lead to inherent lumpiness due to timing At any given time, up to 10% of base production could be shut in for offset fracs 2014 Weekly Net Production & Operated Horizontal Completions 15,000 ~14.6 Mboe/d 3Q Exit Rate 40 Q1 Average: 9,339 Boe/d Q2 Average: 10,714 Boe/d Q3 Average: 11,217 Boe/d 13 Completions 11 Completions Completions 6 Completions 5,000 6 Completions Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Cumulative Operated Horizontal Completions 0 7

8 2014 YTD Drilling Activity Overview Overview of Drilling Activity During 2014 First Half of 2014 Q YTD 2014 Drilled Completed Producing Drilled Completed Producing Drilled Completed Producing Operated Wells Horizontal Vertical Total Non-Operated Wells Horizontal Vertical Executing Multi-Zone Development Focus Area Wells with Production History (1) 1H 2014 Q Middle Spraberry Average Average Average Lateral 30-Day IP 30-Day IP / # of Wells Length (ft) (Boe/d) 1,000' 4 6, YTD Lower Spraberry 9 6, Operated Horizontal Completions Wolfcamp A Wolfcamp B Lower Spraberry Middle Spraberry Wolfcamp D (1) Excludes two wells in Dawson County and Wolfcamp D wells with mechanical issues. Wolfcamp A / B Total 16 6, ,

9 Focus Area Activity Update Overview During the third quarter, RSP completed 9 operated horizontal wells and 12 operated vertical wells in its primary operating area First wells completed in Spanish Trail prospect, including first two 9,000+ foot laterals Concluded the majority of planned multi-well test pilots Notable Recent Horizontal Completions Lateral Peak 30-Day IP 30-Day IP / 1000' Name Completed Zone Length (ft) (Boe/d) (Boe/d) % Oil Spanish Trail 217WB Q3 Wolfcamp B 6,860 1, % Spanish Trail 217LS Q3 Lower Spraberry 6,853 1, % Cross Bar Ranch 2017WA Q3 Wolfcamp A 7, % Cross Bar Ranch 2017LS Q3 Lower Spraberry 7,074 1,052 (1) % Cross Bar Ranch 2017MS Q3 Middle Spraberry 7, (2) 104 NA Johnson Ranch 1018WA Q4 Wolfcamp B 7,392 1,059 (2) 143 NA Johnson Ranch 1018WB Q4 Wolfcamp B 7, (3) 90 NA Spanish Trail 218MS Q4 Middle Spraberry 9, (2) 95 NA Spanish Trail 218LS Q4 Lower Spraberry 9,947 1,278 (2) 128 NA Q Average (4) 9 Wells (7 wells with 30-day IP rates) 7, % Q Average 6 Wells 5, % % Quarterly Difference +22% +37% +16% (1) Cross Bar Ranch 2017LS has 30 days of production history but is still cleaning up and has not yet reached a peak 30-day IP rate (2) Reflect last 7-day average rates; wells are on ESP lift, still cleaning up and have not yet reached 30-day peak rates. Not included in quarterly averages. (3) Johnson Ranch 1018WB reflects last 7-day average rate; well is flowing naturally and has not yet reached peak rates. (4) Q average includes the seven wells we completed in 3Q14 with 30-day peak rates. Not all of the seven wells are listed in the table above. 9

10 Boe/d Boe Spanish Trail Pilots Strong Early Results Spanish Trail Unit 218 MS 218 LS N 218 MS/LS 217 WB/LS 217 WB 217 LS Middle Spraberry 700 Gun Barrel View 575 Lower Spraberry Dean Wolfcamp A Wolfcamp B Mile Spanish Trail Completions Daily Production Spanish Trail 217 Cumulative Production LS IP-30 1,217 Boe/d 218 MS IP-24-hr 1,101 Boe/d 217 WB IP-30 1,211 Boe/d 218 LS IP-24hr 1,451 Boe/d 80,000 60,000 40,000 Wells still cleaning up 20, LS 218MS 217WB 217LS WB 217LS 10

11 Boe/d Crossbar Ranch Stacked Lateral Wolfcamp A/B Pilot Cross Bar Ranch 1717 WB MARTIN CO Crossbar 1717 LS Crossbar WA DEAN WC A WC B ANDREWS CO 2017 WA WB 110 Cross Bar Ranch Pilot Summary Cross Bar Ranch Pilots Daily Production WB WA WB WA Lat Length 6,955 7,107 7,074 7,074 Stages Stage Length Proppant #/Ft 1,238 1,160 1,121 1,377 Fluid/Ft Avg Conc. #/gal Day Cum RSP WC Type CBR1717WA CBR1717WB CBR2017WA CBR2017WB 11

12 Boe/d 200 Johnson Ranch Wolfcamp A/B Spacing Pilot Johnson Ranch Wolfcamp B Full Development W E 1021 WA 1019 WA N Lower Spraberry Gun Barrel View 1018 WA Gun Barrel View Dean Wolfcamp A Wolfcamp B WB 1021 WB 1022 WB 1018 WB 1019 WB Mile Johnson Ranch 1018 Wolfcamp A / B Pilot Daily Production 1000 Wolfcamp B Flowing Wolfcamp A Artificial Lift

13 Dawson Activity Update Overview From Q to Q1 2014, RSP spent minimal capital acquiring 11,481 net acres in southern Dawson County as a low-cost option on the Wolfcamp and Spraberry horizontal play extending further North In Q3 2014, RSP completed its first two wells in Dawson County in the Lower Spraberry and Wolfcamp B zones Morgan 3601 LS: 30-Day IP of 311 Boe/d, virtually flat since coming online with cumulative production of ~30 MBoe in 100 days Encouraging result considering the well is facilityconstrained and would produce at higher rates if adequate SWD facilities were in place Morgan 3601 WB: Extremely high water cut Less than 100 Boe/d RSP will further evaluate the results and the geology prior to drilling any additional wells, but believes area will support economic horizontal drilling Focus Area Acreage Map Dawson Morgan

14 30-Day IP / Foot (Boe/d) Cost per Lateral Foot Proppant Pounds Per Foot RSP Continues to Improve on its Horizontal Drilling & Completions Horizontal drilling costs continue to go down, while overall horizontal well costs are flat due to improved completion techniques Drilling Costs Trending Down Improving Horizontal Completion Techniques $2,000 RSPP s Proppant per Foot of Lateral Over Time $1,500 $1,000 Jan-13 Apr-13 Jun-13 Sep-13 Dec-13 Mar-14 Jun-14 Sep-14 Completion Date 30-Day IPs vs Proppant per Foot of Lateral $500 $ Q Q Q Total D&C Drilling Cost Only Proppant Pounds per Foot 14

15 24-Hr IP (Boe/d) RSP s Vertical Drilling Program Remains Strong RSP Notable Vertical Wells in 2014 & Locator Map Well Peak 24 HR Peak 30 Day (Boe/D) (Boe/D) CALVERLEY 24-04A BUS BARN 2619D CALVERLEY 09-03A ESTES SPANISH TRAIL SPANISH TRAIL CALVERLEY 36S-01A CALVERLEY 09-01A BRUNSON 30-01A SPANISH TRAIL Vertical Well Results Continue to Improve Estes Bus Barn Spanish Trail Martin Co. Calverley/Brunson YTD 100% 80% 60% 40% 20% Midland Co. Glasscock Co. 30-Day IP % Oil 15

16 Longitudinal distance from stage center (feet) Propped Fracture Volume Cross Bar Ranch 2017 Stacked Pad Micro Seismic Review Cross Bar Ranch 2017 Stacked Pad Micro Seismic Lateral Wellbore Spacing (Map View) All Stages All Stages All Stages Middle Spraberry Lower Spraberry Wolfcamp A / Wolfcamp B Perpendicular distance from stage center (feet) Middle Spraberry Lower Spraberry Wolfcamp A / Wolfcamp B Maximum Propped Total Length: 450 ft 300 ft 400 ft Microseismic Suggested Lateral Wellbore Spacing: 400 ft 300 ft 400 ft RSP Selected Lateral Wellbore Spacing ft 16

17 Vertical distance from stage center (Feet) Propped Fracture Volume Cross Bar Ranch 2017 Stacked Pad Micro Seismic Review Vertical Wellbore Spacing Commentary Middle Spraberry Vertical wellbore spacing between the MS and LS wells is likely excessive, leaving potential for possible Jo Mill locations Jo Mill Zone Lower Spraberry Vertical wellbore spacing between the LS and WA wells is likely sufficient MS LS WA Dean Wolfcamp A Wolfcamp B Current Vertical Wellbore Spacing: Maximum Propped Total Height: 625 ft 430 ft 400 ft 280 ft 350 ft Cline Median Propped Total Height: 300 ft 260 ft 200 ft Perpendicular distance from stage center (Feet) 17

18 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 18

19 Other Initiatives Saltwater Disposal Joint Venture Entered into agreement with multiple operators to drill saltwater disposal wells Secures SWD capacity for substantial portion of RSP s leasehold in its primary operating area Contract with Halliburton for dedicated frac crew Begin building infrastructure to support a horizontal drilling program on recently acquired Glasscock acreage Continuing to evaluate ways to ensure availability of services and infrastructure 19

20 RSP in a Strong Financial Position to Execute its Strategy Financial Strategy Following Q3 capital markets and acquisition activity, RSP had ~$650 million of liquidity at 9/30/14 Ensures capital to execute drilling program into 2016 with no additional capital raises or borrowing base increases Allows RSP to take advantage of future acquisition opportunities Maintain conservative balance sheet and financial flexibility Capitalization Table ($ in millions) 9/30/2014 Cash $151 Revolving Credit Facility % Senior Unsecured Notes Due Total Debt $500 Net Debt $349 Liquidity Borrowing Base $500 Less: Borrowings & LCs (0) Plus: Cash 151 Liquidity $651 Financial & Operating Statistics Q Annualized Adjusted EBITDAX (1) $220.3 Latest Daily Production (MBoe/d) (2) 14.6 Credit Metrics Net Debt / Annualized Adjusted EBITDAX 1.6x Net Debt / Latest Daily Production ($/Boe/d) $23,878 (1) Based on 3Q 2014 Adjusted EBITDAX annualized. Please see reconciliation of Adjusted EBITDAX in Appendix. (2) Average daily production rate for the seven days ending October 1,

21 Protecting Cash Flows Through Hedging Program RSP has hedged 100% of its projected PDP oil production and more than half of its expected total oil production through the end of next year RSP will continue to add hedges in 2015 and beyond Oil Hedge Summary Q Q Q Q Q Swaps Volumes (MBbls) Average Swap Price ($/Bbl) $94.50 $92.60 $92.60 $92.60 $92.60 $92.60 Collars Volumes (MBbls) ,337 Average Floor ($/Bbl) $87.49 $87.57 $86.43 $85.57 $85.57 $86.42 Average Ceiling ($/Bbl) $ $94.97 $94.81 $94.33 $94.28 $94.64 Total Volumes Hedged (MBbls) ,457 Total Blended Floor $88.16 $87.77 $86.72 $85.97 $85.97 $86.72 Daily Volumes (Bbls/day) 6,750 8,367 7,121 5,739 5,739 6,732 % Future Oil Production Hedged ~60% >50% 21

22 RSP Permian Planning for the Future Focus on Executing Development of High-Quality Multi-Year Inventory Maximize Efficiency by Continuing 100% Multi-Well, Multi-Zone Pad Development Leverage Results of Science and Pilots in Setting Development Scheme Evaluate Opportunistic Acquisitions that Supplement Existing Inventory Maintain Financial & Operational Flexibility Evaluate Oil Price Environment in Scheduling New Rigs and Setting Pace for Growth Target Conservative Debt Levels and Sufficient Liquidity to Self-Fund Organic Growth Proactively Work to Secure Service Providers, Supply Sources & Infrastructure 22

23 Appendix 23

24 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 Sept 30, 2014 June 30, 2014 Sept 30, 2014 Sept 30, 2013 Revenues Oil sales $64,119 $66,134 $64,119 $33,139 Natural gas sales 2,297 3,117 2,297 1,400 NGL sales 4,229 4,811 4,229 2,321 Total revenues $70,645 $74,062 $70,645 $36,860 Net cash from derivative instruments (1,641) (1,517) (1,641) (1,338) Adjusted Total Revenues $69,004 $72,545 $69,004 $35,522 Operating Expenses Lease operating expenses $7,140 $9,279 $7,140 $3,785 Production and ad valorem taxes 5,137 5,964 5,137 2,413 General and administrative expenses 3,295 3,573 3,295 1,048 Total operating costs and expenses $15,572 $18,816 $15,572 $7,246 Adjusted EBITDAX, as defined $53,432 $53,729 $53,432 $28,276 Depreciation, depletion, and amortization $18,991 $21,734 $18,991 $18,879 Asset retirement obligation accretion Exploration 967 1, Interest expense 2,241 1,142 2, Stock-based compensation, net ,919 Adjusted income before income taxes $30,283 $28,924 $29,276 $8,376 Adjusted income tax expense 10,902 10,413 11,436 Adjusted net income, as defined $19,381 $18,511 $17,840 $8,376 Adjusted net income per common share - Basic $0.26 $0.25 $0.24 N/A Adjusted net income per common share - Diluted $0.26 $0.25 $0.24 N/A 24

25 Boe/d Wolfcamp A/B Horizontals Continue to Exceed Expectations RSP has completed 16 wells in the Wolfcamp B and 3 wells in the Wolfcamp A, with an average lateral length of ~6,500, including 5 Wolfcamp A/B wells in the third quarter Wolfcamp A/B Type Curve and Operated Well Production 1000 Johnson Ranch 1018WA (~7,400 lateral) First Spanish Trail Wolfcamp: Spanish Trail 217WB (~6,900 lateral) Wolfcamp A/B Type Curve 7,000' Lateral Per 1,000' MBOE ~665 ~95 MBO ~475 ~68 First Wolfcamp A Well Crossbar Ranch 1717WA: Drilled on a Wolfcamp A/B Pad (~7,100 lateral) Wolfcamp A/B 7,000 Lateral Type Curve Note: Average production data normalized for a 7,000 lateral and operational downtime. As of October Excludes Wolfcamp well in Dawson County. Wolfcamp A/B Average Normalized 25

26 Boe/d Lower Spraberry Results Also Exceeding Expectations RSP has completed 11 wells in the Lower Spraberry with an average lateral length of ~6,600, including 3 in the third quarter Lower Spraberry Type Curve and Operated Well Production 1000 Spanish Trail 218LS (~9,900 lateral) First Spanish Trail Spraberry: Spanish Trail 217LS (~6,900 lateral) Lower Spraberry Type Curve 7,000' Lateral Per 1,000' MBOE ~665 ~95 MBO ~475 ~68 First Well in Dawson County: Morgan 3601LS (~7,200 lateral) Lower Spraberry 7,000 Lateral Type Curve Note: Average production data normalized for a 7,000 lateral and operational downtime. As of October Lower Spraberry Average Normalized 26

27 Boe/d Initial Middle Spraberry Results Reflect Potential RSP has completed 7 wells in the Middle Spraberry with an average lateral length of ~7,100, including 3 in the third quarter Middle Spraberry Type Curve and Operated Well Production Middle Spraberry Type Curve 1000 Spanish Trail 218MS (~9,900 lateral) Headlee 3911 MS (~7,400 lateral) 7,000' Lateral Per 1,000' MBOE ~615 ~88 MBO ~455 ~65 Cross Bar Ranch 2017MS (~7,100 lateral) Middle Spraberry 7,000 Lateral Type Curve Note: Average production data normalized for a 7,000 lateral and operational downtime. As of October Middle Spraberry Average Normalized 27

28 Extensive Multi-Year Drilling Inventory with Strong Rates of Return 3,250 3,000 2,750 2,500 2,250 2,000 1,750 1,500 1,250 1, Middle Spraberry Lower 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) Focus Areas (1) 298 Dawson Area 1,760 WC-A WC-B WC-D (Cline) Total Target Horizontal Locations 438 Vertical 40- Acre Spacing Note: As of June 30, 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 ) 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 803 Vertical 20- Acre Spacing 3,001 Total Locations Net Locations: Focus Areas (1) ,788 Dawson Total: , ,989 EUR (2) NA Avg. Length 6,748' 6,722' 6,627' 6,738' 6,727' 6,719' 28

29 Acquisitions Create Another Primary Operating Area for RSP Acquisition Acreage Offset by Significant Industry Activity Energen Epley Lease 4 Permitted Locations Pioneer Flanagan 14 Lloyd A #21H (Lower Spraberry) 24-hr IP: 1,010 Boe/d Cum: 88 MBoe 7,212 lateral length Flanagan 14 Lloyd B#1H(Wolfcamp B) 24 hr IP: 1,460 Boe/d 9,542 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 RSP Permian 2015 Planned Wolfcamp Laterals Pioneer Houston Ranch 1H,10H,11H Permitted Locations 3 Rivers Graves Lease 3 Permitted Locations BTA Cox Unit 4 Permitted Locations ~6,900 Planned Lateral Lengths Apache Shackelton Lease (Wolfcamp A) 6 Permitted Locations - ~4,900 Lateral Length Athlon / Energen 12 Permitted Locations Hunt Boone-Coffee 1HB, 2HB 2 Permitted Locations Energen Brazos / Trinity Leases 35 Permitted Locations Pioneer Shackleford Unit (Wolfcamp) 11 Permitted Locations Athlon Wilkinson 31 #8H (Wolfcamp A) 30-day IP: 1,562 Boe/d 69% Oil 7,132 Lateral Length Hunt Harris-Hutchinson Lease (Wolfcamp) 2 Permitted Locations Apache Shrock Lease (Wolfcamp) 10 Permitted Locations XTO Midkiff / LHS Leases Permitted Locations 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: 1406 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 29

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