3Q 2017 FINANCIAL & OPERATING RESULTS. November 6, 2017

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1 3Q 2017 FINANCIAL & OPERATING RESULTS November 6, 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 for RSP s operating activities, access to and availability of transportation, processing and refining facilities, the financial strength of counterparties to RSP s credit facility and derivative contracts and the purchasers of RSP s production and third parties providing services to RSP, acts of war or terrorism and the fact that 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 Report on Form 10-K and Quarterly Reports on Form 10-Q. Existing and prospective investors are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. 2

3 RSP PERMIAN OVERVIEW RSP OVERVIEW CONTIGUOUS ACREAGE POSITION IN CORE OF PERMIAN BASIN (1) ~92,000 net acres across highly contiguous acreage blocks in the core of the Midland and Delaware Basins ~6,000 net royalty acres in the Delaware Basin (1) 4,200+ net horizontal locations in drilling inventory Current production of 65 MBoe/d (2) Expect 2017 YoY production growth of 89% at midpoint of guidance Organizational focus on returns, efficiency and execution Leading drill-bit F&D costs, reserve replacement ratios and cash operating margins Positive adj. net income at sub-$50 oil prices Key Statistics (as of 9/30/17) NYSE Symbol RSPP Shares Outstanding Market Capitalization (share price as of 11/3/17) Enterprise Value MM $5.6 B $7.0 B Net Debt / Adj. EBITDAX (3) 2.5x Net Acres Net Locations (4) Proved Reserves (MMBoe) (5) Resource Potential (BBoe) Midland 46,700 1,750-2, Delaware 45,600 2, Total 92,300 4,200-5, (1) Net royalty acre defined as one surface acre leased at a 1/8 th royalty. (2) As of November 3, (3) Based on Annualized 3Q17 Adjusted EBITDAX. (4) Midland Basin locations based on range of base to upside case well spacing. (5) As of 1/1/17, pro forma Silver Hill closing on 3/1/17. 3

4 3Q CORPORATE UPDATE

5 Production Cash G&A/BOE Adj. EBITDAX Adj. Net Income HIGHLIGHTS On track to meet Company 2017 guidance objectives 3Q17 vs. 2Q17 8% 11% 7% 8% Positive adj. net income with average realized oil price less than $50 per barrel over past year, underscoring RSP s ability to deliver profitable growth in lower oil price environment D&C capex flat QoQ; increased infrastructure and other capex during 3Q attributable to continued Delaware Basin build-out Closed several bolt-on acquisitions of leasehold acreage and mineral interests for an aggregate purchase price of $234 million, significant majority located in the heart of Delaware Basin position 5,800 net leasehold acres and 5,800 net royalty acres (1) (includes deals closed in July, previously announced at 2Q17 release) Recent Updates Subsequent to 3Q17, borrowing base increased from $1.1 B to $1.5 B, enhancing liquidity position Negotiated interest rate reduction on outstanding borrowings pricing grid Elected commitment remains at $900 million Bolstered hedging profile into 2018 during recent oil price rally Extending partnership with Halliburton for 2 full-time frac crews in 2018 In process of finalizing local sand contract (1) Net royalty acre defined as one surface acre leased at a 1/8th royalty. 5

6 RSPP Stock Price RSP BUILDING SHAREHOLDER VALUE THROUGH THE CYCLES Production (MBoe/d) Quarterly Annualized EBITDAX IPO (Jan 2014) 8.2 $194.8 (2) Current (1) 58.9 $ ,000 6,000 5,000 4,000 3,000 HORIZONTAL INVENTORY EXPANSION SINCE IPO (GROSS LOCATIONS) Silver Hill Acquisition HZ Drilling Locations (Base Spacing) Proved Reserves (MMBoe) 1, ,930 (3) (3) 2,000 1,000 0 IPO YE 2014 YE 2015 YE 2016 GROWTH IN SHAREHOLDER VALUE SINCE IPO Net Surface Acreage Enterprise Value ($ Billions) Market Cap ($ Billions) ~34,000 $1.4 $1.4 ~92,300 $7.0 (4) $5.6 (4) $50 $40 $30 $20 $10 $0 Jan 14 Jan 15 Jan 16 Jan % -42% $120 $100 $80 $60 $40 $20 $0 Oil Price (1) As of 3Q17, except where otherwise noted. (2) 1Q14 annualized EBITDAX. (3) As of YE 2016, pro forma for Silver Hill acquisition. (4) Share price as of 11/3/17. RSPP WTI Oil 6

7 RSP STRATEGY: RATE-OF-RETURN DRIVEN GROWTH Emphasis on high rate of return, rather than growth for growth s sake 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 PRODUCTION GROWTH (MBOE/D) Increased to 7 Hz rigs from 6, averaged 2 full-time frac crews 2017E Production growth (82% 95%) over 2016 Slight cash flow outspend Leverage ~2.5x (1) 57 Assuming $50+ oil price 53 Prelim 2018E Plan to add 1 completion crew and likely 1 Hz rig next year 30%+ production growth Operating Cash Flow > Capex by YE 2018 at $ Leverage ~2.0x (1) by YE 2018 at $ '11 '12 '13 '14 '15 '16 '17E '18E (1) Leverage calculated as Total Debt / LQA EBITDAX. 7

8 TRACK RECORD OF DELIVERING SUPERIOR DEBT-ADJUSTED GROWTH Rank #2 amongst oil-weighted peer group ( >$2 B market cap) for production growth per DAS from 2Q16 to 2Q17 50% 2Q16 2Q17 PRODUCTION GROWTH PER DEBT-ADJUSTED SHARE 40% 30% 20% 10% 0% -10% -20% Source: Public filings. Peer companies include: APA, APC, CLR, CPE, CXO, DVN, EGN, EOG, FANG, HES, LPI, MRO, MTDR, MUR, NFX, OAS, PDCE, PE, PXD, WPX, XEC. 8

9 RSP OWNERSHIP UPDATE RSP MANAGEMENT AND BOARD ARE STRONGLY ALIGNED WITH SHAREHOLDERS Management and Board hold ~14% of outstanding shares (>$750 MM of value) compared to <5% average insider ownership of E&P SMID-Caps Management compensation is heavily weighted (>2/3rds) towards stock, further aligning objectives ½ of stock awards are performance shares earned based on relative total shareholder return Cash bonus amounts are tied to metrics that measure overall financial performance of the Company, not absolute growth metrics, M&A success etc. KAYNE ANDERSON AND OTHER SILVER HILL SHAREHOLDERS OWNERSHIP IN RSP HAS BEEN DRAMATICALLY REDUCED Upon closing of the Silver Hill transaction, Silver Hill owners received 31 MM shares of RSP stock, subject to certain escrow holdbacks Kayne Anderson, Silver Hill s largest shareholder, became RSP s largest shareholder Through a block trade executed in May 2017 and subsequent open market sales and distributions, Kayne Anderson s beneficial ownership has dropped from 18% to ~1% of outstanding shares (1) Cash Bonus Metrics LOE / Boe Cash G&A / Boe F&D Cost / Boe Leverage Multiple Recycle Ratio LOE / Boe Cash G&A / Boe F&D Cost / Boe Capex / Production Added Production per Debt-Adjusted Share Growth (1) As of form 13-G filed on 10/2/17. 9

10 3Q FINANCIAL & OPERATIONAL UPDATE

11 3Q17 FINANCIAL RESULTS 3Q17 3Q16 2Q17 3Q17 3Q16 2Q17 Avg. Daily Production Cash Op. Exp. ($/Boe) Oil (MBbl/d) LOE $5.18 $4.67 $4.72 Gas (MMcf/d) G&T NGL (MBbl/d) Prod. Taxes Total (MBoe/d) Cash G&A Total Cash Operating Exp. $10.04 $9.36 $9.49 Pricing Non-Cash/Other Exp. ($/Boe) Average NYMEX Oil ($/Bbl) $48.20 $44.94 $48.28 Stock Comp G&A $0.81 $1.20 $0.90 Realized Price (Incl. Hedges) DD&A Oil ($/Bbl) $45.16 $41.46 $45.27 Exploration Gas ($/Mcf) Interest Expense NGL ($/Bbl) Other (1) (0.18) (0.07) (0.09) Total ($/Boe) $36.72 $33.37 $36.88 Total Non-Cash / Other Exp. (2) $18.43 $24.33 $19.10 Financial Results ($MM) Capital Expenditures ($MM) Total Revenues $201.7 $93.6 $183.1 D&C $168.9 $65.3 $168.7 Net Income $21.3 $1.0 $31.1 Infrastructure and Other Adj. EBITDAX $144.7 $65.7 $135.5 Total Development Capex $191.6 $ Adj. Net Income (Loss) $28.2 ($0.8) $26.0 (1) Includes Other income net of Asset retirement obligation accretion expense. (2) Excludes non-recurring non-cash expenses. 11

12 PEER-LEADING PROFITABILITY High quality assets + low cost operations = excellent corporate returns & profitability Durability in periods of commodity price lows as well as significant leverage to commodity price upside 2Q17 OPERATING PROFIT PER BARREL (DEFINED BELOW) $25.00 $20.00 Note: Average WTI crude oil price of $48.28 for 2Q17 $15.00 $10.00 $5.00 $- $(5.00) $(10.00) $(15.00) Operating Profit Unhedged Revenue 2-YR AVG. PDP F&D (1) Operating Costs G&A Better, more comparable metric than DD&A which is influenced by accounting methodology and write-downs LOE Production Taxes Source: Public filings. Peer companies include: APA, APC, CDEV, CLR, CPE, CXO, DVN, EGN, EOG, FANG, HES, JAG, LPI, MRO, MTDR, MUR, NFX, OAS, PDCE, PE, PXD, WPX, XEC, XOG. (1) 2015 and 2016 average PDP F&D Cost per Boe, as calculated by Seaport Global Securities. Cash G&A Non-Cash G&A 12

13 CAPITALIZATION AND LIQUIDITY SUMMARY Recently increased borrowing base to $1.5 B from $1.1 B, reiterating $900 MM Company-elected commitment under the amended and restated credit facility ($2.5 B maximum lender commitments) Key financial covenants: $1,600 $1,400 $1,200 $1,000 $800 $600 $400 $200 Maximum of 4.25x Total Debt / TTM EBITDAX Minimum current ratio of 1.0x Next redetermination April 2018 $0 DEBT MATURITIES ($MM) Borrowing Base Elected Commitment 9/30/17 Balance 6.625% 5.25% /30/17 Balance Elected Commitment Borrowing Base Senior Notes CAPITALIZATION TABLE ($ in millions) 9/30/2017 Cash $46 Revolving Credit Facility $ % Senior Unsecured Notes Due % Senior Unsecured Notes Due Total Debt $1,495 Net Debt $1,449 Liquidity Elected Commitment $900 Less: Borrowings & LCs (345) Plus: Cash 46 Liquidity $601 Financial & Operating Statistics Annualized 3Q17 Adjusted EBITDAX $ Q17 Avg. Daily Production (MBoe/d) 58.9 Credit Metrics Net Debt / Adjusted EBITDAX 2.5x Net Debt / Daily Production ($/Boe/d) $24,580 13

14 FULL YEAR 2017 GUIDANCE Production FULL YEAR 2017 GUIDANCE SUMMARY 3Q17 YTD Actuals 2017 Guidance Range Avg. Daily Production (Boe/d) 52,864 53,000-57,000 % Oil 72% 71% - 73% % Natural Gas 12% 11% - 13% % NGLs 16% 15% - 17% Income Statement ($/Boe) LOE (incl. workovers) $5.09 $ $5.50 Gathering & Transportation $0.99 $ $1.40 Exploration Expenses $0.48 $ $0.60 Cash G&A $1.62 $ $1.75 Non-Cash G&A $0.88 $ $0.90 DD&A $14.03 $ $16.00 Prod. & Ad Val. (% Rev.) 5.9% 6.0% - 8.0% Capital Expenditures ($MM) Drilling & Completion $448.1 $575 - $625 Infrastructure & Other $38.7 $50 - $75 Total Development Capital $486.8 $625 - $700 Non-Operated (%) 10% 8% - 12% Operated Completions Gross Hz Operated WI 91% 92% 29% 4% 5% COMMENTARY Reiterated full year 2017 guidance ranges for production, unit costs and capex Revised completion guidance to gross operated horizontal completions, as compared to previous guidance of Originally budgeted to run 3 frac crews for a portion of 2H17, instead elected to run 2 crews Revised average operated working interest to 92% from 88% Currently running 7 operated rigs (4 Midland, 3 Delaware) Currently running 2 completion crews 2017E CAPEX SUMMARY 62% Midland D&C Midland Infrastructure Delaware D&C Delaware Infrastructure Avg. LL (Midland / Delaware) 8,300 / 5,600 8,500 / 6,250 14

15 MBoe/d DRILLING & COMPLETIONS UPDATE 2017 OPERATED DRILLING & COMPLETION ACTIVITY During 3Q17, RSP drilled 26 and completed 22 operated HZ wells 18 Midland, 4 Delaware completions Expect to drill and complete in 4Q17 26 operated DUCs as of 9/30/17, estimate as of YE 2017 YE 2016A DUCs YTD 4Q YTD 4Q YE 2017E Drilling Completions DUCs 2017 PLANNED COMPLETION ACTIVITY BY HORIZON 2017 YTD PRODUCTION PROFILE WA MS BS WB Midland WXY LS WB WA Delaware MBoe/d Q1 Q2 Q3 Current Avg. Daily Production ~ Closing of SHEP II transaction 15

16 Cuml. MBoe MIDLAND BASIN WELL PERFORMANCE IMPROVEMENT 2017 wells drilled to date outperforming 2014 / 2015 / 2016 vintage wells 210 MIDLAND BASIN WELL PERFORMANCE BY VINTAGE Avg. LL: 8,300 Avg. LL: 7,100 Avg. LL: 7, Days & 2015 Avg Avg Avg. AVG. WELL SPACING FIRST PRODUCTION Avg. distance decreased >28% Note: Includes all zones. 16

17 MIDLAND BASIN UPDATE With addition of 2 nd Halliburton frac crew in 3Q17, able to simultaneously frac 2, 2-well pads Reduced downtime for offset producers Increased complexity/efficiency of stimulations Completed several wells in 3Q17 with higher percentage of 100 mesh sand Early results are outstanding (ST 347 WA wells, Woody 3-46 WB well, Keystone WA and LS wells) MIDLAND BASIN LOCATOR MAP Spanish Trail WA (LL: 6,500 ) IP30: 1,400 Boe/d (215 Boe/d / 1k ), 72% oil Spanish Trail WA (LL: 6,500 ) IP30: 1,850 Boe/d (285 Boe/d / 1k ), 82% oil Keystone West Side area wells continue to impress Average cumulative production for 3 well pad is ~100 MBoe in less than 90 days (WA well produced 125 MBoe in same time period) Next two wells in Spanish Trail WA pattern with 8 wells drilled across the section have average cumulative production of 100 MBoe in 75 days (100% 100 mesh) Implemented several gas lift pilots, testing application in different areas/reservoirs Strong results; plan to increase usage, benefiting LOE Keystone 1007 WA (LL: 9,800 ) IP30: 2,220 Boe/d (227 Boe/d / 1k ), 90% oil Keystone 1006 LLS (LL: 9,800 ) IP30: 1,600 Boe/d (163 Boe/d / 1k ), 88% oil Keystone 1005 ULS (LL: 9,750 ) IP30: 1,270 Boe/d (130 Boe/d / 1k ), 85% oil Woody 3-46 WB (LL: 7,600 ) IP30: 1,520 Boe/d (200 Boe/d / 1k ), 80% oil Calverley UWA (LL: 10,250 ) 170 Day Cuml: 175 MBoe, 72% oil Calverley LWA (LL: 10,250 ) 170 Day Cuml: 170 MBoe, 71% oil Calverley UWB (LL: 7,630 ) 170 Day Cuml: 135 MBoe, 60% oil Calverley LWB (LL: 7,630 ) 170 Day Cuml: 125 MBoe, 61% oil 17

18 MIDLAND BASIN 2018 PLANS Run 4 rigs on average, drilling almost entirely in full development mode Focus on highest return leases Initiate development of Glass Ranch leases where RSP has higher net revenue interest Continue with full development sequence across West Side area based on excellent recent step-out results in the WA MIDLAND BASIN LOCATOR MAP Continue to pair 2-well pads and complete 4 wells at once when possible Limited additional infrastructure requirements Denotes area with significant 2018 drilling activity 18

19 Cuml. MBoe DELAWARE BASIN WELL PERFORMANCE IMPROVEMENT 2017 wells drilled to date outperforming 2015 / 2016 vintage wells 300 DELAWARE BASIN WELL PERFORMANCE BY VINTAGE Avg. LL: 6, Avg. LL: 5,100 Avg. LL: 4, Avg Avg Avg. Note: Includes all zones. 19

20 DELAWARE BASIN UPDATE First 3BS well, Rudd Draw H, completed on southern end of acreage with excellent early results 7-day IP: 1,428 Boe/d (79% oil) Current rate: 1,822 Boe/d (73% oil), still cleaning up at >2,500 psi 8 other operated 3BS HZ wells across acreage First RSP drilled & completed WB well brought online during 3Q17, strong results with flat decline profile First well completed with 100% regional sand Now have WB well results on far east and far west side of acreage block Recently returned Bullet well to production; came back on with an initial flush rate of >1,000 Bo/d, has since declined but is stabilizing after ~30 days around 560 Boe/d (64% oil) DELAWARE BASIN LOCATOR MAP Ludeman A 603 WB (LL: 4,830 ) IP30: 935 Boe/d (194 Boe/d / 1k ), 77% oil Ludeman D 2105 LWA (LL: 4,750 ) 170 Day Cuml: 200 MBoe, 72% oil Bullet H WB First pass of Delaware 3D looks very high quality, showing consistent presence of thick Wolfcamp and Bone Spring section throughout eastern portion of acreage position Continuing to test variations to stimulation design and flowback methods In early stages of data gathering, will likely result in different optimized designs for different geographic areas and formations Modified Delaware casing design, evaluating from cost/benefit perspective Build-out of fresh water distribution system underway Rudd Draw XY (LL: 6,700 ) 275 Day Cuml: 450 MBoe, 73% oil Rudd Draw H 3BS (LL: 4,440 ) IP7: 1,428 Boe/d (322 Boe/d / 1k ), 79% oil 20

21 DELAWARE BASIN 2018 PLANS Run 3 rigs minimum, with likelihood of 4th Move majority of drilling to multi-well pads, reducing well costs Previously ~40%, going forward ~85% Focus will remain in Wolfcamp A, pending additional results could see increasing allocation to Bone Spring intervals and Wolfcamp B Dedicate one rig to Rudd Draw area - highly prolific well results to date and above average net revenue interest Continue to test a couple of additional targets within pay column With likely 4th rig, drill delineation and extension wells on east side where new 3D seismic (and offset wells) shows promising potential pending full interpretation of 3D DELAWARE BASIN LOCATOR MAP Continue science projects to further refine landing targets, flowback methodology and completion designs Implement new fresh water distribution system which will provide surety of supply, on-time delivery and reduced D&C costs Denotes areas with significant 2018 drilling activity 21

22 DELAWARE BASIN CROSS-SECTION (LOVING & WINKLER COUNTIES) West-to-east seismic cross-section across RSP s acreage position based on newly acquired 3D data Confirms Central Basin Platform is well East of RSP s Winkler County position LOVING W WINKLER E Avalon / 1 st Bone Springs 1,700 2 nd /3 rd Bone Springs T/Wolfcamp 1,300 Carbonate % Increases 1,700 1,400 WC A WC B WC C X/Y SAND ,400 WC D 2,700 E Atoka High T/ATOKA W 22

23 OUTLOOK FOR 4Q17 AND BEYOND Continued focus on corporate-level returns and capital efficiency, not growth for growth s sake Strong execution YTD, on track to meet 2017 guidance objectives Ability to achieve 30%+ production growth in 2018 in $50+ oil price environment, reaching cash flow neutrality by end of year Maintain strong balance sheet and liquidity through periods of commodity price volatility RSP flexible to accelerate or decelerate in response to commodity prices & service costs 23

24 APPENDIX

25 Bo/d Bo/d JOHNSON RANCH LS SPACING PILOT UPDATE Drilled 5 wells across eastern half of section, 7 wells across western half of section (equivalent of 14 wells per full section) Last 4 wells of pattern completed during 3Q17 Restricted production during first ~45 days to work around third party SWD well mechanical issue Performance now trending in-line with type curve JOHNSON RANCH SECTION 10 DOWNSPACED BASE Positive initial indications, but awaiting additional data before reaching conclusions LAST 4 DOWNSPACED WELLS (Q3 FRACS) VS. TYPE CURVE 7 DOWNSPACED WELLS VS. TYPE CURVE Days Days 25

26 HEDGE PROFILE RSP continuing to protect $45+ floor into 4Q17 and 2018 HEDGE CONTRACT DETAIL Crude Oil (Bbl, $/Bbl) 4Q17 1Q18 2Q18 3Q18 4Q Three-Way Collars (1) 552,000 2,219,000 1,941,000 1,319,000 1,227,000 6,706,000 Ceiling Floor Short Put $54.10 $45.00 $35.00 $58.81 $46.96 $36.96 $59.07 $47.11 $37.11 $60.56 $47.79 $37.79 $60.96 $48.00 $38.00 $59.62 $47.36 $37.36 Costless Collars (1) 1,150, , , , ,000 2,713,000 Ceiling Floor $60.05 $45.00 Deferred Premium Puts (1) 920,000 Floor $48.50 Deferred Premium (2) ($4.00) Swaps (1) 552,000 Swap Price $48.95 Total Hedge 3,174,000 Weighted Average Floor (3) $45.54 % Hedged on Midpoint Oil Volume Guidance (4) 78% $60.19 $ ,790,000 $46.56 $60.20 $ ,457,000 $46.67 $60.14 $ ,209,000 $46.67 $60.16 $ ,963,000 $46.87 $60.17 $ ,419,000 $46.68 Mid-Cush Differential Swaps (5) 1,104,000 1,800,000 1,820,000 1,840,000 1,840,000 7,300,000 Weighted Average Swap ($0.63) ($0.62) ($0.62) ($0.62) ($0.62) ($0.62) Natural Gas (MMBtu, $/MMBtu) 4Q17 1Q18 2Q18 3Q18 4Q Costless Collars (6) 2,545,000 Ceiling Floor $3.86 $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 during the relevant period. (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) Utilizing 2017 midpoint oil volume guidance. (5) 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. (6) 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. 26

27 ADJUSTED EBITDAX AND ADJUSTED NET INCOME RECONCILIATION Reconciliation of Net Income to Adjusted EBITDAX (in thousands) Three Months Ended September 30, Three Months Ended June 30, Net income Interest expense Income tax expense (benefit) Depreciation, depletion, and amortization Asset retirement obligation accretion Exploration Acquisition costs Impairments (Gain) loss on derivative instruments Stock-based compensation, net Other income, net $ 21,326 $ 985 $ 31,090 21,553 13,146 19,508 3,678 (3,507) 17,072 73,408 50,022 68, , , ,312 19, (12,910) 4,361 3,272 4,443 (1,106) (310) (589) Adjusted EBITDAX $ 144,662 $ 65,732 $ 135,450 Reconciliation of Net Income to Adjusted Net Income (Loss) (in thousands) Three Months Ended September 30, Three Months Ended June 30, Net income Acquisition costs Impairments (Gain) loss on derivative instruments Other income, net Income tax expense (benefit) for above items $ 21,326 $ 985 $ 31, ,312 19, (12,910) (1,106) (310) (589) (11,827) (3,086) 2,744 Adjusted Net Income (Loss) $ 28,187 $ (764) $ 26,048 27

28 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