2016 Year-End Results. Rick Muncrief, Chairman & CEO February 23, 2017

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1 2016 Year-End Results Rick Muncrief, Chairman & CEO February 23, 2017

2 WPX 4Q Highlights Record oil production, up 15% vs. 3Q 16 Delaware: Third Wolfcamp D and second X/Y delineation wells online Delaware: Oil started flowing on crude gathering system San Juan: 6-well West Lybrook pad surpassed 1 MMBOE in first 180 days (70% oil) Williston: Completed inventory of DUCs ahead of schedule 2017 notes paid off before maturity 317% reserve replacement in 2016 Began midstream JV process for a portion of our Delaware assets 2

3 Expanding WPX s World-Class Delaware Position PANTHER ACQUISITION OVERVIEW 18,000+ acres in core of Delaware EDDY 920 gross locations, including 150+ long lateral locations Significant current production of ~6,500 Boe/d (55% oil) LEA Maintain Panther s current 2 rig program Valuation primarily supported on 3 zones with upside in 5 additional zones Expected to close in late March NEW MEXICO TEXAS LOVING WINKLER BENEFITS HIGH QUALITY ROCK Multiple stacked pay intervals with significant upside CULBERSON WARD SELF-FUNDING DEVELOPMENT 2 rig program funded with operating cashflows REEVES DEEP INVENTORY OF CORE DELAWARE Resource supports sustained growth ACCRETIVE TO CASHFLOWS AND NAV Accretive to shareholders 2017 and beyond WPX OPERATED ACREAGE PANTHER ACREAGE PECOS 3

4 Panther Acquisition Enhances Sustained Growth Outlook ASSET QUALITY SUPPORTS RAPID GROWTH ASSET QUALITY SUPPORTS RAPID GROWTH CAGR: 30%- 40% CAGR: 30%- 40% $2,500 $2,000 OIL MBBL/D MILLIONS ($) $1, $1, $ $ UPDATED PRO FORMA RANGE PREVIOUS FORECAST UPDATED PRO FORMA RANGE PREVIOUS FORECAST 30% oil growth in % oil growth in 2018 Panther Acquisition enhances growth strategy Free cash-flow positive by year-end 2018 Assumes modest 1-3 rig additions per year Assumes 2017 WTI $50Bbl /NYMEX $2.75Mcf and WTI $55Bbl /NYMEX $3.00Mcf. 4

5 Operational Update Clay Gaspar, Chief Operating Officer

6 Contracted Service Cost Mitigates Potential Inflation 2017 D&C COST BREAKDOWN Fluids/Cuttings/Solids Control Directional Equipment & Services Chemicals Other (Completions) Other (Drilling) Sand Stimulation Services Drilling Rigs Tubulars/Wellhead Cementing Material and Services Water of D&C costs are contracted through 2017 Majority of services exposed to inflation are contracted Focused on securing services since 2Q 2016 to prepare for activity ramp Some contracts go through 2018, others have options to extend past 2017 ~90% of D&C costs go through Supply Chain Mgmt. Contracts in Place for 2017 Services Exposed to Spot Market Note: D&C components based on latest blended AFE (Williston, San Juan, Delaware) 6

7 Delaware Basin: Delineation of the Wolfcamp XY C-STATE 16-1H IP 30: 1,635 BOE/D (65% OIL) 90 DAY CUM: 114,338 BOE LEA DELINEATING WOLFCAMP ACROSS POSITION EDDY E. PECOS FED COM 22-14H IP 30: 1,736 BOE/D (30% OIL) 90 DAY CUM: 139,336 BOE WOLFCAMP XY-PECOS STATE 46-6H Lateral length: ~4,800 ft Proppant (#/ft): ~1,750 Utilized diverter Hybrid completion design NEW MEXICO D LINDSAY 16-6H IP 30: 1,434 BOE/D (18% OIL) 90 DAY CUM: 119,047 BOE Tracking in-line with WCA 1,000 MBOE type curve after 45 days Engineered completions TEXAS D WOLFCAMP D-PECOS STATE 46-5H PECOS STATE 46-6H IP 30: 1,780 BOE/D (50% OIL) REEVES XY D LOVING PECOS STATE 46-5H IP 30: 1,628 BOE/D (22% OIL) Lateral length: ~4,850 ft Proppant (#/ft): ~2,750 Currently producing with 3,800 psi flowing tubing pressure (2-17) Utilized diverter Hybrid completion design Engineered completions CULBERSON WPX OPERATED ACREAGE PANTHER ACREAGE CBR SPACING TEST UNDERWAY PURPOSE OF TEST Validate 16 well U/L Wolfcamp A spacing Understand future infrastructure needs UPDATE ON CBR Expected first sales end of March 16 day record well spud-to-rig release 350 FT WOLFCAMP X/Y UPPER WOLFCAMP A LOWER WOLFCAMP A WOLFCAMP B Encouraging DFIT results Note: Well production data is on a 3-stream basis 1 MILE 7

8 Williston Basin: Strong, Consistent Results 39% oil growth 4Q 16 vs 3Q 16 4Q production 28.8 MBOE/d Set new drilling record of 11.7 days 1 WILLISTON HIGHLIGHTS Completed DUC inventory Current total well cost $5.5MM 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10, DAYS CUM OIL PRODUCTION FOR 2016 NEW WELLS 2 WPX PEER 1 PEER 2 PEER 3 PEER 4 PEER 5 PEER 6 PEER 7 PEER 8 PEER 9 14 wells on 1 st sales during 4Q 6 Middle Bakken and 8 Three forks wells 180, , DAYS CUM OIL PRODUCTION FOR 2016 NEW WELLS 2 140, ,000 #1 PRODUCER ON CUMULATIVE OIL BASIS 90 DAYS/180 DAYS 2 100,000 80,000 60,000 40,000 20,000 - WPX PEER 1 PEER 2 PEER 3 PEER 4 PEER 5 PEER 6 PEER 7 PEER 8 PEER 9 1 Spud-to-rig release for a 2-mile lateral 2 Public data based on production from wells completed in 2016 Peers include AXA,BURLINGTON RESOURCES,EOG,ERF,HESS,LIBERTY RESOURCE,MRO,NFX,OAS,PETRO-HUNT,QEP,SM,STL,TPLM,WLL,XTO 8

9 San Juan Basin: Continued Strong Well Results CONTINUING TO RAISE THE BAR 21% oil growth 4Q 16 vs 3Q SAN JUAN GALLUP WELLS Set new basin record Drilled 1.5 mile lateral in 5.8 days Strong performance on 6-well pad Cumulative 180-day production: +1.0 MMBOE Average day: ~1,000 BOE/D per well (70% oil) Average lateral length: 7,250 ft. Average D&C cost: ~$4.1MM Cum Production MBOE Focused on West Lybrook in 2017 New rig spud first well 12/31/ Days of Production 65% IN EUR SINCE INCREASE CURRENT 650 MBOE 6-WELL PAD 2016 GALLUP WELLS Note: Well production data is on a 3-stream basis well performance based on 1 mile laterals, 2016 based on average of 7,200 laterals 9

10 Financial Update Kevin Vann, Chief Financial Officer

11 4 th Dollars Quarter in millions, except and production Full-Year numbers Results 4Q Full-Year Average Daily Production Oil (Mbbl/d) Gas (MMcf/d) NGLs (Mbbl/d) Equivalent (MBOE/d) Adjusted EBITDAX Adjusted Net Income (Loss) from Continuing Operations (54) (23) (255) 41 Capital Expenditures/Activity PRODUCTION CAPEX OIL PRODUCTION 9% Y/Y 88.7 MBOE/D FULL-YEAR D&C CAPEX IN-LINE WITH GUIDANCE 16% Y/Y 44.7 MBBL/D 1 Includes $84 million in land purchases and $27 million in Piceance activity that was reimbursed through the purchase price. Note: Adjusted EBITDAX and adjusted net income are non-gaap measures. A reconciliation to relevant measures included in GAAP is provided in this presentation. 11

12 WPX Liquidity, Hedges and Debt Maturities Liquidity Cash and (12/31/16) $496 Revolver Capacity $1,025 Letters of Credit <$66> Liquidity $1,450 Dollars listed in millions STRONG LIQUIDITY % of Production Hedged 100% 80% 60% 40% 20% 0% STRONG HEDGE POSITION CREATES CERTAINITY FOR DRILLING PROGRAM $3.93 $50.93 $3.02 Oil Natural Gas 2017 Oil: 39,554 bbl/d Hedged $50.93 per barrel Gas: 170,000 mmbtu/d $3.02 per MMBtu 2018 Oil: 30,000 bbl/d Hedged $54.61 per barrel Gas: 155,000 mmbtu/d $2.98 per MMBtu Debt Maturities $1,200 $MM $1,000 $800 $600 $400 $200 Expect $1.2B OF SALES PROCEEDS IN 1H OF 2016 $1,485 UNDRAWN $500 $1,100 $500 $500 $ Senior Notes Senior Notes Senior Notes Senior Notes 1 Based on midpoint of guidance. 12

13 2017 Pro Forma Full-Year Guidance Production FY17 Pro Forma Oil Mbbl/d Natural Gas MMcf/d NGL Mbbl/d Total MBOE/d Cap Ex ($ in Millions) FY17 Pro Forma Delaware $410 $430 $480 $510 1 Williston San Juan Total D&C Capital 2 $800 $860 $870 $940 Delaware Infrastructure Total 3 $835 $905 $905 $985 Avg. Price Differentials 4 FY17 Pro Forma Oil WTI per barrel ($6.00) ($7.00) ($6.00) ($7.00) NYMEX Nat. Gas (Mcf) ($0.60) ($0.80) ($0.60) ($0.80) Net Realized Price 5 FY17 Pro Forma NGL % of WTI 23% 28% 23% 28% Expenses FY17 Pro Forma $ per BOE LOE $4.75 $5.25 $4.75 $5.25 GP&T Production Tax Cash Operating $9.00 $10.50 $9.00 $10.50 DD&A $20.00 $21.00 $20.00 $21.00 $ in Millions G&A Cash $110 $120 $110 $120 G&A Non Cash $30 $40 $30 $40 Exploration $30 $40 $30 $40 Interest Expense $185 $195 $185 $195 Tax Rate FY17 Pro Forma Tax Provision 6 33% 37% 33% 37% Pro Forma assumes 9 month impact of Panther 1 Includes first sales from Panther acquisition (April 1-December 31, 2017). 2 Includes non-operated wells and wells which include additional science work. 3 Excludes any acquisition capital. 4 Average price differentials ranges for oil and natural gas exclude hedges, but include basis differential and revenue adjustments. 5 Percentage of realized price ranges for NGLs excludes hedges, but includes basis differential and revenue adjustments. 6 Rate does not reflect potential valuation allowance on deferred tax assets. 13

14 Foundation in Place for Enhancing and Accelerating Value POSITIONED PRUDENT WILLISTON BASIN FLEXIBLE SAN JUAN BASIN HEADQUARTERS: TULSA DELAWARE BASIN DISCIPLINED 14

15 Appendix

16 WPX Hedges Updated: February 22, Volume/Day Average Price Volume/Day Average Price Volume/Day Average Price Crude Oil (bbl) Fixed Price Swaps¹ 39,554 $ ,000 $ Fixed Price Calls 4,500 $ ,000 $ Crude Oil Basis (bbl) Midland Basis Swaps 12,778 ($0.52) 13,000 ($0.94) 7,000 ($1.00) Natural Gas (MMBtu) Fixed Price Swaps 1 170,000 $ ,000 $ Fixed Price Calls 16,301 $ ,301 $ Natural Gas Basis (MMBtu) San Juan Basis Swaps 97,500 ($0.18) 50,000 ($0.34) - - Permian Basis Swaps 72,500 ($0.20) 42,500 ($0.28) 20,000 ($0.34) West Texas Basis Swaps ,500 ($0.16) 80,000 ($0.19) 1 In connection with several natural gas and crude oil swaps, WPX entered into swaptions with the swap counterparties granting the counterparty the right, but not the obligation, to enter into an underlying swap with WPX in the future. Crude oil swaptions for 2017 total 1,764 bbl/d at a weighted average strike price of $ Natural Gas Swaptions for 2018 total 20,000 mmbtu/d at a weighted average strike price of $

17 Proved Reserves Reconciliation Chart MMBOE YE2015 SEC Case Production Extensions & Discoveries Acquistions Divestitures Technical Revisions Price Revisions YE2016 SEC Case 17

18 Domestic Price Realization for 2016 Oil ($/bbl) Gas ($/Mcf) NGL ($/bbl) 1Q 16 2Q 16 3Q 16 4Q 16 1Q 16 2Q 16 3Q 16 4Q 16 1Q 16 2Q 16 3Q 16 4Q 16 Weighted-Average Sales Price $26.78 $39.81 $39.15 $42.93 $1.77 $1.63 $2.44 $2.69 $11.60 $15.02 $14.92 $20.05 Revenue Adjustments 1 $(1.16) $(1.43) $(.44) $(.75) $(.25) $(.40) $(.47) $(.56) $(4.46) $(3.81) $(3.42) $(1.51) Net Price 2 $25.62 $38.38 $38.71 $42.18 $1.52 $1.23 $1.97 $2.13 $7.14 $11.21 $11.50 $18.54 Realized Portion of Derivatives 3 $19.90 $11.05 $12.15 $7.32 $3.41 $1.48 $.79 $ Net Price Including Derivatives $45.52 $49.43 $50.86 $49.50 $4.93 $2.71 $2.76 $2.78 $7.14 $11.21 $11.50 $ Natural gas revenue adjustments are primarily related to field compression fuel. NGL revenue adjustments include T&F and revenue sharing. Of the oil revenue adjustments, gathering deductions represent $(1.49). 2 Net Price equals income statement product revenues by commodity, divided by volume. 3 Represents the realized settlement on derivatives that occurred during each quarter 18

19 Delaware WPX Crude Gathering System Phase one underway Initial oil flows began late 4Q miles of pipe EDDY Future Oil Gathering Pipeline Fresh Water Pipeline Gas Gathering Pipeline Produced Water Disposal WPX Leasehold Focused on eastern Stateline acreage LEA Project details Access to multiple markets and local refineries Multiple system storage locations Planning ~50 miles of crude pipeline NEW MEXICO TEXAS Total system capacity ~100,000 Bpd Total Cost $35MM - $45MM Benefits of crude gathering system PHASE ONE Increase optionality to markets Significantly reduce truck traffic REEVES LOVING Decrease differentials Reduce operating costs Decrease downtime 19

20 Delaware Overview 120,000+ net acres 1 6,420+ gross locations 2 CHAVES Commodity mix 3 54% oil 30% natural gas 16% NGLs LEA Available sales outlets Holley Frontier s Artesia, NM Refinery Western s El Paso Refinery Gulf Coast Cushing Midland NEW MEXICO TEXAS EDDY LOVING WINKLER EXPECTED WELLS ON 1 ST SALES 4 1Q 17 2Q Q 17 4Q CULBERSON REEVES WARD WPX OPERATED (PRO FORMA) ACREAGE NON-OP ACREAGE PECOS 1 Includes acreage from recent acquisition 2 Includes non-op and operated locations 3 Based on FY2016 Production 4 Includes 1 st sales from Panther acquisition 20

21 Williston Basin ~85,000 net acres ~570 gross locations ~500 operated locations ~70 non-op locations DIVIDE BURKE Commodity mix 1 83% oil 9% natural gas 8% NGLs WILLIAMS MOUNTRAIL Available sales outlets Clearbrook, Minn. (WTI) Guernsey, Wyo. (WTI) Local refining markets Rail to all coastal markets (Brent, LLS, WTI) MCKENZIE MCLEAN EXPECTED WELLS ON 1 ST SALES 1Q Q Q Q WPX OPERATED ACREAGE DUNN MERCER NON-OP ACREAGE 1 Based on FY2016 production 21

22 San Juan Basin ~235,000 net acres Oil window: ~105,000 acres Gas window: ~130,000 acres 1 LA PLATA ARCHULETA ~4,635 total gross locations 1 Oil window: ~335 2 Gas window: ~4,300 Commodity mix 3 Oil window Oil: 47% NGLs: 22% Gas: 31% Available sales outlets Oil: Local refining markets or rail (WTI, Brent, LLS) Gas: Blanco Hub Gas window Natural gas: 99% NGLs: 1% SAN JUAN RIO ARRIBA COLORADO NEW MEXICO GAS WINDOW 1 ~130,000 acres ~4,300 locations OIL WINDOW ~105,000 acres ~335 2 locations EXPECTED WELLS ON 1 ST SALES 1Q 17 2Q 17 3Q 17 4Q WPX OPERATED ACREAGE NON-OP ACREAGE SANDOVAL 1 Includes non-op and operated 2 Assumes average lateral length of 7,000' 3 Based on FY2016 production 22

23 Consolidated Statement of Operations (GAAP) (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Revenues: Product revenues: Oil sales $ 112 $ 138 $ 120 $ 124 $ 494 $ 97 $ 142 $ 139 $ 173 $ 551 Natural gas sales Natural gas liquid sales Total product revenues Net gain (loss) on derivatives 105 (71) (154) 38 (148) (207) Gas management Other Total revenues , Costs and expenses: Depreciation, depletion and amortization Lease and facility operating Gathering, processing and transportation Taxes other than income Exploration General and administrative Gas management, including charges for unutilized pipeline capacity Net (gain) loss on sales of assets, divestment of transportation contracts and impairment of producing properties (69) (208) (2) (70) (349) (198) (4) 227 (3) 22 Acquisition costs Other-net Total costs and expenses , ,424 Operating income (loss) (299) (301) (221) (731) Interest expense (33) (32) (65) (57) (187) (57) (53) (49) (48) (207) Gain (loss) on extinguishment of debt - - (65) - (65) 3 (3) - (1) (1) Investment income and other (4) (2) (1) Income (loss) from continuing operations before income taxes $ 81 $ 24 $ (97) $ 12 $ 20 $ 35 $ (353) $ (350) $ (269) $ (937) Provision (benefit) for income taxes 29 1 (27) (130) (132) (98) (325) Income (loss) from continuing operations $ 52 $ 23 $ (70) $ (9) $ (4) $ - $ (223) $ (218) $ (171) $ (612) Income (loss) from discontinued operations 16 (53) (160) (1,525) (1,722) (12) 25 (1) (1) 11 Net income (loss) $ 68 $ (30) $ (230) $ (1,534) $ (1,726) $ (12) $ (198) $ (219) $ (172) $ (601) Less: Net income (loss) attributable to noncontrolling interests Net income (loss) attributable to WPX Energy, Inc. $ 67 $ (30) $ (230) $(1,525) $ (1,727) $ (12) $ (198) $ (219) $ (172) $ (601) Less: Dividends on preferred stock Less: Loss on induced conversion of preferred stck Net income (loss) attributable to WPX Energy, Inc. common stockholders $ 67 $ (30) $ (234) $(1,539) $ (1,736) $ (17) $ (204) $ (245) $ (175) $ (641) Amounts attributable to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ 52 $ 23 $ (74) $ (14) $ (13) $ (5) $ (229) $ (244) $ (174) $ (652) Income (loss) from discontinued operations 15 (53) (160) (1,525) (1,723) (12) 25 (1) (1) 11 Net income (loss) $ 67 $ (30) $ (234) $(1,539) $ (1,736) $ (17) $ (204) $ (245) $ (175) $ (641) 23

24 Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited) (Dollars in millions, except per share amounts) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders $ 52 $ 23 $ (74) $ (14) $ (13) $ (5) $ (229) $ (244) $ (174) $ (652) Income (loss) from continuing operations - diluted earnings per share $ 0.25 $ 0.11 $(0.29) $(0.06) $(0.06) $ (0.02) $ (0.76) $ (0.72) $ (0.51) $ (2.08) Pre-tax adjustments: Impairments- exploratory related and inventory $ - $ - $ 47 $ 3 $ 50 $ - $ - $ 4 $ - $ 4 Net (gain) loss on sales of assets and divestment of transportation contracts $ (69) $ (208) $ (2) $ (70) $ (349) $ (198) $ (4) $ 227 $ (3) $ 22 Contract termination and early rig release expenses $ 26 $ - $ - $ 5 $ 31 $ - $ - $ - $ - $ - Accrual for Denver office lease $ - $ - $ - $ - $ - $ - $ - $ 5 $ 5 Accrual for certain future gathering obligations associated with an abandoned area $ - $ - $ - $ 23 $ 23 $ - $ - $ - $ - $ - Costs related to severance and relocation $ 8 $ 7 $ 1 $ (1) $ 15 $ 3 $ 7 $ 3 $ 2 $ 15 Costs related to acquisition $ - $ 1 $ 38 $ 1 $ 40 $ - $ - $ - $ - $ - Previously capitalized costs expensed following credit facility amendment $ - $ - $ - $ - $ - $ 4 $ - $ - $ - $ 4 (Gain) loss on retirement of debt $ - $ - $ 65 $ - $ 65 $ (3) $ 3 $ - $ 1 $ 1 Unrealized MTM (gain) loss $ 30 $ 203 $ (50) $ 16 $ 199 $ 76 $ 223 $ 20 $ 190 $ 509 Total pre-tax adjustments $ (5) $ 3 $ 99 $ (23) $ 74 $ (118) $ 229 $ 259 $ 190 $ 560 Less tax effect for above items $ 2 $ (1) $ (35) $ 7 $ (27) $ 43 $ (85) $ (96) $ (71) $ (208) Impact of state deferred tax rate change $ - $ - $ - $ 7 $ 7 $ 14 $ - $ - $ 1 $ 15 Impact of state tax valuation allowance $ - $ - $ - $ - $ - $ 8 $ - $ - $ - $ 8 Loss on induced conversion of preferred stock $ - $ - $ - $ - $ - $ - $ - $ 22 $ - $ 22 Total after-tax adjustments $ (3) $ 2 $ 64 $ (9) $ 54 $ (53) $ 144 $ 185 $ 120 $ 397 Adjusted income (loss) from continuing operations available to common stockholders $ 49 $ 25 $ (10) $ (23) $ 41 $ (58) $ (85) $ (59) $ (54) $ (255) Adjusted diluted earnings (loss) per common share $ 0.24 $ 0.12 $(0.04) $(0.08) $ 0.17 $ (0.21) $ (0.28) $ (0.17) $ (0.16) $ (0.82) Diluted weighted-average shares (millions)

25 Reconciliation EBITDAX (Unaudited) (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Adjusted EBITDAX Reconciliation to net income (loss): Net income (loss) $ 68 $ (30) $ (230) $ (1,534) $ (1,726) $ (12) $ (198) $ (219) $ (172) $ (601) Interest expense Provision (benefit) for income taxes 29 1 (27) (130) (132) (98) (325) Depreciation, depletion and amortization Exploration expenses EBITDAX (1,288) (902) 241 (100) (142) (53) (54) Accrual for Denver office lease Accrual for certain future gathering obligations associated with an abandoned area Net (gain) loss on sales of assets, divestment of transportation contracts and impairment of producing properties (69) (208) (2) (70) (349) (198) (4) 227 (3) 22 Impairment of inventory RKI acquisition costs and loss on extinguishment of acquired debt Net (gain) loss on derivatives (105) 71 (205) (179) (418) (57) 154 (38) Net cash received (paid) related to settlement of derivatives (Income) loss from discontinued operations (16) ,525 1, (25) 1 1 (11) Adjusted EBITDAX $ 199 $ 181 $ 195 $ 206 $ 781 $ 131 $ 94 $ 115 $ 135 $

26 Disclaimer The information contained in this summary has been prepared to assist you in making your own evaluation of the Company and does not purport to contain all of the information you may consider important in deciding whether to invest in shares of the Company s common stock. In all cases, it is your obligation to conduct your own due diligence. All information contained herein, including any estimates or projections, is based upon information provided by the Company. Any estimates or projections with respect to future performance have been provided to assist you in your evaluation but should not be relied upon as an accurate representation of future results. No persons have been authorized to make any representations other than those contained in this summary, and if given or made, such representations should not be considered as authorized. Certain statements, estimates and financial information contained in this summary constitute forward-looking statements or information. Such forward-looking statements or information involve known and unknown risks and uncertainties that could cause actual events or results to differ materially from the results implied or expressed in such forward-looking statements or information. While presented with numerical specificity, certain forward-looking statements or information are based (1) upon assumptions that are inherently subject to significant business, economic, regulatory, environmental, seasonal, competitive uncertainties, contingencies and risks including, without limitation, the ability to obtain debt and equity financings, capital costs, construction costs, well production performance, operating costs, commodity pricing, differentials, royalty structures, field upgrading technology, and other known and unknown risks, all of which are difficult to predict and many of which are beyond the Company's control, and (2) upon assumptions with respect to future business decisions that are subject to change. There can be no assurance that the results implied or expressed in such forward-looking statements or information or the underlying assumptions will be realized and that actual results of operations or future events will not be materially different from the results implied or expressed in such forward-looking statements or information. Under no circumstances should the inclusion of the forward-looking statements or information be regarded as a representation, undertaking, warranty or prediction by the Company or any other person with respect to the accuracy thereof or the accuracy of the underlying assumptions, or that the Company will achieve or is likely to achieve any particular results. The forward-looking statements or information are made as of the date hereof and the Company disclaims any intent or obligation to update publicly or to revise any of the forward-looking statements or information, whether as a result of new information, future events or otherwise. Recipients are cautioned that forward-looking statements or information are not guarantees of future performance and, accordingly, recipients are expressly cautioned not to put undue reliance on forward-looking statements or information due to the inherent uncertainty therein. 26

27 Reserves Disclaimer The SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and governmental regulations. The SEC permits the optional disclosure of probable and possible reserves. We have elected to use in this presentation probable reserves and possible reserves, excluding their valuation. The SEC defines probable reserves as those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. The SEC defines possible reserves as those additional reserves that are less certain to be recovered than probable reserves. The Company has applied these definitions in estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC s reserves reporting guidelines. Investors are urged to consider closely the disclosure regarding our business that may be accessed through the SEC s website at The SEC s rules prohibit us from filing resource estimates. Our resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves, (ii) other areas to take into account the low level of certainty of recovery of the resources and (iii) uneconomic proved, probable or possible reserves. Resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon. Resource estimates might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors. 27

28 WPX Non-GAAP Disclaimer This presentation may include certain financial measures, including adjusted EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses), that are non-gaap financial measures as defined under the rules of the Securities and Exchange Commission. This presentation is accompanied by a reconciliation of these non-gaap financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare a company s performance. Management believes that these measures provide investors an enhanced perspective of the operating performance of the company and aid investor understanding. Management also believes that these non-gaap measures provide useful information regarding our ability to meet future debt service, capital expenditures and working capital requirements. These non-gaap financial measures should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles. 28