August 6, Q 2015 Results. Rick Muncrief, President and Chief Executive Officer

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1 August 6, Q 2015 Results Rick Muncrief, President and Chief Executive Officer

2 2nd Quarter Highlights Strong oil production of 32.7 Mbbl/d, 38% increase 1 YTD cash margin only ~5% lower despite ~45% decrease in commodity prices 2 Costs continue to trend lower 1 General and administrative down 18% 3 Lease operating expense decreased 14% Gathering, processing and transportation lowered 12% Oil netbacks improved 30% Increased EUR s in Williston to 750Mboe, 25% increase Added ~14,300 net acres in the San Juan Gallup, ~100,000 total net acres Closed Northeast Supply Link sale, ~$200MM in proceeds 1 2Q 15 vs. 2Q 14 2 Cashflows are adjusted for Powder River and Apco, $67MM YTD 2Q 14 and $9MM YTD 2Q Excludes one-time expenses associated with Early Exit Program (2014), Severance and Relocation (2015) 2

3 RKI Acquisition: Core Delaware Basin Acreage ~92,000 net acres with 12 prospective zones 670,000+ net prospective acres of stacked pay 3,600+ gross risked locations ~98% of net acres held by production ~22,000 Boe/d current production Expect transaction to close mid-august Infrastructure capacity in place for rapid development 375+ miles of gas gathering and water infrastructure 200,000 barrels per day of water disposal capacity Current disposal: ~90,000 bpd 90 MMcf/d of gas compression capacity Current compression: ~40 MMcf/d Wolfcamp Bone Spring Avalon Significant upside opportunities High intensity completions Downspacing/longer laterals Netback improvements Balance sheet delevering is under way Targeting $400MM - $500MM in proceeds by YE15 Additional $400MM - $500MM in proceeds in 2016 New Mexico Texas Delaware Sands Infrastructure Hub RKI ACREAGE 3

4 Operational Results Clay Gaspar, Sr. VP Operations and Resource Development

5 $/BOE Williston: Production Up, Costs Down with EUR Increased 25% production growth 1 $9 $8.61 LOE per BOE Flexible capital program 2nd rig in August and 3rd rig in November Inventory of 14 drilled uncompleted wells $6 $3 29% Decrease $6.11 Increased EUR s 25% to 750 Mboe Additional upside with larger stimulations $- 2Q'14 2Q'15 Testing larger stimulations Higher intensity slick water completions 10MM pounds with more stages Advancing drilling technology in 3 mile laterals Record 14,707 rotary steerable run Cost reduction in rotary steerables competing with conventional tools HIGH INTENSITY COMPLETIONS 1 2Q 15 vs. 2Q 14 equivalent production 5

6 Drilling Cost/ft. San Juan Gallup: Continued Growth and Execution 300%+ production growth 1 Efficiencies drive more wells with fewer rigs Two record wells of 7.9 days Intra-pad rig move of 0.3 days Surpassed basin measured depth record 3x Unit 13,418 Unit 13,741 Unit 15,391, longest lateral drilled in basin Oil gathering agreement improving netbacks Oil netbacks improve 24% 2 $8 -$10 netbacks 2nd half of 2015 and beyond Increased Gallup position to ~100,000 net acres $0 -$2 -$4 -$6 -$8 -$10 -$12 -$14 -$16 $180 $160 $140 $120 $100 $172 -$ Q'14 $152 Oil Netbacks Y/Y 24% Improvement $130 $130 $129 $126 $120 $115 -$10.22 $110 2Q'15 Gallup Drilling Efficiency $98 $95 $80 $60 1 2Q 15 vs. 2Q 14 equivalent production 2 2Q 15 vs. 2Q 14 6

7 Measured Depth (ft) Piceance: Large-Scale Resource with Deep Potential Half the time and twice the depth Spud May 2014: 1 mile drilled in 117 days Spud April 2015: 2 mile drilled in 50 days Niobrara technical challenges High pressures 10,000+ psi High temperatures 330 o + Heavy mud weights 0 2,500 5,000 7,500 Piceance Niobrara Days vs. Depth Testing alternative spacing in Mesa Verde Valley 20-acre spacing Ryan Gulch 15-acre spacing Tailor frac design/volume in Mesa Verde Valley 1,100 gal/ft to 2,500 gal/ft Ryan Gulch 1,500 gal/ft to 2,500 gal/ft High volume 100 mesh test Continue to reduce lifting cost despite declining production 10,000 12,500 15,000 17,500 20, Days From Spud 1 mile lateral spud May 2014 (Total measured depth of 15,787 ) 2 mile lateral spud April 2015 (Total measured depth of 19,070 ) 7

8 Financial Results Kevin Vann, Chief Financial Officer

9 2nd Quarter and YTD Results Dollars in millions, except production numbers 2Q YTD Daily Production Gas (MMcf/d) Oil (Mbbl/d) NGLs (Mbbl/d) Equivalent (Mboe/d) Adjusted EBITDAX Adjusted Net Income from Continuing Operations (22) 6 (3) 32 Capital Activity Note: Adjusted EBITDAX and adjusted net income are non-gaap measures. A reconciliation to relevant measures included in GAAP is provided in this presentation. 9

10 Pro Forma 2015 Full-Year Guidance 1 Production Prior Guidance Current Guidance Natural Gas MMcf/d Oil Mbbl/d NGL Mbbl/d Total Mboe/d Cap Ex ($ in Millions) Prior Guidance Current Guidance Delaware - $100 - $120 Williston San Juan Piceance Other Total 4 $675 - $775 $825 - $925 Avg. Price Differentials 5 Prior Guidance Current Guidance NYMEX Nat. Gas (Mcf) ($0.40) - ($0.60) ($0.40) - ($0.60) Oil WTI per barrel ($9.00) - ($12.00) ($8.00) - ($10.00) Net Realized Price 6 Prior Guidance Current Guidance NGL % of WTI 30% - 35% 30% - 35% Expenses Prior Guidance Current Guidance $ per Boe LOE $ $4.75 $ $4.25 GP&T Production Tax Cash Operating Expense $ $11.75 $ $11.00 DD&A $ in Millions G&A 7 $215 - $235 $230 - $240 Gas Management Exploration Interest Expense Equity (Earnings) Loss 0 - (5) 0 - (5) Tax Rate Prior Guidance Current Guidance Tax Provision 33% - 37% 33% - 37% 1 Assumes mid-august close for RKI transaction and reflects increased activity in Williston 2 NGL guidance assumes only 15% ethane recovery. 3 Other includes expenditures for Other Basins, Land, Exploration and Corporate. 4 Excludes any acquisition capital. 5 Average price differentials ranges for oil and natural gas exclude hedges, but include basis differential and revenue adjustments, such as fuel. 6 Percentage of realized price ranges for NGLs excludes hedges, but includes basis differential and revenue adjustments. 7 Excludes severance and relocation costs and includes stock compensation expenses of $30 - $40MM. 8 Gas Management impact is net of revenues and expenses and includes unutilized transport capacity. Includes impact of realized hedges on non-equity production 10

11 Pro Forma WPX Hedges including RKI Updated: August 3, 2015 Jul - Dec Volume/Day Average Price Volume/Day Average Price Volume/Day Average Price Natural Gas (MMBtu) Fixed Price Swaps 435,929 $ ,132 $ Costless Collars 50,000 $ $ Fixed Price Calls ,301 $4.50 Natural Gas Basis (MMBtu) MidCon Basis Swaps 20,000 ($0.18) Rockies Basis Swaps 280,000 ($0.17) San Juan Basis Swaps 107,500 ($0.11) SoCal Basis Swaps 50,000 $ Crude Oil (bbl) Fixed Price Swaps 30,872 $ ,049 $ ,554 $65.30 Crude Oil Basis (bbl) Midland Basis Swaps 2,500 $0.30 5,000 ($0.45) - - Note: In connection with several natural gas and crude oil swaps, we entered into swaptions with the swap counterparties granting the counterparty the right, but not the obligation, to enter into an underlying swaps with us in the future. Natural gas swaptions for 2016 total 90,000 MMBtu/d at a weighted average strike price of $4.23. Crude oil swaptions for 2016 total 8,500 bbl/d; 3,250 bbl/d at a weighted average strike price of $62.81 and 5,250 bbl/d at a weighted average strike price of $ Natural gas swaptions for 2017 total 65,000 MMBtu/d at a weighted average strike price of $

12 Premier Western Energy Producer PERMIAN BASIN Deep Inventory of High-Return Locations Decades of drillable locations Significant upside potential from downspacing and additional prospective horizons 670,000+ net prospective acres WILLISTON BASIN High Oil Content with Continuing Growth 600+ operated remaining locations, ~87,000 acres 37% production CAGR 2Q 12-2Q 15 (Mboe/d) Downspacing, infrastructure, operational efficiencies drive upside SAN JUAN BASIN Oil and Natural Gas Development Opportunities Gallup Oil: 400+ locations, ~100,000 acres Natural gas: potential for future development opportunities Established infrastructure PICEANCE BASIN Cash Flow + Resource Potential Vertical: Deep inventory (~10,000 locations) with infrastructure in place Niobrara/Mancos: Tcfe stacked-pay resource potential Stable cash flows provide financial flexibility 12

13 Appendix

14 Williston Overview ~87,000 net acres Currently operating 1 rig 2 nd rig in August, well-to-well contract 3 rd rig in November, well-to-well contract 600+ gross drilling locations 520 operated drilling locations 90 non-op locations Commodity mix 87% oil 7% natural gas 6% NGLs Available sales outlets Clearbrook, Minn. (WTI) Guernsey, Wyo. (WTI) Local refining markets Rail to all coastal markets (Brent, LLS, WTI) N D 14

15 San Juan Overview ~232,000 net acres Oil window: ~100,000 acres 1 Gas window: ~132,000 acres Currently operating 2 rigs ~3,900 total gross drilling locations 2 Oil window: Gas window: ~3,500 2 Commodity mix Oil window Oil: 54% NGLs: 22% Gas: 24% Gas window Natural gas: 99% NGLs: 1% OIL WET GAS DRY GAS Available sales outlets Oil: Local refining markets or rail (WTI, Brent, LLS) Gas: Blanco Hub 1 Acreage owned or controlled by WPX 2 Includes non-op and operated locations 3 Assumes 4,600' laterals 15

16 Piceance Overview ~200,000 net acres Currently operating 1 rig ~10,000 gross drilling locations Commodity mix 1 2% oil 77% natural gas 21% NGLs Available sales outlets San Juan Rockies California MidCon Unbooked deep resource potential Niobrara/Mancos: ~160,000 acres Dry gas CO 1 Assumes full ethane recovery 16

17 $ in Millions $ in Millions $ in Millions Cost Continue to Trend Lower $60 LOE $80 G&A 1 $58 $56 $54 $52 $50 $48 $59 14% Decrease $51 $70 $60 $50 $40 $30 $20 $10 $68 18% Decrease 10% Decrease $56 $46 2Q'14 2Q'15 $0 2Q'14 2Q'15 $80 GP&T $- Oil Netbacks $78 $76 $74 $72 $70 $68 $66 $ 78 12% Decrease $69 $(2.00) $(4.00) $(6.00) $(8.00) $(10.00) $(10.92) 30% Improvement $(7.62) $64 2Q'14 2Q'15 $(12.00) 2Q'14 2Q'15 1 Excludes one-time expenses associated with Early Exit Program (2014), Severance and Relocation (2015) 17

18 Reported Daily Production Total Production Q 2Q 3Q 4Q Total 1Q 2Q 3Q 4Q Total Gas (MMcf/d) Oil (Mbbl/d) NGLs (Mbbl/d) Mboe/d Note: Excludes discontinued operations (Powder River and International production) 18

19 Domestic Price Realization for 2015 Gas ($/Mcf) Oil ($/bbl) NGL ($/bbl) 1Q 15 2Q 15 3Q 15 4Q 15 1Q 15 2Q 15 3Q 15 4Q 15 1Q 15 2Q 15 3Q 15 4Q 15 Weighted-Average Sales Price $2.90 $2.40 $38.34 $49.64 $22.74 $20.40 Revenue Adjustments 1 $(.28) $(.32) $(.70) $(1.04) $(7.34) $(6.64) Hedge Impact Net Price 2 $2.62 $2.08 $37.64 $48.60 $15.40 $13.76 Realized Portion of Derivatives Not Designated as Hedges 3 $1.05 $1.02 $29.49 $24.92 Net Price Including All Derivatives $3.67 $3.10 $67.13 $73.52 $15.40 $ 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 $(1.40). 2 Net Price equals income statement product revenues by commodity, divided by volume. 3 Represents the realized cash flows that occurred during each quarter, which are attributable to derivatives that were not designated as hedges for accounting purposes. 19

20 $ per MMBtu Western Prices Have Increased Relative to Eastern Locations 0.50 West Basis Strengthening 1 East Basis Weakening 2 $ ($0.19) ($0.24) ($0.42) ($1.06) ($1.76) to to Now 3 Yr Fwd 2006 to to Now 3 Yr Fwd 1 Northwest Wyoming/Rocky Mountain basis 2 Dominion South basis 3 3-year average strip price as of 7/27/

21 Mexican Exports to Drive Western Demand Growth Total Current Capacity 7.4 Bcf/d Total Proposed Capacity 7.7 Bcf/d July 2014, El Paso announced 21 Year deal with Mexico s CFE to provide up to 500 MMBtu/d of firm capacity from SJ basin to Mexico border beginning Nov North Baja 130 Mcf/d Arizona 812 MMcf/d W. Texas 3.1 Bcf/d Sept 2014, CFE outlines two pipeline projects sourcing 2.5 Bcf/d from Waha, Texas, by Costa Azul LNG Facility Sempra and Pemex recently announced coordination for the potential development of LNG exports with assumed capacity of up to 1 Bcf/d. S. Texas 3.64 Bcf/d Colorado Interstate Gas Co El Paso Natural Gas Co Kern River Gas Transmission Co Northwest Pipeline Corp Questar Pipeline Co Transcolorado Gas Transmission Co Transwestern Pipeline Co Bentek Sourced Export Capacities 21

22 San Juan Gallup: Gathering Infrastructure Asset Description WPX built multi-commodity gathering system with multiple market outlets Current crude oil market access to Western s Gallup, NM refinery and El Paso, TX refinery through Tex-New-Mex pipeline Additional outlets by rail (Brent, LLS, WTI) Natural gas market access through Williams and Enterprise 3rd party gathering potential System Capacity WPX CDP site WPX constructed pipe WPX planned pipe for 2015 Western Refining (oil pipe) WPX leasehold Western dedicated acreage ~220 total miles oil, natural gas, and water infrastructure by YE2015 Existing CDPs with current storage of 10,000 bbls for water and oil Western s Tex-New-Mex takeaway capacity of 65,000 bbls/d Western adding additional rail capacity 22

23 Williston: Van Hook Gathering System WPX CDP Site WPX constructed pipe WPX planned pipe WPX Leasehold Whiting CDP Van Hook CDP Asset Description WPX built multiple commodity gathering system Access to utility grade power 2nd Bench Three Forks upside 3rd party gathering potential System Capacity 45 miles of oil, natural gas and water lines 30 mile expansion complete by 3Q, 2016 CDP with 7,200 bbls crude storage and 1,600 bbls water storage Gas market at Whiting CDP Multiple crude oil markets through Slawson 23

24 Piceance: Water Treatment System The Highlands WPX constructed pipe WPX Leasehold Asset Description WPX built produced and completions water handling system Three water treatment facilities located in basin ~400 miles of water pipeline infrastructure System designed for 10 + rig program 3 rd party water service opportunities System Capacity Three water treatment facilities 18,700 37,400 bpd capacity per facility Disposal capacity of ~22,000 bpd Total storage capacity of ~1.9 MM bbls The Valley 24

25 Non-GAAP

26 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. 26

27 Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited) (Dollars in millions, except per share amounts) 1Q 2Q 3Q 4Q Year 1Q 2Q 3Q 4Q YTD Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders $ - $ (144) $ 46 $ 227 $ 129 $ 22 $ (23) $ (1) Income (loss) from continuing operations - diluted earnings per share $ - $(0.71) $ 0.23 $ 1.10 $ 0.62 $ 0.11 $ (0.12) $ (0.01) Pre-tax adjustments: Impairment of producing properties, costs of acquired unproved reserves and leasehold (1) $ - $ - $ - $ 20 $ 20 $ - $ - $ - Impairments- exploratory related $ - $ 40 $ 22 $ 67 $ 129 $ - $ - $ - Loss on sale of working interests in the Piceance Basin $ - $ 195 $ 1 $ - $ 196 $ - $ - $ - Net gain on sales of assets $ - $ - $ - $ - $ - $ (69) $ (209) $ (278) Expense related to Early Exit Program $ - $ 2 $ 8 $ - $ 10 $ - $ - $ - Contract termination and early rig release expenses $ - $ - $ 6 $ 6 $ 12 $ 26 $ - $ 26 Assignment of natural gas storage commitment $ - $ - $ - $ 14 $ 14 $ - $ - $ - Costs related to severance and relocation $ - $ - $ - $ - $ - $ 8 $ 7 $ 15 Costs related to acquistion $ - $ - $ - $ - $ - $ - $ 1 $ 1 Unrealized MTM (gain) loss $ 27 $ - $ (133) $ (453) $ (559) $ 30 $ 203 $ 233 Total pre-tax adjustments $ 27 $ 237 $ (96) $ (346) $ (178) $ (5) $ 2 $ (3) Less tax effect for above items $ (10) $ (87) $ 35 $ 126 $ 64 $ 2 $ (1) $ 1 Impact of new state tax law in New York (net of federal benefit) $ 9 $ - $ - $ - $ 9 $ - $ - $ - Total adjustments, after-tax $ 26 $ 150 $ (61) $ (220) $ (105) $ (3) $ 1 $ (2) Adjusted income (loss) from continuing operations available to common stockholders $ 26 $ 6 $ (15) $ 7 $ 24 $ 19 $ (22) $ (3) Adjusted diluted earnings (loss) per common share $ 0.13 $ 0.03 $(0.07) $ 0.03 $ 0.12 $ 0.09 $ (0.11) $ (0.02) Diluted weighted-average shares (millions) (1) These items are presented net of amounts attributable to noncontrolling interests. 27

28 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) $ 19 $ (133) $ 66 $ 219 $ 171 $ 68 $ (30) $ 38 Interest expense Provision (benefit) for income taxes 13 (82) (14) (1) Depreciation, depletion and amortization Exploration expenses EBITDAX , Impairment of producing properties, costs of acquired unproved reserves and equity investments Loss on sale of working interests in the Piceance Basin Net gain on sales of assets (69) (209) (278) Net (gain) loss on derivatives (148) (498) (434) (105) 71 (34) Net cash received (paid) related to settlement of derivatives (168) (17) (125) (Income) loss from discontinued operations (19) (11) (20) 8 (42) (46) 7 (39) Adjusted EBITDAX $ 277 $ 253 $ 199 $ 238 $ 967 $ 252 $ 222 $

29 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. 29

30 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. 30