1Q 2017 Investor Update. Rick Muncrief, Chairman and Chief Executive Officer May 4, 2017

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1 1Q 2017 Investor Update Rick Muncrief, Chairman and Chief Executive Officer May 4, 2017

2 Foundation in Place for Enhancing and Accelerating Value POSITIONED PRUDENT WILLISTON BASIN FLEXIBLE SAN JUAN BASIN HEADQUARTERS: TULSA DELAWARE BASIN DISCIPLINED 2

3 1Q Highlights CONTINUING TO EXECUTE: Production growth on track Panther wells exceeding expectations Acquired Delaware acreage at attractive prices with significant upside Drilling and completion spending as expected, no change to FY guidance Permian Midstream JV process on track with agreement expected mid-year 3

4 WPX Exploration Team at Work in the Delaware WPX completed another acquisition in the Delaware Basin for acreage that is exploratory in nature TAYLOR RANCH: WHY WE LIKE IT CONTIGUOUS POSITION ~17,900 contiguous acres in East-Central Culberson County ~95% locations suitable for long-laterals GREAT ROCK AT A LOW ENTRY COST ~$2,000 per acre ACTIVE OFFSET OPERATORS Increased drilling activity in Culberson EDDY MACK ENERGY 9,300 ACRES $6.8K/ACRE RKI E&P 92,000 ACRES $12.5K/ACRE LOVING LEA MINIMAL DRILLING COMMITMENTS 1-well commitment in well commitment in 2019 CULBERSON WPX S UPDATED POSITION TAYLOR RANCH 17,900 ACRES $2K/ACRE REEVES WARD PANTHER ENERGY 18,100 ACRES $28.5K/ACRE ACRES IN DELAWARE BASIN 4

5 Operational Update Clay Gaspar, Chief Operating Officer

6 Delaware Basin: Encouraging Early Results from CBR Spacing Test CBR 10H SPACING 11H 12H 13H 15H TEST 17H UPDATE CBR 9 WELL SPACING TEST: LOVING COUNTY, TX WOLFCAMP X/Y UPPER WOLFCAMP A LOWER WOLFCAMP A Best representation of full section development and the tightest spacing for Wolfcamp A pad development Vertically and laterally bounded wells in both landing zones WPX will use the results of the spacing test to maximize its Wolfcamp A development program 350 FT 1 MILE 14H 16H 18H 10H 11H 12H 13H 15H 17H WOLFCAMP B 30-day production averaging 1,538 BOE/D per well 1 and total cumulative production exceeds 250,000 bbls of oil to date Initial flowing tubing pressure of ~3,000 PSI per well. Minimal fracture interference between the nine wells or with offset wells during testing 1 On a three-stream basis, post cleanout 6

7 Central Reeves Wolfcamp A Outperforming NEW MEXICO TEXAS LOVING WARD REEVES 1. MAC STATE: 30 DAY AVG: 2,234 BOE/D 1,2 (56% OIL) 2. LOUIS STATE: 30 DAY AVG: 2,173 BOE/D 1,2 (55% OIL) 3. FIVER STATE: 30 DAY AVG: 1,914 BOE/D 1,2 (55% OIL) 4. TITAN STATE: 30 DAY AVG: 1,987 BOE/D 1,2 (53% OIL) MAC STATE LOUIS STATE FIVER STATE TITAN STATE 1000 MBOE EUR (WOLFCAMP A) 1 One-mile laterals on a three-stream basis 2 Post cleanout 7

8 Williston Basin: Strong, Consistent Results FIRST QUARTER WELL RESULTS CUM MBOE STRONG INITIAL RESULTS 1 BEHR PAD AVG 30 DAY RATE: 1,375 BOE/D (80% oil) CARIBOU PAD AVG 30 DAY RATE: 2,145 BOE/D (80% oil) GRIZZLY PAD AVG 30 DAY RATE: 1,703 BOE/D (80% oil) DAYS ON The highest single well peak rate among the nine was 3,343 BOE/D (81% oil) on the Grizzly 24-13HG BEHR PAD AVERAGE CARIBOU PAD AVERAGE GRIZZLY PAD AVERAGE 850 MBOE EUR 1 On a three-stream basis, post cleanout 8

9 San Juan Basin: Getting Back to Work SAN JUAN GALLUP ACTIVITY UPDATE Focused development in 2017 in the West Lybrook Unit 58 approved drilling permits in Gallup Oil 2 additional units (12,000 acres) in the approval process 26 miles of pipeline installed YTD (oil/gas/water) SAN JUAN RIO ARRIBA SANDOVAL WEST LYBROOK UNIT Average lateral length: 7, : 6 WELL PAD WELLS ARE PRODUCING DRILLING LATERALS WAITING ON DRILL OUT New basin drilling record 6,258-ft lateral drilled in a 24-hour period 5.8 day 1.5 mile lateral well drilling record 14 new spuds for 2017 (utilizing 2 and 6-well pads) 5 wells completed in April and bringing on production 713H initial production: 1,410 BOE/D (74% oil) 9

10 Financial Update Kevin Vann, Chief Financial Officer

11 1 st Dollars Quarter in millions, except Results production numbers 1Q YTD Average Daily Production Oil (Mbbl/d) Gas (MMcf/d) NGLs (Mbbl/d) Equivalent (MBOE/d) Adjusted EBITDAX Adjusted Net Income (Loss) from Continuing Operations (59) (58) (59) (58) Capital Expenditures PRODUCTION CAPEX OIL PRODUCTION 12% Y/Y 90.0 MBOE/D D&C CAPEX IN-LINE WITH GUIDANCE 11% Y/Y 46.1 MBBL/D 1 Includes D&C $210MM, land $54MM, crude line $9MM, and other corporate $7MM Note: Adjusted EBITDAX and adjusted net income are non-gaap measures for general corporate purposes A reconciliation to relevant measures included in GAAP is provided in this presentation. 11

12 WPX Liquidity, Hedges and Debt Maturities Liquidity Cash and (3/31/2017) $142 Revolver Capacity $1,025 Letters of Credit <$66> Liquidity $1,101 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 $50.84 $3.02 Oil ,2 Natural Gas In April, revolver capacity increased to $1.2B 2017 Oil: 39,392 bbl/d Hedged $50.84 per barrel Gas: 170,000 mmbtu/d $3.02 per MMBtu 2018 Oil: 42,000 bbl/d Hedged $54.36 per barrel Gas: 185,000 mmbtu/d $2.98 per MMBtu Debt Maturities $ MM $1,200 $1,000 $800 $600 $400 $200 $0 $1,100 $500 $500 $ Senior Notes Senior Notes Senior Notes Senior Notes 1 Based on midpoint of guidance 2 Hedge position April-December

13 TRACK RECORD OF EXECUTION 13

14 Appendix

15 2017 Full-Year Guidance Production FY 2017 Oil Mbbl/d Natural Gas MMcf/d NGL Mbbl/d Total MBOE/d Cap Ex ($ in Millions) FY 2017 Delaware $480 $510 Williston San Juan Total D&C Capital 2 $870 $940 Delaware Infrastructure Total 3 $905 $985 Avg. Price Differentials 4 FY 2017 Oil WTI per barrel ($6.00) ($7.00) NYMEX Nat. Gas (Mcf) ($0.60) ($0.80) Net Realized Price 5 FY 2017 NGL % of WTI 23% 28% Expenses FY 2017 $ per BOE LOE $4.75 $5.25 GP&T Production Tax Cash Operating $9.00 $10.50 DD&A $20.00 $21.00 $ in Millions G&A Cash $110 $120 G&A Non Cash $30 $40 Exploration 7 $30 $40 Interest Expense $185 $195 Tax Rate FY 2017 Tax Provision 6 33% 37% Infrastructure 4% Williston 27% San Juan 18% D&C 96% Delaware 55% TOTAL D&C CAPITAL 1 $870-$940 MM 1 Based on the mid-point of guidance. 2 Includes non-operated wells and wells which include additional science work. 3 Excludes any acquisition and land 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. 7 Excludes impairments and lease expiration expense. TOTAL CAPITAL EXPENDITURES 1 $905-$985 MM 15

16 First Quarter Cash Roll-Forward $496MM 400 $132MM $MM 300 $70MM $76MM $218MM $76MM $142MM 0 Cash balance 12/31 Panther purchase price net of equity proceeds Land/crude line/other corporate Normalized cash interest payment and one-time cash items Adjusted cash balance Normalized 1Q outspend1 Ending cash balance 3/31 1 Includes EBITDAX, drilling and completion capital, $44MM cash interest, and working capital 16

17 WPX Hedges Updated: May 3, 2017 Apr Dec Volume/Day Average Price Volume/Day Average Price Volume/Day Average Price Crude Oil (bbl) Fixed Price Swaps¹ 39,392 $ ,000 $ Fixed Price Calls 4,500 $ ,000 $ Crude Oil Basis (bbl) Midland Basis Swaps 14,007 ($0.57) 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 Apr Dec 2017 total 2,342 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 $

18 Domestic Price Realization for 2017 Oil ($/bbl) Gas ($/Mcf) NGL ($/bbl) 1Q 17 2Q 17 3Q 17 4Q 17 1Q 17 2Q 17 3Q 17 4Q 17 1Q 17 2Q 17 3Q 17 4Q 17 Weighted-Average Sales Price $46.38 $3.01 $22.14 Revenue Adjustments 1 $(1.07) $(.50) $(1.29) Net Price 2 $45.31 $2.51 $20.85 Realized Portion of Derivatives 3 $(.77) $(.11) - Net Price Including Derivatives $44.54 $2.40 $ 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 $(1.64). 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 Overview ~135,000 net acres ~6,400+ gross locations 1,2 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 EDDY NEW MEXICO TEXAS LOVING WINKLER EXPECTED WELLS ON 1 ST SALES 4 1Q 17 2Q Q 17 4Q CULBERSON WPX OPERATED ACREAGE REEVES WARD NON-OP ACREAGE PECOS 1 Does not include Taylor Ranch locations 2 Includes non-op and operated locations 3 Based on FY2016 Production 4 Includes 1 st sales from Panther acquisition 19

20 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 20

21 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 21

22 Consolidated Statement of Operations (GAAP) (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Revenues: Product revenues: Oil sales $ 97 $ 142 $ 139 $ 173 $ 551 $ 188 $ 188 Natural gas sales Natural gas liquid sales Total product revenues Net gain (loss) on derivatives 57 (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 Net (gain) loss on sales of assets and divestment of transportation contracts (198) (4) 227 (3) 22 (35) (35) Other-net Total costs and expenses , Operating income (loss) 90 (299) (301) (221) (731) Interest expense (57) (53) (49) (48) (207) (47) (47) Investment income and other 2 (1) Income (loss) from continuing operations before income taxes $ 35 $ (353) $ (350) $ (269) $ (937) $ 125 $ 125 Provision (benefit) for income taxes 35 (130) (132) (98) (325) Income (loss) from continuing operations $ - $ (223) $ (218) $ (171) $ (612) $ 94 $ 94 Income (loss) from discontinued operations (12) 25 (1) (1) 11 (2) (2) Net income (loss) $ (12) $ (198) $ (219) $ (172) $ (601) $ 92 $ 92 Less: Dividends on preferred stock Less: Loss on induced conversion of preferred stock Net income (loss) available to WPX Energy, Inc. common stockholders $ (17) $ (204) $ (245) $ (175) $ (641) $ 88 $ 88 Amounts available to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ (5) $ (229) $ (244) $ (174) $ (652) $ 90 $ 90 Income (loss) from discontinued operations (12) 25 (1) (1) 11 (2) (2) Net income (loss) $ (17) $ (204) $ (245) $ (175) $ (641) $ 88 $ 88 22

23 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 available to WPX Energy, Inc. common stockholders $ (5) $ (229) $ (244) $ (174) $ (652) $ 90 $ 90 Income (loss) from continuing operations - diluted earnings per share $ (0.02) $ (0.76) $ (0.72) $ (0.51) $ (2.08) $ 0.22 $ 0.22 Pre-tax adjustments: Impairments reported in exploration expense $ - $ - $ - $ - $ - $ 23 $ 23 Impairments- exploratory related and inventory $ - $ - $ 4 $ - $ 4 $ - $ - Net (gain) loss on sales of assets and divestment of transportation contracts $ (198) $ (4) $ 227 $ (3) $ 22 $ (35) $ (35) Accrual for Denver office lease $ - $ - $ 5 $ - $ 5 $ - $ - Costs related to severance and relocation $ 3 $ 7 $ 3 $ 2 $ 15 $ - $ - Previously capitalized costs expensed following credit facility amendment $ 4 $ - $ - $ - $ 4 $ - $ - (Gain) loss on retirement of debt $ (3) $ 3 $ - $ 1 $ 1 $ - $ - Unrealized MTM (gain) loss $ 76 $ 223 $ 20 $ 190 $ 509 $ (208) $ (208) Total pre-tax adjustments $ (118) $ 229 $ 259 $ 190 $ 560 $ (220) $ (220) Less tax effect for above items $ 43 $ (85) $ (96) $ (71) $ (208) $ 83 $ 83 Impact of state deferred tax rate change $ 14 $ - $ - $ 1 $ 15 $ (6) $ (6) Impact of state tax valuation allowance $ 8 $ - $ - $ - $ 8 $ (6) $ (6) Loss on induced conversion of preferred stock $ - $ - $ 22 $ - $ 22 $ - $ - Total after-tax adjustments $ (53) $ 144 $ 185 $ 120 $ 397 $ (149) $ (149) Adjusted loss from continuing operations available to common stockholders $ (58) $ (85) $ (59) $ (54) $ (255) $ (59) $ (59) Adjusted diluted loss per common share $ (0.21) $ (0.28) $ (0.17) $ (0.16) $ (0.82) $ (0.15) $ (0.15) Diluted weighted-average shares (millions) Adjusted diluted weighted-average shares (millions) (1) Adjusted diluted weighted-average shares excludes the impact of dilutive securities due to the adjusted loss from continuing operations available to common stockholders for the period. 23

24 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) $ (12) $ (198) $ (219) $ (172) $ (601) $ 92 $ 92 Interest expense Provision (benefit) for income taxes 35 (130) (132) (98) (325) Depreciation, depletion and amortization Exploration expenses EBITDAX 241 (100) (142) (53) (54) Accrual for Denver office lease Net (gain) loss on sales of assets and divestment of transportation contracts (198) (4) 227 (3) 22 (35) (35) Impairment of inventory Net (gain) loss on derivatives (57) 154 (38) (203) (203) Net cash received (paid) related to settlement of derivatives (5) (5) (Income) loss from discontinued operations 12 (25) 1 1 (11) 2 2 Adjusted EBITDAX $ 131 $ 94 $ 115 $ 135 $ 475 $ 115 $

25 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. 25

26 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. 26

27 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. 27