FOURTH QUARTER 2017 EARNINGS CALL FEBRUARY 22, 2018

Transcription

1 FOURTH QUARTER 2017 EARNINGS CALL FEBRUARY 22, 2018

2 Recent Highlights OPERATIONAL Oil grew 68% 1 Set well productivity records in the Williston 2 Strong long-lateral results in the Delaware FINANCIAL Unhedged discretionary cash flow per BOE growth of 84% 1 Unhedged adj. EBITDAX growth of 195% 1 2.4x leverage at YE 17 3 TRANSACTIONAL Announced San Juan Gallup sale, $700MM Closed San Juan Legacy sale, $175MM Closed Midstream JV with Howard, $349MM 1. 4Q 16 vs. 4Q Based on latest internal and public data for HZ wells in Three Forks and Middle Bakken. 3. Based on annualized 4Q 17 adjusted EBITDAX. 2

3 Midstream: Flow Assurance and Value Creation 50% owned gas processing facility through JV 100% owned gas gathering system Atmos WAHA takeaway agreement WhiteWater takeaway agreement OIL 50% owned Stateline crude gathering system through JV Stateline takeaway agreement with Oryx II GAS MIDSTREAM Strategy EQUITY ~81,000 undedicated net acres outside Stateline 100% owned Stateline gas & water gathering systems Monetization optionality OPTIONALITY 20% equity ownership exercised with WhiteWater 25% equity ownership in Oryx II pipeline 1 1 Assumes WPX exercises equity option 2H

4 Operational Update Clay Gaspar, President & Chief Operating Officer

5 Delaware Operations: Long Laterals Outperform NM TX EDDY REEVES LEA LOVING STRONG RESULTS WOLFCAMP A WELLS CBR 6-7 PAD WELLS DAY AVG: 1,800+ BOE/D (52% OIL) 10,000 CBR WELLS 120-DAY AVG: 2,060 BOE/D (52% OIL) SHIFT TO LONG LATERALS 400 CBR 6-7 PAD RESULTS CUM MBOE Normalized Days on Production CBR 6-7 PAD (WOLFCAMP A) 1 CBR 7H (5,700 ) CBR 2H (6,700 ) CBR 3H (10,000 ) CBR 4H (10,000 ) CBR 5H (10,000 ) 1. CBR 6H was excluded from results since it was from drilled in a different bench (Wolfcamp D). 5

6 Delaware: Continued Strong Long-Lateral Results NM TX EDDY REEVES LEA LOVING STRONG RESULTS SHIFT TO LONG LATERALS 400 LINDSAY PAD RESULTS 350 CUM MBOE Normalized Days on Production LINDSAY 10-3A1H (WC X/Y- 7,700 ) 24-HR IP: 3,634 BOE 90-DAY CUM: ~242,000 BOE (55% OIL) LINDSAY PAD (WC A- 7,500 ) 90-DAY AVG: 210 MBOE (55% OIL) LINDSAY PAD & LINDSAY 10-3A LINDSAY 14H (WC A, 4,500 ) LINDSAY 17H (WC A, 7,400 ) LINDSAY 15H (WC A, 7,500 ) LINDSAY 16H (WC A, 7,500 ) LINDSAY 18H (WC A, 7,500 ) LINDSAY 19H (WC A, 7,500 ) LINDSAY 10-3A 1H (WC X/Y, 7,700 ) 6

7 Midstream Update and Timeline ANNOUNCED JV WITH HOWARD ENERGY PARTNERS (50% INTEREST) COMPLETE CRUDE GATHERING SYSTEM (50% INTEREST) 1 ST TRAIN OF GAS PROCESSING PLANT ONLINE (MID-YEAR 2018) (50% INTEREST) 2 nd TRAIN OF GAS PROCESSING PLANT ONLINE (2019) (50% INTEREST) SIGNED WAHA TAKEAWAY AGREEMENT WITH ATMOS EXERCISED OPTION WITH WHITEWATER (20% EQUITY STAKE) SIGNED EQUITY & TAKEAWAY AGREEMENTS WITH WHITEWATER & ORYX II EXERCISE OPTION WITH ORYX II (25% EQUITY STAKE) 7

8 Williston Operations: Execute and Outperform DUNN MOUNTRAIL BEST WELLS IN THE BASIN 90-day & 120-day cum production 1 Continued strong results from NORTH SUNDAY ISLAND 120-day cum: ~576 MBOE (81% OIL) Averaging 1,980 barrels of oil per day after 120 days CUM MBOE Strong performance from 4Q MANDAREE SOUTH PAD 60-day Average: ~126 MBOE Averaging 1,700 bbl/d after 60 days Adding 3 RD RIG in 2Q SOLD Mineral Rights Will receive~$20mm in 1Q Normalized Days on Production 1. Based on latest internal and public data for HZ wells in Three Forks and Middle Bakken. 8

9 Financial Update Kevin Vann, Chief Financial Officer

10 4Q & Full-Year 2017 Actual Results 4Q FULL-YEAR Average Daily Production Oil (Mbbl/d) Gas (MMcf/d) NGLs (Mbbl/d) Equivalent (MBOE/d) Adjusted EBITDAX $255 $135 $710 $475 Adjusted Net Income (Loss) from Continuing Operations ($9) ($54) ($166) ($255) Capital Expenditures $321 $160 $1,232 $584 Note: Adjusted EBITDAX and adjusted net income are non-gaap measures. A reconciliation to relevant GAAP measures is provided in this presentation. 10

11 WPX Executing on Strategy ADJ. EBITDAX ($MM) ANNUALIZED ADJ. EBITDAX 2 (NET DEBT/ANNUALIZED ADJ. EBITDAX) NET DEBT/ANNUALIZED ADJ. EBITDAX UNHEDGED ADJ. EBITDAX $93 UNHEDGED ADJ. EBITDAX 195% IN UNHEDGED ADJ. EBITDAX $120 $138 $174 $ Q 16 1Q 17 2Q 17 3Q Q Q16 1Q17 2Q17 3Q17 4Q17 ANNUALIZED ADJ. EBITDAX NET DEBT/ANNUALIZED ADJ. EBITDAX 1. 3Q net debt includes $349MM in proceeds received from Howard Energy Partners on 10/18/ Quarterly Adjusted EBITDAX multiplied by four periods. 11

12 2018 Full-Year Guidance 6 Production FY 2018 Oil Mbbl/d Natural Gas MMcf/d NGL Mbbl/d Total MBOE/d Cap Ex ($ in Millions) FY 2018 D&C / Facilities Capital $1,040 $1,110 Land Acquisition Midstream Opportunities Total Capital Continuing Ops $1,125 $1,250 Midstream Equity Investments Total Capital and Equity Investments Continuing Ops $1,160 $1,310 San Juan Gallup 2 40 Avg. Price Differentials 3 FY 2018 Oil WTI per barrel ($4.50) ($5.50) NYMEX Nat. Gas (Mcf) ($1.00) ($1.25) Net Realized Price 4 FY 2018 NGL % of WTI 34% 38% Expenses FY 2018 $ per BOE LOE $5.50 $6.00 GP&T $1.40 $1.90 DD&A $17.00 $19.00 G&A Cash $2.70 $3.10 G&A Non-Cash $0.65 $0.75 Exploration $1.50 $1.75 Interest Expense $3.85 $3.95 Total Capital and Equity Investments $1,200 $1,350 Production Tax 7% 9% Tax Provision 5 21% 25% 1. 25% equity ownership in Oryx II and 20% Interest with WhiteWater recorded in the investing section of the cash flow statement, purchase of investments. 2. San Juan Gallup capital will be reimbursed in the purchase price adjustment. 3. Average price differentials ranges for oil and natural gas exclude hedges, but include basis differential and revenue adjustments. 4. Percentage of realized price ranges for NGLs excludes hedges, but includes basis differential and revenue adjustments. 5. Rate does not reflect any potential valuation allowance on deferred tax assets. 6. San Juan Gallup is expected to be classified as discontinued operations in

13 WPX: Positioned for Long-Term Value Creation FINANCIAL STRENGTH LEVERAGE OF 1.5X DURING 2019 OIL FOCUSED 150 MBBL/D DURING 2022 MIDSTREAM OPTIONALITY VALUE CREATION/FLOW ASSURANCE DEEP INVENTORY OF HIGH RETURNS 13

14 Appendix

15 WPX Delaware Midstream Infrastructure Overview ASSETS INCLUDED IN JV Crude Gathering System: ~125,000 Bbl/d Gas Processing Facility: 400 MMcf/d First 200 MMcf/d train complete mid-year 2018 ASSETS WHOLLY OWNED BY WPX Stateline Gas & Water Gathering Systems: ~200,000 Bbl/d of water disposal capacity 150 MMcf/d of gas compression capacity ~81,000 Net Acres Outside Stateline Dedication WPX retains all existing midstream rights in other areas SIGNED TAKEAWAY AGREEMENTS Atmos Waha Takeaway Agreement Up to 200,000 MMBtu/d from Waha to Katy, TX RETAINED BY WPX WATER SYSTEM GAS GATHERING EDDY NEW MEXICO TEXAS CULBERSON ACREAGE DEDICATION 50,000 ACRES No drilling or volume commitment REEVES LOVING LEA JV AGREEMENT GAS PROCESSING PLANT CRUDE GATHERING ORYX II UP TO 100,000 BBL/D FROM STATELINE TO MIDLAND & CRANE WARD WAHA WhiteWater Midstream Agreement Up to 500,000 MMBtu/d from Stateline to Waha In-service date first half of % equity ownership Oryx II Crude Takeaway Agreement 100,000 Bbl/d capacity 12.5% equity ownership with option to increase to 25% WHITEWATER UP TO 500,000 MMBTU/D FROM STATELINE TO WAHA PECOS WAHA AGREEMENT UP TO 200,000 MMBTU/D FROM WAHA TO KATY, TX 15

16 WPX Asset Overview DELAWARE BASIN ~131,000 net acres 1 6,600+ gross locations 2,3 52% oil/18% NGLS/30% gas 4 WILLISTON BASIN ~85,000 net acres 1 ~465 gross locations 3 86% oil/7% NGLS/7% gas 4 CHAVES WILLIAMS MOUNTRAIL LEA EDDY NEW MEXICO TEXAS MCKENZIE MCLEAN LOVING WINKLER CULBERSON REEVES WARD DUNN MERCER WPX OPERATED ACREAGE NON-OP ACREAGE PECOS WPX OPERATED ACREAGE 1. Acreage as of December 31, Primarily based on 1-mile laterals and does not include Taylor Ranch locations. 3. Includes non-op and operated locations. 4. Based on FY 2017 production. 16

17 WPX Liquidity and Debt Maturities Liquidity Cash and (12/31/2017) $189 Revolver Capacity $1,200 Letters of Credit ($70) Liquidity 12/31/2017 $1,319 Dollars listed in millions Senior Debt Maturities $ MM $1,200 $1,000 $800 $600 $400 $200 $0 $1,100 $650 $350 $ Senior Notes Senior Notes Senior Notes Senior Notes 17

18 WPX Financial Transformation Continues 68% IN OIL VOLUMES 195% IN UNHEDGED ADJUSTED EBITDAX 84% IN UNHEDGED DISCRETIONARY CASH FLOW PER BOE $7 $6 $5 $4 $3 $2 $1 $- INTEREST EXPENSE $5.87 $5.75 ($ PER BOE) $4.83 $4.61 $3.96 4Q16 1Q17 2Q17 3Q17 4Q $8 $7 $6 $5 $4 $3 $2 $1 $ OIL (MBBL/D) G&A ($ PER BOE) Q16 1Q17 2Q17 3Q17 4Q17 $6.71 $5.27 4Q16 1Q17 2Q17 3Q17 4Q17 G&A Cash $4.80 $4.09 $3.53 G&A Equity Comp $300 $250 $200 $150 $100 $50 $0 $25 $20 $15 $10 $5 $- UNHEDGED ADJUSTED EBITDAX ($ IN MILLIONS) $93 $120 $138 $174 DD&A ($ PER BOE) $274 4Q16 1Q17 2Q17 3Q17 4Q17 $19.27 $18.11 $17.78 $16.39 $ Q16 1Q17 2Q17 3Q17 4Q17 $20 $18 $16 $14 $12 $10 1 $8 $6 $4 $2 $0 UNHEDGED DISCRETIONARY CASH FLOW ($ PER BOE) $9.68 $9.39 $10.45 $ % IN INTEREST EXP ($ PER BOE) 47% IN G&A ($ PER BOE) $ Q16 1Q17 2Q17 3Q17 4Q17 20% IN DD&A ($ PER BOE) NOTE: Percentage change is based on the change from 4Q 16 to 4Q A portion of this rate decrease is due to ceasing depletion on natural gas producing assets in the San Juan Basin that were held for sale in 4Q

19 WPX Hedges Updated: February 20, 2018 Crude Oil (bbl) Volume/Day Average Price Volume/Day Average Price Volume/Day Average Price Fixed Price Swaps 1 56,979 $ ,000 $ Fixed Price Calls 13,000 $ ,000 $ Crude Oil Basis (bbl) Midland Basis Swaps 14,496 ($0.86) 20,000 ($0.93) 5,000 ($1.16) Natural Gas (MMBtu) Fixed Price Swaps 131,616 $ ,000 $ Fixed Price Calls 16,301 $ Natural Gas Basis (MMBtu) Houston Ship Channel Basis Swaps 42,500 ($0.08) 30,000 ($0.09) - - Permian Basis Swaps 47,500 ($0.31) 25,000 ($0.39) - - West Texas Basis Swaps 15,000 $ ,000 $ ,000 ($0.57) San Juan Basis Swaps 23,233 ($0.01) Natural Gas Liquids (bbl) Mont Belvieu Ethane Swaps 2 3,078 $ Mont Belvieu Propane Swaps 2 3,604 $ Conway Propane Swaps $ Mont Belvieu Iso Butane Swaps $ Mont Belvieu Normal Butane Swaps 2 1,701 $ Mont Belvieu Natural Gasoline Swaps 2 1,401 $ In addition to several crude oil swaps, WPX entered into calendar monthly average(cma) Nymex roll swaps which provide pricing adjustments to the trade month versus the delivery month for contract pricing. CMA Nymex roll swaps for 2018 total 20,000 bbls/d at a weighted average price of $0.03. CMA Nymex roll swaps for 2019 total 20,000 bbls/d at a weighted average price of $ Average price in $/gallon. 19

20 Price Realization for 2017 Weighted-Average Sales Price 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 $46.38 $43.60 $44.24 $52.45 $3.01 $2.65 $2.60 $2.52 $22.14 $18.98 $24.31 $28.47 Revenue Adjustments 1 $(1.07) $(1.14) $(0.90) $(0.95) $(0.50) $(0.52) $(0.54) $(0.61) $(1.29) $(0.70) $(0.74) $(0.98) Net Price 2 $45.31 $42.46 $43.34 $51.50 $2.51 $2.13 $2.06 $1.91 $20.85 $18.28 $23.57 $27.49 Realized Portion of Derivatives 3 $(0.77) $2.18 $1.70 $(3.57) $(0.11) $0.14 $0.18 $ Net Price Including Derivatives $44.54 $44.64 $45.04 $47.93 $2.40 $2.27 $2.24 $2.19 $20.85 $18.28 $23.57 $ 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 $(1.43). 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. 20

21 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 $ 226 $ 259 $ 356 $ 1,029 Natural gas sales Natural gas liquid sales Total product revenues ,307 Net gain (loss) on derivatives 57 (154) 38 (148) (207) (106) (210) 3 Commodity management Other Total revenues ,336 Costs and expenses: Depreciation, depletion and amortization Lease and facility operating Gathering, processing and transportation Taxes other than income Exploration General and administrative Commodity management Net (gain) loss-sales of assets, divestment of transportation contracts or impairment of producing properties (198) (4) 227 (3) 22 (35) (7) (56) (13) (111) Other-net Total costs and expenses , ,293 Operating income (loss) 90 (299) (301) (221) (731) (67) (129) 43 Interest expense (57) (53) (49) (48) (207) (47) (46) (48) (47) (188) Loss on extinguishment of debt 3 (3) - (1) (1) - - (17) - (17) Investment income and other (1) (1) 3 Income (loss) from continuing operations before income taxes $ 35 $ (353) $ (350) $ (269) $ (937) $ 125 $ 23 $ (130) $ (177) $ (159) Provision (benefit) for income taxes 35 (130) (132) (98) (325) 31 (53) 20 (146) (148) Income (loss) from continuing operations $ - $ (223) $ (218) $ (171) $ (612) $ 94 $ 76 $ (150) $ (31) $ (11) Income (loss) from discontinued operations (12) 25 (1) (1) 11 (2) - 4 (7) (5) Net income (loss) $ (12) $ (198) $ (219) $ (172) $ (601) $ 92 $ 76 $ (146) $ (38) $ (16) 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 $ 72 $ (149) $ (42) $ (31) Amounts available to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ (5) $ (229) $ (244) $ (174) $ (652) $ 90 $ 72 $ (153) $ (35) $ (26) Income (loss) from discontinued operations (12) 25 (1) (1) 11 (2) - 4 (7) (5) Net income (loss) $ (17) $ (204) $ (245) $ (175) $ (641) $ 88 $ 72 $ (149) $ (42) $ (31) 21

22 Reconciliation-Adjusted Income (Loss) from Continuing Operations (Non-GAAP) (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Reconciliation of adjusted loss from continuing operations available to common stockholders: Income (loss) from continuing operations available to WPX Energy, Inc. common stockholders - reported $ (5) $ (229) $ (244) $ (174) $ (652) $ 90 $ 72 $ (153) $ (35) $ (26) Pre-tax adjustments: Impairments reported in exploration expense $ - $ - $ - $ - $ - $ 23 $ - $ - $ - $ 23 Impairment of inventory $ - $ - $ 4 $ - $ 4 $ - $ - $ - $ - $ - Net (gain) loss-sales of assets, divestment of transportation contracts or impairment of producing properties $ (198) $ (4) $ 227 $ (3) $ 22 $ (35) $ (7) $ (56) $ (13) $ (111) (Gain) loss on extinguishment of debt $ (3) $ 3 $ - $ 1 $ 1 $ - $ - $ 17 $ - $ 17 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 $ - $ - $ - $ - $ - Unrealized MTM (gain) loss $ 76 $ 223 $ 20 $ 190 $ 509 $ (208) $ (102) $ 120 $ 191 $ 1 Total pre-tax adjustments $ (118) $ 229 $ 259 $ 190 $ 560 $ (220) $ (109) $ 81 $ 178 $ (70) Less tax effect for above items $ 43 $ (85) $ (96) $ (71) $ (208) $ 83 $ 40 $ (30) $ (67) $ 25 Impact of state deferred tax rate change $ 14 $ - $ - $ 1 $ 15 $ (6) $ - $ - $ (6) $ (12) Impact of state tax valuation allowance (annual effective tax rate method) $ 8 $ - $ - $ - $ 8 $ (6) $ (34) $ 36 $ 4 $ - Impact of federal rate change 1 $ - $ - $ - $ - $ - $ - $ - $ - $ (83) $ (83) Adjustment for estimated annual effective tax rate method $ - $ - $ - $ - $ - $ - $ (26) $ 26 $ - $ - Loss on induced conversion of preferred stock $ - $ - $ 22 $ - $ 22 $ - $ - $ - $ - $ - Total adjustments, after tax $ (53) $ 144 $ 185 $ 120 $ 397 $ (149) $ (129) $ 113 $ 26 $ (140) Adjusted loss from continuing operations available to common stockholders $ (58) $ (85) $ (59) $ (54) $ (255) $ (59) $ (57) $ (40) $ (9) $ (166) 1. Includes $92 million for the provisional impact of the Tax Cuts and Jobs Act offset by the impact of the pretax adjustments above. 22

23 Reconciliation Adjusted Diluted Loss Per Common Share Reconciliation of adjusted diluted loss per common share: Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Income (loss) from continuing operations - diluted earnings per share - reported $ (0.02) $ (0.76) $ (0.72) $ (0.51) $ (2.08) $ 0.22 $ 0.18 $ (0.39) $ (0.09) $ (0.06) Impact of adjusted diluted weighted-average shares $ - $ - $ - $ - $ - $ 0.01 $ - $ - $ - $ - Pretax adjustments (1): Impairments reported in exploration expense $ - $ - $ - $ - $ - $ 0.06 $ - $ - $ - $ 0.06 Impairment of inventory $ - $ - $ 0.01 $ - $ 0.01 $ - $ - $ - $ - $ - Net (gain) loss-sales of assets, divestment of transportation contracts or impairment of producing properties $ (0.72) $ (0.01) $ 0.67 $ (0.01) $ 0.07 $ (0.09) $ (0.02) $ (0.14) $ (0.03) $ (0.28) Loss on extinguishment of debt $ (0.01) $ 0.01 $ - $ - $ - $ - $ - $ 0.04 $ - $ 0.04 Accrual for Denver office lease $ - $ - $ 0.01 $ - $ 0.02 $ - $ - $ - $ - $ - Costs related to severance and relocation $ 0.01 $ 0.02 $ 0.01 $ 0.01 $ 0.05 $ - $ - $ - $ - $ - Previously capitalized costs expensed following credit facility amendment $ 0.01 $ - $ - $ - $ 0.01 $ - $ - $ - $ - $ - Unrealized MTM (gain) loss $ 0.27 $ 0.74 $ 0.06 $ 0.55 $ 1.62 $ (0.54) $ (0.26) $ 0.30 $ 0.48 $ - Total pretax adjustments $ (0.44) $ 0.76 $ 0.76 $ 0.55 $ 1.78 $ (0.57) $ (0.28) $ 0.20 $ 0.45 $ (0.18) Less tax effect for above items $ 0.17 $ (0.28) $ (0.27) $ (0.20) $ (0.67) $ 0.22 $ 0.12 $ (0.07) $ (0.16) $ 0.06 Impact of state tax rate change $ 0.05 $ - $ - $ - $ 0.05 $ (0.01) $ - $ - $ (0.02) $ (0.03) Impact of state valuation allowance (annual effective tax rate method) $ 0.03 $ - $ - $ - $ 0.03 $ (0.02) $ (0.09) $ 0.09 $ 0.01 $ - Impact of federal rate change $ - $ - $ - $ - $ - $ - $ - $ - $ (0.21) $ (0.21) Adjustment for estimated annual effective tax rate method $ - $ - $ - $ - $ - $ - $ (0.07) $ 0.07 $ - $ - Loss on induced conversion of preferred stock $ - $ - $ 0.06 $ - $ 0.07 $ - $ - $ - $ - $ - Total adjustments, after-tax $ (0.19) $ 0.48 $ 0.55 $ 0.35 $ 1.26 $ (0.38) $ (0.32) $ 0.29 $ 0.07 $ (0.36) Adjusted diluted loss per common share $ (0.21) $ (0.28) $ (0.17) $ (0.16) $ (0.82) $ (0.15) $ (0.14) $ (0.10) $ (0.02) $ (0.42) Reported diluted weighted-average shares (millions) Effect of dilutive securities due to adjusted loss from continuing operations available to common stockholders (24.1) (25.4) Adjusted diluted weighted-average shares (millions) Per share impact is based on adjusted diluted weighted-average shares. 23

24 Reconciliation Adjusted EBITDAX (Non-GAAP) (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Reconciliation of Adjusted EBITDAX Net income (loss) - reported $ (12) $ (198) $ (219) $ (172) $ (601) $ 92 $ 76 $ (146) $ (38) $ (16) Interest expense Provision (benefit) for income taxes 35 (130) (132) (98) (325) 31 (53) 20 (146) (148) Depreciation, depletion and amortization Exploration expenses EBITDAX 241 (100) (142) (53) (54) Accrual for Denver office lease Net (gain) loss-sales of assets, divestment of transportation contracts or impairment of producing properties (198) (4) 227 (3) 22 (35) (7) (56) (13) (111) Loss on extinguishment of debt Impairment of inventory Net (gain) loss on derivatives (57) 154 (38) (203) (116) (3) Net cash received (paid) related to settlement of derivatives (5) (19) 4 (Income) loss from discontinued operations 12 (25) 1 1 (11) 2 - (4) 7 5 Adjusted EBITDAX $ 131 $ 94 $ 115 $ 135 $ 475 $ 115 $ 152 $ 188 $ 255 $

25 Disclaimers 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. 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. 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. 25