3Q 2017 Investor Update Rick Muncrief, Chairman and CEO Nov. 2, 2017
Recent Highlights Raising 2017 oil growth guidance from 40% to 45% year-over-year Current oil production averaging 75,000 BBL/D Increasing EURs in the Williston to 1,000 MBOE 67% increase unhedged margin per BOE past 12 months, $9.68 to $16.20 Closed joint venture with Howard Energy Partners, $349MM in cash Signed PSA Legacy San Juan Dry Gas, $169MM with closing by year-end 2
WPX Executing on Strategy ADJ. EBITDAX ($MM) $800 $700 $600 $500 $400 $300 ANNUALIZED ADJ. EBITDAX 2 (NET DEBT / ANNUALIZED ADJ. EBITDAX) 3.9x 5.5x 4.3x 3.4x 6.0 5.0 4.0 3.0 2.0 NET DEBT/ADJ. EBITDAX PER BOE $18 $16 $14 $12 $10 $8 $6 UNHEDGED DISCRETIONARY CASH FLOW ($ PER BOE) $9.68 $9.39 $10.45 $16.20 $200 $100 1.0 $4 $2 $0 0.0 1 4Q16 1Q17 2Q17 3Q17 ANNUALIZED ADJ. EBITDAX NET DEBT/ANNUALIZED ADJ. EBITDAX $- 4Q16 1Q17 2Q17 3Q17 Deleveraging and Margin Expansion Progressing Rapidly 1. 3Q net debt includes $349MM in proceeds received from Howard Energy Partners on 10/18/2017. 2. Quarterly Adjusted EBITDAX multiplied by four periods 3
WPX 2018 Guidance Highlights CASH FLOW NEUTRAL 2018 1 NET DEBT TTM ADJ. EBITDAX BELOW 2.5X 4Q 18 OIL GROWTH 40% - 45% TOTAL CAPITAL $1.1B - $1.2B FLAT RIG COUNT ~10 RIGS COMMODITY MIX ~60% OIL ~80% LIQUIDS Free Cash Flow 2019 and Beyond Leverage Below 2.0x 1. Includes proceeds for non-core asset sales. 4
Operational Update Clay Gaspar, Chief Operating Officer
Delaware Basin STRONG WELL PERFORMANCE 1.5 MILE LATERALS LINDSAY 10 15-15H 30-DAY AVG: ~3,000 BOE (54% OIL) LINDSAY 10 15-16H 30-DAY AVG: 3,128 BOE (53% OIL) LINDSAY 10 15-17H 30-DAY AVG: 3,020 BOE (53% OIL) LINDSAY 10 15-18H 30-DAY AVG: 2,902 BOE (56% OIL) LINDSAY 10 15-19H 30-DAY AVG: 3,301 BOE (53% OIL) 4Q PLANNED ACTIVITY DROPPING A RIG & EXITING 2017 WITH 20-25 DUCS MBBL/D GROWING OIL VOLUMES 25 20 15 10 5 0 59% OIL GROWTH SINCE 3Q16 3Q16 4Q16 1Q17 2Q17 3Q17 CLOSED MIDSTREAM JV AGREEMENT RECEIVED $349MM FROM HOWARD ENERGY PARTNERS 6
Delaware Drilling More Lateral Feet in 2018 +20% MORE LATERAL FEET DRILLED WITH FLAT RIG COUNT 2017 ~515,000 LATERAL FEET DRILLED IN 2017 Average lateral drilled 6,150 ~7 rig average Landed in 8 different zones 2018 ~625,000 LATERAL FEET TO BE DRILLED IN 2018 Average lateral ~7,500 6-7 rigs Primary target: Upper/Lower WCA +20% MORE LATERAL 7
Delaware Completing More Lateral Feet in 2018 +50% MORE LATERAL FEET COMPLETED WITH FLAT RIG COUNT 2017 ~350,000 LATERAL FEET COMPLETED IN 2017 2 frac crews 2018 ~540,000 LATERAL FEET TO BE COMPLETED IN 2018 3 frac crews +50% MORE LATERAL 8
Williston Basin RAISING THE TYPE CURVE GROWING OIL VOLUMES MBBL/D MOVING TO 1,000 MBOE CURVE (81% OIL) (BLENDED THREE FORKS AND MIDDLE BAKKEN) 81% OIL GROWTH SINCE 3Q16 35 30 25 20 15 10 5 0 3Q16 4Q16 1Q17 2Q17 3Q17 STRONG WELL PERFORMANCE 2018 DRILLING PROGRAM: FOCUSED ON NORTH SUNDAY ISLAND RECENT 24-HOUR IPS: MANDAN NORTH 13-24HW: 4,464 BOE/D (81% OIL) HIDATSA NORTH 14-23HX: 4,081 BOE/D (81% OIL) CUM MBOE 180 160 140 120 100 80 60 40 20 0 2016-2017 PERFORMANCE VS. 1,000 MBOE TYPE CURVE 0 30 60 90 120 150 180 CUM MBOE 80 70 60 50 40 30 20 10 0 2016 AVG. 2017 AVG. DAYS ON PRODUCTION NORTH SUNDAY ISLAND 0 DAYS ON PRODUCTION 30 9
San Juan Basin SIGNED PSA LEGACY SAN JUAN DRY GAS EXPECTED CLOSE BY YE 2017 STRONG WELL PERFORMANCE UNITS FORMED FOR FUTURE DRILLING WEST LYBROOK UNIT SAN JUAN COUNTY RIO ARRIBA COUNTY SANDOVAL COUNTY WELL RESULTS FROM RODEO UNIT: 30-DAY AVG. CUM PRODUCTION: 28 MBOE (71% OIL) RODEO UNIT ESCAVADA UNITS 4Q 2017 PLANNED ACTIVITY EXITING 2017 WITH 12 DUCS AND 0 RIGS GROWING OIL VOLUMES 50% OIL GROWTH SINCE 3Q16 MBBL/D 12 10 8 6 4 CUM MBOE 120 100 80 60 40 20 RODEO UNIT PERFORMANCE NORMALIZED TO 7,500 2 0 3Q16 4Q16 1Q17 2Q17 3Q17 0 0 10 20 30 40 50 60 70 80 DAYS ON PRODUCTION 10
Financial Update Kevin Vann, Chief Financial Officer
3 rd Dollars Quarter in millions, except Results production numbers 3Q 2017 2016 2017 2016 Average Daily Production Oil (Mbbl/d) 64.8 38.9 56.6 40.4 Gas (MMcf/d) 204 205 201 199 NGLs (Mbbl/d) 13.3 11.4 12.8 9.7 Equivalent (MBOE/d) 112.0 84.4 102.8 83.2 YTD Adjusted EBITDAX $188 $115 $455 $340 Adjusted Net Income (Loss) from Continuing Operations ($40) ($59) ($157) ($201) Capital Expenditures $315 1 $160 $911 $424 1. Including $30 million for items not associated with D&C activity such as infrastructure development that was reimbursed in the JV closing process, facilities construction and land. Note: Adjusted EBITDAX and adjusted net income are non-gaap measures. A reconciliation to relevant GAAP measures is provided in this presentation. 12
WPX Financial Transformation Underway 45% IN OIL VOLUMES 67% IN UNHEDGED DISCRETIONARY CASH FLOW 87% IN UNHEDGED ADJUSTED EBITDAX $7 $6 $5 $4 $3 $2 $1 $- INTEREST EXPENSE $5.87 $5.75 ($ PER BOE) $4.83 $4.61 4Q16 1Q17 2Q17 3Q17 $8 $7 $6 $5 $4 $3 $2 $1 $- 70 60 50 40 30 20 10 0 $6.71 44.7 46.1 OIL (MBBLS/D) G&A ($ PER BOE) 58.6 64.8 4Q16 1Q17 2Q17 3Q17 $5.27 $4.80 $4.09 4Q16 1Q17 2Q17 3Q17 $20 $19 $19 $18 $18 $17 $17 $16 $16 $15 $15 $18 $16 $14 $12 $10 $8 $6 $4 $2 $- $19.27 UNHEDGED DISCRETIONARY CASH FLOW ($ PER BOE) $9.68 $9.39 DD&A ($ PER BOE) $10.45 $16.20 4Q16 1Q17 2Q17 3Q17 $18.11 $17.78 $16.39 4Q16 1Q17 2Q17 3Q17 $200 $180 $160 $140 $120 $100 $80 $60 $40 $20 $- UNHEDGED ADJUSTED EBITDAX $93 ($ IN MILLIONS) $120 $138 21% IN INTEREST EXP ($ PER BOE) 39% IN G&A ($ PER BOE) 15% IN DD&A ($ PER BOE) $174 4Q16 1Q17 2Q17 3Q17 NOTE: Percentage change is based on the change from 4Q 16 to 3Q 17. 13
2018 Full-Year Guidance Production FY 2018 Oil Mbbl/d 82.0 88.0 Natural Gas MMcf/d 170 190 NGL Mbbl/d 21.5 23.0 Total MBOE/d 132 143 Cap Ex ($ in Millions) FY 2018 D&C Capital 1 $1,040 $1,110 Midstream Capital 60 90 Total 2 $1,100 $1,200 Avg. Price Differentials 3 FY 2018 Oil WTI per barrel ($5.00) ($6.00) NYMEX Nat. Gas (Mcf) ($1.00) ($1.25) Net Realized Price 4 FY 2018 NGL % of WTI 38% 42% Expenses FY 2018 $ per BOE LOE $5.25 $5.75 GP&T 1.75 2.25 Production Tax 2.75 3.00 Cash Operating $9.75 $11.00 DD&A $17.00 $19.00 G&A Cash $2.40 $2.60 G&A Non-Cash $0.65 $0.75 Exploration $1.45 $1.55 Interest Expense $3.65 $3.95 Tax Rate FY 2018 Tax Provision 5 33% 37% 1 Includes non-operated wells, facilities cost and artificial lift. 2 Excludes any acquisition and land capital. 3 Average price differentials ranges for oil and natural gas exclude hedges, but include basis differential and revenue adjustments. 4 Percentage of realized price ranges for NGLs excludes hedges, but includes basis differential and revenue adjustments. 5 Rate does not reflect potential valuation allowance on deferred tax assets. 6. Based on midpoint of guidance COMMODITY MIX 6 ~60% OIL ~80% LIQUIDS OIL PRODUCTION 40-45% YOY 2018 RIG COUNT DELAWARE: 6-7 WILLISTON: 2-3 SAN JUAN: 0-1 14
WPX Continued Focus on Shareholder Value Paying Off WILLISTON SAN JUAN GALLUP HEADQUARTERS TULSA, OK DELAWARE MULTI-YEAR STRATEGY AHEAD OF SCHEDULE EXECUTION 2018 DISCIPLINE FOCUS RETURNS MARGINS LEVERAGE 15
Appendix
Updated 2017 Full-Year Guidance (Includes Impact of San Juan Legacy Sale) Production FY 2017 Oil Mbbl/d 59.0 62.0 Natural Gas MMcf/d 200 215 NGL Mbbl/d 14.0 19.0 Total MBOE/d 106 117 Cap Ex ($ in Millions) D&C Capital 1 $940 $1,010 Delaware Infrastructure 2 50 60 Total 3 $990 $1,070 Avg. Price Differentials 4 FY 2017 Oil WTI per barrel ($6.00) ($7.00) NYMEX Nat. Gas (Mcf) ($0.80) ($1.00) Net Realized Price 5 FY 2017 NGL % of WTI 38% 42% Expenses FY 2017 $ per BOE LOE $5.25 $5.75 GP&T 2.00 2.50 Production Tax 2.25 2.75 Cash Operating $9.50 $11.00 DD&A $18.00 $19.00 G&A Cash $3.00 $3.25 G&A Non Cash $0.85 $0.90 Exploration 7 $1.75 $1.95 Interest Expense $4.50 $4.90 Tax Rate FY 2017 Tax Provision 6 33% 37% 1 Includes non-operated wells and wells which include additional science work. 2 Incudes $49MM of capital associated with the midstream infrastructure reimbursed through JV by Howard Energy. 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 $23MM of lease expiration expense recorded in the 1 st quarter. 17
WPX Liquidity, Hedges and Debt Maturities Liquidity Cash and Equivalents @ (10/31/2017) $75 Revolver Capacity $1,125 Liquidity $1,200 Dollars listed in millions STRONG LIQUIDITY % of Production Hedged 1 100% 80% 60% 40% 20% 0% STRONG HEDGE POSITION CREATES CERTAINTY FOR DRILLING PROGRAM $3.93 $2.97 $52.69 Oil 2018 Natural Gas 2018 Oil: 55,500 bbl/d Hedged $52.69 per barrel Gas: 140,000 mmbtu/d $2.97 per MMBtu 2019 Oil: 22,000 bbl/d Hedged $50.85 per barrel Senior Debt Maturities $ MM $1,200 $1,000 $800 $600 $400 $200 $0 $1,100 $350 $500 $650 2017 2018 2019 2020 2021 2022 2023 2024 Senior Notes Senior Notes Senior Notes Senior Notes 1 Based on midpoint of guidance 18
WPX Hedges Updated: October 31, 2017 Oct Dec 2017 2018 2019 Volume/Day Average Price Volume/Day Average Price Volume/Day Average Price Crude Oil (bbl) Fixed Price Swaps 1 50,638 $50.23 55,500 $52.69 22,000 $50.85 Fixed Price Calls 4,500 $56.47 13,000 $58.89 5,000 $54.08 Crude Oil Basis (bbl) Midland Basis Swaps 15,000 ($0.62) 17,521 ($0.91) 20,000 ($0.93) Natural Gas (MMBtu) Fixed Price Swaps 2 170,000 $3.02 140,000 $2.97 - - Fixed Price Calls 15,327 $4.50 16,301 $4.75 - - Natural Gas Basis (MMBtu) Houston Ship Channel Basis Swaps - - 42,500 ($0.08) 30,000 ($0.09) Permian Basis Swaps 72,500 ($0.20) 47,500 ($0.31) 25,000 ($0.39) West Texas Basis Swaps - - 15,000 $0.93 45,000 $0.07 San Juan Basis Swaps 97,500 ($0.18) 40,000 ($0.30) - - 1 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 $0.11. 2 In connection with several natural gas 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. Natural Gas Swaptions for 2018 total 20,000 mmbtu/d at a weighted average strike price of $3.33. 19
Domestic Price Realization for 2017 Oil ($/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 $43.60 $44.24 $3.01 $2.65 $2.60 $22.14 $18.98 $24.31 Revenue Adjustments 1 $(1.07) $(1.14) $(0.90) $(0.50) $(0.52) $(0.54) $(1.29) $(0.70) $(0.74) Net Price 2 $45.31 $42.46 $43.34 $2.51 $2.13 $2.06 $20.85 $18.28 $23.57 Realized Portion of Derivatives 3 $(0.77) $2.18 $1.70 $(0.11) $0.14 $0.18 - - - Net Price Including Derivatives $44.54 $44.64 $45.04 $2.40 $2.27 $2.24 $20.85 $18.28 $23.57 1 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 $(1.21). 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
Consolidated Statement of Operations (GAAP) 2016 2017 (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 $ 673 Natural gas sales 25 24 37 39 125 44 40 38 122 Natural gas liquid sales 5 10 12 19 46 21 23 29 73 Total product revenues 127 176 188 231 722 253 289 326 868 Net gain (loss) on derivatives 57 (154) 38 (148) (207) 203 116 (106) 213 Gas management 31 116 25 5 177 5 8 4 17 Other 1 - - - 1 - - - - Total revenues 216 138 251 88 693 461 413 224 1,098 Costs and expenses: Depreciation, depletion and amortization 152 163 150 158 623 147 171 169 487 Lease and facility operating 42 41 40 40 163 48 53 58 159 Gathering, processing and transportation 16 20 19 21 76 21 21 25 67 Taxes other than income 11 16 14 19 60 19 23 26 68 Exploration 9 12 10 11 42 39 21 20 80 General and administrative 53 55 51 55 214 43 46 42 131 Gas management 39 132 31 6 208 5 8 4 17 Net (gain) loss-sales of assets, divestment of transportation contracts or impairment of producing properties (198) (4) 227 (3) 22 (35) (7) (56) (98) Other-net 2 2 10 2 16 4 8 3 15 Total costs and expenses 126 437 552 309 1,424 291 344 291 926 Operating income (loss) 90 (299) (301) (221) (731) 170 69 (67) 172 Interest expense (57) (53) (49) (48) (207) (47) (46) (48) (141) Loss on extinguishment of debt - - - - - - - (17) (17) Investment income and other 2 (1) - - 1 2-2 4 Income (loss) from continuing operations before income taxes $ 35 $ (353) $ (350) $ (269) $ (937) $ 125 $ 23 $ (130) $ 18 Provision (benefit) for income taxes 35 (130) (132) (98) (325) 31 (53) 20 (2) Income (loss) from continuing operations $ - $ (223) $ (218) $ (171) $ (612) $ 94 $ 76 $ (150) $ 20 Income (loss) from discontinued operations (12) 25 (1) (1) 11 (2) - 4 2 Net income (loss) $ (12) $ (198) $ (219) $ (172) $ (601) $ 92 $ 76 $ (146) $ 22 Less: Dividends on preferred stock 5 6 4 3 18 4 4 3 11 Less: Loss on induced conversion of preferred stock - - 22-22 - - - - Net income (loss) available to WPX Energy, Inc. common stockholders $ (17) $ (204) $ (245) $ (175) $ (641) $ 88 $ 72 $ (149) $ 11 Amounts available to WPX Energy, Inc. common stockholders: Income (loss) from continuing operations $ (5) $ (229) $ (244) $ (174) $ (652) $ 90 $ 72 $ (153) $ 9 Income (loss) from discontinued operations (12) 25 (1) (1) 11 (2) - 4 2 Net income (loss) $ (17) $ (204) $ (245) $ (175) $ (641) $ 88 $ 72 $ (149) $ 11 21
Reconciliation-Adjusted Income (Loss) from Continuing Operations (Non-GAAP) 2016 2017 (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) $ 9 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) $ (98) Loss on extinguishment of debt $ - $ - $ - $ - $ - $ - $ - $ 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 $ - $ - $ - $ - (Gain) loss on retirement of debt $ (3) $ 3 $ - $ 1 $ 1 $ - $ - $ - $ - Unrealized MTM (gain) loss $ 76 $ 223 $ 20 $ 190 $ 509 $ (208) $ (102) $ 120 $ (190) Total pre-tax adjustments $ (118) $ 229 $ 259 $ 190 $ 560 $ (220) $ (109) $ 81 $ (248) Less tax effect for above items $ 43 $ (85) $ (96) $ (71) $ (208) $ 83 $ 40 $ (30) $ 92 Impact of state deferred tax rate change $ 14 $ - $ - $ 1 $ 15 $ (6) $ - $ - $ (6) Impact of state tax valuation allowance (annual effective tax rate method) $ 8 $ - $ - $ - $ 8 $ (6) $ (34) $ 36 $ (4) 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 $ (166) Adjusted loss from continuing operations available to common stockholders $ (58) $ (85) $ (59) $ (54) $ (255) $ (59) $ (57) $ (40) $ (157) 22
Reconciliation Adjusted Diluted Loss Per Common Share 2016 2017 (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Reconciliation of adjusted diluted loss per common share: 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) $ 0.02 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) $ (0.25) Loss on extinguishment of debt $ - $ - $ - $ - $ - $ - $ - $ 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 $ - $ - $ - $ - (Gain) loss on retirement of debt $ (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 $ (0.63) Less tax effect for above items $ 0.17 $ (0.28) $ (0.27) $ (0.20) $ (0.67) $ 0.22 $ 0.12 $ (0.07) $ 0.23 Impact of state tax rate change $ 0.05 $ - $ - $ - $ 0.05 $ (0.01) $ - $ - $ (0.01) Impact of state valuation allowance (annual effective tax rate method) $ 0.03 $ - $ - $ - $ 0.03 $ (0.02) $ (0.09) $ 0.09 $ (0.01) 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 $ (0.42) Adjusted diluted loss per common share $ (0.21) $ (0.28) $ (0.17) $ (0.16) $ (0.82) $ (0.15) $ (0.14) $ (0.10) $ (0.40) Reported diluted weighted-average shares (millions) 276.1 300.7 341.5 344.6 313.3 410.4 423.2 398.1 396.2 Effect of dilutive securities due to adjusted loss from continuing operations available to common stockholders - - - - - (24.1) (25.4) - (2.1) Adjusted diluted weighted-average shares (millions) 276.1 300.7 341.5 344.6 313.3 386.3 397.8 398.1 394.1 (1) Per share impact is based on adjusted diluted weighted-average shares. 23
Reconciliation EBITDAX (Non-GAAP) 2016 2017 (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Reconciliation of Adjusted EBITDAX Net income (loss) - reported Net income (loss) - reported $ (12) $ (198) $ (219) $ (172) $ (601) $ 92 $ 76 $ (146) $ 22 Interest expense 57 53 49 48 207 47 46 48 141 Provision (benefit) for income taxes 35 (130) (132) (98) (325) 31 (53) 20 (2) Depreciation, depletion and amortization 152 163 150 158 623 147 171 169 487 Exploration expenses 9 12 10 11 42 39 21 20 80 EBITDAX 241 (100) (142) (53) (54) 356 261 111 728 Accrual for Denver office lease - - 5-5 - - - - Net (gain) loss-sales of assets, divestment of transportation contracts or impairment of producing properties (198) (4) 227 (3) 22 (35) (7) (56) (98) Loss on extinguishment of debt - - - - - - - 17 17 Impairment of inventory - - 4-4 - - - - Net (gain) loss on derivatives (57) 154 (38) 148 207 (203) (116) 106 (213) Net cash received (paid) related to settlement of derivatives 133 69 58 42 302 (5) 14 14 23 (Income) loss from discontinued operations 12 (25) 1 1 (11) 2 - (4) (2) Adjusted EBITDAX $ 131 $ 94 $ 115 $ 135 $ 475 $ 115 $ 152 $ 188 $ 455 24
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
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 www.sec.gov. 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
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