3Q 2016 Investor Update Rick Muncrief, President and CEO November 3, 2016
WPX 3Q Highlights Completed 1st Wolfcamp D and X/Y wells Commenced Upper/Lower Wolfcamp A density test Closed on additional attractive Delaware acreage Completing DUCs in the Williston Completed strongest Gallup wells to date Communicated growth strategy through 2020 2
Strong Returns Across Entire Portfolio STRONG OIL & GAS PORTFOLIO PROVIDES OPTIONALITY 4 WELL ECONOMICS Flat $53.15 Oil and $3.03 Gas 1 DELAWARE 16% NGL 28% GAS DELAWARE LONG LATERALS 3 DELAWARE (WCA) 100%+ 80%+ ROR 2 WILLISTON 56% OIL WILLISTON SAN JUAN GALLUP 70%+ 8% NGL 9% GAS 83% OIL WILLISTON BASIN SAN JUAN GALLUP 23% NGL 31% GAS 46% OIL SAN JUAN BASIN HEADQUARTERS TULSA DELAWARE BASIN 1 3-year strip price as of October 26, 2016 2 Excludes G&A, acquisition land costs, and interest expense. Assumes vision for Delaware and Williston 3 Assumes 1.4x cost and 1.7x EUR uplift of current 1-mile WCA well 4 Based on YTD production 3
Executing on Long-Term Strategy WILLISTON SAN JUAN DELAWARE Deep Inventory of High Returns Free cashflow positive by YE18 Avg. well payout period 18-24 months Financial Flexibility Strong hedge book through 2018 Net debt to EBITDAX below 2.5x YE 2018 Increasing Activity Oil/EBITDAX CAGR 20%-35% through 2020 Funded with cash on-hand and CFFO 4
Poised for Rapid Sustainable Growth ASSET QUALITY SUPPORTS RAPID OIL GROWTH ASSET QUALITY SUPPORTS RAPID EBITDAX GROWTH 160 FORECAST AT HIGH-END OF PREVIOUS RANGE $1,800 FORECAST AT HIGH-END OF PREVIOUS RANGE 140 CAGR: 35% HIGH CASE $1,600 CAGR: 35% HIGH CASE 120 CAGR: 20% LOW CASE $1,400 CAGR: 20% LOW CASE OIL MBBL/D 100 80 60 40 $1,200 $1,000 $800 $600 $400 20 $200 0 2014 2015 2016 2017 2018 2019 2020 $0 2015 2016 2017 2018 2019 2020 UPDATED FORECAST LOW CASE HIGH CASE UPDATED FORECAST LOW CASE HIGH CASE 25% oil growth in 2017 50% oil growth in 2018 Forecast at High-End of Previous Range Free cashflow positive by year-end 2018 Assumes modest 1-3 rig additions per year Assumes 2017 WTI $50Bbl /NYMEX $2.75Mcf and 2018-2020 WTI $55Bbl /NYMEX $3.00 Mcf. Note: Prior years adjusted to remove Piceance 5
Operational Update Clay Gaspar
Continued Delineation of Vast Delaware Resource An abundant resource With near-term and long-term growth opportunity 11 Proven Productive Zones DELAWARE SANDS Thickness 4,000 Depth 5,500 Proven/Productive Bell, Cherry, Brushy Canyon AVALON Thickness 850 BONE SPRING Depth 7,500 Proven/Productive Upper & Lower Thickness 2,200 Depth 9,200 Proven/Productive Future Delineation 1 st & 2 nd Bone Spring 3 rd Bone Spring WOLFCAMP Thickness 2,000 Depth 11,000 PROVEN PRODUCTIVE PLANNED 2017 DELINEATION Proven/Productive Future Delineation X/Y, Upper & Lower A, D B, C 7
Delaware Basin: Delineation of the Wolfcamp D INITIAL RESULTS: WOLFCAMP D Completed first Wolfcamp D wells EAST PECOS-~4,200 lateral Frac design: 2,000+ #/ft 24-hour IP: 2,063 BOE/D (33% oil) Casing pressure: 3,800 psi LINDSAY-~4,400 lateral Frac design: 2,000+ #/ft 24-hour IP: 1,662 BOE/D (18% oil) Casing pressure: 4,400 psi OIL RATE (BOPD), GAS RATE (MMCFD), FCP (PSI) 1,000 100 East Pecos 22-14H 1 GAS RATE (MMCFD)- 5,931 FCP (PSI)- 3,800 OIL RATE (BOPD)- 676 0 30 60 90 120 150 Days Online Oil Gas Flowing Casing Pressure EDDY NEW MEXICO TEXAS LOVING Prospective Wolfcamp D WPX Acreage Current Wolfcamp D Wells LEA OIL RATE (BOPD), GAS RATE (MMCFD), FCP (PSI) 1,000 100 Lindsay 16-6H 1 GAS RATE (MMCFD)- 5,819 FCP (PSI)- 4,400 OIL RATE (BOPD)- 294 0 30 60 90 120 150 Days Online 1 Based on 2-stream production Oil Gas Flowing Casing Pressure 8
Delaware Basin: Exciting Future Catalysts TESTING WOLFCAMP A & X/Y CBR 22 spacing test Wolfcamp A Testing 330 spacing Upper/Lower WCA Primary target: Upper/Lower WCA Secondary target: WC X/Y WOLFCAMP D Purpose of spacing test WOLFCAMP X/Y UPPER WOLFCAMP A Validate U/L Wolfcamp A resource Determine future well spacing Understand future stimulation designs First X/Y well on newly acquired acreage 350 FT 660 330 LOWER WOLFCAMP A WOLFCAMP B 24-hour IP: 1,812 BOE/D (70% oil) 7,000 ~56% INCREASE IN AVG. LATERAL LENGTH 1 MILE Avg. Lateral Length (ft.) 6,000 5,000 4,000 3,000 2,000 1,000 CBR 22 TIMELINE 1ST COMPLETIONS 1ST SPUD LAST SPUD EXPECTED FLOWBACK 2016 SEPT OCT NOV DEC JAN FEB 2017 0 2015 2016 2017E DRILLING COMPLETIONS 9
Williston Basin: Strong, Consistent Results GETTING BACK TO WORK REMAINING COMPLETIONS Added 2 nd rig in October Set new drilling record of 11.9 days 1 Resumed completion of DUCS end of 3Q Current inventory of 13 DUCS On track to achieve vision by YE 2016 CHRONOLOGICAL ORDER Peterson Olive Mae Owl Comes Out Wells Helena Ruth Grant North Segment Caribou OLIVE MAE Producing: Early Oct PETERSON Producing: Mid-Sept NORTH SEGMENT Est. 1 st Sales: Mid-Dec OWL COMES OUT Producing: Mid-Oct 24-hr IP 2 Well BOPD MCFD WI 3 NRI WELLS Producing: Mid-Oct PETERSON 6-5-4HC 1,756 994 67.9% 50.9% PETERSON 6-5-4HQ 1,925 687 67.9% 50.9% PETERSON 6-5-4HZL 1,648 939 63.5% 47.6% OLIVE MAE 7-8-9HA 1,864 991 95.8% 71.8% PETERSON 6-5-4HD 1,957 974 67.9% 50.9% OWL COMES OUT 8-9HC 1,673 775 62.0% 46.5% WELLS 32-29HY 2,248 1,295 100.0% 78.9% WELLS 32-29HD 2,552 2,472 100.0% 78.9% WELLS 32-29HZ 2,506 1,907 100.0% 78.9% CARIBOU Est. 1 st Sales: Early Feb HELENA RUTH GRANT Est. 1 st Sales: Mid-Nov 1 Spud to rig release for a 2-mile lateral 2 Does not include NGLs 3 Includes current non-consent interest 10
San Juan Basin: Growing Catalyst with Year-over-Year Improvement CONTINUING TO RAISE THE BAR Driving better well performance Longer laterals 45 degree well azimuth Landing and steering Larger simulations (+1,000 lb/ft) Cum Production MBOE 250 200 150 100 50 YoY Improving Well Performance 1 ~140% INCREASE IN EUR SINCE 2013 ~65% INCREASE IN EUR SINCE 2015 Strong performance on 6-well pad 6-well pad peak rate: 8,571 BOE/D (70% oil) Average 60-day rate: 1,013 BOE/D per well Average lateral length: 7,250 ft. Average D&C cost: ~$4.1MM 0 140 120 0 30 60 90 120 150 180 210 240 270 300 330 360 Days of Production 2016 San Juan Gallup Wells Adding rig late December 2016 Focus on West Lybrook unit Cum Production MBOE 100 80 60 40 20 1 2013-2015 based on 1-mile laterals, 2016 based on average of 7,200 laterals 0 0 20 40 60 80 100 120 CURRENT 650 MBOE Days of Production 2016 GUIDANCE 465 MBOE 6-WELL PAD 2016 GALLUP WELLS 11
2017 Operational Guidance 2017 Activity Plan 2017 Capital Expenditures Basin Rigs Spuds/First Sales D&C Avg. Lateral Length Areas of Focus Delaware 5 70-80 $410-430 6,230+ WC XY, A, C, D Williston 2 38-42 $240-260 10,000+ MB, TF San Juan Gallup 1 40-46 $150-170 7,900+ West Lybrook Williston 30% San Juan 19% Delaware 51% 12,000 10,000 Increased Average Lateral Length Infrastructure 5% TOTAL D&C CAPITAL $800-$860 MM Avg. Lateral Length (ft.) 8,000 6,000 4,000 2,000 D&C 95% 0 2014 20151 20161 2017E Delaware San Juan Gallup Williston TOTAL CAPITAL EXPENDITURES $835-$905 MM 1 Includes 3-mile laterals drilled in Williston. 12
Financial Update Kevin Vann
3rd Dollars Quarter in millions, except and production YTD numbers Results 3Q YTD 2016 2015 2016 2015 Average Daily Production Oil (Mbbl/d) 38.9 33.9 40.4 32.7 Gas (MMcf/d) 205 184 199 175 NGLs (Mbbl/d) 11.4 8.0 9.7 5.8 Equivalent (MBOE/d) 84.4 72.5 83.2 67.6 Adjusted EBITDAX 115 195 340 575 Adjusted Net Income (Loss) from Continuing Operations (59) (10) (201) 64 Capital Expenditures/Activity 160 205 424 640 PRODUCTION LIQUIDS MIX OIL PRODUCTION 16% Y/Y 84.4 MBOE/D 60% OF TOTAL PRODUCTION 15% Y/Y 38.9 MBBL/D Note: Adjusted EBITDAX and adjusted net income are non-gaap measures. A reconciliation to relevant measures included in GAAP is provided in this presentation. 14
WPX Liquidity, Hedges and Debt Maturities Pro-Forma Liquidity Cash and Equivalents @ (9/30/16) $623 Undrawn Revolver 1,025 2017 Note Balance @ (9/30/16) (125) Pro Forma Liquidity $1,523 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 $3.02 $51.45 Oil 2017 1 Natural Gas 2017 Oil: 34,554 bbl/d Hedged $51.45 per barrel Gas: 170,000 mmbtu/d $3.02 per MMBtu 2018 Oil: 20,000 bbl/d Hedged 56.96 per barrel Gas: 60,000 mmbtu/d $2.93 per MMBtu Pro-Forma Debt Maturities $1,200 $MM $1,000 $800 $600 $400 $200 Expect $1.2B OF SALES PROCEEDS IN 1H OF 2016 $1,485 UNDRAWN $500 $1,100 $500 $500 $0 2016 2017 2018 2019 2020 2021 2022 2023 2024 Senior Notes Senior Notes Senior Notes Senior Notes 1 Based on midpoint of guidance. 15
2017 Full-Year Guidance Production FY17 Oil Mbbl/d 49.0-53.0 Natural Gas MMcf/d 210-220 NGL Mbbl/d 12.5 17.5 Total MBOE/d 97-107 Cap Ex ($ in Millions) FY17 Delaware $410-430 Williston 240-260 San Juan 150-170 Total D&C Capital 1 $800 - $860 Delaware Infrastructure 35-45 Total 2 $835 - $905 Avg. Price Differentials 3 FY17 Oil WTI per barrel ($6.00) - ($7.00) NYMEX Nat. Gas (Mcf) ($0.60) - ($0.80) Expenses FY17 $ per BOE LOE $4.75 - $5.25 GP&T 2.00 2.50 Production Tax 2.25 2.75 Cash Operating Expense $9.00 - $10.50 DD&A 20.00 21.00 $ in Millions G&A Cash $110 - $120 G&A Non Cash 30-40 Exploration 30-40 Interest Expense 185-195 OIL PRODUCTION 5 25% GROWTH SPUDS/FIRST SALES 70 80 DELAWARE 38 42 WILLISTON 40 46 SAN JUAN DELAWARE LATERALS 6 35%+ LONGER Net Realized Price 4 FY17 NGL % of WTI 23% - 28% Tax Rate FY17 Tax Provision 33% - 37% 1 Includes non-operated wells and wells which include additional science work. 2 Excludes any acquisition 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 Based on the mid-point of 2016 and high-end of 2017 oil guidance range 6 Based on the average lateral length drilled in the Delaware in 2016 versus the planned average for 2017. 7 Based on the mid-point of 2016 and 2017 guidance. Non-operating costs include G&A, Exploration, Marketing, and Interest Expense NON-OPERATING COSTS PER BOE 7 28% DECREASE 16
Foundation in Place for Enhancing and Accelerating Value POSITIONED PRUDENT WILLISTON BASIN FLEXIBLE SAN JUAN BASIN HEADQUARTERS: TULSA DELAWARE BASIN DISCIPLINED 17
Appendix
WPX Hedges Updated: October 31, 2016 Q4 2016 2017 2018 Volume/Day Average Price Volume/Day Average Price Volume/Day Average Price Crude Oil (bbl) Fixed Price Swaps¹ 30,403 $60.13 34,554 $51.45 20,000 $56.96 Crude Oil Basis (bbl) Midland Basis Swaps 5,000 ($0.45) - - Natural Gas (MMBtu) Fixed Price Swaps 1 145,510 $3.93 170,000 $3.02 60,000 $2.93 Natural Gas Basis (MMBtu) San Juan Basis Swaps 100,000 ($0.18) 102,500 ($0.18) Permian Basis Swaps 37,500 ($0.17) 67,500 ($0.20) 1 In connection with several natural gas and crude oil swaps, we entered into monthly call options, and swaptions with the swap counterparties granting the counterparty the right, but not the obligation, to enter into an underlying swap with us in the future. Crude oil calls for the balance of 2016 total 1,900 bbl/d at a weighted average strike price of $50.70. Natural gas calls and swaptions for 2017 total 16,301 MMBtu/d at a weighted average strike price of $4.50 and 65,000 MMBtu/d at a weighted average strike price of $4.19, respectively. Crude oil calls and swaptions for 2017 total 4,500 bbl/d at a weighted average strike price of $56.47 and 3,264 bbl/d at a weighted average strike price of $51.22, respectively. Natural gas calls and swaptions for 2018 total 16,301 MMBtu/d at a weighted average strike price of $4.75 and 20,000 MMBtu/d at a weighted average strike price of $3.33, respectively. Crude oil calls for 2018 total 13,000 bbl/d at a weighted average strike price of $58.89. 19
2016 Full-Year Guidance Production August 2016 November 2016 Oil Mbbl/d 39.0 41.0 40.0 42.0 Natural Gas MMcf/d 175-185 195 205 NGL Mbbl/d 9.0-10.0 9.5-10.5 Total MBOE/d 77-82 82-87 Cap Ex ($ in Millions) August 2016 November 2016 Delaware $195 215 $195 215 Williston 130 145 130 145 San Juan 75 85 75 85 Other 1 0 5 0 5 Total D&C Capital $400 - $450 $400 - $450 Delaware Midstream 10-20 10-20 Total Capital 2 $410 -$470 $410 -$470 Expenses August 2016 November 2016 $ per BOE LOE $5.25 - $5.75 $5.25 - $5.75 GP&T 2.25 2.75 2.25 2.75 Production Tax 1.75 2.25 1.75 2.25 Cash Operating Expense $9.25 - $10.75 $9.25 - $10.75 DD&A $20.50 $21.50 $20.50 $21.50 $ in Millions G&A 5 $165 - $185 $165 - $185 Marketing 6 25-40 25-40 Exploration 30-40 30-40 Interest Expense 190-200 190-200 Avg. Price Differentials 3 August 2016 November 2016 Oil WTI per barrel ($6.00) - ($7.00) ($6.00) - ($7.00) NYMEX Nat. Gas (Mcf) ($0.50) - ($0.60) ($0.50) - ($0.60) Tax Rate August 2016 November 2016 Tax Provision 33% - 37% 33% - 37% Net Realized Price 4 August 2016 November 2016 NGL % of WTI 23% - 28% 23% - 28% 1 Other includes expenditures for Other Basins, Land, Exploration and Corporate. 2 Excludes any acquisition 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 Excludes one-time charges for severance and relocation costs and includes stock compensation expenses of $25MM $30MM. 6 Excludes the $238MM divestment of the Piceance transportation obligation in July 2016. 20
Domestic Price Realization for 2016 Oil ($/bbl) Gas ($/Mcf) NGL ($/bbl) 1Q 16 2Q 16 3Q 16 4Q 16 1Q 16 2Q 16 3Q 16 4Q 16 1Q 16 2Q 16 3Q 16 4Q 16 Weighted-Average Sales Price $26.78 $39.81 $39.15 $1.77 $1.63 $2.44 $11.60 $15.02 $14.92 Revenue Adjustments 1 $(1.16) $(1.43) $(.44) $(.25) $(.40) $(.47) $(4.46) $(3.81) $(3.42) Net Price 2 $25.62 $38.38 $38.71 $1.52 $1.23 $1.97 $7.14 $11.21 $11.50 Realized Portion of Derivatives 3 $19.90 $11.05 $12.15 $3.41 $1.48 $.79 -- - Net Price Including Derivatives $45.52 $49.43 $50.86 $4.93 $2.71 $2.76 $7.14 $11.21 $11.50 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 $(1.34). 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 21
WPX s Opportunity in the Delaware Grows Significantly AUGUST 2015 TECHNICAL ADDITIONS ACQUIRED LOCATIONS TOTAL AUGUST 2016 Formation Gross Locations Gross Locations Gross Locations Gross Locations Assumed Spacing Delaware Vertical Bell Canyon Delaware Vertical Cherry Canyon 170 170 40 Delaware Vertical Brushy Canyon 750 630 1,380 20 Delaware Horizontal 100 5 105 160 Upper Avalon 330 75 405 107 Lower Avalon 220 185 405 107 1 st Bone Spring 530 10 540 160 2 nd Bone Spring 530 25 90 645 160 3 rd Bone Spring 220 220 160 Wolfcamp X/Y N/A 195 90 285 160 Upper Wolfcamp A 370 370 80 Lower Wolfcamp A N/A 315 315 91 Wolfcamp B Wolfcamp C 200 200 160 Wolfcamp D 200 180 90 470 107 Total 3,600+ 1,600+ 270+ 5,500+ 2.4+ BBOE net resource potential and 5,500+ gross locations Increased EURS Additional benches Tighter spacing Acquisition 22
Delaware WPX Crude Gathering System Benefits of crude gathering system Increase optionality to markets Significantly reduce truck traffic Decrease differentials Reduce operating costs EDDY Future Oil Gathering Pipeline Fresh Water Pipeline Gas Gathering Pipeline Produced Water Disposal WPX Leasehold LEA Decrease downtime Project details Access to multiple markets and local refineries NEW MEXICO TEXAS Multiple system storage locations Planning ~50 miles of crude pipeline Total system capacity ~100,000 Bpd Total Cost $30MM - $50MM Initial phase REEVES LOVING Planning and engineering underway Initial phase to introduce crude in 1Q-2017 5-10 miles of pipe Focused on eastern Stateline acreage 23
Delaware Overview 100,000+ net acres 1 5,500+ gross locations 2 Commodity mix 3 56% oil 28% natural gas 16% NGLs Available sales outlets Holley Frontier s Artesia, NM Refinery Western s El Paso Refinery Gulf Coast Cushing Midland 1 Includes ~1,000 acres in Midland Basin 2 Includes non-op and operated locations 3 Based on YTD Production 24
Williston Overview ~85,000 net acres 575+ gross locations ~510 operated locations ~70 non-op locations Commodity mix 1 83% oil 9% natural gas 8% NGLs Available sales outlets Clearbrook, Minn. (WTI) Guernsey, Wyo. (WTI) Local refining markets Rail to all coastal markets (Brent, LLS, WTI) N D Acreage/locations based on YE 2015 1 Based on YTD production 25
San Juan Overview ~226,000 net acres Oil window: ~96,000 acres 1 Gas window: ~130,000 acres ~3,900 total gross locations 2 Oil window: ~400 3 Gas window: ~3,500 2 Commodity mix 4 Oil window Oil: 46% NGLs: 23% Gas: 31% 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 Acreage/locations based on YE 2015 1 Acreage owned or controlled by WPX 2 Includes non-op and operated locations 3 Assumes 4,600' laterals 4 Based on YTD production 26
Non-GAAP
WPX Non-GAAP Disclaimer This presentation may include certain financial measures, including adjusted EBITDAX (earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses), that are non-gaap financial measures as defined under the rules of the Securities and Exchange Commission. This presentation is accompanied by a reconciliation of these non-gaap financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are widely accepted financial indicators used by investors to compare a company s performance. Management believes that these measures provide investors an enhanced perspective of the operating performance of the company and aid investor understanding. Management also believes that these non-gaap measures provide useful information regarding our ability to meet future debt service, capital expenditures and working capital requirements. These non-gaap financial measures should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles. 28
Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited) 2015 2016 (Dollars in millions, except per share amounts) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders $ 52 $ 23 $ (74) $ (14) $ (13) $ (5) $ (229) $ (244) $ (478) Income (loss) from continuing operations - diluted earnings per share $ 0.25 $ 0.11 $(0.29) $(0.06) $(0.06) $ (0.02) $ (0.76) $ (0.72) $ (1.58) Pre-tax adjustments: Impairments- exploratory related and inventory $ - $ - $ 47 $ 3 $ 50 $ - $ - $ 4 $ 4 Net (gain) loss on sales of assets and divestment of transportation contracts $ (69) $ (208) $ (2) $ (70) $ (349) $ (198) $ (4) $ 227 $ 25 Contract termination and early rig release expenses $ 26 $ - $ - $ 5 $ 31 $ - $ - $ - $ - Accrual for Denver office lease $ - $ - $ - $ - $ - $ - $ - $ 5 $ 5 Accrual for certain future gathering obligations associated with an abandoned area $ - $ - $ - $ 23 $ 23 $ - $ - $ - $ - Costs related to severance and relocation $ 8 $ 7 $ 1 $ (1) $ 15 $ 3 $ 7 $ 3 $ 13 Costs related to acquisition (including loss on acquired debt extinguishment) $ - $ 1 $ 103 $ 1 $ 105 $ - $ - $ - $ - Previously capitalized costs expensed following credit facility amendment $ - $ - $ - $ - $ - $ 4 $ - $ - $ 4 (Gain) loss on retirement of debt $ - $ - $ - $ - $ - $ (3) $ 3 $ - $ - Unrealized MTM (gain) loss $ 30 $ 203 $ (50) $ 16 $ 199 $ 76 $ 223 $ 20 $ 319 Total pre-tax adjustments $ (5) $ 3 $ 99 $ (23) $ 74 $ (118) $ 229 $ 259 $ 370 Less tax effect for above items $ 2 $ (1) $ (35) $ 7 $ (27) $ 43 $ (85) $ (96) $ (137) Impact of state deferred tax rate change $ - $ - $ - $ 7 $ 7 $ 14 $ - $ - $ 14 Impact of state tax valuation allowance $ - $ - $ - $ - $ - $ 8 $ - $ - $ 8 Loss on induced conversion of preferred stock $ - $ - $ - $ - $ - $ - $ - $ 22 $ 22 Total after-tax adjustments $ (3) $ 2 $ 64 $ (9) $ 54 $ (53) $ 144 $ 185 $ 277 Adjusted income (loss) from continuing operations available to common stockholders $ 49 $ 25 $ (10) $ (23) $ 41 $ (58) $ (85) $ (59) $ (201) Adjusted diluted earnings (loss) per common share $ 0.24 $ 0.12 $(0.04) $(0.08) $ 0.17 $ (0.21) $ (0.28) $ (0.17) $ (0.67) Diluted weighted-average shares (millions) 205.9 206.8 251.2 275.4 234.2 276.1 300.7 341.5 302.8 29
Reconciliation EBITDAX (Unaudited) 2015 2016 (Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD Adjusted EBITDAX Reconciliation to net income (loss): Net income (loss) $ 68 $ (30) $ (230) $ (1,534) $ (1,726) $ (12) $ (198) $ (219) $ (429) Interest expense 33 32 65 57 187 57 53 49 159 Provision (benefit) for income taxes 29 1 (27) 21 24 35 (130) (132) (227) Depreciation, depletion and amortization 117 123 136 152 528 152 163 150 465 Exploration expenses 7 6 56 16 85 9 12 10 31 EBITDAX 254 132 - (1,288) (902) 241 (100) (142) (1) Accrual for Denver office lease - - - - - - - 5 5 Accrual for certain future gathering obligations associated with an abandoned area - - - 23 23 - - - - Net (gain) loss on sales of assets and divestment of transportation contracts (69) (208) (2) (70) (349) (198) (4) 227 25 Impairment of inventory - - - - - - - 4 4 RKI acquisition costs and loss on extinguishment of acquired debt - 1 87-88 - - - - Net (gain) loss on derivatives (105) 71 (205) (179) (418) (57) 154 (38) 59 Net cash received (paid) related to settlement of derivatives 135 132 155 195 617 133 69 58 260 (Income) loss from discontinued operations (16) 53 160 1,525 1,722 12 (25) 1 (12) Adjusted EBITDAX $ 199 $ 181 $ 195 $ 206 $ 781 $ 131 $ 94 $ 115 $ 340 30
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. 31
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. 32