Rick Muncrief, Chairman & CEOFebruary 23, 2017

2016 Year-End Results

WPX 4Q Highlights

► Record oil production, up 15% vs. 3Q’16

► Delaware: Third Wolfcamp D and second X/Y delineation wells online

► Delaware: Oil started flowing on crude gathering system

► San Juan: 6-well West Lybrook pad surpassed 1 MMBOE in first 180 days (70% oil)

► Williston: Completed inventory of DUCs ahead of schedule

► 2017 notes paid off before maturity

► 317% reserve replacement in 2016

► Began midstream JV process for a portion of our Delaware assets

2

Expanding WPX’s World-Class Delaware Position

3

PANTHER ACQUISITION OVERVIEW► 18,000+ acres in core of Delaware

► 920 gross locations, including 150+ long lateral locations

► Significant current production of ~6,500 Boe/d (55% oil)

► Maintain Panther’s current 2 rig program

► Valuation primarily supported on 3 zones with upside in 5

additional zones

► Expected to close in late March

N E W M E X I C O

T E X A S

CULBERSON

LEA

EDDY

WARD

REEVES

LOVING

PECOS

WINKLER

WPX OPERATED ACREAGE

PANTHER ACREAGE

SELF-FUNDING DEVELOPMENT2 rig program funded with operating cashflows

DEEP INVENTORY OF CORE DELAWAREResource supports sustained growth

HIGH QUALITY ROCKMultiple stacked pay intervals with significant upside

ACCRETIVE TO CASHFLOWS AND NAVAccretive to shareholders 2017 and beyond

BENEFITS

Panther Acquisition Enhances Sustained Growth Outlook

ASSET QUALITY SUPPORTS RAPID GROWTH ASSET QUALITY SUPPORTS RAPID GROWTH

Assumes 2017 WTI $50Bbl /NYMEX $2.75Mcf and 2018-2020 WTI $55Bbl /NYMEX $3.00Mcf.

OIL

MBB

L/D

UPDATED PRO FORMA RANGE

► Free cash-flow positive by year-end 2018► Assumes modest 1-3 rig additions per year

► 30% oil growth in 2017► 55% oil growth in 2018

4

Panther Acquisition enhances growth strategy

0

20

40

60

80

100

120

140

160

2016 2017 2018 2019 2020$0

$500

$1,000

$1,500

$2,000

$2,500

2016 2017 2018 2019 2020

C A G R : 3 0 % - 4 0 % C A G R : 3 0 % - 4 0 %

MIL

LIO

NS

($)

PREVIOUS FORECAST UPDATED PRO FORMA RANGE PREVIOUS FORECAST

Clay Gaspar, Chief Operating Officer

Operational Update

6

Contracted Service Cost Mitigates Potential Inflation

Contracts in Place for 2017

Services Exposed to Spot Market

Note: D&C components based on latest blended AFE (Williston, San Juan, Delaware)

2017 D&C COST BREAKDOWN

of D&C costs are contracted through 2017

► Majority of services exposed to inflation are contracted

► Focused on securing services since 2Q 2016 to prepare

for activity ramp

► Some contracts go through 2018, others have options

to extend past 2017

► ~90% of D&C costs go through Supply Chain Mgmt.

• Sand• Stimulation Services• Drilling Rigs• Tubulars/Wellhead• Cementing Material and Services• Water

• Fluids/Cuttings/Solids Control• Directional Equipment & Services• Chemicals• Other (Completions)• Other (Drilling)

Delaware Basin: Delineation of the Wolfcamp

N E W M E X I C O

T E X A S

CULBERSON

LEA

EDDY

LOVING

WPX OPERATED ACREAGE

PANTHER ACREAGE

D

D

XY

XY

C-STATE 16-1HIP 30: 1,635 BOE/D (65% OIL)90 DAY CUM: 114,338 BOE

E. PECOS FED COM 22-14HIP 30: 1,736 BOE/D (30% OIL)90 DAY CUM: 139,336 BOE

DELINEATING WOLFCAMP ACROSS POSITION

► WOLFCAMP XY-PECOS STATE 46-6H► Lateral length: ~4,800 ft► Proppant (#/ft): ~1,750► Tracking in-line with WCA 1,000

MBOE type curve after 45 days

660’330’

WOLFCAMP B

LOWER WOLFCAMP A

UPPER WOLFCAMP A

WOLFCAMP X/Y

1 MILE

350

FT

CBR SPACING TEST UNDERWAY

► PURPOSE OF TEST► Validate 16 well U/L Wolfcamp A spacing► Understand future infrastructure needs

PECOS STATE 46-6HIP 30: 1,780 BOE/D (50% OIL)

D

LINDSAY 16-6HIP 30: 1,434 BOE/D (18% OIL)90 DAY CUM: 119,047 BOE

PECOS STATE 46-5HIP 30: 1,628 BOE/D (22% OIL)

REEVES

7

► Utilized diverter► Hybrid completion design► Engineered completions

► WOLFCAMP D-PECOS STATE 46-5H► Lateral length: ~4,850 ft► Proppant (#/ft): ~2,750► Currently producing with 3,800 psi

flowing tubing pressure (2-17)

► UPDATE ON CBR► Expected first sales end of March► 16 day record well spud-to-rig release► Encouraging DFIT results

► Utilized diverter► Hybrid completion design► Engineered completions

Note: Well production data is on a 3-stream basis

Williston Basin: Strong, Consistent Results

1 Spud-to-rig release for a 2-mile lateral2 Public data based on production from wells completed in 2016

Peers include AXA,BURLINGTON RESOURCES,EOG,ERF,HESS,LIBERTY RESOURCE,MRO,NFX,OAS,PETRO-HUNT,QEP,SM,STL,TPLM,WLL,XTO

► 39% oil growth 4Q’16 vs 3Q’16

► 4Q production 28.8 MBOE/d

► Set new drilling record of 11.7 days1

► Completed DUC inventory

► Current total well cost $5.5MM

► 14 wells on 1st sales during 4Q

► 6 Middle Bakken and 8 Three forks wells

8

-

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

WPX PEER 1 PEER 2 PEER 3 PEER 4 PEER 5 PEER 6 PEER 7 PEER 8 PEER 9

180 DAYS CUM OIL PRODUCTION FOR 2016 NEW WELLS2

-

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,00090 DAYS CUM OIL PRODUCTION FOR 2016 NEW WELLS2

WPX PEER 1 PEER 2 PEER 3 PEER 4 PEER 5 PEER 6 PEER 7 PEER 8 PEER 9

WILLISTON HIGHLIGHTS

#1 PRODUCERON CUMULATIVE OIL BASIS 90 DAYS/180 DAYS2

San Juan Basin: Continued Strong Well Results

12015 well performance based on 1 mile laterals, 2016 based on average of 7,200’ laterals

CONTINUING TO RAISE THE BAR

► 21% oil growth 4Q’16 vs 3Q’16

► Set new basin record

► Drilled 1.5 mile lateral in 5.8 days

► Strong performance on 6-well pad

► Cumulative 180-day production: +1.0 MMBOE

► Average day: ~1,000 BOE/D per well (70% oil)

► Average lateral length: 7,250 ft.

► Average D&C cost: ~$4.1MM

► Focused on West Lybrook in 2017

► New rig spud first well 12/31/20160

50

100

150

200

250

300

0 20 40 60 80 100 120 140 160 180 200Cu

m P

rodu

ctio

n M

BOE

Days of Production

6-WELLPAD

2016GALLUP WELLS

CURRENT650 MBOE65% IN EUR

SINCE 20151

2016 SAN JUAN GALLUP WELLS

INCREASE

9Note: Well production data is on a 3-stream basis

Kevin Vann, Chief Financial Officer

Financial Update

4Q Full-Year2016 2015 2016 2015

Average Daily ProductionOil (Mbbl/d) 44.7 38.6 41.5 34.2 Gas (MMcf/d) 200 202 199 181 NGLs (Mbbl/d) 10.7 9.0 10.0 6.6 Equivalent (MBOE/d) 88.7 81.1 84.6 71.0

Adjusted EBITDAX 135 206 475 781

Adjusted Net Income (Loss) from Continuing Operations (54) (23) (255) 41

Capital Expenditures/Activity 160 225 5841 865

Dollars in millions, except production numbers4th Quarter and Full-Year Results

1 Includes $84 million in land purchases and $27 million in Piceance activity that was reimbursed through the purchase price.Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant measures included in GAAP is provided in this presentation.

PRODUCTION

9% Y/Y88.7 MBOE/D

CAPEX

16% Y/Y44.7 MBBL/D

11

FULL-YEAR D&C CAPEX IN-LINE WITH GUIDANCE

OIL PRODUCTION

0%

20%

40%

60%

80%

100%

Oil Natural Gas

WPX Liquidity, Hedges and Debt Maturities

Cash and Equivalents @ (12/31/16) $496

Revolver Capacity $1,025

Letters of Credit <$66>

Liquidity $1,450

Debt Maturities

Senior Notes Senior Notes Senior NotesSenior Notes

Expect $1.2B OF

SALES PROCEEDS

IN 1H OF 2016

$1,485 UNDRAWN

$50.93

% o

f Pro

duct

ion

Hedg

ed $3.93

1 Based on midpoint of guidance.

20171

$500

$1,100

$500 $500

$0

$200

$400

$600

$800

$1,000

$1,200

2016 2017 2018 2019 2020 2021 2022 2023 2024

$MM

STRONG HEDGE POSITION CREATES CERTAINITY FOR DRILLING PROGRAM

Oil: 30,000 bbl/d Hedged► $54.61 per barrel

Gas: 155,000 mmbtu/d► $2.98 per MMBtu

Oil: 39,554 bbl/d Hedged► $50.93 per barrel

Gas: 170,000 mmbtu/d► $3.02 per MMBtu

2018

2017

Liquidity

Dollars listed in millions

STRONG LIQUIDITY

$3.02

12

Production FY17 Pro Forma

Oil Mbbl/d 49.0 – 53.0 52.0 – 56.0Natural Gas MMcf/d 210 – 220 220 – 230NGL Mbbl/d 12.5 – 17.5 14.0 – 19.0Total MBOE/d 97 – 107 103 – 113

Expenses FY17 Pro Forma

$ per BOELOE $4.75 – $5.25 $4.75 – $5.25GP&T 2.00 – 2.50 2.00 – 2.50

Production Tax 2.25 – 2.75 2.25 – 2.75

Cash Operating $9.00 – $10.50 $9.00 – $10.50

DD&A $20.00 – $21.00 $20.00 – $21.00

$ in MillionsG&A – Cash $110 – $120 $110 – $120G&A – Non Cash $30 – $40 $30 – $40Exploration $30 – $40 $30 – $40 Interest Expense $185 – $195 $185 – $195

2017 Pro Forma Full-Year Guidance

Tax Rate FY17 Pro Forma

Tax Provision6 33% – 37% 33% – 37%

Net Realized Price5 FY17 Pro Forma

NGL – % of WTI 23% – 28% 23% – 28%

Cap Ex ($ in Millions) FY17 Pro Forma

Delaware $410 – $430 $480 – $5101

Williston 240 – 260 240 – 260San Juan 150 – 170 150 – 170Total D&C Capital2 $800 – $860 $870 – $940Delaware Infrastructure 35 – 45 35 – 45Total3 $835 – $905 $905 – $985

1 Includes 15-20 first sales from Panther acquisition (April 1-December 31, 2017).2 Includes non-operated wells and wells which include additional science work.3 Excludes any acquisition 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.

Avg. Price Differentials4 FY17 Pro Forma

Oil – WTI per barrel ($6.00) – ($7.00) ($6.00) – ($7.00)NYMEX – Nat. Gas (Mcf) ($0.60) – ($0.80) ($0.60) – ($0.80)

13

Pro Forma assumes 9 month impact of Panther

Foundation in Place for Enhancing and Accelerating Value

► POSITIONED

► PRUDENT

► FLEXIBLE

► DISCIPL INED

WILLISTON BASIN

DELAWARE BASIN

SAN JUAN BASIN

HEADQUARTERS: TULSA

14

Appendix

WPX Hedges 2017 2018 2019

Volume/Day Average Price Volume/Day Average Price Volume/Day Average Price

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 2017 total 1,764 bbl/d at a weighted average strike price of $44.61. Natural Gas Swaptions for 2018 total 20,000 mmbtu/d at a weighted average strike price of $3.33.

Natural Gas (MMBtu)

Fixed Price Swaps1 170,000 $3.02 155,000 $2.98 - -

Fixed Price Calls 16,301 $4.50 16,301 $4.75 - -

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 - - 62,500 ($0.16) 80,000 ($0.19)

Crude Oil (bbl)

Fixed Price Swaps¹ 39,554 $50.93 30,000 $54.61 - -

Fixed Price Calls 4,500 $56.47 13,000 $58.89 - -

Crude Oil Basis (bbl)

Midland Basis Swaps 12,778 ($0.52) 13,000 ($0.94) 7,000 ($1.00)

Updated: February 22, 2017

16

17

Proved Reserves Reconciliation Chart

583

-40+110

+3

-295

+34 -49

346

0

100

200

300

400

500

600

700

YE2015 SEC Case Production Extensions &Discoveries

Acquistions Divestitures TechnicalRevisions

Price Revisions YE2016 SEC Case

MM

BOE

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 $42.93 $1.77 $1.63 $2.44 $2.69 $11.60 $15.02 $14.92 $20.05

Revenue Adjustments1 $(1.16) $(1.43) $(.44) $(.75) $(.25) $(.40) $(.47) $(.56) $(4.46) $(3.81) $(3.42) $(1.51)

Net Price2 $25.62 $38.38 $38.71 $42.18 $1.52 $1.23 $1.97 $2.13 $7.14 $11.21 $11.50 $18.54

Realized Portion of Derivatives3 $19.90 $11.05 $12.15 $7.32 $3.41 $1.48 $.79 $.65 – – -- -

Net Price Including Derivatives

$45.52 $49.43 $50.86 $49.50 $4.93 $2.71 $2.76 $2.78 $7.14 $11.21 $11.50 $18.54

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 $(1.49).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

Future Oil Gathering PipelineFresh Water PipelineGas Gathering PipelineProduced Water DisposalWPX Leasehold

Delaware – WPX Crude Gathering System

► Phase one underway► Initial oil flows began late 4Q 2016

► 5-10 miles of pipe► Focused on eastern Stateline acreage

► Project details► Access to multiple markets and local refineries► Multiple system storage locations► Planning ~50 miles of crude pipeline► Total system capacity ~100,000 Bpd► Total Cost $35MM - $45MM

► Benefits of crude gathering system► Increase optionality to markets► Significantly reduce truck traffic► Decrease differentials► Reduce operating costs► Decrease downtime

NEW MEXICOTEXAS

REEVESLOVING

LEA

EDDY

19

PHASE ONE

1 Includes acreage from recent acquisition2 Includes non-op and operated locations3 Based on FY2016 Production4 Includes 1st sales from Panther acquisition

► 120,000+ net acres1

► 6,420+ gross locations2

► Commodity mix3

► 54% oil► 30% natural gas► 16% NGLs

► Available sales outlets► Holley Frontier’s Artesia, NM Refinery ► Western’s El Paso Refinery ► Gulf Coast► Cushing► Midland

Delaware Overview

20

CULBERSON

LEA

EDDY

WARD

REEVES

LOVING

PECOS

WINKLER

CHAVES

26-31

3Q’17

2-4

1Q’17

25-29

2Q’17

32-36

4Q’17EXPECTED WELLS ON 1ST SALES4

WPX OPERATED (PRO FORMA) ACREAGE

NON-OP ACREAGE

N E W M E X I C O

T E X A S

Williston Basin

21

WILLIAMS

MOUNTRAIL

MCKENZIE

DUNN

MCLEAN

MERCER

► ~85,000 net acres

► ~570 gross locations► ~500 operated locations► ~70 non-op locations

► Commodity mix1

► 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)

1 Based on FY2016 production

DIVIDE BURKE

WPX OPERATED ACREAGE

NON-OP ACREAGE

10-12

3Q’17

11-13

1Q’17

10-12

2Q’17

8-10

4Q’17EXPECTED WELLS ON 1ST SALES

San Juan Basin

22

LA PLATA

RIO ARRIBA

SAN JUAN

ARCHULETA

C O L O R A D O

N E W M E X I C O

SANDOVAL

OIL WINDOW~105,000 acres~3352 locations

GAS WINDOW1

~130,000 acres~4,300 locations

► ~235,000 net acres► Oil window: ~105,000 acres► Gas window: ~130,000 acres1

► ~4,635 total gross locations1

► Oil window: ~3352

► Gas window: ~4,300

► Commodity mix3

► Oil window► Oil: 47%► NGLs: 22%► Gas: 31%

► Available sales outlets► Oil: Local refining markets or rail

(WTI, Brent, LLS)► Gas: Blanco Hub

1 Includes non-op and operated 2 Assumes average lateral length of 7,000' 3 Based on FY2016 production

► Gas window► Natural gas: 99%► NGLs: 1%

WPX OPERATED ACREAGE

NON-OP ACREAGE

12-14

3Q’17

0

1Q’17

10-12

2Q’17

10-12

4Q’17EXPECTED WELLS ON 1ST SALES

23

Consolidated Statement of Operations (GAAP)2015 2016

(Dollars in millions) 1Q 2Q 3Q 4Q YTD 1Q 2Q 3Q 4Q YTD

Revenues:Product revenues:

Oil sales $ 112 $ 138 $ 120 $ 124 $ 494 $ 97 $ 142 $ 139 $ 173 $ 551 Natural gas sales 41 26 37 34 138 25 24 37 39 125 Natural gas liquid sales 3 5 6 9 23 5 10 12 19 46

Total product revenues 156 169 163 167 655 127 176 188 231 722 Net gain (loss) on derivatives 105 (71) 205 179 418 57 (154) 38 (148) (207)Gas management 157 56 35 38 286 31 116 25 5 177 Other 2 - 4 1 7 1 - - - 1

Total revenues 420 154 407 385 1,366 216 138 251 88 693

Costs and expenses:Depreciation, depletion and amortization 117 123 136 152 528 152 163 150 158 623 Lease and facility operating 35 32 34 44 145 42 41 40 40 163 Gathering, processing and transportation 17 16 17 14 64 16 20 19 21 76 Taxes other than income 15 16 14 17 62 11 16 14 19 60 Exploration 7 6 56 16 85 9 12 10 11 42 General and administrative 54 53 45 58 210 53 55 51 55 214 Gas management, including charges for unutilized pipeline capacity 109 58 43 51 261 39 132 31 6 208 Net (gain) loss on sales of assets, divestment of transportation contracts and impairment of producing properties (69) (208) (2) (70) (349) (198) (4) 227 (3) 22 Acquisition costs - - 23 - 23 - - - - -Other-net 22 3 8 30 63 2 2 10 2 16

Total costs and expenses 307 99 374 312 1,092 126 437 552 309 1,424

Operating income (loss) 113 55 33 73 274 90 (299) (301) (221) (731)

Interest expense (33) (32) (65) (57) (187) (57) (53) (49) (48) (207)Gain (loss) on extinguishment of debt - - (65) - (65) 3 (3) - (1) (1)Investment income and other 1 1 - (4) (2) (1) 2 - 1 2

Income (loss) from continuing operations before income taxes $ 81 $ 24 $ (97) $ 12 $ 20 $ 35 $ (353) $ (350) $ (269) $ (937)Provision (benefit) for income taxes 29 1 (27) 21 24 35 (130) (132) (98) (325)Income (loss) from continuing operations $ 52 $ 23 $ (70) $ (9) $ (4) $ - $ (223) $ (218) $ (171) $ (612)Income (loss) from discontinued operations 16 (53) (160) (1,525) (1,722) (12) 25 (1) (1) 11 Net income (loss) $ 68 $ (30) $ (230) $ (1,534) $ (1,726) $ (12) $ (198) $ (219) $ (172) $ (601)

Less: Net income (loss) attributable to noncontrolling interests 1 - - - 1 - - - - -Net income (loss) attributable to WPX Energy, Inc. $ 67 $ (30) $ (230) $(1,525) $ (1,727) $ (12) $ (198) $ (219) $ (172) $ (601)

Less: Dividends on preferred stock - - 4 5 9 5 6 4 3 18 Less: Loss on induced conversion of preferred stck - - - - - - - 22 - 22

Net income (loss) attributable to WPX Energy, Inc. common stockholders $ 67 $ (30) $ (234) $(1,539) $ (1,736) $ (17) $ (204) $ (245) $ (175) $ (641)Amounts attributable to WPX Energy, Inc. common stockholders:

Income (loss) from continuing operations $ 52 $ 23 $ (74) $ (14) $ (13) $ (5) $ (229) $ (244) $ (174) $ (652)Income (loss) from discontinued operations 15 (53) (160) (1,525) (1,723) (12) 25 (1) (1) 11

Net income (loss) $ 67 $ (30) $ (234) $(1,539) $ (1,736) $ (17) $ (204) $ (245) $ (175) $ (641)

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 YTDIncome (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders $ 52 $ 23 $ (74) $ (14) $ (13) $ (5) $ (229) $ (244) $ (174) $ (652)

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) $ (0.51) $ (2.08)

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 $ (3) $ 22

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 $ 2 $ 15

Costs related to acquisition $ - $ 1 $ 38 $ 1 $ 40 $ - $ - $ - $ - $ -

Previously capitalized costs expensed following credit facility amendment $ - $ - $ - $ - $ - $ 4 $ - $ - $ - $ 4

(Gain) loss on retirement of debt $ - $ - $ 65 $ - $ 65 $ (3) $ 3 $ - $ 1 $ 1

Unrealized MTM (gain) loss $ 30 $ 203 $ (50) $ 16 $ 199 $ 76 $ 223 $ 20 $ 190 $ 509

Total pre-tax adjustments $ (5) $ 3 $ 99 $ (23) $ 74 $ (118) $ 229 $ 259 $ 190 $ 560

Less tax effect for above items $ 2 $ (1) $ (35) $ 7 $ (27) $ 43 $ (85) $ (96) $ (71) $ (208)

Impact of state deferred tax rate change $ - $ - $ - $ 7 $ 7 $ 14 $ - $ - $ 1 $ 15

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 $ 120 $ 397

Adjusted income (loss) from continuing operations available to common stockholders $ 49 $ 25 $ (10) $ (23) $ 41 $ (58) $ (85) $ (59) $ (54) $ (255)

Adjusted diluted earnings (loss) per common share $ 0.24 $ 0.12 $(0.04) $(0.08) $ 0.17 $ (0.21) $ (0.28) $ (0.17) $ (0.16) $ (0.82)

Diluted weighted-average shares (millions) 205.9 206.8 251.2 275.4 234.2 276.1 300.7 341.5 344.6 313.3

24

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) $ (172) $ (601)

Interest expense 33 32 65 57 187 57 53 49 48 207

Provision (benefit) for income taxes 29 1 (27) 21 24 35 (130) (132) (98) (325)

Depreciation, depletion and amortization 117 123 136 152 528 152 163 150 158 623

Exploration expenses 7 6 56 16 85 9 12 10 11 42

EBITDAX 254 132 - (1,288) (902) 241 (100) (142) (53) (54)

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, divestment of transportation contracts and impairment of producing properties (69) (208) (2) (70) (349) (198) (4) 227 (3) 22

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) 148 207

Net cash received (paid) related to settlement of derivatives 135 132 155 195 617 133 69 58 42 302

(Income) loss from discontinued operations (16) 53 160 1,525 1,722 12 (25) 1 1 (11)

Adjusted EBITDAX $ 199 $ 181 $ 195 $ 206 $ 781 $ 131 $ 94 $ 115 $ 135 $ 475

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DisclaimerThe 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 futureperformance and, accordingly, recipients are expressly cautioned not to put undue reliance on forward-looking statements or information due to the inherent uncertainty therein.

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Reserves DisclaimerThe 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.

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WPX Non-GAAP DisclaimerThis 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.

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