Rick Muncrief, Chairman and CEONov. 2, 2017

3Q 2017 Investor Update

Recent Highlights

Closed joint venture with Howard Energy Partners, $349MM in cash

Signed PSA Legacy San Juan Dry Gas, $169MM with closing by year-end

Raising 2017 oil growth guidance from 40% to 45% year-over-year

Increasing EURs in the Williston to 1,000 MBOE

67% increase unhedged margin per BOE past 12 months, $9.68 to $16.20

Current oil production averaging 75,000 BBL/D

2

$9.68 $9.39 $10.45

$16.20

$-

$2

$4

$6

$8

$10

$12

$14

$16

$18

4Q16 1Q17 2Q17 3Q17

3

WPX Executing on Strategy

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

3.9x

5.5x

4.3x

3.4x

0.0

1.0

2.0

3.0

4.0

5.0

6.0

$0

$100

$200

$300

$400

$500

$600

$700

$800

4Q16 1Q17 2Q17 3Q17ANNUALIZED ADJ. EBITDAX NET DEBT/ANNUALIZED ADJ. EBITDAX

ADJ.

EBIT

DAX

($M

M) N

ET DEBT/ADJ. EBITDAX

Deleveraging and Margin Expansion Progressing Rapidly

UNHEDGED DISCRETIONARY CASH FLOW($ PER BOE)

1

PER

BOE

ANNUALIZED ADJ. EBITDAX2

(NET DEBT / ANNUALIZED ADJ. EBITDAX)

WPX 2018 Guidance Highlights

4

TOTALCAPITAL

$1.1B - $1.2BOIL

GROWTH40% - 45%

FLAT RIG COUNT

~10 RIGSCOMMODITY

MIX~60% OIL

~80% LIQUIDS

CASH FLOW NEUTRAL

20181

NET DEBTTTM ADJ. EBITDAX

BELOW 2.5X4Q’18

1. Includes proceeds for non-core asset sales.

Free Cash Flow 2019 and BeyondLeverage Below 2.0x

Clay Gaspar, Chief Operating Officer

Operational Update

6

Delaware Basin

GROWING OIL VOLUMES 59% OIL GROWTH SINCE 3Q16

STRONG WELL PERFORMANCE 1.5 MILE LATERALS

• LINDSAY 10 15-15H30-DAY AVG: ~3,000 BOE (54% OIL)

• LINDSAY 10 15-16H30-DAY AVG: 3,128 BOE (53% OIL)

• LINDSAY 10 15-17H30-DAY AVG: 3,020 BOE (53% OIL)

• LINDSAY 10 15-18H30-DAY AVG: 2,902 BOE (56% OIL)

• LINDSAY 10 15-19H30-DAY AVG: 3,301 BOE (53% OIL)

4Q PLANNED ACTIVITY DROPPING A RIG & EXITING 2017

WITH 20-25 DUCS

CLOSED MIDSTREAM JV AGREEMENT RECEIVED $349MM FROM

HOWARD ENERGY PARTNERS

0

5

10

15

20

25

3Q16 4Q16 1Q17 2Q17 3Q17

MBB

L/D

2017

7

Delaware – Drilling More Lateral Feet in 2018

~515,000’ LATERAL FEET DRILLED IN 2017

~625,000’ LATERAL FEET TO BE DRILLED IN 2018

+20% MORE LATERAL FEET DRILLED WITH FLAT RIG COUNT

► Average lateral drilled 6,150’► ~7 rig average ► Landed in 8 different zones

► Average lateral ~7,500’► 6-7 rigs ► Primary target:

► Upper/Lower WCA

+20% MORE LATERAL

2018

2017

8

Delaware – Completing More Lateral Feet in 2018

~350,000’ LATERAL FEET COMPLETED IN 2017

~540,000’ LATERAL FEET TO BE COMPLETED IN 2018

+50% MORE LATERAL FEET COMPLETED WITH FLAT RIG COUNT

► 2 frac crews

► 3 frac crews

+50% MORE LATERAL

2018

9

Williston Basin

0

20

40

60

80

100

120

140

160

180

0 30 60 90 120 150 180

2016-2017 PERFORMANCEVS. 1,000 MBOE TYPE CURVE

0

10

20

30

40

50

60

70

80

0 30

2016 AVG. 2017 AVG.

NORTH SUNDAY ISLAND

GROWING OIL VOLUMES 81% OIL GROWTH SINCE 3Q16

RAISING THE TYPE CURVE MOVING TO 1,000 MBOE CURVE (81% OIL)

(BLENDED THREE FORKS AND MIDDLE BAKKEN)

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)

0

5

10

15

20

25

30

35

3Q16 4Q16 1Q17 2Q17 3Q17

DAYS ON PRODUCTION

DAYS ON PRODUCTION

CUM

MBO

E

CUM

MBO

E

MBB

L/D

0

20

40

60

80

100

120

0 10 20 30 40 50 60 70 80

CUM

MBO

E

DAYS ON PRODUCTION

10

San Juan Basin

WEST LYBROOK UNIT

RODEO UNITESCAVADA

UNITS

RODEO UNIT PERFORMANCENORMALIZED TO 7,500’

SIGNED PSA LEGACY SAN JUAN DRY GAS

0

2

4

6

8

10

12

3Q16 4Q16 1Q17 2Q17 3Q17

50% OIL GROWTH SINCE 3Q16GROWING OIL VOLUMES

STRONG WELL PERFORMANCE WELL RESULTS FROM RODEO UNIT:

30-DAY AVG. CUM PRODUCTION: 28 MBOE (71% OIL)

EXPECTED CLOSE BY YE 2017

4Q 2017 PLANNED ACTIVITY EXITING 2017 WITH 12 DUCS AND 0 RIGS

SAN

JUAN

CO

UN

TY

RIO ARRIBA COUNTY SANDOVAL COUNTY

MBB

L/D

UNITS FORMED FOR FUTURE DRILLING

Kevin Vann, Chief Financial Officer

Financial Update

3Q YTD2017 2016 2017 2016

Average Daily ProductionOil (Mbbl/d) 64.8 38.9 56.6 40.4Gas (MMcf/d) 204 205 201 199NGLs (Mbbl/d) 13.3 11.4 12.8 9.7Equivalent (MBOE/d) 112.0 84.4 102.8 83.2

Adjusted EBITDAX $188 $115 $455 $340

Adjusted Net Income (Loss) from Continuing Operations ($40) ($59) ($157) ($201)

Capital Expenditures $3151 $160 $911 $424

Dollars in millions, except production numbers3rd Quarter Results

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

13

WPX Financial Transformation UnderwayOIL

(MBBLS/D)UNHEDGED DISCRETIONARY

CASH FLOW($ PER BOE)

UNHEDGED ADJUSTED EBITDAX

($ IN MILLIONS)

DD&A ($ PER BOE)

G&A ($ PER BOE)

INTEREST EXPENSE($ PER BOE)

45%IN OIL VOLUMES

67%IN UNHEDGED

DISCRETIONARY CASH FLOW

39%IN G&A ($ PER BOE)

21%IN INTEREST EXP

($ PER BOE)

87%IN UNHEDGED

ADJUSTED EBITDAX

15%IN DD&A

($ PER BOE)

NOTE: Percentage change is based on the change from 4Q’16 to 3Q’17.

$9.68 $9.39 $10.45

$16.20

$-

$2

$4

$6

$8

$10

$12

$14

$16

$18

4Q16 1Q17 2Q17 3Q17

$93

$120 $138

$174

$-

$20

$40

$60

$80

$100

$120

$140

$160

$180

$200

4Q16 1Q17 2Q17 3Q17

44.7 46.1

58.664.8

0

10

20

30

40

50

60

70

4Q16 1Q17 2Q17 3Q17

$5.87 $5.75

$4.83 $4.61

$-

$1

$2

$3

$4

$5

$6

$7

4Q16 1Q17 2Q17 3Q17

$6.71

$5.27 $4.80

$4.09

$-

$1

$2

$3

$4

$5

$6

$7

$8

4Q16 1Q17 2Q17 3Q17

$19.27

$18.11 $17.78

$16.39

$15

$15

$16

$16

$17

$17

$18

$18

$19

$19

$20

4Q16 1Q17 2Q17 3Q17

Production FY 2018

Oil Mbbl/d 82.0 – 88.0Natural Gas MMcf/d 170 – 190NGL Mbbl/d 21.5 – 23.0Total MBOE/d 132 – 143

Expenses FY 2018

$ per BOELOE $5.25 – $5.75GP&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 – $2.60G&A – Non-Cash $0.65 – $0.75Exploration $1.45 – $1.55 Interest Expense $3.65 – $3.95

2018 Full-Year Guidance

Tax Rate FY 2018

Tax Provision5 33% – 37%

Net Realized Price4 FY 2018

NGL – % of WTI 38% – 42%

Cap Ex ($ in Millions) FY 2018

D&C Capital1 $1,040 – $1,110Midstream Capital 60 – 90Total2 $1,100 – $1,200

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

Avg. Price Differentials3 FY 2018

Oil – WTI per barrel ($5.00) – ($6.00)NYMEX – Nat. Gas (Mcf) ($1.00) – ($1.25)

14

COMMODITY MIX6

OIL PRODUCTION

2018 RIG COUNT

~60% OIL

~80% LIQUIDS

40-45% YOY

DELAWARE: 6-7 WILLISTON: 2-3SAN JUAN: 0-1

15

WPX Continued Focus on Shareholder Value Paying Off

MULTI-YEAR STRATEGY

AHEAD OF SCHEDULEEXECUTION

WILLISTON

SAN JUAN GALLUP

DELAWARE DISCIPLINEFOCUS

2018

RETURNS LEVERAGEMARGINS

HEADQUARTERSTULSA, OK

Appendix

Production FY 2017

Oil Mbbl/d 59.0 – 62.0Natural Gas MMcf/d 200 – 215NGL Mbbl/d 14.0 – 19.0Total MBOE/d 106 – 117

Expenses FY 2017

$ per BOELOE $5.25 – $5.75GP&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 – $3.25G&A – Non Cash $0.85 – $0.90Exploration7 $1.75 – $1.95 Interest Expense $4.50 – $4.90

Updated 2017 Full-Year Guidance (Includes Impact of San Juan Legacy Sale)

Tax Rate FY 2017

Tax Provision6 33% – 37%Net Realized Price5 FY 2017

NGL – % of WTI 38% – 42%

Cap Ex ($ in Millions)D&C Capital1 $940 – $1,010Delaware Infrastructure2 50 – 60Total3 $990 – $1,070

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 1st quarter.

Avg. Price Differentials4 FY 2017

Oil – WTI per barrel ($6.00) – ($7.00)NYMEX – Nat. Gas (Mcf) ($0.80) – ($1.00)

17

0%

20%

40%

60%

80%

100%

Oil Natural Gas

WPX Liquidity, Hedges and Debt Maturities

Cash and Equivalents @ (10/31/2017) $75

Revolver Capacity $1,125

Liquidity $1,200

Senior Debt Maturities

Senior Notes Senior Notes Senior NotesSenior Notes

$52.69

% o

f Pro

duct

ion

Hedg

ed1

$3.93

1 Based on midpoint of guidance

2018

STRONG HEDGE POSITION CREATES CERTAINTY FOR DRILLING PROGRAM

Oil: 22,000 bbl/d Hedged► $50.85 per barrel

Oil: 55,500 bbl/d Hedged► $52.69 per barrel

Gas: 140,000 mmbtu/d► $2.97 per MMBtu

2019

2018

Liquidity

Dollars listed in millions

STRONG LIQUIDITY

$2.97

18

$350

$1,100

$500 $650

$0

$200

$400

$600

$800

$1,000

$1,200

2017 2018 2019 2020 2021 2022 2023 2024

$ M

M

WPX Hedges Oct – Dec 2017 2018 2019

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

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.

Crude Oil (bbl)

Fixed Price Swaps1 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 Swaps2 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) - -

Updated: October 31, 2017

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 Adjustments1 $(1.07) $(1.14) $(0.90) $(0.50) $(0.52) $(0.54) $(1.29) $(0.70) $(0.74)

Net Price2 $45.31 $42.46 $43.34 $2.51 $2.13 $2.06 $20.85 $18.28 $23.57

Realized Portion of Derivatives3 $(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

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

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

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

23

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.

2016 2017

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

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

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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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