3Q 2016 Investor UpdateRick Muncrief, President and CEONovember 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

DELAWARE

56%

28%

GAS

OIL

STRONG OIL & GAS PORTFOLIOPROVIDES OPTIONALITY4

80%+DELAWARE (WCA)

WILLISTONSAN JUAN GALLUP

ROR

2

WELL ECONOMICSFlat $53.15 Oil and $3.03 Gas1

WILLISTON BASIN

DELAWARE BASIN

SAN JUANBASIN

1 3-year strip price as of October 26, 20162 Excludes G&A, acquisition land costs, and interest expense. Assumes vision for Delaware and Williston3 Assumes 1.4x cost and 1.7x EUR uplift of current 1-mile WCA well4 Based on YTD production

70%+

100%+DELAWARE LONG LATERALS3

HEADQUARTERSTULSA

NG

L16%

WILLISTON

83%

9%

GAS

OIL

NG

L8%

SAN JUAN GALLUP

46%

31%

GAS

NG

L23%

OIL

3

Executing on Long-Term Strategy

Increasing Activity Oil/EBITDAX CAGR 20%-35% through 2020 Funded with cash on-hand and CFFO

Financial FlexibilityStrong hedge book through 2018 Net debt to EBITDAX below 2.5x YE 2018

WILLISTONSAN JUAN

DELAWARE

Free cashflow positive by YE18 Avg. well payout period 18-24 months

Deep Inventory of High Returns

4

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

$1,800

2015 2016 2017 2018 2019 2020

Poised for Rapid Sustainable Growth

ASSET QUALITY SUPPORTS RAPID OIL GROWTH ASSET QUALITY SUPPORTS RAPID EBITDAX GROWTH

0

20

40

60

80

100

120

140

160

2014 2015 2016 2017 2018 2019 2020

Assumes 2017 WTI $50Bbl /NYMEX $2.75Mcf and 2018-2020 WTI $55Bbl /NYMEX $3.00 Mcf.Note: Prior years adjusted to remove Piceance

OIL

MBB

L/D

LOW CASEUPDATED FORECAST HIGH CASE

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

► 25% oil growth in 2017► 50% oil growth in 2018

LOW CASEUPDATED FORECAST HIGH CASE

CAGR: 35%HIGH CASE

CAGR: 20%LOW CASE

CAGR: 35%HIGH CASE

CAGR: 20%LOW CASE

5

FORECAST AT HIGH-END OF PREVIOUS RANGE FORECAST AT HIGH-END OF PREVIOUS RANGE

Forecast at High-End of Previous Range

Clay Gaspar

Operational Update

Continued Delineation of Vast Delaware Resource

An abundant resourceWith near-term and long-term growth opportunity

11Proven Productive Zones

PLANNED 2017 DELINEATION

PROVEN PRODUCTIVE

Thickness 2,200’

Depth 9,200’

Proven/Productive 1st & 2nd Bone Spring

Future Delineation 3rd Bone Spring

Thickness 4,000’

Depth 5,500’

Proven/Productive Bell, Cherry, Brushy Canyon

DELAWARE SANDS

Thickness 850’

Depth 7,500’

Proven/Productive Upper & Lower

Thickness 2,000’

Depth 11,000’

Proven/Productive X/Y, Upper & Lower A, D

Future Delineation B, C

AVALON

WOLFCAMP

BONE SPRING

7

100

1,000

0 30 60 90 120 150Days Online

100

1,000

0 30 60 90 120 150Days Online

Delaware Basin: Delineation of the Wolfcamp D

Lindsay 16-6H1

OIL

RAT

E (B

OPD

), G

AS R

ATE

(MM

CFD)

, FCP

(PSI

)

► Completed first Wolfcamp D wellsEAST 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

East Pecos 22-14H1

OIL

RAT

E (B

OPD

), G

AS R

ATE

(MM

CFD)

, FCP

(PSI

)

Oil Gas Flowing Casing Pressure

Oil Gas Flowing Casing Pressure

GAS RATE (MMCFD)- 5,931FCP (PSI)- 3,800

OIL RATE (BOPD)- 676

GAS RATE (MMCFD)- 5,819FCP (PSI)- 4,400

OIL RATE (BOPD)- 294

Prospective Wolfcamp D WPX Acreage Current Wolfcamp D Wells

INITIAL RESULTS: WOLFCAMP D

NEW MEXICO

TEXAS

EDDYLEA

LOVING

81 Based on 2-stream production

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2015 2016 2017E

Delaware Basin: Exciting Future Catalysts

WOLFCAMP D

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

► Purpose of spacing test

► Validate U/L Wolfcamp A resource ► Determine future well spacing► Understand future stimulation designs

► First X/Y well on newly acquired acreage

► 24-hour IP: 1,812 BOE/D (70% oil)

LAST SPUD1ST SPUD

1ST COMPLETIONS

2016 SEPT OCT NOV DEC JAN FEB 2017

EXPECTED FLOWBACK

CBR 22 TIMELINE

660’330’

WOLFCAMP B

LOWER WOLFCAMP

A

UPPER WOLFCAMP

A

WOLFCAMP X/Y

1 MILE

350

FT

~56%INCREASE IN AVG. LATERAL LENGTH

D R I L L I N G C O M P L E T I O N S

9

Avg.

Late

ral L

engt

h (ft

.)

Williston Basin: Strong, Consistent Results

1 Spud to rig release for a 2-mile lateral2 Does not include NGLs3 Includes current non-consent interest

GETTING BACK TO WORK

► Added 2nd rig in October

► Set new drilling record of 11.9 days1

► Resumed completion of DUCS end of 3Q

► Current inventory of 13 DUCS

► On track to achieve vision by YE 2016

REMAINING COMPLETIONS

24-hr IP2

Well BOPD MCFD WI3 NRI

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%

OLIVE MAEProducing: Early Oct

PETERSONProducing: Mid-Sept

OWL COMES OUTProducing: Mid-Oct

NORTH SEGMENTEst. 1st Sales: Mid-Dec

CARIBOUEst. 1st Sales: Early Feb

HELENA RUTH GRANTEst. 1st Sales: Mid-Nov

WELLSProducing: Mid-Oct

CHRONOLOGICAL ORDERPetersonOlive MaeOwl Comes OutWellsHelena Ruth GrantNorth SegmentCaribou

10

0

20

40

60

80

100

120

140

0 20 40 60 80 100 120

Cum

Pro

duct

ion

MBO

E

Days of Production

San Juan Basin: Growing Catalyst with Year-over-Year Improvement

12013-2015 based on 1-mile laterals, 2016 based on average of 7,200’ laterals

0

50

100

150

200

250

0 30 60 90 120 150 180 210 240 270 300 330 360

Cum

Pro

duct

ion

MBO

E

Days of Production

YoY Improving Well Performance1

2016 San Juan Gallup Wells

CONTINUING TO RAISE THE BAR

► Driving better well performance ► Longer laterals► 45 degree well azimuth► Landing and steering► Larger simulations (+1,000 lb/ft)

► 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

► Adding rig late December 2016► Focus on West Lybrook unit

CURRENT650 MBOE

6-WELLPAD

2016GALLUP WELLS

2016 GUIDANCE 465 MBOE

~65%INCREASE IN EUR SINCE 2015

~140%INCREASE IN EUR SINCE 2013

11

0

2,000

4,000

6,000

8,000

10,000

12,000

2014 2015 2016 2017E

Delaware San Juan Gallup Williston

2017 Operational Guidance

2017 Activity Plan

Increased Average Lateral Length

2017 Capital Expenditures

Delaware51%

San Juan19%

Williston30%

D&C95%

Infrastructure5%

TOTAL CAPITAL EXPENDITURES$835-$905 MM

Basin Rigs Spuds/First Sales D&C Avg. Lateral

LengthAreas 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

1 Includes 3-mile laterals drilled in Williston.

11

TOTAL D&C CAPITAL$800-$860 MM

12

Avg.

Late

ral L

engt

h (ft

.)

Kevin Vann

Financial Update

3Q YTD2016 2015 2016 2015

Average Daily ProductionOil (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

Dollars in millions, except production numbers3rd Quarter and YTD Results

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

16% Y/Y84.4 MBOE/D

LIQUIDS MIX

60% OF TOTAL PRODUCTION

OIL PRODUCTION

15% Y/Y38.9 MBBL/D

14

0%

20%

40%

60%

80%

100%

Oil Natural Gas

WPX Liquidity, Hedges and Debt Maturities

Cash and Equivalents @ (9/30/16) $623

Undrawn Revolver 1,025

2017 Note Balance @ (9/30/16) (125)

Pro Forma Liquidity $1,523

Pro-Forma Debt Maturities

Senior Notes Senior Notes Senior NotesSenior Notes

Expect $1.2B OF

SALES PROCEEDS

IN 1H OF 2016

$1,485 UNDRAWN

$51.45

% 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: 20,000 bbl/d Hedged► 56.96 per barrel

Gas: 60,000 mmbtu/d► $2.93 per MMBtu

Oil: 34,554 bbl/d Hedged► $51.45 per barrel

Gas: 170,000 mmbtu/d► $3.02 per MMBtu

2018

2017

Pro-Forma Liquidity

Dollars listed in millions

STRONG LIQUIDITY

$3.02

15

Production FY17

Oil Mbbl/d 49.0 - 53.0Natural Gas MMcf/d 210 - 220NGL Mbbl/d 12.5 – 17.5Total MBOE/d 97 - 107

Expenses FY17

$ per BOELOE $4.75 - $5.25GP&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 MillionsG&A – Cash $110 - $120G&A – Non Cash 30 -40Exploration 30 - 40 Interest Expense 185- 195

2017 Full-Year Guidance

Tax Rate FY17

Tax Provision 33% - 37%

Net Realized Price4 FY17

NGL – % of WTI 23% - 28%

Cap Ex ($ in Millions) FY17

Delaware $410 - 430Williston 240 - 260San Juan 150 - 170Total D&C Capital1 $800 - $860Delaware Infrastructure 35 - 45Total2 $835 - $905

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 range6 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

Avg. Price Differentials3 FY17

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

NON-OPERATINGCOSTS PER BOE7

OIL PRODUCTION5

25% GROWTH

DELAWARE LATERALS6

35%+ LONGER

SPUDS/FIRST SALES70 – 80 DELAWARE

38 – 42 WILLISTON

40 – 46 SAN JUAN

16

28% DECREASE

Foundation in Place for Enhancing and Accelerating Value

► POSITIONED

► PRUDENT

► FLEXIBLE

► DISCIPL INED

WILLISTON BASIN

DELAWARE BASIN

SAN JUAN BASIN

HEADQUARTERS: TULSA

17

Appendix

Q4 2016 2017 2018Volume/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 Swaps1 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)

WPX Hedges Updated: October 31, 2016

19

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.

2016 Full-Year Guidance

Production August 2016 November 2016

Oil Mbbl/d 39.0 – 41.0 40.0 – 42.0Natural Gas MMcf/d 175 - 185 195 – 205NGL Mbbl/d 9.0 - 10.0 9.5 - 10.5Total MBOE/d 77 - 82 82 - 87

Expenses August 2016 November 2016

$ per BOELOE $5.25 - $5.75 $5.25 - $5.75GP&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 MillionsG&A5 $165 - $185 $165 - $185Marketing6 25 - 40 25 - 40Exploration 30 - 40 30 - 40 Interest Expense 190- 200 190- 200

Avg. Price Differentials3 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 Price4 August 2016 November 2016

NGL – % of WTI 23% - 28% 23% - 28%

Cap Ex ($ in Millions) August 2016 November 2016

Delaware $195 – 215 $195 – 215Williston 130 – 145 130 – 145San Juan 75 – 85 75 – 85Other1 0 – 5 0 – 5Total D&C Capital $400 - $450 $400 - $450Delaware Midstream 10 - 20 10 - 20Total Capital 2 $410 -$470 $410 -$470

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 Adjustments1 $(1.16) $(1.43) $(.44) $(.25) $(.40) $(.47) $(4.46) $(3.81) $(3.42)

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

Realized Portion of Derivatives3 $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

Formation GrossLocations

GrossLocations

GrossLocations

GrossLocations 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 160Upper Avalon 330 75 405 107Lower Avalon 220 185 405 107

1st Bone Spring 530 10 540 1602nd Bone Spring 530 25 90 645 1603rd Bone Spring 220 220 160Wolfcamp X/Y N/A 195 90 285 160

Upper Wolfcamp A 370 370 80Lower Wolfcamp A N/A 315 315 91

Wolfcamp BWolfcamp C 200 200 160Wolfcamp D 200 180 90 470 107

Total 3,600+ 1,600+ 270+ 5,500+

AUGUST 2015ACQUIRED LOCATIONS TOTAL AUGUST 2016

► Increased EURS► Tighter spacing

2.4+ BBOE net resource potential and 5,500+ gross locations

TECHNICAL ADDITIONS

► Additional benches► Acquisition

22

Future Oil Gathering PipelineFresh Water PipelineGas Gathering PipelineProduced Water DisposalWPX Leasehold

Delaware – WPX Crude Gathering System

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

► 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 $30MM - $50MM

► Initial phase► Planning and engineering underway► Initial phase to introduce crude in 1Q-2017

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

NEW MEXICOTEXAS

REEVESLOVING

LEA

EDDY

23

1 Includes ~1,000 acres in Midland Basin2 Includes non-op and operated locations3 Based on YTD Production

► 100,000+ net acres1

► 5,500+ gross locations2

► Commodity mix3

► 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

Delaware Overview

24

Williston Overview

► ~85,000 net acres

► 575+ gross locations► ~510 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)

N D

Acreage/locations based on YE 20151 Based on YTD production 25

San Juan Overview► ~226,000 net acres

► Oil window: ~96,000 acres1

► Gas window: ~130,000 acres

► ~3,900 total gross locations2

► Oil window: ~4003

► Gas window: ~3,5002

► Commodity mix4

► Oil window► Oil: 46%► NGLs: 23%► Gas: 31%

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

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

(WTI, Brent, LLS)► Gas: Blanco Hub

DRY GAS

WET GAS

OIL

1 Acreage owned or controlled by WPX 2 Includes non-op and operated locations3 Assumes 4,600' laterals4 Based on YTD production

26

Acreage/locations based on YE 2015

Non-GAAP

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.

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

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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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