Operational UpdateWPX Operational Update | February 27, 2014 2 . Reserves Disclaimer The SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves,

Operational Update Jim Bender, Chief Executive Officer

February 27, 2014

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.

2 WPX Operational Update | February 27, 2014

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.


2013 Highlights

Piceance

► Ran 7 rigs in 2013 – Setting the stage for growth

► Delineation of Niobrara progressing

► 1st vertical test in the East (Rulison field), total depth of 13,797 feet with initial reservoir pressure of 13,800 psi

► 4th horizontal well peak rate of 6.4 MMcf/d from 1,000-foot lateral at 8,200 psi

► 2013 margin improvement of $41MM with renegotiated Willow Creek and Piceance gathering contracts

Williston

► 39% growth in oil production Y/Y

► WPX is #1 in cumulative Middle Bakken production per well¹

► Increased density drilling commenced in 4Q

► Van Hook throughput capacity grows to 7,500 bo/d

San Juan Gallup

► Drilled and operate 5 of the top 7 producing wells in the play

► Average 30-day IP of 388 barrels of oil in first 13 producing wells

► Added 13,000 net acres for a total of 44,000 net acres

¹Based on NDIC data for Middle Bakken longs put on 1st sales since January 2011.


WPX 2013 Domestic Reported Reserves

Reserve growth in 2013 ► Total domestic replacement rate for all products was 162% ► Exceeding 100 million barrels of proved domestic oil reserves ► Replaced domestic oil production at a rate of 547% ► Domestic F&D costs of $1.55 Mcfe or $9.29 boe:

► Gas properties all in F&D of $1.01/Mcf ► Oil properties all in F&D of $15.59/bbl

*Prices defined by SEC Rules

Chart numbers affected by rounding

4,051

4,051

4,584 4,584

4,491 439 534 -0.5

177

4,762

3,000

3,200

3,400

3,600

3,800

4,000

4,200

4,400

4,600

4,800

5,000

YE2012 RESERVES PRODUCTION EXTENSIONS DIVESTITURES REVISIONS YE2013 RESERVES

BC

Fe


Operational Update Bryan Guderian, Sr. VP of Operations

February 27, 2014

Piceance Highlights – Efficient Production Growth

2013 activity

► New WPX record: 36-well pad

► Spud 45 wells in 4Q

► Spud 210 wells in 2013

► Increased rig count to 7 mid-year

2014 Piceance outlook

► 6% growth in YE exit rate

► Running 9 rigs on average

► Drilling 285 wells

► Producing 17,300 NGL barrels per day

2014 Niobrara program

► Plan up to 10 Niobrara wells this year

► Continued delineation

► Parachute Valley field

► Ryan Gulch Highlands field test

► Repeatability and improving costs

► Testing well spacing and density

► Evaluating new horizons


Piceance Continuous Improvements

Continued improvement in Valley ► Maintained or decreasing drilling days

in the Valley drilling program

► State-of-the-art water management systems

► High-grading drilling locations

Efficiency gains in Ryan Gulch ► 55% decrease in drilling times in Ryan Gulch

from 2008 to 2013 ► Recent record well of 8.5 days to drill

► Reduced well costs by 20% in Ryan Gulch in 2013 ► 44% reduction in well costs since 2008

► Optimizing completion designs

► Improved water infrastructure

► Higher NGL and EURs compared to Valley

Lowest-cost operator in Piceance ► 34% less D&C capital costs1

► 57% less operating lifting costs2

1Utilizing data from eight 2012 Rulison field non-op wells 2Utilizing data from 215 Valley non-op wells – total well expense

1,389

2,800

1,276

2,357

1,246

2,157

0

500

1,000

1,500

2,000

2,500

3,000

Valley Ryan Gulch

Dri

llin

g &

Co

mp

leti

on

Co

st (

$M

)

2013 Plan 2013 Jan-Jun 2013 Jul-Dec

Total Well Cost 2013

0

5

10

15

20

25

30

Grand Valley Parachute Rulison Ryan Gulch

Day

s

2009 2010 2011 2012 2013

3.8 5.0

6.8 8.5

Record

Spud-to-Release Performance


Williston Continues Strong Production Growth

4th quarter ► Increased infill density drilling

commences ► Currently permitting 6 Middle

Bakken and 5 Three Forks wells

► Produced 15.1 Mbo/d in 4Q (17.0 Mboe/d)

► 7% production growth Q/Q

► 15 wells put on 1st sales ► 4 Middle Bakken

► 11 Three Forks

► Van Hook throughput capacity of 7,500 bo/d

2013 production growth ► Operated 4 rigs

► 33% increase in number of wells put on first sales compared to 2012

► 39% growth in oil Y/Y

2014 Williston outlook ► Operating 5 rigs

► 30% - 35% growth in daily production Y/Y

► 25% growth in spuds

OLSON 12-1HC FIRST SALES: 11/24/2013 30 Day IP: 1,062 BOPD

MARY R SMITH 5-8HX FIRST SALES: 12/19/2013 30 Day IP: 1,106 BOPD

ELK 16-21HW FIRST SALES: 10/30/2013 30 Day IP: 838 BOPD

STATE OF ND 10-3HW FIRST SALES: 10/19/2013 30 Day IP: 935 BOPD

OLSON 12-1HX FIRST SALES: 11/24/2013 30 Day IP: 943 BOPD

ADAM GOOD BEAR 15-22HX FIRST SALES: 10/19/2013 30 Day IP: 1,132 BOPD

ADAM GOOD BEAR 15-22HW FIRST SALES: 10/10/2013 30 Day IP: 1,105 BOPD

BRUNSELL 9-4HB FIRST SALES: 12/30/2013 30 Day IP: 1,200 BOPD

STATE OF ND 10-3HA FIRST SALES: 10/10/2013 30 Day IP: 912 BOPD

GOOD BIRD 36-25HX FIRST SALES: 11/11/2013 30 Day IP: 996 BOPD

GOOD BIRD 36-25HZ FIRST SALES: 10/26/2013 30 Day IP: 1,365 BOPD

GOOD BIRD 36-25HD FIRST SALES: 10/19/2013 30 Day IP: 1,140 BOPD

ELK 16-21HX FIRST SALES: 11/1/2013 30 Day IP: 838 BOPD

BRUNSELL 9-4HZ FIRST SALES: 12/31/2013 30 Day IP: 1,141 BOPD

MARY R SMITH 5-8HW FIRST SALES: 12/19/2013 30 Day IP: 1,614 BOPD


0

50,000

100,000

150,000

200,000

250,000

300,000

WPX is #1 in Middle Bakken Cumulative Production

Average 365-day cumulative production per well of 136.8 Mbo, 52% higher than the peer average

Average 730-day cumulative production per well of 240.8 Mbo, 66% higher than the peer average

Leader in completion design ► Started using cement liners

in May 2012

► Identified plug and perf as superior completion method in early 2012

► Reviewing new completion design: ► Increase number of frac stages

► Increase perforation clusters

► Reduce pumping rate

► Ceramic proppant (65/35) increases EUR

¹Based on NDIC data for Middle Bakken longs put on 1st sales since January 2011.

WPX acquired Williston properties December 2010.

Cumulative production as of 12/31/2013.

1-Yr and 2-Yr Cum. Oil Production (Based on productive days)

Peer 2-Yr Cumulative Production per Well

Peer 1-Yr Cumulative Production per Well

WPX 2-Yr Cumulative Production per Well

WPX 1-Yr Cumulative Production per Well

1-Yr and 2-Yr Cumulative Production per Well1 (Based on productive days)

Cu

mu

lati

ve O

il P

rod

uct

ion

Peer 2-Yr Avg Peer 1-Yr Avg


San Juan Gallup Transitioning to Pad Development

2013 activity

► WPX drilled and operates 5 of the 7 peak- performing wells in the Mancos Gallup

2014 outlook

► 275% Y/Y growth in daily oil production

► Spud 29 gross spuds (5 already spud)

► Average 1.8 rigs in basin

Multi-well pad development under way

► Pad development with both rigs

► Zipper fracs started in 1Q 2014

Drilling and completion cost improving

44,000 net acres in oil window

► 83.7% NRI

► Targeting additional acreage

Multi-Well Pad

WPX-Spud Horizontal Oil Wells

WPX-Completed Horizontal Oil Wells

WPX Acreage (Shallow/Deep Rights)-

CHACO 2308 16I #147H FIRST SALES: 4/26/2013 30 Day IP: 430 BOPD

CHACO 2408 32P #114H FIRST SALES: 3/18/2013 30 Day IP: 268 BOPD

CHACO 2307 12E #168H FIRST SALES: 7/19/2013 30 Day IP: 452 BOPD

CHACO 2206 02H #225H FIRST SALES: 8/22/2013 30 Day IP: 507 BOPD

CHACO 230 19M #191H FIRST SALES: 6/5/2013 30 Day IP: 559 BOPD

CHACO 2306 20 #208H FIRST SALES: 12/15/2013 30 Day IP: 505 BOPD





CHACO 2206 16A #221H FIRST SALES: 10/4/2013 30 Day IP: 206 BOPD




Financial Results Rod Sailor, Chief Financial Officer

4th Quarter Results

Dollars in millions, except production numbers

4Q 2013 2012

YTD 2013 2012

Daily Production

Gas (MMcf/d) 971 1,070 1,003 1,105

Oil (Mbbl/d) 24.2 19.4 21.8 18.0

NGLs (Mbbl/d) 20.1 25.0 20.8 28.9

Equivalent (MMcfe/d) 1,237 1,336 1,258 1,386

Adjusted EBITDAX $192 $256 $779 $1,000

Adjusted Net Income (Loss) from Continuing Operations $(66) $(39) $(244) $(123)

Capital Expenditures $311 $356 $1,154 $1,521

Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant measures included in GAAP is provided in this presentation.


Tax Rate 1Q FY 2014 Corporate Tax Rate 33% - 37% 33% - 37%

Production 1Q FY 2014 Natural Gas MMcf/d 952 - 962 960 - 969

Oil Mbbl/d 23.0 - 23.3 28.1 - 28.5

NGL Mbbl/d 19.0 - 19.2 19.6 - 19.9

Total MMcfe/d 1,204 - 1,217 1,246 - 1,259

Expenses 1Q FY 2014 $ per Mcfe

LOE $0.74 - $0.76 $0.73 - $0.75

DD&A 1.85 - 1.90 1.92 - 2.02

GP&T 0.97 - 1.01 0.93 - 0.98

SG&A 0.67 - 0.69 0.63 - 0.67

Production Tax 0.38 - 0.42 0.38 - 0.43

$ in Millions

Gas Management (Inc)/ Exp4 ($20) - ($25) $45 - $55

Exploration 25 - 30 70 - 80

Interest Expense 29 - 30 130 - 140

Equity (Earnings) Loss (4) - (6) (20) - (25)

% of Net Realized Price3 1Q FY 2014 Natural Gas - NYMEX 83% - 86% 81% - 87%

Oil - WTI 83% - 86% 84% - 87%

NGL - OPIS/ Mt Belvieu5 76% - 80% 76% - 80%

Number of Rigs 1Q FY 2014 Piceance Valley 6.0 6.6

Piceance Highlands 1.0 1.3

Piceance Niobrara 1.0 1.0

Total Piceance 7.0 9.0

Williston 4.0 4.9

San Juan Gallup 1.7 1.8

Total Rigs 12.7 15.7

Cap Ex ($ in Millions) 1Q FY 2014 Growth Basins

Piceance $100 - $110 $475 - $495

Williston 140 - 150 580 - 600

San Juan Gallup 35 - 40 155 - 180

Other

Appalachia 15 - 20 20 - 30

Other1 0 - 5 10 - 15

Land 10 - 20 75 - 85

Exploration 15 - 20 25 - 30

Total Domestic $315 - $365 $1,340 - $1,435

International2 20 - 30 80 - 90

Total Capital $335 - $395 $1,420 - $1,525

2014: 1st Quarter and Full-Year Guidance

1 Other includes expenditures for Powder River and Other basins. 2 International is a self-funded entity and does not receive any cash from WPX Energy. 3 Percentage of realized price ranges for NYMEX, WTI and OPIS exclude hedges, but

include basis differential and revenue adjustments. Assumes $4.00 NYMEX, $90.00 WTI and $41.59 composite barrel Mt. Belvieu.

4 Gas Management impact is net of revenues and expenses and includes unutilized transport capacity.

5 Assumed NGL composite barrel: Ethane 37%, Propane 28%, Isobutane 8%, Norm-Butane 7% and Natural Gasoline 20%.


Hedging Overview

1Details for natural gas basis swaps can be found in our most recent quarterly report.

²Details for crude oil basis swaps can be found in our most recent quarterly report. 3In connection with several natural gas swaps, we entered into 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. For 2014, we have 50k MMBtu/d capped at a monthly settlement price of $4.24 per MMBtu, and for 2015, we have 50k MMBtu/d capped at a settlement price of $4.38 per MMBtu.

As of 2/26/2014

2014 Volumes 2014 Price 2015 Volumes 2015 Price

Natural Gas1 (BBtu/d) ($MMBtu) (BBtu/d) ($MMBtu)

Fixed Price Swaps 1,3 323 $4.21 130 $4.38

Collars 184 $4.04 - $4.66 25 $4.00 - $4.50

Crude Oil (bbl/d) ($/bbl) (bbl/d) ($/bbl)

Fixed Price Swaps2 13,243 $94.82 - -

Natural Gas Liquids (bbl/d) ($/gallon) (bbl/d) ($/gallon)

Ethane Swaps 3,096 $0.29 - -

Propane Swaps 493 $1.19 - -

Iso Butane Swaps 548 $1.38 - -

Normal Butane Swaps 301 $1.38 - -

Natural Gasoline Swaps 1,438 $2.06 - -


Outlook for 2014

2014 highlights ► Average rig count of 15 - 16 rigs

► Production in growth basins up 6% year over year, offset by other basins declining 12%

Improved financial performance ► 85% of capital expenditures directed to highest-returning basins

► Williston, San Juan Gallup and Piceance

► EBITDAX growth of 35% - 40% using the 2014 forward prices at 2/21/2014

Domestic oil investments ► 40% of capital invested in Williston

► Increased rig count by 1; 5-rig program in 2014

► Daily production expected to grow 30% - 35%

► 11% of capital invested in San Juan Gallup ► Increased rig count by 1; 2-rig program in 2014

► Daily oil production expected to grow 250% - 275%

Natural gas/NGL investments ► 33% of capital invested in Piceance Basin

► Running a 9-rig program, which includes 1 rig dedicated to Niobrara

► Drilling up to 10 Niobrara delineation and science wells

► YE-exit rate expected to grow 6%

Continue to pursue asset sales and potential formation of MLP


Appendix

WPX Portfolio

Piceance

3,019 Bcfe Proved 11,878 Bcfe 3P 221,186 Net Acres

Williston

105 MMboe Proved 176 MMboe 3P 80,736 Net Acres

Powder River

245 Bcfe Proved 657 Bcfe 3P 360,002 Net Acres

Apco1

22 MMboe Proved 58 MMboe 3P 385,796 Net Acres

Total Domestic

4,905 Bcfe Proved 17,211 Bcfe 3P 1,554,635 Net Acres

Total2

San Juan

517 Bcfe Proved 1,645 Bcfe 3P 160,825 Net Acres

POWDER RIVER BASIN

PICEANCE BASIN

SAN JUAN BASIN

APPALACHIAN BASIN

WILLISTON BASIN

Natural Gas

Oil

Natural Gas & Natural Gas Liquids

Note: Acreage, Proved and 3P numbers are as of 12/31/13. 1 Reflects WPX’s 69% ownership in APCO, as well as additional acreage owned by WPX. 2 Total includes other reserves and acreage not depicted on slide.

ARGENTINA

Appalachia

328 Bcfe Proved 1,555 Bcfe 3P 87,994 Net Acres


Key Statistics by Basin

1 Piceance includes Niobrara acreage, which may be underlying existing leasehold acreage 2San Juan Legacy includes both shallow and deep rights 3Reflects WPX’s 69% ownership, except 3P drilling locations, which are gross.

Net Acreage (YE2013)

2014 Average

Rig Count (Op)¹

2013 Production (MMcfe/d)

Oil/NGL Focused

3P Gross Drilling

Locations

Proved Reserves (YE2013

Bcfe)

3P Reserves (YE2013

Bcfe)

Primary Areas of Focus

Piceance1 221,186 9 727 X 9,023 3,019 11,878

Williston 80,736 4.9 14.8 Mboe/d X 369 105.5 MMboe 176 MMboe

San Juan2 160,825 1.7 123 X 1,376 517 1,645

Appalachia 87,994 0 83 417 328 1,555

Total 550,741 15.6 1,022 11,185 4,497 16,133

Exploration

Exploration X

Other

Powder River 360,002 0 174 836 245 657

Apco3 385,796 0 9.0 Mboe/d X 664 22 MMboe 58 MMboe

Other 258,096 0 8.0 495 20 72

Chart numbers affected by rounding.


2012 - 13 Daily Production

2012 Avg 2013 Avg 1Q 2Q 3Q 4Q Total 1Q 2Q 3Q 4Q Total

Domestic Production

Gas (MMcf/d) 1,114 1,123 1,058 1,051 1,086 1,005 989 993 953 985

Oil (Mbbl/d) 10.4 12.3 11.7 13.6 12 13.8 15.1 17.1 18.9 16.2

NGLs (Mbbl/d) 30.2 30.5 28.4 24.5 28.4 21.2 20.8 19.7 19.7 20.3

MMcfe/d 1,357 1,380 1,298 1,279 1,328 1,215 1,205 1,214 1,184 1,204

International Production

Gas (MMcf/d) 19 19 20 19 19 17 18 19 19 18

Oil (Mbbl/d) 5.6 6.2 6.2 5.8 6 5.6 6.1 5.3 5.3 5.6

NGLs (Mbbl/d) 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.4 0.5

MMcfe/d 56 59 61 57 58 53 57 53 53 54

Total Production

Gas (MMcf/d) 1,133 1,142 1,078 1,070 1,105 1,021 1,007 1,012 971 1,003

Oil (Mbbl/d) 16 .0 18.5 17.9 19.4 18 19.4 21.2 22.4 24.2 21.8

NGLs (Mbbl/d) 30.7 31.0 28.9 25.0 28.9 21.7 21.3 20.1 20.1 20.8

MMcfe/d 1,413 1,439 1,359 1,336 1,386 1,268 1,262 1,267 1,237 1,258


Growing Higher-Margin Oil

77% oil CAGR since 2010

► Record oil production in 2013 ► Averaged 16.2 Mbo/d – a 35% increase Y/Y

► Discovered and developing San Juan Mancos Gallup

2014 growth in higher-margin oil

► 39% year-over-year domestic oil growth

► Williston up 30% - 35% Y/Y

► San Juan Gallup up 275% Y/Y

► Allocated 51% of total capital

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

2010Act 2011Act 2012Act 2013Act 2014Est

An

nu

al D

om

est

ic M

bb

l

Total Domestic Oil Growth 2010-14


Domestic Price Realization for 2013

Gas ($/Mcf) NGL ($/bbl) Oil ($/bbl)

1Q ’13 2Q ’13 3Q ’13 4Q’13 1Q ’13 2Q ’13 3Q ’13 4Q’13 1Q ’13 2Q ’13 3Q ’13 4Q’13

Weighted-Average Sales Price $3.12 $3.78 $3.16 $3.30 $37.27 $37.41 $43.10 $43.32 $89.23 $88.62 $99.43 $87.79

Revenue Adjustments1 (0.27) (0.33) (0.44) (.43) (9.06) (7.20) (11.91) (9.99) 0.54 (0.86) (1.52) (2.29)

Hedge Impact 0.05 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00

Net Price(2) $2.90 $3.45 $2.72 $2.87 $28.21 $30.21 $31.19 $33.33 $89.77 $87.76 $97.91 $85.50

Realized Portion of Derivatives Not Designated as Hedges(3) 0.01 (0.28) 0.04 0.01 0.00 0.00 0.09 0.23 4.03 3.75 (2.63) 1.71

Net Price Including All Derivatives

$2.91 $3.17 $2.76 $2.88 $28.21 $30.21 $31.28 $33.56 $93.80 $91.51 $95.28 $87.21

1Q ’13 2Q ’13 3Q ’13 4Q’13

Impact of Rockies Sale-for- Resale Contract exp. in Nov ’14

$(0.26) ($0.21) ($0.29) (0.30)

Weighted-Average Sales Price Excluding Rex

$3.17 $3.38 $3.05 $3.18

► 4Q – Rockies sale-for-resale agreement impacted net realized gas price ($0.30). Contract expires in November 2014.

1Natural 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 $(1.35).

2“Net Price” equals income statement product revenues by commodity, divided by volume.

3Represents the realized cash flows that occurred during each quarter, which are attributable to derivatives that were not designated as hedges for accounting purposes.


Impairment Summary of 2013

Income Statement Category

$ in Millions Basin Total

Impairment Expense

Exploration Expense

Other Investment Income

Appalachian Basin $1,109 $772 $317 $20

Piceance-Kokopelli $88 $88 - -

Powder River $192 $192 - -

Other $3 $3 - -

Total $1,392 $1,055 $317 $20


Piceance Basin

1Acreage and drilling locations are as of 12/31/13

Orange: Highlands Yellow: Valley Net acreage: 221,1861 Average rigs running in 2013: 6.6 Remaining 3P drilling locations: 9,0231

Composition: Gas/NGL focused


Niobrara Delineation to the East with Vertical Test

Valley delineation

► 50% delineated 2013

► Up to 10 wells planned for 2014

► Increases delineation to 80%

3D seismic coverage

► Finished shooting new seismic

► Existing 83% 3D seismic coverage of Ryan Gulch acreage

► Total 3D seismic coverage in 2014 will be 100,000 acres

2014 plan objectives

► Continued delineation

► Parachute Valley field

► Ryan Gulch Highlands field test

► Testing well spacing and density

► Evaluating new horizons

► Repeatability and improving costs

5

Valley Acreage and 3D Seismic Coverage

Producing

Producing

Discovery Well

New seismic: 30,700 acres

Existing seismic: 25,000 acres

Drilled

2013 Testing

Drilled wells

2014 1st Spud


Piceance Composite NGL Barrel and Realized Price (4th Quarter, 2013)

NGL Product Product

Mix $/Gal

Ethane1 39% .20

Propane 28% 1.18

Isobutane 8% 1.45

Normal Butane 7% 1.43

Natural Gasoline 17% 2.11

*Included in revenue as a deduction ** Total NGL sales revenue minus any associated cost, divided by total Piceance gas sales volumes. 1Lower ethane percentage as a component of the composite barrel was driven by reduced ethane recovery.

$41.66 Weighted Average

NGL $/barrel

**$0.61 per Mcf NGL Uplift in 4Q 2013

$33.85 Net Realized Price


Williston Basin


Net acreage: 80,7361 Average rigs running in 2013: 4.1 Remaining 3P drilling locations: 3691

Composition: Oil focused


Williston Basin – Ranked by F&D Cost (including WPX)

Area Assumed

F&D Cost1*

Avg. EUR (Mboe) 1

Southern Antelope $11.96 920

Sanish and Parshall $12.63 634

WPX Energy FBIR $15.09 729

Nesson Anticline $15.35 456

Fort Berthold $15.43 713

North Williams Co. $17.28 463

Lewis and Clark $17.77 394

Central Dunn Co. $18.00 500

East Nesson $18.22 494

West Williston $21.23 424

¹Data Source: Hart Energy and Investor Presentations (as of 8/1/2013) *Assumed F&D is equal to the publicly-stated well cost divided by EUR *Royalty percentage not factored into calculation

DIVIDE BURKE RENVILLE

WILLIAMS

MOUNTRAIL

WARD

MCLEAN

MERCER

MORTON STARK

GOLDEN VALLEY

MCKENZIE

DUNN BILLINGS


Williston Netback Price Analysis

Assumed 1Q 2014 total netback of WTI less $10 - $11 per barrel

Our current sales agreements consist of the following:

► Basin Sales: Arrow CDP WASP

► Rail: Receive Gulf, West and East Coast pricing

► Enbridge: Receive Enbridge Clearbrook, Minn., price

Our sales agreements in 2014-16 are expected to consist of the following:

► Basin sales: Receive a basket price from sales to third party marketers

► Rail: Receive Gulf, West and East Coast pricing less associated fees

► Enbridge: Receive Clearbrook, Minn., price less associated fees

► Unit train rail options: WPX will have up to 14,000 bbl/d of committed unit train capacity through the first quarter of 2014, decreasing to 9,250 bbl/d until mid-2016, receiving West, East or Gulf Coast pricing less associated fees

Sales Outlets Estimated Volume %

(Jan - Mar 2014)

Basin-Priced Sales 50%

Rail Deals 38%

Enbridge Capacity 12%

Total Sales Outlets 100%


San Juan Basin


Green: Deep/Shallow Yellow: Shallow Net Acreage: 160,8251 Average rigs running in 2013: 1 Remaining 3P drilling locations: 1,3761

Composition: Gas/Oil


Argentina Asset Map

Concession/Contract Basin

Noreste Basin

Nequen Basin

San Jorge Basin

Austral Basin

Entre Lomas: 23% WI, 40.7% Stock Interest

in Petrolera (Effective Interest – 52.8%)

Agua Amarga: 23% WI, 40.7% Stock Interest


Bajada del Palo: 23% WI, 40.7% Stock Interest


Coirón Amargo: 45% WI

Drill to earn farm-in

Sur Rio Deseado Este:

44% WI

Tierra del Fuego: 26% WI

Acambuco: 1.5% WI


Colombia Asset Map

Block Basin

Turpial Block 50% WI

100,000 acres

Llanos 40 Block 50% WI

163,000 acres

Llanos 32 Block 20% WI

111,000 acres

Llanos Orientales Basin

Valle Medio Del Magdalena Basin


Apco Highlights

Argentina

► 2013 Neuquén Basin development drilling program concluded with 28 wells spud

► Initiated 7-well Neuquén horizontal drilling program with encouraging early results

► Testing vertical Vaca Muerta well in Coiron Amargo

► $7.50/Mcf pricing available for incremental gas production for qualifying producers

► Initiated exploration drilling activities in each of our 3 areas (Llanos 40, Llanos 32 and Turpial)

► Maniceño field production has surpassed 1.1 MMbo

Neuquén Basin (Vaca Muerta acreage)

► Entre Lomas 96,000 net acres

► Bajada del Palo 59,000 net acres

► Agua Amarga 37,000 net acres

► Coiron Amargo 45,000 net acres

► Charco del Palenque 12,000 net acres

Total 249,000 net acres

Vaca Muerta Exposure

Colombia


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.


Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited)

2012 2013

(Dollars in millions, except per share amounts) 1Q 2Q 3Q 4Q Year 1Q 2Q 3Q 4Q YTD

Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders

$ (41) $ (33) $ (66) $ (105) $ (245) $ (116) $ 18 $ (114) $ (973) $(1,185)

Income (loss) from continuing operations – diluted earnings per share $(0.21) $(0.17) $(0.33) $(0.53) $(1.23) $ (0.58) $ 0.09 $(0.57) $(4.85) $ (5.91)

Pre-tax adjustments:

Impairment of producing properties, costs of acquired unproved reserves, leasehold and equity method investment1

$ 52 $ 65 $ - $ 108 $ 225 $ - $ - $ 19 $1,361 $1,380

Gain on sale of Powder River Basin deep rights leasehold $ - $ - $ - $ - $ - $ - $ - $ - $ (36) $ (36)

Accrual for litigation $ - $ - $ - $ - $ - $ - $ - $ 7 $ 1 $ 8

Costs related to chief executive officer separation $ - $ - $ - $ - $ - $ - $ - $ - $ 4 $ 4

Buyout of transportation agreement $ - $ - $ - $ - $ - $ - $ - $ - $ 9 $ 9

Unrealized MTM (gain) loss $ 1 $ (60) $ 31 $ (4) $ (32) $ 103 $ (98) $ 13 $ 89 $ 107

Total pre-tax adjustments $ 53 $ 5 $ 31 $ 104 $ 193 $ 103 $ (98) $ 39 $1,428 $1,472

Less tax effect for above items $ (19) $ (2) $ (12) $ (38) $ (71) $ (38) $ 36 $ (14) $ (521) $(537)

Impact of new Argentine capital tax law 1 $ - $ - $ - $ - $ - $ - $ - $ 6 $ - $ 6

Total adjustments, after-tax $ 34 $ 3 $ 19 $ 66 $ 122 $ 65 $ (62) $ 31 $ 907 $ 941

Adjusted income (loss) from continuing operations available to common stockholders

$ (7) $ (30) $ (47) $ (39) $ (123) $ (51) $ (44) $ (83) $ (66) $(244)

Adjusted diluted earnings (loss) per common share $(0.04) $(0.15) $(0.23) $(0.20) $(0.62) $ (0.25) $ (0.22) $(0.41) $(0.34) $(1.22)

Diluted weighted-average shares (millions) 198.1 198.9 199.1 199.2 198.8 199.9 203.8 200.7 200.9 200.4

1These items are presented net of amounts attributable to noncontrolling interest


Consolidated Statements of Operations and EBITDAX Reconciliations (Unaudited)

2012 2013

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

Revenues:

Product revenues:

Natural gas sales $ 357 $ 312 $ 331 $ 364 $1,364 $ 267 $ 316 $ 252 $ 258 $ 1,093

Oil and condensate sales 106 122 118 145 491 139 151 183 176 649

Natural gas liquid sales 93 78 65 63 299 54 58 57 61 230

Total product revenues 556 512 514 572 2,154 460 525 492 495 1,972

Gas management 337 187 186 239 949 261 205 176 249 891

Net gain (loss) on derivatives not designated as hedges 14 71 (22) 15 78 (94) 78 (15) (93) (124)

Other 3 5 (1) 1 8 4 7 5 6 22

Total revenues 910 775 677 827 3,189 631 815 658 657 2,761

Costs and expenses:

Lease and facility operating 67 67 68 81 283 75 73 82 78 308

Gathering, processing and transportation 135 120 124 127 506 107 111 106 109 433

Taxes other than income 30 25 23 33 111 35 36 36 34 141

Gas management, including charges for unutilized pipeline capacity 355 194 200 247 996 243 222 201 265 931

Exploration 19 19 22 23 83 19 20 21 371 431

Depreciation, depletion and amortization 228 248 243 247 966 231 227 241 241 940

Impairment of producing properties and costs of acquired unproved reserves 52 65 - 108 225 - - 19 1,036 1,055

Gain on sale of Powder River Basin deep rights leasehold - - - - - - - - (36) (36)

General and administrative 68 71 67 81 287 72 74 68 75 289

Other – net 5 (2) 5 4 12 7 1 10 (1) 17

Total costs and expenses 959 807 752 951 3,469 789 764 784 2,172 4,509

Operating income (loss) (49) (32) (75) (124) (280) (158) 51 (126) (1,515) (1,748)

Interest expense (26) (26) (25) (25) (102) (26) (28) (28) (26) (108)

Interest capitalized 2 3 2 1 8 1 1 2 1 5

Investment income, impairment of equity method investment and other 10 8 7 5 30 7 9 4 (15) 5

Income (loss) from continuing operations before income taxes $ (63) $ (47) $ (91) $ (143) $ (344) $ (176) $ 33 $ (148) $ (1,555) $ (1,846)

Provision (benefit) for income taxes (25) (18) (28) (40) (111) (63) 11 (32) (571) (655)

Income (loss) from continuing operations $ (38) $ (29) $ (63) $ (103) $ (233) $ (113) $ 22 $ (116) $ (984) $ (1,191)

Income (loss) from discontinued operations (2) 23 2 (1) 22 - - - - -

Net income (loss) $ (40) $ (6) $ (61) $ (104) $ (211) $ (113) $ 22 $ (116) $ (984) $ (1,191)

Less: Net income (loss) attributable to noncontrolling interests 3 4 3 2 12 3 4 (2) (11) (6)

Net income (loss) attributable to WPX Energy, Inc. $ (43) $ (10) $ (64) $ (106) $ (223) $ (116) $ 18 $ (114) $ (973) $ (1,185)

Adjusted EBITDAX

Reconciliation to net income (loss):

Net income (loss) $ (40) $ (6) $ (61) $ (104) $ (211) $ (113) $ 22 $ (116) $ (984) $ (1,191)

Interest expense 26 26 25 25 102 26 28 28 26 108

Provision (benefit) for income taxes (25) (18) (28) (40) (111) (63) 11 (32) (571) (655)


Exploration expenses 19 19 22 23 83 19 20 21 371 431

EBITDAX 208 269 201 151 829 100 308 142 (917) (367)

Impairment of producing properties, costs of acquired unproved reserves and equity investments 52 65 - 108 225 - - 19 1,056 1,075

(Gain) on sale of Powder River Basin deep rights leasehold - - - - - - - - (36) (36)

Net (gain) loss on derivatives not designated as hedges (14) (71) 22 (15) (78) 94 (78) 15 93 124

Net cash received (paid) related to settlement of derivatives not designated as hedges 15 11 9 11 46 9 (20) (2) (4) (17)

(Income) loss from discontinued operations 2 (23) (2) 1 (22) - - - - -

Adjusted EBITDAX $ 263 $ 251 $ 230 $ 256 $1,000 $ 203 $ 210 $ 174 $ 192 $ 779


Domestic Segment (Unaudited)

2012 2013

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

Revenues:

Product revenues:

Natural gas sales $ 353 $ 307 $ 327 $ 359 $ 1,346 $ 263 $ 310 $ 248 $ 253 $ 1,074


Natural gas liquid sales 92 77 65 62 296 53 58 57 60 228

Total product revenues 525 479 479 535 2,018 427 489 459 461 1,836

Gas management 337 187 186 239 949 261 205 176 249 891

Net gain (loss) on derivatives not designated as hedges 14 71 (22) 15 78 (94) 78 (15) (93) (124)

Other 3 4 (1) 1 7 1 1 3 1 6

Total revenues 879 741 642 790 3,052 595 773 623 618 2,609

Costs and expenses:


Gathering, processing and transportation 135 120 124 125 504 106 110 106 108 430


Gas management, including charges for unutilized pipeline capacity 355 194 200 247 996 243 222 201 265 931

Exploration 14 16 19 23 72 18 17 21 368 424


Impairment of producing properties and costs of acquired unproved reserves 52 65 - 108 225 - - 19 1,033 1,052

Gain on sale of Powder River Basin deep rights leasehold - - - - - - - - (36) (36)


Other – net 5 - 4 3 12 6 5 7 (1) 17

Total costs and expenses 934 783 724 918 3,359 762 733 756 2,136 4,387

Operating income (loss) (55) (42) (82) (128) (307) (167) 40 (133) (1,518) (1,778)

Interest expense (26) (26) (25) (25) (102) (26) (28) (28) (26) (108)

Interest capitalized 2 3 2 1 8 1 1 2 1 5

Investment income, impairment of equity method investment and other 2 - 1 - 3 2 2 - (20) (16)

Income (loss) from continuing operations before income taxes $ (77) $ (65) $ (104) $ (152) $ (398) $ (190) $ 15 $ (159) $ (1,563) $ (1,897)

Summary of Production Volumes

Natural gas (MMcf) 101,346 102,163 97,310 96,664 397,483 90,411 90,022 91,392 87,638 359,463

Oil (Mbbl) 948 1,123 1,076 1,247 4,394 1,242 1,373 1,575 1,738 5,928

Natural gas liquids (Mbbl) 2,746 2,779 2,613 2,254 10,392 1,907 1,895 1,811 1,808 7,421

Combined equivalent volumes (MMcfe)(1) 123,511 125,574 119,443 117,670 486,198 109,303 109,628 111,707 108,916 439,554

(1) Oil and natural gas liquids were converted to MMcfe using the ratio of one barrel of oil, condensate or natural gas liquids to six thousand cubic feet of natural gas.

Realized average price per unit, including the impact of hedges

Natural gas (per Mcf) $ 3.48 $ 3.01 $ 3.35 $ 3.71 $ 3.38 $ 2.90 $ 3.45 $ 2.72 $ 2.87 $ 2.99

Oil (per barrel) $ 84.54 $ 83.89 $82.31 $90.76 $ 85.58 $ 89.77 $ 87.76 $97.91 $85.50 $ 90.21

Natural gas liquids (per barrel) $ 33.46 $ 27.96 $24.43 $28.12 $ 28.56 $ 28.21 $ 30.21 $31.19 $33.33 $ 30.70

Expenses per Mcfe

Lease and facility operating $ 0.50 $ 0.47 $ 0.51 $ 0.60 $ 0.52 $ 0.61 $ 0.59 $ 0.65 $ 0.63 $ 0.62

Gathering, processing and transportation $ 1.09 $ 0.95 $ 1.04 $ 1.06 $ 1.04 $ 0.98 $ 1.00 $ 0.94 $ 1.00 $ 0.98

Taxes other than income $ 0.20 $ 0.15 $ 0.14 $ 0.23 $ 0.18 $ 0.27 $ 0.27 $ 0.27 $ 0.26 $ 0.27

Depreciation, depletion and amortization $ 1.80 $ 1.93 $ 1.98 $ 2.02 $ 1.93 $ 2.04 $ 1.98 $ 2.09 $ 2.13 $ 2.06

General and administrative $ 0.52 $ 0.54 $ 0.53 $ 0.65 $ 0.56 $ 0.62 $ 0.64 $ 0.58 $ 0.66 $ 0.62

Unutilized pipeline capacity

Total unutilized pipeline capacity in gas management expense $ 11 $ 12 $ 12 $ 11 $ 46 $ 13 $ 14 $ 17 $ 17 $ 61


International Segment (Unaudited)

2012 2013

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

Revenues:

Product revenues:

Natural gas sales $ 4 $ 5 $ 4 $ 5 $ 18 $ 4 $ 6 $ 4 $ 5 $ 19


Natural gas liquid sales 1 1 - 1 3 1 - - 1 2

Total product revenues 31 33 35 37 136 33 36 33 34 136

Gas management - - - - - - - - - -

Net gain (loss) on derivatives not designated as hedges - - - - - - - - - -

Other - 1 - - 1 3 6 2 5 16

Total revenues 31 34 35 37 137 36 42 35 39 152

Costs and expenses:


Gathering, processing and transportation - - - 2 2 1 1 - 1 3


Gas management, including charges for unutilized pipeline capacity - - - - - - - - - -

Exploration 5 3 3 - 11 1 3 - 3 7


Impairment of producing properties - - - - - - - - 3 3

Gain on sale of Powder River Basin deep rights - - - - - - - - - -


Other – net - (2) 1 1 - 1 (4) 3 - -

Total costs and expenses 25 24 28 33 110 27 31 28 36 122

Operating income (loss) 6 10 7 4 27 9 11 7 3 30

Interest expense - - - - - - - - - -

Interest capitalized - - - - - - - - - -

Investment income and other 8 8 6 5 27 5 7 4 5 21

Income (loss) from continuing operations before income taxes $ 14 $ 18 $ 13 $ 9 $ 54 $ 14 $ 18 $ 11 $ 8 $ 51

Summary of Net Production Volumes (1)

Natural gas (MMcf) 1,737 1,726 1,861 1,737 7,061 1,485 1,620 1,707 1,723 6,534

Oil (Mbbl) 507 562 573 536 2,178 506 553 484 489 2,032

Natural gas liquids (Mbbl) 45 44 45 47 181 42 44 42 40 167

Combined equivalent volumes (MMcfe)(2) 5,052 5,362 5,569 5,235 21,218 4,775 5,202 4,862 4,894 19,733

(1) Reflects approximately 69 percent of Apco's production, which corresponds to our ownership interest in Apco, and other minor directly held interests.

(2) Oil and natural gas liquids were converted to MMcfe using the ratio of one barrel of oil, condensate or natural gas liquids to six thousand cubic feet of natural gas.


Documents

Operational UpdateWPX Operational Update | February 27, 2014 2 . Reserves Disclaimer The SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves,