Operational Update
February 27, 2014
Operational Update Jim Bender, Chief Executive Officer
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.
WPX 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, 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.
WPX Operational Update | February 27, 2014
3
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 Operational Update | February 27, 2014
4
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 $15.59/bbl
5,000 4,800
177
4,600 4,400
4,491
439
534
-0.5
BCFe
4,200 4,000
3,800
4,584
4,584
4,762
DIVESTITURES
REVISIONS
YE2013 RESERVES
4,051
3,600
4,051
3,400 3,200 3,000
YE2012 RESERVES
*Prices defined by SEC Rules
PRODUCTION
EXTENSIONS
Chart numbers affected by rounding
WPX Operational Update | February 27, 2014
5
February 27, 2014
Operational Update Bryan Guderian, Sr. VP of Operations
Piceance Highlights – Efficient Production Growth 2013 activity ► ► ► ►
New WPX record: 36-well pad Spud 45 wells in 4Q Spud 210 wells in 2013 Increased rig count to 7 mid-year
2014 Piceance outlook ► ►
6% growth in YE exit rate Running 9 rigs on average ►
►
Drilling 285 wells
Producing 17,300 NGL barrels per day
2014 Niobrara program ► ►
Plan up to 10 Niobrara wells this year Continued delineation ► ►
► ► ►
Parachute Valley field Ryan Gulch Highlands field test
Repeatability and improving costs Testing well spacing and density Evaluating new horizons
WPX Operational Update | February 27, 2014
7
Piceance Continuous Improvements Continued improvement in Valley
► ►
Maintained or decreasing drilling days in the Valley drilling program State-of-the-art water management systems High-grading drilling locations
Efficiency gains in Ryan Gulch ►
55% decrease in drilling times in Ryan Gulch from 2008 to 2013 ►
►
► ►
3,000
2013 Plan
2013 Jan-Jun
2013 Jul-Dec
2,800 2,357
2,500
2,157
2,000 1,500
1,389 1,276 1,246
1,000 500 0 Valley
Reduced well costs by 20% in Ryan Gulch in 2013 ►
►
Recent record well of 8.5 days to drill
Total Well Cost 2013 Drilling & Completion Cost ($M)
►
Ryan Gulch
44% reduction in well costs since 2008
Optimizing completion designs Improved water infrastructure Higher NGL and EURs compared to Valley
Spud-to-Release Performance 30
2009
2010
2011
2012
2013
Record
25
Lowest-cost operator in Piceance ►
34% less D&C capital costs1 57% less operating lifting costs2
Days
►
20 15 10 5 0
1Utilizing
data from eight 2012 Rulison field non-op wells 2Utilizing data from 215 Valley non-op wells – total well expense
5.0
3.8 Grand Valley
Parachute
6.8
Rulison
8.5
Ryan Gulch
WPX Operational Update | February 27, 2014
8
Williston Continues Strong Production Growth 4th quarter ►
Increased infill density drilling commences ►
►
► ►
Produced 14.6 Mbo/d in 4Q (16.7 Mboe/d) 7% production growth Q/Q 15 wells put on 1st sales ► ►
►
Currently permitting 6 Middle Bakken and 5 Three Forks wells
4 Middle Bakken 11 Three Forks
Van Hook throughput capacity of 7,500 bo/d
MARY R SMITH 5-8HX FIRST SALES: 12/19/2013 30 Day IP: 1,106 BOPD BRUNSELL 9-4HZ FIRST SALES: 12/31/2013 30 Day IP: 1,141 BOPD
►
►
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 ► ►
►
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
OLSON 12-1HX FIRST SALES: 11/24/2013 30 Day IP: 943 BOPD
ELK 16-21HX FIRST SALES: 11/1/2013 30 Day IP: 838 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
2013 production growth ►
MARY R SMITH 5-8HW FIRST SALES: 12/19/2013 30 Day IP: 1,614 BOPD
OLSON 12-1HC FIRST SALES: 11/24/2013 30 Day IP: 1,062 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
Operating 5 rigs 30% - 35% growth in daily production Y/Y 25% growth in spuds
WPX Operational Update | February 27, 2014
9
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
1-Yr Cum.Production Oil Production 1-Yr andand 2-Yr 2-Yr Cumulative per Well1 (Based on productive days)
300,000
Average 730-day cumulative production per well of 240.8 Mbo, 66% higher than the peer average
►
►
►
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
Cumulative Oil Production
Leader in completion design
250,000
WPX 2-Yr Cumulative Production per Well
Peer 2-Yr Cumulative Production per Well
WPX 1-Yr Cumulative Production per Well
Peer 1-Yr Cumulative Production per Well
200,000
150,000
100,000
50,000
0
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.
Peer 2-Yr Avg
Peer 1-Yr Avg
WPX Operational Update | February 27, 2014
10
San Juan Gallup Transitioning to Pad Development 2013 activity ►
WPX drilled and operates 5 of the 7 peakperforming wells in the Mancos Gallup CHACO 2408 36P #143H FIRST SALES: 11/18/2013 30 Day IP: 322 BOPD CHACO 2307 12E #168H FIRST SALES: 7/19/2013 30 Day IP: 452 BOPD
2014 outlook ►
► ►
275% Y/Y growth in daily oil production Spud 29 gross spuds (5 already spud) Average 1.8 rigs in basin
CHACO 2408 32P #115H FIRST SALES: 11/26/2013 30 Day IP: 276 BOPD
CHACO 230 19M #191H FIRST SALES: 6/5/2013 30 Day IP: 559 BOPD
CHACO 2408 32P #114H FIRST SALES: 3/18/2013 30 Day IP: 268 BOPD
CHACO 2306 20 #208H FIRST SALES: 12/15/2013 30 Day IP: 505 BOPD
CHACO 2206 02H #225H FIRST SALES: 8/22/2013 30 Day IP: 507 BOPD
Multi-well pad development under way ► ►
Pad development with both rigs Zipper fracs started in 1Q 2014
CHACO 2308 16I #147H FIRST SALES: 4/26/2013 30 Day IP: 430 BOPD
CHACO 2307 13I #175H FIRST SALES: 10/25/2013 30 Day IP: 357 BOPD
Drilling and completion cost improving 44,000 net acres in oil window ► ►
83.7% NRI Targeting additional acreage
CHACO 2206 16A #221H FIRST SALES: 10/4/2013 30 Day IP: 206 BOPD
CHACO 2206 2P #227H FIRST SALES: 12/1/2013 30 Day IP: 514 BOPD
CHACO 2206 2P #228H FIRST SALES: 8/4/2013 30 Day IP: 512 BOPD CHACO 2206 16I #224H FIRST SALES: 10/10/2013 30 Day IP: 140 BOPD
Multi-Well Pad WPX-Spud Horizontal Oil Wells WPX-Completed Horizontal Oil Wells WPX Acreage (Shallow/Deep Rights)-
WPX Operational Update | February 27, 2014
11
Financial Results Rod Sailor, Chief Financial Officer
4th Quarter Results 4Q
YTD
2013
2012
2013
2012
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
Dollars in millions, except production numbers
Daily Production
Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant measures included in GAAP is provided in this presentation.
WPX Operational Update | February 27, 2014
13
2014: 1st Quarter and Full-Year Guidance Production
1Q
FY 2014
952 - 962 23.0 - 23.3 19.0 - 19.2 1,204 - 1,217
960 - 969 28.1 - 28.5 19.6 - 19.9 1,246 - 1,259
1Q
FY 2014
$100 - $110 140 - 150 35 - 40
$475 - $495 580 - 600 155 - 180
15 - 20 0-5 10 - 20 15 - 20 $315 - $365 20 - 30 $335 - $395
20 - 30 10 - 15 75 - 85 25 - 30 $1,340 - $1,435 80 - 90 $1,420 - $1,525
Number of Rigs
1Q
FY 2014
Piceance Valley Piceance Highlands Piceance Niobrara Total Piceance Williston San Juan Gallup Total Rigs
6.0 1.0 1.0 7.0 4.0 1.7 12.7
6.6 1.3 1.0 9.0 4.9 1.8 15.7
Natural Gas MMcf/d Oil Mbbl/d NGL Mbbl/d Total MMcfe/d
Cap Ex ($ in Millions) Growth Basins Piceance Williston San Juan Gallup Other Appalachia Other1 Land Exploration Total Domestic International2 Total Capital
% of Net Realized Price3 Natural Gas - NYMEX Oil - WTI NGL - OPIS/ Mt Belvieu5
Expenses $ per Mcfe LOE DD&A GP&T SG&A Production Tax $ in Millions Gas Management (Inc)/ Exp4 Exploration Interest Expense Equity (Earnings) Loss
Tax Rate Corporate Tax Rate
1Q
FY 2014
83% - 86% 83% - 86% 76% - 80%
81% - 87% 84% - 87% 76% - 80%
1Q
FY 2014
$0.74 - $0.76 1.85 - 1.90 0.97 - 1.01 0.67 - 0.69 0.38 - 0.42
$0.73 - $0.75 1.92 - 2.02 0.93 - 0.98 0.63 - 0.67 0.38 - 0.43
($20) - ($25) 25 - 30 29 - 30 (4) - (6)
$45 - $55 70 - 80 130 - 140 (20) - (25)
1Q
FY 2014
33% - 37%
33% - 37%
1 Other
includes expenditures for Powder River and Other basins. 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 $41.59 composite barrel Mt. Belvieu. 4 Gas Management impact is net of revenues and expenses and includes unutilized transport capacity. 5 Assumed NGL composite barrel: Ethane 37%, Propane 28%, Isobutane 8%, NormButane 7% and Natural Gasoline 20%. 2 International
WPX Operational Update | February 27, 2014
14
Hedging Overview
As of 2/26/2014
2014 Volumes
2014 Price
2015 Volumes
2015 Price
(BBtu/d)
($MMBtu)
(BBtu/d)
($MMBtu)
Fixed Price Swaps 1,3
323
$4.21
130
$4.38
Collars
184
$4.04 - $4.66
25
$4.00 - $4.50
(bbl/d)
($/bbl)
(bbl/d)
($/bbl)
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
-
-
1,438
$2.06
-
-
Natural Gas1
Crude Oil Fixed Price Swaps2
Natural Gasoline Swaps
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.
WPX Operational Update | February 27, 2014
15
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
WPX Operational Update | February 27, 2014
16
Appendix
WPX Portfolio Piceance
Williston
San Juan
Appalachia
Powder River
Apco1
3,019 Bcfe Proved 11,878 Bcfe 3P 221,186 Net Acres
105 MMboe Proved 176 MMboe 3P 80,736 Net Acres
517 Bcfe Proved 1,645 Bcfe 3P 160,825 Net Acres
328 Bcfe Proved 1,555 Bcfe 3P 87,994 Net Acres
245 Bcfe Proved 657 Bcfe 3P 360,002 Net Acres
22 MMboe Proved 58 MMboe 3P 385,796 Net Acres
Total 2Domestic
WILLISTON BASIN
4,905 Bcfe Proved 17,211 Bcfe 3P 1,554,635 Net Acres
POWDER RIVER BASIN PICEANCE BASIN
APPALACHIAN BASIN
SAN JUAN BASIN Natural Gas
ARGENTINA
Oil Natural Gas & Natural Gas Liquids Note: Acreage, Proved and 3P numbers are as of 12/31/13.
WPX’s 69% ownership in APCO, as well as additional acreage owned by WPX. includes other reserves and acreage not depicted on slide.
1 Reflects 2 Total
WPX Operational Update | February 27, 2014
18
Key Statistics by Basin 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)
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
836
245
657
664
22 MMboe
58 MMboe
495
20
72
Primary Areas of Focus
Exploration Exploration
X
Other Powder River
360,002
0
174
Apco3
385,796
0
9.0 Mboe/d
Other
258,096
0
8.0
X
1
Piceance includes Niobrara acreage, which may be underlying existing leasehold acreage Juan Legacy includes both shallow and deep rights 3Reflects WPX’s 69% ownership, except 3P drilling locations, which are gross. 2San
Chart numbers affected by rounding.
WPX Operational Update | February 27, 2014
19
2012 - 13 Daily Production 2012
Avg
2013
1Q
2Q
3Q
4Q
Total
1Q
2Q
3Q
4Q
Avg Total
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
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
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
Domestic Production
International Production
Total Production
WPX Operational Update | February 27, 2014
20
Growing Higher-Margin Oil 77% oil CAGR since 2010 ►
2014 growth in higher-margin oil
Record oil production in 2013
►
Averaged 16.2 Mbo/d – a 35% increase Y/Y Discovered and developing San Juan Mancos Gallup
► ►
► ► ►
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
Total Domestic Oil Growth 2010-14 9,000 8,000
Annual Domestic Mbbl
7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 2010Act
2011Act
2012Act
2013Act
2014Est
WPX Operational Update | February 27, 2014
21
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
$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-forResale Contract exp. in Nov ’14
$(0.26) ($0.21) ($0.29)
(0.30)
Weighted-Average Sales Price Excluding Rex
$3.17
$3.18
Net Price Including All Derivatives
$3.38
$3.05
►
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.
WPX Operational Update | February 27, 2014
22
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
WPX Operational Update | February 27, 2014
23
Piceance Basin Orange: Highlands Yellow: Valley 1 Net acreage: 221,186 Average rigs running in 2013: 6.6 Remaining 3P drilling locations: 9,0231 Composition: Gas/NGL focused
1Acreage
and drilling locations are as of 12/31/13
WPX Operational Update | February 27, 2014
24
Niobrara Delineation to the East with Vertical Test Valley Acreage and 3D Seismic Coverage
Valley delineation ► ►
►
2013 Testing
Producing
50% delineated 2013 Up to 10 wells planned for 2014 Increases delineation to 80%
3D seismic coverage Discovery Well
2014 1st Spud
5
► ►
►
Drilled
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 Producing ►
Continued delineation ► ►
New seismic: 30,700 acres Existing seismic: 25,000 acres
Drilled wells
► ► ►
Parachute Valley field Ryan Gulch Highlands field test
Testing well spacing and density Evaluating new horizons Repeatability and improving costs
WPX Operational Update | February 27, 2014
25
Piceance Composite NGL Barrel and Realized Price (4th Quarter, 2013)
$41.66 Product Mix
$/Gal
Ethane1
39%
.20
Propane
28%
1.18
Isobutane
8%
1.45
NGL Product
Weighted Average NGL $/barrel
$33.85
Net Realized Price
**$0.61 per Mcf NGL Uplift in 4Q 2013
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.
WPX Operational Update | February 27, 2014
26
Williston Basin Net acreage: 80,7361 Average rigs running in 2013: 4.1 Remaining 3P drilling locations: 3691 Composition: Oil focused
1Acreage
and drilling locations are as of 12/31/13
WPX Operational Update | February 27, 2014
27
Williston Basin – Ranked by F&D Cost (including WPX) DIVIDE
BURKE
RENVILLE
WILLIAMS
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
Area
MOUNTRAIL WARD
MCLEAN
MCKENZIE MERCER
BILLINGS GOLDEN VALLEY
DUNN
STARK
MORTON
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
WPX Operational Update | February 27, 2014
28
Williston Netback Price Analysis Sales Outlets
Estimated Volume % (Jan - Mar 2014)
Basin-Priced Sales
50%
Rail Deals
38%
Enbridge Capacity
12%
Total Sales Outlets
100%
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
WPX Operational Update | February 27, 2014
29
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 1Acreage
and drilling locations are as of 12/31/13
WPX Operational Update | February 27, 2014
30
Argentina Asset Map Acambuco: Noreste Basin
1.5% WI
Agua Amarga:
Entre Lomas: 23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%)
23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%)
Nequen Basin
Bajada del Palo:
Coirón Amargo: 45% WI Drill to earn farm-in
23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%) San Jorge Basin
Tierra del Fuego:
Sur Rio Deseado Este:
26% WI
Austral Basin
44% WI
Concession/Contract Basin
WPX Operational Update | February 27, 2014
31
Colombia Asset Map
Valle Medio Del Magdalena Basin
Turpial Block 50% WI 100,000 acres
Llanos 40 Block 50% WI 163,000 acres
Llanos Orientales Basin
Llanos 32 Block 20% WI 111,000 acres
Block Basin
WPX Operational Update | February 27, 2014
32
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
Vaca Muerta Exposure Neuquén Basin (Vaca Muerta acreage) ► ► ► ► ►
Entre Lomas Bajada del Palo Agua Amarga Coiron Amargo Charco del Palenque Total
96,000 net acres 59,000 net acres 37,000 net acres 45,000 net acres 12,000 net acres 249,000 net acres
Colombia ►
►
Initiated exploration drilling activities in each of our 3 areas (Llanos 40, Llanos 32 and Turpial) Maniceño field production has surpassed 1.1 MMbo
WPX Operational Update | February 27, 2014
33
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.
WPX Operational Update | February 27, 2014
35
Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited) 2012 (Dollars in millions, except per share amounts)
1Q
2Q
2013
3Q
4Q
Year
1Q
$ (105)
2Q
3Q
4Q
YTD
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders
$ (41) $ (33) $ (66)
$ (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)
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
$
31
$ 104
$ 193
$
103
$ (98)
$ 39
$1,428
$1,472
$ (38)
$ (71)
$
(38)
$
36
$ (14)
$ (521)
$(537)
-
$
-
$
-
$
$
$
$ 122
$
65
$ (62)
$ 31
$ 907
$ 941
$ (51)
$ (44)
$ (83)
$ (66)
$(244)
$ (0.25) $ (0.22)
$(0.41)
$(0.34)
$(1.22)
200.7
200.9
200.4
Pre-tax adjustments:
Total pre-tax adjustments
$ 53
$
Less tax effect for above items
$ (19)
$ (2)
$ (12)
Impact of new Argentine capital tax law 1
$
-
$
-
$
-
Total adjustments, after-tax
$ 34
$
3
$
19
Adjusted income (loss) from continuing operations available to common stockholders
$ (7)
$ (30)
Adjusted diluted earnings (loss) per common share Diluted weighted-average shares (millions) 1These
5
$ (47)
$
-
$ 66
$
$ (39) $ (123)
$(0.04) $(0.15) $(0.23) $(0.20) $(0.62) 198.1
198.9
199.1
199.2
198.8
199.9
203.8
6
-
6
items are presented net of amounts attributable to noncontrolling interest
WPX Operational Update | February 27, 2014
36
Consolidated Statements of Operations and EBITDAX Reconciliations (Unaudited) (Dollars in millions) Revenues: Product revenues: Natural gas sales Oil and condensate sales Natural gas liquid sales Total product revenues Gas management Net gain (loss) on derivatives not designated as hedges Other Total revenues Costs and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income Gas management, including charges for unutilized pipeline capacity Exploration Depreciation, depletion and amortization Impairment of producing properties and costs of acquired unproved reserves Gain on sale of Powder River Basin deep rights leasehold General and administrative Other – net Total costs and expenses Operating income (loss) Interest expense Interest capitalized Investment income, impairment of equity method investment and other Income (loss) from continuing operations before income taxes Provision (benefit) for income taxes Income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) Less: Net income (loss) attributable to noncontrolling interests Net income (loss) attributable to WPX Energy, Inc. Adjusted EBITDAX Reconciliation to net income (loss): Net income (loss) Interest expense Provision (benefit) for income taxes Depreciation, depletion and amortization Exploration expenses EBITDAX Impairment of producing properties, costs of acquired unproved reserves and equity investments (Gain) on sale of Powder River Basin deep rights leasehold Net (gain) loss on derivatives not designated as hedges Net cash received (paid) related to settlement of derivatives not designated as hedges (Income) loss from discontinued operations Adjusted EBITDAX
1Q
2012 3Q
2Q
4Q
Year
1Q
2013 3Q
2Q
$ 357 106 93 556 337 14 3 910
$ 312 122 78 512 187 71 5 775
$ 331 118 65 514 186 (22) (1) 677
$ 364 145 63 572 239 15 1 827
$1,364 491 299 2,154 949 78 8 3,189
$ 267 139 54 460 261 (94) 4 631
$ 316 151 58 525 205 78 7 815
$ 252 183 57 492 176 (15) 5 658
67 135 30 355 19 228 52 68 5 959 (49) (26) 2 10 (63) (25) (38) (2) (40) 3 (43)
67 120 25 194 19 248 65 71 (2) 807 (32) (26) 3 8 (47) (18) (29) 23 (6) 4 (10)
68 124 23 200 22 243 67 5 752 (75) (25) 2 7 (91) (28) (63) 2 (61) 3 (64)
81 127 33 247 23 247 108 81 4 951 (124) (25) 1 5 (143) (40) (103) (1) (104) 2 (106)
283 506 111 996 83 966 225 287 12 3,469 (280) (102) 8 30 (344) (111) (233) 22 (211) 12 (223)
75 107 35 243 19 231 72 7 789 (158) (26) 1 7 $ (176) (63) $ (113) $ (113) 3 $ (116)
73 111 36 222 20 227 74 1 764 51 (28) 1 9 33 11 22 22 4 18
$ (211) 102 (111) 966 83 829 225 (78) 46 (22) $1,000
$ (113) 26 (63) 231 19 100 94 9 $ 203
22 28 11 227 20 308 (78) (20) $ 210
$ $ $ $
$ (40) 26 (25) 228 19 208 52 (14) 15 2 $ 263
$ $ $ $
$
(6) 26 (18) 248 19 269 65 (71) 11 (23) $ 251
$ $ $ $
$ (61) 25 (28) 243 22 201 22 9 (2) $ 230
$ $ $ $
$ (104) 25 (40) 247 23 151 108 (15) 11 1 $ 256
$ $ $ $
$ $ $ $
$
4Q
$
YTD
258 176 61 495 249 (93) 6 657
$ 1,093 649 230 1,972 891 (124) 22 2,761
82 106 36 201 21 241 19 68 10 784 (126) (28) 2 4 $ (148) (32) $ (116) $ (116) (2) $ (114)
78 109 34 265 371 241 1,036 (36) 75 (1) 2,172 (1,515) (26) 1 (15) $ (1,555) (571) $ (984) $ (984) (11) $ (973)
308 433 141 931 431 940 1,055 (36) 289 17 4,509 (1,748) (108) 5 5 $ (1,846) (655) $ (1,191) $ (1,191) (6) $ (1,185)
$ (116) 28 (32) 241 21 142 19 15 (2) $ 174
$ (984) 26 (571) 241 371 (917) 1,056 (36) 93 (4) $ 192
$ (1,191) 108 (655) 940 431 (367) 1,075 (36) 124 (17) $ 779
WPX Operational Update | February 27, 2014
37
Domestic Segment (Unaudited) 2012 (Dollars in millions)
1Q
2Q
2013
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
Oil and condensate sales
$
80
95
87
114
376
111
121
154
148
534
Natural gas liquid sales
92
77
65
62
296
53
58
57
60
228
525
479
479
535
2,018
427
489
459
461
1,836
337
187
186
239
949
261
205
176
249
891
14
71
(22)
15
78
(94)
78
(15)
(93)
(124)
Total product revenues Gas management Net gain (loss) on derivatives not designated as hedges Other Total revenues
$
3
4
(1)
1
7
1
1
3
1
6
879
741
642
790
3,052
595
773
623
618
2,609
Costs and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income Gas management, including charges for unutilized pipeline capacity Exploration Depreciation, depletion and amortization Impairment of producing properties and costs of acquired unproved reserves Gain on sale of Powder River Basin deep rights leasehold
61
60
60
70
251
67
63
74
67
271
135
120
124
125
504
106
110
106
108
430
25
18
17
27
87
29
30
30
28
117
355
194
200
247
996
243
222
201
265
931
14
16
19
23
72
18
17
21
368
424
222
242
236
239
939
224
217
233
232
906
52
65
-
108
225
-
-
19
1,033
1,052
-
-
-
-
-
-
-
-
(36)
(36)
65
68
64
76
273
69
69
65
72
275
5
-
4
3
12
6
5
7
(1)
17
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)
(77)
$ (65)
$ (104)
$ (152)
$ (398)
$ (190)
15
$ (159)
$ (1,563)
$ (1,897)
101,346
102,163
97,310
96,664
397,483
90,411
90,022
91,392
87,638
359,463
948
1,123
1,076
1,247
4,394
1,242
1,373
1,575
1,738
5,928
2,746
2,779
2,613
2,254
10,392
1,907
1,895
1,811
1,808
7,421
123,511
125,574
119,443
117,670
486,198
109,303
109,628
111,707
108,916
439,554
General and administrative Other – net Total costs and expenses
Income (loss) from continuing operations before income taxes
$
$
Summary of Production Volumes Natural gas (MMcf) Oil (Mbbl) Natural gas liquids (Mbbl) Combined equivalent volumes (MMcfe)(1)
(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
$
2.90
$ 3.45
$ 2.72
$ 2.87
$
Oil (per barrel)
$ 84.54
$ 83.89
$82.31
$90.76
$ 85.58
3.38
$ 89.77
$
$ 87.76
$97.91
$85.50
$ 90.21
2.99
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
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
$
11
$
$
$
$
46
$
13
$
$
$
$
61
Expenses per Mcfe
Unutilized pipeline capacity Total unutilized pipeline capacity in gas management expense
12
12
11
14
17
17
WPX Operational Update | February 27, 2014
38
International Segment (Unaudited) (Dollars in millions) Revenues: Product revenues: Natural gas sales Oil and condensate sales Natural gas liquid sales Total product revenues Gas management Net gain (loss) on derivatives not designated as hedges Other Total revenues Costs and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income Gas management, including charges for unutilized pipeline capacity Exploration Depreciation, depletion and amortization Impairment of producing properties Gain on sale of Powder River Basin deep rights General and administrative Other – net Total costs and expenses
1Q
$
2012 3Q
2Q
4 26 1 31 31
$
5 27 1 33 1 34
$
4Q
4 31 35 35
$
YTD
5 31 1 37 37
$
1Q
18 115 3 136 1 137
$
2013 3Q
2Q
4 28 1 33 3 36
$
6 30 36 6 42
$
4Q
4 29 33 2 35
$
YTD
5 28 1 34 5 39
$
19 115 2 136 16 152
6 5 5 6 3 25
7 7 3 6 3 (2) 24
8 6 3 7 3 1 28
11 2 6 8 5 1 33
32 2 24 11 27 14 110
8 1 6 1 7 3 1 27
10 1 6 3 10 5 (4) 31
8 6 8 3 3 28
11 1 6 3 9 3 3 36
37 3 24 7 34 3 14 122
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
54
$ 14
Income (loss) from continuing operations before income taxes
$ 14
$
18
$
13
$
9
$
$
18
$
11
$
8
$
51
Summary of Net Production Volumes (1) Natural gas (MMcf) Oil (Mbbl) Natural gas liquids (Mbbl) Combined equivalent volumes (MMcfe)(2)
1,737
1,726
1,861
1,737
7,061
1,485
1,620
1,707
1,723
6,534
507
562
573
536
2,178
506
553
484
489
2,032
45
44
45
47
181
42
44
42
40
167
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.
WPX Operational Update | February 27, 2014
39
Operational Update Jim Bender, Chief Executive Officer
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.
WPX 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, 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.
WPX Operational Update | February 27, 2014
3
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 Operational Update | February 27, 2014
4
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 $15.59/bbl
5,000 4,800
177
4,600 4,400
4,491
439
534
-0.5
BCFe
4,200 4,000
3,800
4,584
4,584
4,762
DIVESTITURES
REVISIONS
YE2013 RESERVES
4,051
3,600
4,051
3,400 3,200 3,000
YE2012 RESERVES
*Prices defined by SEC Rules
PRODUCTION
EXTENSIONS
Chart numbers affected by rounding
WPX Operational Update | February 27, 2014
5
February 27, 2014
Operational Update Bryan Guderian, Sr. VP of Operations
Piceance Highlights – Efficient Production Growth 2013 activity ► ► ► ►
New WPX record: 36-well pad Spud 45 wells in 4Q Spud 210 wells in 2013 Increased rig count to 7 mid-year
2014 Piceance outlook ► ►
6% growth in YE exit rate Running 9 rigs on average ►
►
Drilling 285 wells
Producing 17,300 NGL barrels per day
2014 Niobrara program ► ►
Plan up to 10 Niobrara wells this year Continued delineation ► ►
► ► ►
Parachute Valley field Ryan Gulch Highlands field test
Repeatability and improving costs Testing well spacing and density Evaluating new horizons
WPX Operational Update | February 27, 2014
7
Piceance Continuous Improvements Continued improvement in Valley
► ►
Maintained or decreasing drilling days in the Valley drilling program State-of-the-art water management systems High-grading drilling locations
Efficiency gains in Ryan Gulch ►
55% decrease in drilling times in Ryan Gulch from 2008 to 2013 ►
►
► ►
3,000
2013 Plan
2013 Jan-Jun
2013 Jul-Dec
2,800 2,357
2,500
2,157
2,000 1,500
1,389 1,276 1,246
1,000 500 0 Valley
Reduced well costs by 20% in Ryan Gulch in 2013 ►
►
Recent record well of 8.5 days to drill
Total Well Cost 2013 Drilling & Completion Cost ($M)
►
Ryan Gulch
44% reduction in well costs since 2008
Optimizing completion designs Improved water infrastructure Higher NGL and EURs compared to Valley
Spud-to-Release Performance 30
2009
2010
2011
2012
2013
Record
25
Lowest-cost operator in Piceance ►
34% less D&C capital costs1 57% less operating lifting costs2
Days
►
20 15 10 5 0
1Utilizing
data from eight 2012 Rulison field non-op wells 2Utilizing data from 215 Valley non-op wells – total well expense
5.0
3.8 Grand Valley
Parachute
6.8
Rulison
8.5
Ryan Gulch
WPX Operational Update | February 27, 2014
8
Williston Continues Strong Production Growth 4th quarter ►
Increased infill density drilling commences ►
►
► ►
Produced 14.6 Mbo/d in 4Q (16.7 Mboe/d) 7% production growth Q/Q 15 wells put on 1st sales ► ►
►
Currently permitting 6 Middle Bakken and 5 Three Forks wells
4 Middle Bakken 11 Three Forks
Van Hook throughput capacity of 7,500 bo/d
MARY R SMITH 5-8HX FIRST SALES: 12/19/2013 30 Day IP: 1,106 BOPD BRUNSELL 9-4HZ FIRST SALES: 12/31/2013 30 Day IP: 1,141 BOPD
►
►
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 ► ►
►
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
OLSON 12-1HX FIRST SALES: 11/24/2013 30 Day IP: 943 BOPD
ELK 16-21HX FIRST SALES: 11/1/2013 30 Day IP: 838 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
2013 production growth ►
MARY R SMITH 5-8HW FIRST SALES: 12/19/2013 30 Day IP: 1,614 BOPD
OLSON 12-1HC FIRST SALES: 11/24/2013 30 Day IP: 1,062 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
Operating 5 rigs 30% - 35% growth in daily production Y/Y 25% growth in spuds
WPX Operational Update | February 27, 2014
9
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
1-Yr Cum.Production Oil Production 1-Yr andand 2-Yr 2-Yr Cumulative per Well1 (Based on productive days)
300,000
Average 730-day cumulative production per well of 240.8 Mbo, 66% higher than the peer average
►
►
►
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
Cumulative Oil Production
Leader in completion design
250,000
WPX 2-Yr Cumulative Production per Well
Peer 2-Yr Cumulative Production per Well
WPX 1-Yr Cumulative Production per Well
Peer 1-Yr Cumulative Production per Well
200,000
150,000
100,000
50,000
0
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.
Peer 2-Yr Avg
Peer 1-Yr Avg
WPX Operational Update | February 27, 2014
10
San Juan Gallup Transitioning to Pad Development 2013 activity ►
WPX drilled and operates 5 of the 7 peakperforming wells in the Mancos Gallup CHACO 2408 36P #143H FIRST SALES: 11/18/2013 30 Day IP: 322 BOPD CHACO 2307 12E #168H FIRST SALES: 7/19/2013 30 Day IP: 452 BOPD
2014 outlook ►
► ►
275% Y/Y growth in daily oil production Spud 29 gross spuds (5 already spud) Average 1.8 rigs in basin
CHACO 2408 32P #115H FIRST SALES: 11/26/2013 30 Day IP: 276 BOPD
CHACO 230 19M #191H FIRST SALES: 6/5/2013 30 Day IP: 559 BOPD
CHACO 2408 32P #114H FIRST SALES: 3/18/2013 30 Day IP: 268 BOPD
CHACO 2306 20 #208H FIRST SALES: 12/15/2013 30 Day IP: 505 BOPD
CHACO 2206 02H #225H FIRST SALES: 8/22/2013 30 Day IP: 507 BOPD
Multi-well pad development under way ► ►
Pad development with both rigs Zipper fracs started in 1Q 2014
CHACO 2308 16I #147H FIRST SALES: 4/26/2013 30 Day IP: 430 BOPD
CHACO 2307 13I #175H FIRST SALES: 10/25/2013 30 Day IP: 357 BOPD
Drilling and completion cost improving 44,000 net acres in oil window ► ►
83.7% NRI Targeting additional acreage
CHACO 2206 16A #221H FIRST SALES: 10/4/2013 30 Day IP: 206 BOPD
CHACO 2206 2P #227H FIRST SALES: 12/1/2013 30 Day IP: 514 BOPD
CHACO 2206 2P #228H FIRST SALES: 8/4/2013 30 Day IP: 512 BOPD CHACO 2206 16I #224H FIRST SALES: 10/10/2013 30 Day IP: 140 BOPD
Multi-Well Pad WPX-Spud Horizontal Oil Wells WPX-Completed Horizontal Oil Wells WPX Acreage (Shallow/Deep Rights)-
WPX Operational Update | February 27, 2014
11
Financial Results Rod Sailor, Chief Financial Officer
4th Quarter Results 4Q
YTD
2013
2012
2013
2012
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
Dollars in millions, except production numbers
Daily Production
Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant measures included in GAAP is provided in this presentation.
WPX Operational Update | February 27, 2014
13
2014: 1st Quarter and Full-Year Guidance Production
1Q
FY 2014
952 - 962 23.0 - 23.3 19.0 - 19.2 1,204 - 1,217
960 - 969 28.1 - 28.5 19.6 - 19.9 1,246 - 1,259
1Q
FY 2014
$100 - $110 140 - 150 35 - 40
$475 - $495 580 - 600 155 - 180
15 - 20 0-5 10 - 20 15 - 20 $315 - $365 20 - 30 $335 - $395
20 - 30 10 - 15 75 - 85 25 - 30 $1,340 - $1,435 80 - 90 $1,420 - $1,525
Number of Rigs
1Q
FY 2014
Piceance Valley Piceance Highlands Piceance Niobrara Total Piceance Williston San Juan Gallup Total Rigs
6.0 1.0 1.0 7.0 4.0 1.7 12.7
6.6 1.3 1.0 9.0 4.9 1.8 15.7
Natural Gas MMcf/d Oil Mbbl/d NGL Mbbl/d Total MMcfe/d
Cap Ex ($ in Millions) Growth Basins Piceance Williston San Juan Gallup Other Appalachia Other1 Land Exploration Total Domestic International2 Total Capital
% of Net Realized Price3 Natural Gas - NYMEX Oil - WTI NGL - OPIS/ Mt Belvieu5
Expenses $ per Mcfe LOE DD&A GP&T SG&A Production Tax $ in Millions Gas Management (Inc)/ Exp4 Exploration Interest Expense Equity (Earnings) Loss
Tax Rate Corporate Tax Rate
1Q
FY 2014
83% - 86% 83% - 86% 76% - 80%
81% - 87% 84% - 87% 76% - 80%
1Q
FY 2014
$0.74 - $0.76 1.85 - 1.90 0.97 - 1.01 0.67 - 0.69 0.38 - 0.42
$0.73 - $0.75 1.92 - 2.02 0.93 - 0.98 0.63 - 0.67 0.38 - 0.43
($20) - ($25) 25 - 30 29 - 30 (4) - (6)
$45 - $55 70 - 80 130 - 140 (20) - (25)
1Q
FY 2014
33% - 37%
33% - 37%
1 Other
includes expenditures for Powder River and Other basins. 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 $41.59 composite barrel Mt. Belvieu. 4 Gas Management impact is net of revenues and expenses and includes unutilized transport capacity. 5 Assumed NGL composite barrel: Ethane 37%, Propane 28%, Isobutane 8%, NormButane 7% and Natural Gasoline 20%. 2 International
WPX Operational Update | February 27, 2014
14
Hedging Overview
As of 2/26/2014
2014 Volumes
2014 Price
2015 Volumes
2015 Price
(BBtu/d)
($MMBtu)
(BBtu/d)
($MMBtu)
Fixed Price Swaps 1,3
323
$4.21
130
$4.38
Collars
184
$4.04 - $4.66
25
$4.00 - $4.50
(bbl/d)
($/bbl)
(bbl/d)
($/bbl)
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
-
-
1,438
$2.06
-
-
Natural Gas1
Crude Oil Fixed Price Swaps2
Natural Gasoline Swaps
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.
WPX Operational Update | February 27, 2014
15
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
WPX Operational Update | February 27, 2014
16
Appendix
WPX Portfolio Piceance
Williston
San Juan
Appalachia
Powder River
Apco1
3,019 Bcfe Proved 11,878 Bcfe 3P 221,186 Net Acres
105 MMboe Proved 176 MMboe 3P 80,736 Net Acres
517 Bcfe Proved 1,645 Bcfe 3P 160,825 Net Acres
328 Bcfe Proved 1,555 Bcfe 3P 87,994 Net Acres
245 Bcfe Proved 657 Bcfe 3P 360,002 Net Acres
22 MMboe Proved 58 MMboe 3P 385,796 Net Acres
Total 2Domestic
WILLISTON BASIN
4,905 Bcfe Proved 17,211 Bcfe 3P 1,554,635 Net Acres
POWDER RIVER BASIN PICEANCE BASIN
APPALACHIAN BASIN
SAN JUAN BASIN Natural Gas
ARGENTINA
Oil Natural Gas & Natural Gas Liquids Note: Acreage, Proved and 3P numbers are as of 12/31/13.
WPX’s 69% ownership in APCO, as well as additional acreage owned by WPX. includes other reserves and acreage not depicted on slide.
1 Reflects 2 Total
WPX Operational Update | February 27, 2014
18
Key Statistics by Basin 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)
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
836
245
657
664
22 MMboe
58 MMboe
495
20
72
Primary Areas of Focus
Exploration Exploration
X
Other Powder River
360,002
0
174
Apco3
385,796
0
9.0 Mboe/d
Other
258,096
0
8.0
X
1
Piceance includes Niobrara acreage, which may be underlying existing leasehold acreage Juan Legacy includes both shallow and deep rights 3Reflects WPX’s 69% ownership, except 3P drilling locations, which are gross. 2San
Chart numbers affected by rounding.
WPX Operational Update | February 27, 2014
19
2012 - 13 Daily Production 2012
Avg
2013
1Q
2Q
3Q
4Q
Total
1Q
2Q
3Q
4Q
Avg Total
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
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
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
Domestic Production
International Production
Total Production
WPX Operational Update | February 27, 2014
20
Growing Higher-Margin Oil 77% oil CAGR since 2010 ►
2014 growth in higher-margin oil
Record oil production in 2013
►
Averaged 16.2 Mbo/d – a 35% increase Y/Y Discovered and developing San Juan Mancos Gallup
► ►
► ► ►
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
Total Domestic Oil Growth 2010-14 9,000 8,000
Annual Domestic Mbbl
7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 2010Act
2011Act
2012Act
2013Act
2014Est
WPX Operational Update | February 27, 2014
21
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
$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-forResale Contract exp. in Nov ’14
$(0.26) ($0.21) ($0.29)
(0.30)
Weighted-Average Sales Price Excluding Rex
$3.17
$3.18
Net Price Including All Derivatives
$3.38
$3.05
►
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.
WPX Operational Update | February 27, 2014
22
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
WPX Operational Update | February 27, 2014
23
Piceance Basin Orange: Highlands Yellow: Valley 1 Net acreage: 221,186 Average rigs running in 2013: 6.6 Remaining 3P drilling locations: 9,0231 Composition: Gas/NGL focused
1Acreage
and drilling locations are as of 12/31/13
WPX Operational Update | February 27, 2014
24
Niobrara Delineation to the East with Vertical Test Valley Acreage and 3D Seismic Coverage
Valley delineation ► ►
►
2013 Testing
Producing
50% delineated 2013 Up to 10 wells planned for 2014 Increases delineation to 80%
3D seismic coverage Discovery Well
2014 1st Spud
5
► ►
►
Drilled
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 Producing ►
Continued delineation ► ►
New seismic: 30,700 acres Existing seismic: 25,000 acres
Drilled wells
► ► ►
Parachute Valley field Ryan Gulch Highlands field test
Testing well spacing and density Evaluating new horizons Repeatability and improving costs
WPX Operational Update | February 27, 2014
25
Piceance Composite NGL Barrel and Realized Price (4th Quarter, 2013)
$41.66 Product Mix
$/Gal
Ethane1
39%
.20
Propane
28%
1.18
Isobutane
8%
1.45
NGL Product
Weighted Average NGL $/barrel
$33.85
Net Realized Price
**$0.61 per Mcf NGL Uplift in 4Q 2013
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.
WPX Operational Update | February 27, 2014
26
Williston Basin Net acreage: 80,7361 Average rigs running in 2013: 4.1 Remaining 3P drilling locations: 3691 Composition: Oil focused
1Acreage
and drilling locations are as of 12/31/13
WPX Operational Update | February 27, 2014
27
Williston Basin – Ranked by F&D Cost (including WPX) DIVIDE
BURKE
RENVILLE
WILLIAMS
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
Area
MOUNTRAIL WARD
MCLEAN
MCKENZIE MERCER
BILLINGS GOLDEN VALLEY
DUNN
STARK
MORTON
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
WPX Operational Update | February 27, 2014
28
Williston Netback Price Analysis Sales Outlets
Estimated Volume % (Jan - Mar 2014)
Basin-Priced Sales
50%
Rail Deals
38%
Enbridge Capacity
12%
Total Sales Outlets
100%
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
WPX Operational Update | February 27, 2014
29
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 1Acreage
and drilling locations are as of 12/31/13
WPX Operational Update | February 27, 2014
30
Argentina Asset Map Acambuco: Noreste Basin
1.5% WI
Agua Amarga:
Entre Lomas: 23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%)
23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%)
Nequen Basin
Bajada del Palo:
Coirón Amargo: 45% WI Drill to earn farm-in
23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%) San Jorge Basin
Tierra del Fuego:
Sur Rio Deseado Este:
26% WI
Austral Basin
44% WI
Concession/Contract Basin
WPX Operational Update | February 27, 2014
31
Colombia Asset Map
Valle Medio Del Magdalena Basin
Turpial Block 50% WI 100,000 acres
Llanos 40 Block 50% WI 163,000 acres
Llanos Orientales Basin
Llanos 32 Block 20% WI 111,000 acres
Block Basin
WPX Operational Update | February 27, 2014
32
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
Vaca Muerta Exposure Neuquén Basin (Vaca Muerta acreage) ► ► ► ► ►
Entre Lomas Bajada del Palo Agua Amarga Coiron Amargo Charco del Palenque Total
96,000 net acres 59,000 net acres 37,000 net acres 45,000 net acres 12,000 net acres 249,000 net acres
Colombia ►
►
Initiated exploration drilling activities in each of our 3 areas (Llanos 40, Llanos 32 and Turpial) Maniceño field production has surpassed 1.1 MMbo
WPX Operational Update | February 27, 2014
33
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.
WPX Operational Update | February 27, 2014
35
Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited) 2012 (Dollars in millions, except per share amounts)
1Q
2Q
2013
3Q
4Q
Year
1Q
$ (105)
2Q
3Q
4Q
YTD
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders
$ (41) $ (33) $ (66)
$ (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)
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
$
31
$ 104
$ 193
$
103
$ (98)
$ 39
$1,428
$1,472
$ (38)
$ (71)
$
(38)
$
36
$ (14)
$ (521)
$(537)
-
$
-
$
-
$
$
$
$ 122
$
65
$ (62)
$ 31
$ 907
$ 941
$ (51)
$ (44)
$ (83)
$ (66)
$(244)
$ (0.25) $ (0.22)
$(0.41)
$(0.34)
$(1.22)
200.7
200.9
200.4
Pre-tax adjustments:
Total pre-tax adjustments
$ 53
$
Less tax effect for above items
$ (19)
$ (2)
$ (12)
Impact of new Argentine capital tax law 1
$
-
$
-
$
-
Total adjustments, after-tax
$ 34
$
3
$
19
Adjusted income (loss) from continuing operations available to common stockholders
$ (7)
$ (30)
Adjusted diluted earnings (loss) per common share Diluted weighted-average shares (millions) 1These
5
$ (47)
$
-
$ 66
$
$ (39) $ (123)
$(0.04) $(0.15) $(0.23) $(0.20) $(0.62) 198.1
198.9
199.1
199.2
198.8
199.9
203.8
6
-
6
items are presented net of amounts attributable to noncontrolling interest
WPX Operational Update | February 27, 2014
36
Consolidated Statements of Operations and EBITDAX Reconciliations (Unaudited) (Dollars in millions) Revenues: Product revenues: Natural gas sales Oil and condensate sales Natural gas liquid sales Total product revenues Gas management Net gain (loss) on derivatives not designated as hedges Other Total revenues Costs and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income Gas management, including charges for unutilized pipeline capacity Exploration Depreciation, depletion and amortization Impairment of producing properties and costs of acquired unproved reserves Gain on sale of Powder River Basin deep rights leasehold General and administrative Other – net Total costs and expenses Operating income (loss) Interest expense Interest capitalized Investment income, impairment of equity method investment and other Income (loss) from continuing operations before income taxes Provision (benefit) for income taxes Income (loss) from continuing operations Income (loss) from discontinued operations Net income (loss) Less: Net income (loss) attributable to noncontrolling interests Net income (loss) attributable to WPX Energy, Inc. Adjusted EBITDAX Reconciliation to net income (loss): Net income (loss) Interest expense Provision (benefit) for income taxes Depreciation, depletion and amortization Exploration expenses EBITDAX Impairment of producing properties, costs of acquired unproved reserves and equity investments (Gain) on sale of Powder River Basin deep rights leasehold Net (gain) loss on derivatives not designated as hedges Net cash received (paid) related to settlement of derivatives not designated as hedges (Income) loss from discontinued operations Adjusted EBITDAX
1Q
2012 3Q
2Q
4Q
Year
1Q
2013 3Q
2Q
$ 357 106 93 556 337 14 3 910
$ 312 122 78 512 187 71 5 775
$ 331 118 65 514 186 (22) (1) 677
$ 364 145 63 572 239 15 1 827
$1,364 491 299 2,154 949 78 8 3,189
$ 267 139 54 460 261 (94) 4 631
$ 316 151 58 525 205 78 7 815
$ 252 183 57 492 176 (15) 5 658
67 135 30 355 19 228 52 68 5 959 (49) (26) 2 10 (63) (25) (38) (2) (40) 3 (43)
67 120 25 194 19 248 65 71 (2) 807 (32) (26) 3 8 (47) (18) (29) 23 (6) 4 (10)
68 124 23 200 22 243 67 5 752 (75) (25) 2 7 (91) (28) (63) 2 (61) 3 (64)
81 127 33 247 23 247 108 81 4 951 (124) (25) 1 5 (143) (40) (103) (1) (104) 2 (106)
283 506 111 996 83 966 225 287 12 3,469 (280) (102) 8 30 (344) (111) (233) 22 (211) 12 (223)
75 107 35 243 19 231 72 7 789 (158) (26) 1 7 $ (176) (63) $ (113) $ (113) 3 $ (116)
73 111 36 222 20 227 74 1 764 51 (28) 1 9 33 11 22 22 4 18
$ (211) 102 (111) 966 83 829 225 (78) 46 (22) $1,000
$ (113) 26 (63) 231 19 100 94 9 $ 203
22 28 11 227 20 308 (78) (20) $ 210
$ $ $ $
$ (40) 26 (25) 228 19 208 52 (14) 15 2 $ 263
$ $ $ $
$
(6) 26 (18) 248 19 269 65 (71) 11 (23) $ 251
$ $ $ $
$ (61) 25 (28) 243 22 201 22 9 (2) $ 230
$ $ $ $
$ (104) 25 (40) 247 23 151 108 (15) 11 1 $ 256
$ $ $ $
$ $ $ $
$
4Q
$
YTD
258 176 61 495 249 (93) 6 657
$ 1,093 649 230 1,972 891 (124) 22 2,761
82 106 36 201 21 241 19 68 10 784 (126) (28) 2 4 $ (148) (32) $ (116) $ (116) (2) $ (114)
78 109 34 265 371 241 1,036 (36) 75 (1) 2,172 (1,515) (26) 1 (15) $ (1,555) (571) $ (984) $ (984) (11) $ (973)
308 433 141 931 431 940 1,055 (36) 289 17 4,509 (1,748) (108) 5 5 $ (1,846) (655) $ (1,191) $ (1,191) (6) $ (1,185)
$ (116) 28 (32) 241 21 142 19 15 (2) $ 174
$ (984) 26 (571) 241 371 (917) 1,056 (36) 93 (4) $ 192
$ (1,191) 108 (655) 940 431 (367) 1,075 (36) 124 (17) $ 779
WPX Operational Update | February 27, 2014
37
Domestic Segment (Unaudited) 2012 (Dollars in millions)
1Q
2Q
2013
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
Oil and condensate sales
$
80
95
87
114
376
111
121
154
148
534
Natural gas liquid sales
92
77
65
62
296
53
58
57
60
228
525
479
479
535
2,018
427
489
459
461
1,836
337
187
186
239
949
261
205
176
249
891
14
71
(22)
15
78
(94)
78
(15)
(93)
(124)
Total product revenues Gas management Net gain (loss) on derivatives not designated as hedges Other Total revenues
$
3
4
(1)
1
7
1
1
3
1
6
879
741
642
790
3,052
595
773
623
618
2,609
Costs and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income Gas management, including charges for unutilized pipeline capacity Exploration Depreciation, depletion and amortization Impairment of producing properties and costs of acquired unproved reserves Gain on sale of Powder River Basin deep rights leasehold
61
60
60
70
251
67
63
74
67
271
135
120
124
125
504
106
110
106
108
430
25
18
17
27
87
29
30
30
28
117
355
194
200
247
996
243
222
201
265
931
14
16
19
23
72
18
17
21
368
424
222
242
236
239
939
224
217
233
232
906
52
65
-
108
225
-
-
19
1,033
1,052
-
-
-
-
-
-
-
-
(36)
(36)
65
68
64
76
273
69
69
65
72
275
5
-
4
3
12
6
5
7
(1)
17
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)
(77)
$ (65)
$ (104)
$ (152)
$ (398)
$ (190)
15
$ (159)
$ (1,563)
$ (1,897)
101,346
102,163
97,310
96,664
397,483
90,411
90,022
91,392
87,638
359,463
948
1,123
1,076
1,247
4,394
1,242
1,373
1,575
1,738
5,928
2,746
2,779
2,613
2,254
10,392
1,907
1,895
1,811
1,808
7,421
123,511
125,574
119,443
117,670
486,198
109,303
109,628
111,707
108,916
439,554
General and administrative Other – net Total costs and expenses
Income (loss) from continuing operations before income taxes
$
$
Summary of Production Volumes Natural gas (MMcf) Oil (Mbbl) Natural gas liquids (Mbbl) Combined equivalent volumes (MMcfe)(1)
(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
$
2.90
$ 3.45
$ 2.72
$ 2.87
$
Oil (per barrel)
$ 84.54
$ 83.89
$82.31
$90.76
$ 85.58
3.38
$ 89.77
$
$ 87.76
$97.91
$85.50
$ 90.21
2.99
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
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
$
11
$
$
$
$
46
$
13
$
$
$
$
61
Expenses per Mcfe
Unutilized pipeline capacity Total unutilized pipeline capacity in gas management expense
12
12
11
14
17
17
WPX Operational Update | February 27, 2014
38
International Segment (Unaudited) (Dollars in millions) Revenues: Product revenues: Natural gas sales Oil and condensate sales Natural gas liquid sales Total product revenues Gas management Net gain (loss) on derivatives not designated as hedges Other Total revenues Costs and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income Gas management, including charges for unutilized pipeline capacity Exploration Depreciation, depletion and amortization Impairment of producing properties Gain on sale of Powder River Basin deep rights General and administrative Other – net Total costs and expenses
1Q
$
2012 3Q
2Q
4 26 1 31 31
$
5 27 1 33 1 34
$
4Q
4 31 35 35
$
YTD
5 31 1 37 37
$
1Q
18 115 3 136 1 137
$
2013 3Q
2Q
4 28 1 33 3 36
$
6 30 36 6 42
$
4Q
4 29 33 2 35
$
YTD
5 28 1 34 5 39
$
19 115 2 136 16 152
6 5 5 6 3 25
7 7 3 6 3 (2) 24
8 6 3 7 3 1 28
11 2 6 8 5 1 33
32 2 24 11 27 14 110
8 1 6 1 7 3 1 27
10 1 6 3 10 5 (4) 31
8 6 8 3 3 28
11 1 6 3 9 3 3 36
37 3 24 7 34 3 14 122
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
54
$ 14
Income (loss) from continuing operations before income taxes
$ 14
$
18
$
13
$
9
$
$
18
$
11
$
8
$
51
Summary of Net Production Volumes (1) Natural gas (MMcf) Oil (Mbbl) Natural gas liquids (Mbbl) Combined equivalent volumes (MMcfe)(2)
1,737
1,726
1,861
1,737
7,061
1,485
1,620
1,707
1,723
6,534
507
562
573
536
2,178
506
553
484
489
2,032
45
44
45
47
181
42
44
42
40
167
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.
WPX Operational Update | February 27, 2014
39
