Operational Update
Operational Update Ralph Hill, Chief Executive Officer November 7, 2013
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 – Nov. 7, 2013
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 – Nov. 7, 2013
3
Recent Highlights 2nd Niobrara well comes online with strong IP ►
Southern delineation well ► ► ►
► ► ►
2nd well delineates southern acreage IP at 11.8 MMcf/d Producing 8 MMcf/d after being choked back
Accelerating step out to the east with vertical test in November 2013 On pace to spud 2 more delineation wells in 2013 Discovery well produced 2 Bcf in first 10 months
46% growth in Williston oil production ► ► ►
Efficiency gains driving more wells drilled and increased production Remain a leader in basin F&D cost Expect 16% increase in Three Forks EUR reserve bookings at year-end 2013
New Mexico’s Mancos/Gallup play continues to exceed expectations ► ► ► ►
9 wells drilled and completed Last well drilled in record 14.6 days Early production results indicate EUR averages greater than 500 Mboe Average IP rate of 728 Boe/d
Poised for natural gas production growth ► ►
Sequential production growth Appalachia production up 40% Y/Y
Sold deep rights in Powder River for $40MM
WPX Operational Update – Nov. 7, 2013
4
Significant Cost Structure Improvements by End of 2014 2013 run-rate savings of $45MM - $70MM* ► ► ►
Willow Creek improved processing fee and tier margin sharing Piceance gathering rate change Van Hook gathering system $2 - $4 bbl savings versus hauling by truck 4Q ’13
Total run-rate savings start November 2014 of $125MM - $165MM* ►
Sale-for-resale agreement on Rockies Express expires November 2014
Continue to evaluate buyout of unutilized transport ► ►
Continue to evaluate with multiple parties to buy out some or all unutilized transportation contracts $25MM - $46MM of potential annual cost savings
✔ Laser gathering contract renegotiated early, resulting in savings of $10MM for 2013 Eliminated minimum volume commitment
* Contractual cost savings detail in Appendix of this presentation
WPX Operational Update – Nov. 7, 2013
5
Piceance Highlights – Production Decline Arrested, Continued Efficiencies Increased drilling plan ► ► ►
Currently operating 7 rigs Sequential quarter gas production growth Spud 60 wells in 3Q
Additional disposal capacity reducing LOE ►
►
6,500 bbl/d additional injection capacity in 2013 Eliminated third-party disposal in Ryan Gulch
Efficiencies decreasing well costs ►
►
►
►
Average Valley drilling time reduced to 8 days; 11.5 days in Ryan Gulch for 2013 Two more rigs converted to natural gas, two more by year-end Successfully tested fracturing completion equipment with dual fuel, and plan to have full crew in 2014. New WPX record: 36-well pad
Sufficient takeaway capacity in place to support future plans WPX Operational Update – Nov. 7, 2013
6
Advancing the Niobrara Program Niobrara discovery well drilled in 2012 ►
Produced 2 Bcf in first 10 months ► ►
IP 16 MMcf/d @ 7,300 psi flowing pressure Currently producing 3.5 MMcf/d
Niobrara 2013-planned activity ►
2nd horizontal well producing ► ► ►
►
3rd
Niobrara horizontal well drilled in August
► ► ►
►
►
Accelerated delineation of Rulison Field Well delineates formations and stacked pay potential zones in Rulison Field
5th well spud 3 miles to the north of discovery well ► ►
►
43% reduction in drilling times Unexpected technical issues in the lateral Potential sidetrack well being considered
4th well spud 12 miles northeast of discovery well ►
►
IP 11.8 MMcf/d @ 5,700 psi Choked back to 8 MMcf/d @ 5,400 psi In lowest expected pressure area
Ready to commence drilling operations Well delineates Middle Niobrara to the north of the discovery well
6th well to spud early January 2014 ►
Horizontal step out 3 miles to the east of discovery well
Niobrara/Mancos reserves potential ► ►
180,000 net acres 20 - 30 Tcfe potential resource
WPX’s new Aztec 1000 rig delineating Niobrara – 100% natural gas
WPX Operational Update – Nov. 7, 2013
7
Accelerating Step Out to the East with Vertical Test Valley Acreage and 3D Seismic Coverage
Focused plan ► ►
2013 Spud ►
2013 Spud ►
2013/14
Discovery Well
2014 1st Spud
Valley delineation schedule ►
2013/14 2013/14
Drilled
Proving up acreage Repeatability and improving costs Delineating well spacing and density Evaluating new horizons
► ►
18% of acreage delineated 50% delineated by year-end 10 - 12 wells planned for 2014 ►
Increases delineation to 80%
3D seismic coverage Producing
► ►
New seismic: 30,700 acres Existing seismic: 25,000 acres Drilled wells To-be-drilled wells
► ►
34% of Valley acreage 68% of Valley acreage covered by mid-year 2014 83% of Ryan Gulch acreage Brings total 3D seismic coverage in Valley/Ryan Gulch to 100,000 acres
WPX Operational Update – Nov. 7, 2013
8
Increased Efficiencies Continue to Drive Strong Production Growth in Williston Basin Continued strong production growth ►
►
Produced 14,000 bo/d in 3Q (15,600 boe/d) 13% production growth Q/Q
Three Forks performance exceeding expectations ►
►
12 wells put on 1st sales YTD Expect 16% increase in Three Forks EUR reserve bookings at year-end 2013
13 wells put on 1st sales ► ► ► ►
5 Middle Bakken 8 Three Forks All long laterals Fully transitioned to pad drilling
On target to meet YE exit rate of 16,000 boe/d (15,000 bo/d) ►
Avg daily production expected to grow 25 - 30% Y/Y
WPX Operational Update – Nov. 7, 2013
9
Williston Basin – Ranked by F&D Cost (including WPX) 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
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 – Nov. 7, 2013
10
Technical Expertise Drives Leading Basin Results WPX is #1 in cumulative Middle Bakken production for 1st sales since Jan 2011¹
180- and 365-Day Cumulative Production (Based on productive days)
Currently permitting 6 Middle Bakken and 5 Three Forks wells Encouraging results from well density projects: ► ►
Increased in-fill locations Increase reserves Increase asset value
Leader of completion design technology ►
►
Started using cement liners in May 2012 Identified plug and perf as superior completion method in early 2012 ►
►
Implemented new completion design: ► ► ►
►
Recent 2012-13 well-density project confirms superiority
140,000
Increased number of frac stages Increased perforation clusters Reduced pumping rate
WPX 180 Average WPX 365 Average
Peer180 Average Peer 365 Average
120,000 100,000 80,000 60,000 40,000 20,000 0
Ceramic proppant (65/35) increases EUR
Drilled recent long lateral well in less than 20 days 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 8/1/2013.
WPX ENERGY SLAWSON STATOIL WHITING KODIAK NEWFIELD QEP SM ENERGY EOG BURLINGTON RES HESS DENBURY MARATHON CONTINENTAL RES ZENERGY OASIS HUNT OIL XTO ENERGY PETRO-HUNT MUREX OXY G3 OPERATING SAMSON RES
►
160,000
Cumulative BO Production
►
Avg of CUM. 180
Avg of CUM. 365
WPX Operational Update – Nov. 7, 2013
11
San Juan Mancos Gallup Delivers Strong Results 2013 program ► ►
► ► ► ►
9 wells producing 2 wells expected to begin production next week 1 well currently being drilled 2013 expected exit rate to 3,400 boe/d Record drilling time of 14.6 days Decreased spud-to-rig release days resulting in 15 spuds in 2013
31,040 net acres in oil window ► ►
83.7% NRI Targeting additional acreage
Target metrics ►
► ►
D&C < $5.0MM EURs > 500 Mboe Lateral length: 5,000 feet
Spud-to-Rig Release
Exploration Development
60 40
20 0 114H 147H 191H 168H 228H 225H 221H 224H 175H 143H 115H
WPX Operational Update – Nov. 7, 2013
12
San Juan Mancos Gallup Exceeding Expecations Company wells continue to exceed expectations ► ►
►
San Juan Mancos Gallup Wells Average of Peak Full Month Reported to State*
Current production of 2,343 boe/d Early production indicates EUR > 500 Mboe Above-plan returns
14,000
Producer Avg.
Other operators return to area Offset operator performance validates EUR expectations and returns
WPX drilled and operates 4 of the top 8 producing wells in the Mancos Gallup Continued efficiencies driving improved well results ►
►
►
Zipper frac process beginning in late 4Q ’13 Intend to transition to pad drilling by the end of 2013 Shared surface facilities via multi-well pad drilling in mid-2014
10,000
Peak Bo/d
►
WPX Wells Other Producers
12,000
8,000
6,000
4,000
2,000
0 WPX (5 Wells)
Company A Company B Company C Company D Company E (20 Wells) (5 Wells) (2 Wells) (1 Well) (2 Wells)
*Based only on wells available on the NMOCD website
WPX Operational Update – Nov. 7, 2013
13
Financial Results Rod Sailor, Chief Financial Officer
3rd Quarter Results 3Q
YTD
2013
2012
2013
2012
Gas (MMcf/d)
1,012
1,078
1,013
1,117
Oil (Mbbl/d)
22.4
17.9
21.0
17.5
NGLs (Mbbl/d)
20.1
28.9
21.0
30.2
Equivalent (MMcfe/d)
1,267
1,359
1,265
1,403
Adjusted EBITDAX
174
230
587
744
Adjusted Net Income (Loss) from Continuing Operations
(83)
(47)
(178)
(84)
Capital Expenditures
295
337
843
1,165
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 – Nov. 7, 2013
15
3Q vs. 2Q Adjusted EPS – Key Drivers Lower natural gas realizations partially offset by higher domestic oil volumes and realizations ►
Lower NYMEX pricing ►
►
► ►
Wider natural gas basis; led by wider Dominion basis
Record domestic oil volumes and higher realizations Increase in valuation allowance of net operating loss carryover Marketing seasonality of third-party obligations
-$0.45 ($0.03)
Adjusted Earnings Per Share
-$0.40 ($0.13)
-$0.35
$0.01
$0.02
($0.41)
($0.05) $0.06
-$0.30 -$0.25
($0.03)
($0.04)
($0.22)
-$0.20 -$0.15 -$0.10 -$0.05 $0.00 2Q Adjusted EPS
Natural Gas Price
Natural Gas Volume
Domestic Oil Price
Domestic Oil Volume
Exp. Marketing/ Related Int'l to Higher Oil Volumes
Other
Deferred 3Q Tax Adjusted Valuation EPS Allowance
WPX Operational Update – Nov. 7, 2013
16
Path to Greater Shareholder Value Maintaining disciplined natural gas development ►
Added two rigs in Piceance, arrested production decline
Growing oil production ► ► ► ► ►
46% Williston production growth Leaders in Williston completion design technology SJ Mancos Gallup YE targeted exit rate of 3,400 boe/d Williston efficiencies driving 7 more wells and 10 more spuds than planned 2013 efficiencies drive 2014 production growth
Continuing cost improvements ►
► ► ►
Williston efficiencies drive leading F&D cost position Laser contracts renegotiated early, resulting in $10MM in savings in 2013 Willow Creek improved processing fee and tier margin sharing Piceance gathering rate change
Pursuing new opportunities, including Niobrara discovery and oil exploration ► ►
New discovery in San Juan oil window with resource potential of approximately 66 MMboe Rapid delineation of the Niobrara discovery
Evaluating alternative financial structures, MLP, JV and royalty trust ►
Optimize portfolio over time, which includes the potential sale of a core asset.
WPX Operational Update – Nov. 7, 2013
17
Appendix
Premier WPX Portfolio Piceance Basin
Bakken Shale
Marcellus Shale
San Juan
Powder River
Apco*
3,010 Bcfe Proved 12,039 Bcfe 3P 216,829 Net Acres
80 MMboe Proved 173 MMboe 3P 84,205 Net Acres
322 Bcfe Proved 2,023 Bcfe 3P 114,067 Net Acres
423 Bcfe Proved 1,873 Bcfe 3P 155,472 Net Acres
236 Bcfe Proved 1,044 Bcfe 3P 398,470 Net Acres
25 MMboe Proved 62 MMboe 3P 435,191 Net Acres *Reflects WPX’s 69% ownership
Total Total*Domestic
BAKKEN SHALE
4,650 Bcfe Proved 18,530 Bcfe 3P 1,558,124 Net Acres
POWDER RIVER BASIN PICEANCE BASIN
MARCELLUS SHALE
SAN JUAN BASIN
Natural Gas ARGENTINA
Oil Natural Gas Liquids Note: Acreage, Proved and 3P numbers are as of 12/31/12. *Total includes other acreage not depicted on slide.
WPX Operational Update – Nov. 7, 2013
19
Key Statistics by Basin
Net Acreage (YE2012)
2013 Current Rig Count (Op)¹
2012 Production (MMcfe/d)
Piceance
216,829
7
852
Williston
84,205
4
10.3 Mboe/d
Appalachia
114,067
1
63
San Juan/Mancos-Gallup
155,472
1
133
Total
570,573
13
1,110
Oil/NGL Focused
3P Gross Drilling Locations
Proved Reserves (YE2012 Bcfe)
3P Reserves (YE2012 Bcfe)
Additional Resource Potential
10,424
3,010
12,039
20 - 30 Tcfe
478
80 MMboe
173 MMboe
Evaluating
561
322
2,023
Evaluating
1,914
423
1,873
2- 3 Tcfe/ 66 MMboe
13,377
4,235
16,975
22 - 33 Tcfe
1,945
236
1,044
Evaluating
627
25 MMboe
62 MMboe
Evaluating
1,298
29
141
Primary Areas of Focus X X
X
Exploration Exploration
X
Other Powder River
398,470
0
209
Apco*
435,191
0
9.6 Mboe/d
Other
153,890
0
10
X
*Reflects WPX’s 69% ownership, except 3P drilling locations, which are gross. ¹ As of 9/30/2013 Chart numbers affected by rounding
WPX Operational Update – Nov. 7, 2013
20
2012-13 Daily Production 2012 1Q
2Q
3Q
4Q
Avg Total
1Q
2013 2Q
3Q
Avg Total
Gas (MMcf/d)
1,114
1,123
1,058
1,051
1,086
1,005
989
993
996
NGLs (Mbbl/d)
30.2
30.5
28.4
24.5
28.4
21.2
20.8
19.7
20.6
Oil (Mbbl/d)
10.4
12.3
11.7
13.6
12
13.8
15.1
17.1
15.3
MMcfe/d
1,357
1,380
1,298
1,279
1,328
1,215
1,205
1,214
1,211
Gas (MMcf/d)
19
19
20
19
19
17
18
19
18
NGLs (Mbbl/d)
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Oil (Mbbl/d)
5.6
6.2
6.2
5.8
6
5.6
6.1
5.3
5.7
MMcfe/d
56
59
61
57
58
53
57
53
54
Gas (MMcf/d)
1,133
1,142
1,078
1,070
1,105
1,021
1,007
1,012
1,013
NGLs (Mbbl/d)
30.7
31
28.9
25
28.9
21.7
21.3
20.1
21.0
Oil (Mbbl/d)
16 .0
18.5
17.9
19.4
18
19.4
21.2
22.4
21.0
MMcfe/d
1,413
1,439
1,359
1,336
1,386
1,268
1,262
1,267
1,265
Domestic Production
International Production
Total Production
WPX Operational Update – Nov. 7, 2013
21
WPX 2012 Domestic Reported Reserves 2012 year-end reserves before price revisions show strong growth year ► ► ► ►
200% reserve replacement ratio* Proved reserves growth of 10%* $1.74 drilling finding and development cost Liquids increase from 21 to 25%, all from oil growth
Domestic Reserves (Bcfe)
5,500 5,000
-496
4,500 4,000
+634
+6
+848
-498
5,339
4,984.0
4,846 4,350.2
4,350.2
4,492.0
4,491
Revisions
YE2012 SEC Case
4,491.1
3,500 3,000 YE2011 Adjusted for Asset Sale
Production
Extensions Purchases and and Discoveries Transfers
**Price Alternate Price Revisions and Scenario Extensions
*Adjusted for sale of Barnett Shale and Arkoma assets ** Assumes natural gas price of $3.68 per Mcf, oil price of $86.75 and NGL price of $51.83 per barrel Chart numbers affected by rounding
WPX Operational Update – Nov. 7, 2013
22
2013 Consolidated Guidance Annual Production
Low
Base
High
Capital Expenditures (in millions)
Low
Base
High
Gas – MMcf/d Oil – Mbbl/d NGLs – Mbbl/d* Total – MMcfe/d
1,008 21.7 20.5 1,261
1,028 21.7 20.8 1,283
1,039 21.8 20.9 1,295
Piceance Williston Appalachia Core Development
$320 360 85 765
$340 370 125 835
$380 415 130 925
$4.00 95.00 45.00
International Oil Exploration Development of Oil Opportunities Land/Other Total
70 95 40 30 1,000
70 95 40 30 1,070
70 95 55 55 1,200
Piceance Valley Piceance Highlands Total Piceance
3 1 4
4 1 5
6 1 7
Williston Appalachia Exploration Total
4 0 1 9
4 1 1 11
4 1 1 13
POV Natural Gas ($MMbtu) – NYMEX Oil ($/bbl) – WTI NGLs ($/bbl) – Mont Belvieu
$3.20 85.00 38.00
$3.50 92.50 41.00
Annual Rig Count
Expense ($/Mcfe) LOE GP&T DD&A SG&A Production tax
$0.66 0.95 1.98 0.64 0.29
$0.66 0.95 1.98 0.63 0.30
$0.66 0.95 1.98 0.63 0.33
$105 78 (28)
$105 82 (28)
$105 82 (28)
Annual Expense (in millions) Interest expense Exploration Equity earnings Tax provision
33% - 38% 33% - 38% 33% - 38%
*NGL composite barrel - 39% Ethane, 26.5% Propane, 7.9%, Iso-Butane, 6.8% Normal-Butane and 19.8% Natural Gasoline.
Notes: (1) Net realized price ranges as a percentage of NYMEX, WTI and OPIS excluding hedges but including basis differential and revenue adjustments. Natural gas 85% 88%, Oil 80% - 82% and NGL 75% - 80%. (2) Appalachia rig penalties are $9MM per rig annually, 3 rigs currently under contract. (3) Annual unutilized firm transportation of $46MM. (4) Assumes international oil price of $75 per barrel. (5) High case assumes 2 additional rigs in the Piceance . (6) Tax provision excludes unusual adjustments in 3rd quarter 2013.
WPX Operational Update – Nov. 7, 2013
23
Domestic Price Realization for 2013 Gas ($/Mcf)
NGL ($/bbl)
Oil ($/bbl)
1Q ’13
2Q ’13
3Q ’13
1Q ’13
2Q ’13
3Q ’13
1Q ’13
2Q ’13
3Q ’13
$3.12
$3.78
$3.16
$37.27
$37.41
$43.10
$89.23
$88.62
$99.43
(0.27)
(0.33)
(0.44)
(9.06)
(7.20)
(11.91)
0.54
(0.86)
(1.52)
0.05
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Net Price
$2.90
$3.45
$2.72
$28.21
$30.21
$31.19
$89.77
$87.76
$97.91
Realized Portion of Derivatives Not Designated as Hedges(3)
0.01
(0.28)
0.04
0.00
0.00
0.09
4.03
3.75
(2.63)
$2.91
$3.17
$2.76
$28.21
$30.21
$31.28
$93.80
$91.51
$95.28
1Q ’13
2Q ’13
3Q ’13
Weighted-Average Sales Price (1)
Revenue Adjustments Hedge Impact (2)
Net Price Including All Derivatives
Impact of Rockies Sale-forResale Contract exp. in Nov ’14
$(0.26) ($0.21) ($0.29)
Weighted- Average Sales Price Excluding Rex
$3.17
$3.38
►
3.05
3Q – Rockies sale-for-resale agreement impacted net realized gas price ($0.29). Contract expires in November 2014.
(1) Natural gas revenue adjustments are primarily related to field compression fuel. NGL revenue adjustments include T&F and revenue sharing. Of the Oil revenue adjustments, gathering deductions represent $(1.58). (2) “Net Price” equals income statement product revenues by commodity, divided by volume.
(3) Represents 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 – Nov. 7, 2013
24
2012 Year-End Domestic Reserves Year-End 2012 Before Price Changes*
2012 SEC Case Gas Bcf
NGL Mbbl
Oil Mbbl
Equivalent Bcfe
Gas Bcf
NGL Mbbl
Oil Mbbl
Equivalent Bcfe
2,339
103,094
8,755
3,010
2,773
124,204
11,025
3,584
Bakken Shale
34
6,790
67,463
480
34
6,835
67,911
483
Marcellus Shale
322
̶
̶
322
389
̶
̶
389
Powder River Basin
235
17
110
236
324
17
111
325
San Juan Basin
420
458
78
423
526
565
77
530
Other
19
̶
141
20
27
̶
200
28
3,369
110,359
76,547
4,491
4,073
131,621
79,324
5,339
Piceance Basin
Total Proved Domestic
PV-10 (in millions)
$2,340
$5,072
*Overall average natural gas price of $3.68 per Mcf, oil price of $86.75 and NGL price of $51.83 per barrel. These average prices reflect the 12-month average, first-of-month price during 2011 for the applicable indices for each basin as adjusted for local price differentials and applied to our 2012 SEC case or 2012 year-end reserves PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”), the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas assets. We, and others in the industry, use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
WPX Operational Update – Nov. 7, 2013
25
Hedging Overview
As of 11/4/2013
4Q ’13
2014
2015
470 $3.59
40 $4.35
– –
–
145
–
–
$4.00 - $4.66
–
11,000 $102.11
11,743 $94.78
– –
815 $1.165
– –
– –
815
–
–
$2.265
–
–
Natural Gas Fixed Price Swaps1,4 Volumes (Bbtu/d) Price ($/MMBtu) Collars Volumes (Bbtu/d) Price ($/MMBtu)
Crude Oil Fixed Price Swaps2,4 Volumes (bbl/d) Price ($/bbl)
Natural Gas Liquids Propane Swaps³ Volumes (bbl/d) Price ($/gallon) Natural Gasoline Swaps³ Volumes (bbl/d)
Price ($/gallon) 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. ³Our natural gas liquid hedges consists of swaps executed at Mont Belvieu . The hedged prices correspond to a weighted average composite barrel of $44.86. 4In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Details for natural gas and crude oil swaptions can be found in our most recent quarterly report.
WPX Operational Update – Nov. 7, 2013
26
Contractual Cost Structure Improvements Description
Effective Start Date
Financial Run Rate Impact (1)
Income Statement
Willow Creek
Change in fee and margin %
1Q ’13
$25MM - $40MM
Expense (Gathering & Processing)
Piceance Gathering
Contract rate change
1Q ’13
$10MM
Expense (Gathering & Processing )
Van Hook
WPX-built gathering system for Williston
3Q ’13
$12MM - $18MM
Laser
Early renegotiation of contract²
N/A
N/A
Rockies
Sales agreement adjustment
4Q ’14
$80MM - $100MM
Contract
Revenue (Oil Sales) Expense (Gathering & Processing) Revenue (Gas Sales)
Note: (1) Under the financial run rate impact, a point estimate denotes a fixed cost and a range is given for variable costs. (2) Eliminated minimum volume commitments and included flow assurances, capacity allocation, pressure requirements and temporary release clauses.
WPX Operational Update – Nov. 7, 2013
27
Preeminent Piceance Position Superior acreage position Increased drilling plan ► ►
► ►
Currently operating 7 rigs Sequential quarter gas production growth Spud 60 wells in 3Q with 7 rigs Average Valley drilling time reduced to 8 days; 11.5 days in Ryan Gulch for 2013
WPX contrast to offset operators ► ►
►
$2,500
$2,000
38% Less
$1,500
53% Less
38% less D&C capital costs(1) 53% less operating lifting costs(2)
State-of-the-art water management systems ►
WPX vs. Offset Operator Well D&C and Lifting Costs
6,500 bbl/d additional injection capacity 2013 Eliminated third-party disposal in Ryan Gulch
Infrastructure and takeaway capacity in place
$1,000
$500
$0 D&C Well Cost ($M/well)
Notes: (1) Utilizing data from eight 2012 Rulison field non-op wells (2) Utilizing data from 221 Valley non-op wells
Offset Operator WPX Energy
Lifting Cost ($/well/month)
WPX Operational Update – Nov. 7, 2013
28
Piceance Continuous Improvements Major cost savings made in Ryan Gulch ► ► ►
Drilling cycle time improvements Completion design improvements New infrastructure
Continued improvement in Valley ► ►
Ruthless attention to efficiencies High-grading drilling/completion locations
Continued D&C cost reductions ►
►
►
►
7% decrease drilling days for the Valley 22% decrease in drilling days in Ryan Gulch Reduced well costs by 20% in Ryan Gulch Continue to focus on rig efficiencies and areas for further cost reductions
WPX Operational Update – Nov. 7, 2013
29
WPX Positioned for Rapid Growth When Natural Gas Prices Recover We are ready to do it again…
We’ve done it before…
12% CAGR 800
Well Count
700
238 197
500
116
100
251
22
17
250
100
301 10
800
150
650
550
489
81
200
350
200
152
400
300
900
300
+157 Bcfe
600
400
25
26
0
50 0
2004
2005
2006
2007
2008
700
600
400
424
400
370
350
+155 Bcfe
310
450
300
269
250
500 200
400 300
539
150
577
576
573
100
200 100
262 8
16
17
17
17
Year 1
Year 2
Year 3
Year 4
Year 5
0
50 0
Infrastructure built for growth
Current 150-permit inventory
2006 milestone year
Highly experienced team in place
►
First delivery of “new” rigs
Support services available
►
Begin SIMOPS
We are faster, better, smarter
►
Highlands drilling under way
WPX Operational Update – Nov. 7, 2013
30
Net Operated Bcfe
900
1,000
Well Count
Well Count Avg. Rig Count Net Op Bcfe
450
Net Operated Bcfe
1,000
WPX Has Drilled the Top Niobrara Shale Well IP Flow 2,667 boe/d (1) (16 MMcf/d) 1,967 boe/d (1) (11.8 MMcf/d) 1,831 boe/d (367,875 Mcf; 1,770 bo/d) 1,775 boe/d (4.36 MMcf, 1,048 bo/d) 1,770 boe/d (2.4 MMcf, 1,270 bo/d) 1,677 boe/d (4.94 MMcf, 854 bo/d) 1,605 boe/d (3 MMcf, 1,105 bo/d) 1,477 boe/d (2.46 MMcf, 1,067 bo/d) 1,451 boe/d (3.61 MMcf, 849 bo/d) 1,441 boe/d (2.2 MMcf, 1,075 bo/d) 1,321 boe/d (1.56 MMcf, 1,061 bo/d) 1,243 boe/d (7.46 MMcf/d)* 1,110 boe/d (2.15 MMcf, 752 bo/d) 1,178.3 boe/d (7.07 MMcf/d)
Operator WPX Energy
Well # 701-4 HN1 Williams GM
County, State
Location/Basin
Comp. Date
Garfield, Colo.
Piceance
Dec. 2012
WPX Energy
702-23 HN1 Williams GM
Garfield, Colo.
Piceance
Sept. 2013
EOG Resources, Inc.
2-01H Jake
Weld, Colo.
Denver Julesburg
Dec. 2009
Chesapeake
31-33-69-A-3H York Ranch Unit
Converse, Wyo.
Powder River
Mar. 2013
Chesapeake
33-71 25-1H Sims
Converse, Wyo.
Powder River
Aug. 2012
Chesapeake
29-33-70 1H Combs Ranch Unit
Converse, Wyo.
Powder River
May 2012
Chesapeake
23-33-71A 3H Wallis
Converse, Wyo.
Powder River
Sept. 2012
Chesapeake
1-33-69 A 7H Crawford
Converse, Wyo.
Powder River
Mar. 2013
Converse, Wyo.
Powder River
Sept. 2012
Converse, Wyo.
Powder River
Aug. 2012
Weld, Colo.
Denver Julesburg
June 2011
Mesa, Colo.
Piceance
Jan. 2010
Converse, Wyo.
Powder River
Aug. 2012
Moffat, Colo.
SandWash
Nov. 2012
Chesapeake Chesapeake Whiting Oil & Gas Corp. Encana Oil & Gas Chesapeake Axia Energy
Data Source: IHS Inc. - As of *Source: Encana Oil & Gas 1) Barrel of oil equivalent is used for comparison purposes
32-35-71A 1H Box Creek 25-34-71 STA 1H Clausen Ranch 16-13H Wild Horse 20-12H (K20OU) Orchard Unit 26-33-70A 1H York Ranch 5-31H-790 Bulldog
Gas: 6,000 cu. ft. of gas = 1 bbl. of oil equivalent
WPX Operational Update – Nov. 7, 2013
31
Piceance Composite NGL Barrel and Realized Price (3rd Quarter, 2013)
Product Mix
$/Gal
Ethane(1)
36%
.26
Propane
30%
1.05
Iso-Butane
8%
1.39
Normal Butane
8%
1.37
Natural Gasoline
18%
2.21
NGL Product
*Included in revenue as a deduction ** Total NGL sales revenue minus any associated cost, divided by total Piceance gas sales volumes (1) Lower ethane percentage as a component of the composite barrel was driven by reduced ethane recovery
WPX Operational Update – Nov. 7, 2013
32
Piceance Cryo Capacity Willow Creek ►
►
►
Modified processing agreement with a revenue sharing component Mont Belvieu-priced products via Overland Pass Pipeline Volume dedication yields advantaged OPPL T&F rates
Enterprise – Meeker ►
►
Modified processing agreement with a revenue-sharing component Mont Belvieu-priced products via Mid-America Pipeline
Cryo Capacity ► ►
►
Willow Creek, 450 MMcf/d Meeker, 200 MMcf/d (plus 100 300 Mcf of additional interruptible) Echo Springs, 120 MMcf/d
WPX Operational Update – Nov. 7, 2013
33
Piceance Basin Orange: Highlands Yellow: Valley Net acreage: 216,829(1) Average rigs running in 2013: 6.6 Remaining 3P drilling locations: 10,424(1) Composition: 80% gas/20% liquids
(1) Acreage and drilling locations are based on YE 2012
WPX Operational Update – Nov. 7, 2013
34
Williston – Positioned for Continued Growth Efficiencies driving additional spuds in 2013 without increasing rig count ► ► ►
7 additional spuds 10 more wells on 1st sales Oil exit rate increases by ~2,000 bo/d to 15,000 bo/d at year-end
Spud-to-rig release days down 33% 3Q ’12 to 3Q ’13 Quarterly Average Net Production Mboe/d 16.0
15.6 13.9
14.0 12.4
12.6
Q4'12
Q1'13
12.0 10.2
10.5
Q2'12
Q3'12
Mboe/d
10.0 8.1 8.0 6.6
6.7
Q3'11
Q4'11
5.6
6.0 4.0
2.0
1.9
0.0 Q1'11
Q2'11
Q1'12
Q2'13
WPX Operational Update – Nov. 7, 2013
Q3'14
35
Dunn County Middle Bakken Well Performance WPX is one of the top performers in Dunn County with 41.0% of wells in the top quartile 400,000
Well Performance Detail Operator WPX ENERGY WILLISTON LLC CONTINENTAL RESOURCES INCORPORATED KODIAK OIL & GAS USA INCORPORATED G3 OPERATING LIMITED LIABILITY CORP ENERPLUS RESOURCES (USA) CORPORATION XTO ENERGY INCORPORATED QEP ENERGY COMPANY HESS CORPORATION BURLINGTON RESOURCES O&G CO LP (1) OXY USA INC MARATHON OIL COMPANY OTHER Total
350,000
Cumulative Oil Production (MBO)
300,000
250,000
Total Wells
Top Quartile Wells 39 111 42 25 59 72 25 69 52 125 215 49 883
16 41 15 7 16 19 6 16 12 25 40 8 221
% of Wells in Top Quartile 41.0% 36.9% 35.7% 28.0% 27.1% 26.4% 24.0% 23.2% 23.1% 20.0% 18.6% 16.3% 25.0%
200,000
All Operators 150,000
100,000
50,000
0 0
10
20
30
40
50
60
70
80
90
100
Months
(1)
BURLINGTON RESOURCES O&G CO LP
CONTINENTAL RESOURCES INCORPORATED
ENERPLUS RESOURCES (USA) CORPORATION
G3 OPERATING LIMITED LIABILITY CORP
HESS CORPORATION
KODIAK OIL & GAS USA INCORPORATED
MARATHON OIL COMPANY
OXY USA INC
QEP ENERGY COMPANY
WPX ENERGY WILLISTON LLC
XTO ENERGY INCORPORATED
(1) Burlington Resources O&G Co LP refers to holdings by ConocoPhillips
Source: IHS Enerdeq (Data as of 5/31/13)
WPX Operational Update – Nov. 7, 2013
36
Dunn County Three Forks Well Performance 400,000
Well Performance Detail
Cumulative Oil Production (MBO)
350,000
Operator WPX ENERGY WILLISTON LLC KODIAK OIL & GAS USA INCORPORATED CONTINENTAL RESOURCES INCORPORATED EOG RESOURCES INCORPORATED QEP ENERGY COMPANY HESS CORPORATION XTO ENERGY INCORPORATED G3 OPERATING LIMITED LIABILITY CORP BURLINGTON RESOURCES O&G CO LP (1) ENERPLUS RESOURCES (USA) CORPORATION MARATHON OIL COMPANY OXY USA INC Total
300,000 250,000 200,000
Total Wells
Top Quartile Wells 1 7 8 2 11 3 10 6 5 6 9 7 75
1 4 4 1 4 1 3 1 0 0 0 0 19
% of Wells in Top Quartile 100.0% 57.1% 50.0% 50.0% 36.4% 33.3% 30.0% 16.7% 0.0% 0.0% 0.0% 0.0% 25.3%
All Operators 150,000
100,000 50,000 0
0
5
(1)
10
15
20
25
30
35
Months BURLINGTON RESOURCES O&G CO LP EOG RESOURCES INCORPORATED KODIAK OIL & GAS USA INCORPORATED QEP ENERGY COMPANY
CONTINENTAL RESOURCES INCORPORATED G3 OPERATING LIMITED LIABILITY CORP MARATHON OIL COMPANY WPX ENERGY WILLISTON LLC
(1) Burlington Resources O&G Co LP refers to holdings by ConocoPhillips
ENERPLUS RESOURCES (USA) CORPORATION HESS CORPORATION OXY USA INC XTO ENERGY INCORPORATED
Source: IHS Enerdeq (Data as of 5/31/13)
WPX Operational Update – Nov. 7, 2013
37
Williston Netback Price Analysis Estimated Volume % (Oct - Dec 2013)
Sales Outlets Basin-Priced Sales
38%
Rail Deals
50%
Enbridge Capacity
12%
Total Sales Outlets
100%
Assumed 4th quarter total netback of WTI less $10 - $15 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 2013-16 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 beginning in mid 2013, and will receive a Gulf Coast price less associated fees with options to access West Coast, Northeast and Cushing markets.
WPX Operational Update – Nov. 7, 2013
38
Williston Basin (1) (1) Net acreage: 84,205 Acreage: 83,756 Average rigs running in 2013: 4 Average rigs running in 2013: 4 Remaining 3P drilling locations: 478(1) Remaining drilling locations: 478 (1) Composition: Oil focused Composition: Oil focused
(1) Acreage and drilling locations are based on YE 2012.
WPX Operational Update – Nov. 7, 2013
39
Leveraging Experienced San Juan Team to Rapidly Develop the Mancos/Gallup WPX has long history in the basin ► ► ► ►
31 years of continuous operation in the San Juan Basin Drilled and operate 880 wells, hold joint interest in another 2,400 Operations center in Aztec, N.M., with 50 employees and more than 500 years experience Drilled the first two Mancos horizontal gas wells in the basin
Leveraging existing operation ► ► ► ►
Developing play with existing San Juan team Infrastructure already in place Long-term relationships with service companies, vendors Proven permitting process in place
Spud-to-rig release days down 65% from exploration wells Continued efficiencies driving improved well results ► ► ►
Zipper frac process beginning in late 4Q ’13 Intend to transition to pad drilling by the end of 2013 Shared surface facilities via multi-well pad drilling in mid-2014
WPX Operational Update – Nov. 7, 2013
40
San Juan Basin
Green: Oil Yellow: Gas Net Acreage: 159,000 Average rigs running in 2013: 1 Remaining 3P drilling locations: 561(1) Composition: Dry Gas/Oil (1) Acreage and drilling locations are based on YE 2012.
WPX Operational Update – Nov. 7, 2013
41
Appalachia – Growing Production Volumes Production growth with only 1 rig running
Production pressure constrained ~10 MMcf/d 3Q; exploring options to further lower Susquehanna pressures
v
►
Reduced rig count to 1 rig; mostly drilling in our 50% WI area in Westmoreland County
Completed 6-well Duralia pad in north Westmoreland late in the 3Q
►
MARCELLUS SHALE
v
►
v
►
Net production increased 40% Y/Y
vv
►
WPX acreage
Wells initially tested at a gross rate of ~5 MMcf/d each Production impact will be in the 4Q
2013 Susquehanna County
2013 Westmoreland County
Qtr
Wells Spud
Fracture Stimulated
Placed in Service
Awaiting Completion
WOPL
Qtr
Wells Spud
Fracture Stimulated
Placed in Service
Awaiting Completion
WOPL
Q1
4
11
7
8
12
Q1
1
0
0
12
3
Q2
0
2
9
6
5
Q2
2
0
1
14
2
Q3
0
0
3
6
2
Q3
3
6
4
10
4
YTD
4
13
19
YTD
6
6
5
WPX Operational Update – Nov. 7, 2013
42
Pennsylvania
Net acreage: 114,067(1) Average rigs running in 2013: 1 Remaining 3P drilling locations: 561(1) Composition: Dry Gas
(1) Acreage and drilling locations are based on YE 2012.
WPX Operational Update – Nov. 7, 2013
43
Apco Recent Highlights Vaca Muerta Exposure
Argentina
Neuquén Basin activity in progress ►
Two new Vaca Muerta deals announced subsequent to the Chevron/YPF deal ► ►
►
►
►
Wintershall/GyP $115MM Dow Chemicals/YPF $120MM
2013 Neuquén Basin development program is progressing 1st 2013 vertical Coiron Amargo-Vaca Muerta Shale well was drilled in July and is being evaluated
Neuquen 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
2nd 2013 vertical Coiron Amargo-Vaca Muerta Shale well to be drilled by year-end
Colombia exploration program ►
►
►
Block 40 exploration drilling to commence in November
Turpial and Block 32 exploration drilling to restart early 2014 Maniceño field production has surpassed 1 MMbo WPX Operational Update – Nov. 7, 2013
44
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:
26% WI
78% WI Austral Basin
Concession/Contract Basin
WPX Operational Update – Nov. 7, 2013
45
Colombia Asset Map
Valle Medio Del Magdalena Basin
Turpial Block 100,000 acres
Llanos 40 Block 163,000 acres
Llanos Orientales Basin
Llanos 32 Block 111,000 acres
Block Basin
WPX Operational Update – Nov. 7, 2013
46
Two New Vaca Muerta Deals Subsequent to Chevron’s Deal
El Orejano
Wintershall/ GyP Deal $115MM
Dow Chemicals/ YPF Deal $120MM
Entre Lomas Nuequen
Aguada Aguada DelDel Chañar Chañar Entre Lomas Rio Negro
Bajada del Palo Chevron/ YPF Deal $1.2 Billion Loma Campana
Coiron Amargo Agua Amarga
LomaLata La Lomala Lata
Legend Area included in CVX/YPF First Phase of Development for VM Apco Neuquen Properties DOW Chemicals/YPF Deal Wintershall/GyP Deal YPF
WPX Operational Update – Nov. 7, 2013
47
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 – Nov. 7, 2013
49
Reconciliation − Adjusted Income (Loss) from Continuing Operations (Unaudited) 2012
Dollars in million, except per share amounts 1Q
2Q
2013
3Q
Year
4Q
1Q
2Q
3Q
YTD
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders
$
(66) $ (105) $ (245)
$ (116) $
18 $ (114) $ (212)
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) $ (1.06)
Impairment of producing properties and costs of acquired unproved reserves
$
52 $
65 $
‒
$
225
$
‒
$
‒
$
19 $
19
Accrual for litigation
$
‒
‒
‒
$
‒
$
‒
$
‒
$
7 $
7
Unrealized MTM (gain) loss
$
1 $
(60) $
31 $
(4) $
(32)
$
103 $
(98) $
13 $
18
Total pre-tax adjustments
$
53 $
5 $
31 $
104 $
193
$
103 $
(98) $
39 $
44
Less tax effect for above items
$
(19) $
(2) $
(12) $
(38) $
(71)
$
(38) $
36 $
(14) $
(16)
Impact of new Argentine capital tax law (1)
$
‒
‒
$
‒
$
6 $
6
Total adjustments, after-tax
$
34 $
3 $
19 $
122
$
65 $
(62) $
31 $
34
Adjusted income (loss) from continuing operations available to common stockholders
$
(7) $
(30) $
(47) $
(39) $ (123)
$
(51) $
(44) $
Adjusted diluted earnings (loss) per common share
$ (0.04) $ (0.15) $ (0.23) $ (0.20) $ (0.62)
(41) $
(33) $
Pre-tax adjustments:
Diluted weighted-average shares (millions)
198.1
$
$
‒
198.9
$
$
‒
$
199.1
108 $ ‒
‒
$
$
66 $
199.2
198.8
$
‒
(83) $ (178)
$ (0.25) $ (0.22) $ (0.41) $ (0.89) 199.9
203.8
200.7
200.3
(1) This item is presented net of amounts attributable to noncontrolling interests.
WPX Operational Update – Nov. 7, 2013
50
Consolidated Statements of Operations and EBITDAX Reconciliations (Unaudited) Dollars in million, except per share amounts
2012 1Q
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
$
357 106 93 556 337 14 3 910
Cost 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 General and administrative Other - net Total costs and expenses Operating income (loss)
2Q
$
312 122 78 512 187 71 5 775
$
67 135 30 355 19 228 52 68 5 959
$
(49)
$
2013
3Q
4Q
$
331 118 65 514 186 (22) (1) 677
$
67 120 25 194 19 248 65 71 (2) 807
$
68 124 23 200 22 243 ̶ 67 5 752
$
81 127 33 247 23 247 108 81 4 951
$
(32)
$
(75)
$
(124)
$
$
Year
$
364 145 63 572 239 15 1 827
1,364 491 299 $ 2,154 949 78 8 $ 3,189
$
1Q
$
267 139 54 460 261 (94) 4 631
283 506 111 996 83 966 225 287 12 $ 3,469
$
$
2Q
3Q
YTD
$
316 151 58 525 220 78 7 830
75 107 35 243 19 231 ̶ 72 7 789
$
73 111 36 238 20 227 ̶ 74 1 779
(280)
$ (158)
$
51
$ (126)
$ (233)
$
$
$
252 183 57 492 176 (15) 5 658
835 473 169 $ 1,477 642 (31) 16 $ 2,104
$
82 106 36 201 21 241 19 68 10 784
230 324 107 666 60 699 19 214 18 $ 2,337
$
Interest expense Interest capitalized Investment income and other
(26) 2 10
(26) 3 8
(25) 2 7
(25) 1 5
(102) 8 30
(26) 1 7
(28) 1 9
(28) 2 4
(82) 4 20
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
(63) (25) (38) (2) (40) 3 (43)
(47) (18) (29) 23 (6) 4 (10)
(91) (28) (63) 2 (61) 3 (64)
(143) (40) (103) (1) (104) 2 (106)
$
(344) (111) (233) 22 (211) 12 (223)
(176) (63) (113) ̶ (113) 3 $ (116)
33 11 22 ̶ 22 4 18
(148) (32) (116) ̶ (116) (2) $ (114)
(291) (84) (207) ̶ (207) 5 $ (212)
(104) 25 (40) 247 23 151 108 (15) 11 1 256
(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
(116) 28 (32) 241 21 $ 142 19 15 (2) ̶ $ 174
(207) 82 (84) 699 60 $ 550 19 31 (13) ̶ $ 587
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 and costs of acquired unproved reserves Net (gain) loss on derivatives not designated as hedges Realized gain (loss) on derivatives not designated as hedges (Income) loss from discontinued operations Adjusted EBITDAX
$
$
$
(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
$
$
$
$
$
$
WPX Operational Update – Nov. 7, 2013
51
Domestic Segment (Unaudited) Dollars in million, except per share amounts 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
2012
$
$
Cost and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income
2013
1Q
2Q
3Q
4Q
353 80 92 525 337 14 3 879
307 95 77 479 187 71 4 741
327 87 65 479 186 (22) (1) 642
359 114 62 535 239 15 1 790
$
$
$
$
$
$
Year
1,346 376 296 2,018 949 78 7 3,052
$
$
$
$
1Q
2Q
3Q
YTD
263 111 53 427 261 (94) 1 595
310 121 58 489 220 78 1 788
248 154 57 459 176 (15) 3 623
821 386 168 1,375 642 (31) 5 1,991
$
$
$
$
$
$
61 135 25
60 120 18
60 124 17
70 125 27
251 504 87
67 106 29
63 110 30
74 106 30
204 322 89
Gas management, including charges for unutilized pipeline capacity
355
194
200
247
996
243
238
201
666
Exploration Depreciation, depletion and amortization
14 222
16 242
19 236
23 239
72 939
18 224
17 217
21 233
56 674
52
65
̶
108
225
̶
19
19
$
68 ̶ 783
$
203 18 2,251
$
(42)
$
Impairment of producing properties and costs of acquired unproved reserves General administrative Other - net Total costs and expenses
$
65 5 934
Operating income (loss)
$
(55)
Interest expense Interest capitalized Investment income and other Income (loss) from continuing operations before income taxes
(26) 2 2 $
(77)
$
64 4 724
$
(82)
(26) 3 ̶ $
(65)
$
76 3 918
$
$
(128)
$
(25) 2 1 $
(104)
273 12 3,359 (307)
(25) 1 ̶ $
(152)
Summary of Production Volumes Natural gas (MMcf) 101,346 102,163 97,310 96,664 Oil (Mbbl) 948 1,123 1,076 1,247 Natural gas liquids (Mbbl) 2,746 2,779 2,613 2,254 Combined equivalent volumes (MMcfe) (1) 123,511 125,574 119,443 117,670 (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.
̶
$
69 6 762
$
(167)
(102) 8 3 $
(398)
397,483 4,394 10,392 486,198
$
69 4 748
$
65 7 756
$
40
$
(133)
(26) 1 2 $
(190)
90,411 1,242 1,907 109,303
(28) 1 2 $
15
90,022 1,373 1,895 109,628
(260)
(28) 2 ̶ $
(159)
91,392 1,575 1,811 111,707
(82) 4 4 $
(334)
271,825 4,189 5,613 330,638
Realized average price per unit, including the impact of hedges Natural gas (per Mcf) Oil (per barrel) Natural gas liquids (per barrel)
$ 3.48 $ 84.54 $ 33.46
$ 3.01 $ 83.89 $ 27.95
$ 3.35 $ 82.31 $ 24.43
$ 3.71 $ 90.76 $ 28.12
$ 3.38 $ 85.58 $ 28.56
$ 2.90 $ 89.77 $ 28.21
$ 3.45 $ 87.76 $ 30.21
$ 2.72 $ 97.91 $ 31.19
$ 3.02 $ 92.17 $ 29.85
Expenses per Mcfe Lease and facility operating Gathering, processing and transportation Taxes other than income Depreciation, depletion and amortization General and administrative
$ $ $ $ $
0.50 1.09 0.20 1.80 0.52
$ $ $ $ $
0.47 0.95 0.15 1.93 0.54
$ $ $ $ $
0.51 1.04 0.14 1.98 0.53
$ $ $ $ $
0.60 1.06 0.23 2.02 0.65
$ $ $ $ $
0.52 1.04 0.18 1.93 0.56
$ $ $ $ $
0.61 0.98 0.27 2.04 0.62
$ $ $ $ $
0.59 1.00 0.27 1.98 0.64
$ $ $ $ $
0.65 0.94 0.27 2.09 0.58
$ $ $ $ $
0.62 0.97 0.27 2.04 0.61
Unutilized pipeline capacity Total unutilized pipeline capcity in gas management expense
$
11
$
12
$
12
$
11
$
46
$
13
$
14
$
17
$
44
WPX Operational Update – Nov. 7, 2013
52
International Segment (Unaudited) 2012 3Q
Dollars in million, except per share amounts
1Q 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
̶
̶
̶
̶
̶
̶
̶
̶ ̶
̶
$
Operating Income (loss)
$
31 $
6
35 $
35 $
7
37 $
8
̶
11 2 6
5
̶ 7
̶
6
̶
̶
5 6
̶
3 6
̶
3 7
̶
̶
8
̶
3
1Q
18 115 3 136 ̶ ̶ 1 137
2Q
̶
3Q
4 29
̶
̶
̶
̶
$
6 30 36 $ ̶
̶
3 36 $
$
6 42 $
8 1 6
25 $
14 ̶ 110
6 $
10 $
7 $
4 $
27
2 35 $
̶
̶
̶ 3 10
̶
̶
̶
̶
10 1 6
1 7 ̶
5 1 33 $
33 $ ̶
̶
̶
3 1 28 $
YTD
4 28 1 33 $
32 2 24 ̶ 11 27
3 (2) 24 $
̶
8 6
8
̶
$
3 3 28 $
11 ̶ 86
$
9 $
11 $
7 $
27
̶
̶
̶
̶
̶
̶
̶
̶
̶
̶
̶
̶
̶
14 $
1,737 507 45 5,052
8 18 $
1,726 562 44 5,362
6
5
13 $
9 $
54
1,861 573 45 5,569
1,737 536 47 5,235
7,061 2,178 181 21,218
26 2 18 ̶ 4 25
5 (4) 31 $
̶
̶ 27
14 87 1 102 ̶ ̶ 11 113
3 1 27 $
̶ 8 $
5 31 1 37 $
̶
1 34 $
̶
Interest expense Interest capitalized Investment income and other
Summary of Production Volumes (1) Natural gas (MMcf) Oil (Mbbl) Natural gas liquids (Mbbl) Combined equivalent volumes (MMcfe) (2)
4 31
Year
5 27 1 33 $
̶
$
2013 4Q
4 26 1 31 $
$
Cost 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 General and administrative Other - net Total costs and expenses
Income (loss) from continuing operations before income taxes
2Q
5 $
7
14 $
1,485 506 42 4,775
18 $
1,620 553 44 5,202
̶ 4
̶ 16
11 $
43
1,707 484 42 4,862
4,812 1,543 128 14,839
(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 – Nov. 7, 2013
53
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 – Nov. 7, 2013
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 – Nov. 7, 2013
3
Recent Highlights 2nd Niobrara well comes online with strong IP ►
Southern delineation well ► ► ►
► ► ►
2nd well delineates southern acreage IP at 11.8 MMcf/d Producing 8 MMcf/d after being choked back
Accelerating step out to the east with vertical test in November 2013 On pace to spud 2 more delineation wells in 2013 Discovery well produced 2 Bcf in first 10 months
46% growth in Williston oil production ► ► ►
Efficiency gains driving more wells drilled and increased production Remain a leader in basin F&D cost Expect 16% increase in Three Forks EUR reserve bookings at year-end 2013
New Mexico’s Mancos/Gallup play continues to exceed expectations ► ► ► ►
9 wells drilled and completed Last well drilled in record 14.6 days Early production results indicate EUR averages greater than 500 Mboe Average IP rate of 728 Boe/d
Poised for natural gas production growth ► ►
Sequential production growth Appalachia production up 40% Y/Y
Sold deep rights in Powder River for $40MM
WPX Operational Update – Nov. 7, 2013
4
Significant Cost Structure Improvements by End of 2014 2013 run-rate savings of $45MM - $70MM* ► ► ►
Willow Creek improved processing fee and tier margin sharing Piceance gathering rate change Van Hook gathering system $2 - $4 bbl savings versus hauling by truck 4Q ’13
Total run-rate savings start November 2014 of $125MM - $165MM* ►
Sale-for-resale agreement on Rockies Express expires November 2014
Continue to evaluate buyout of unutilized transport ► ►
Continue to evaluate with multiple parties to buy out some or all unutilized transportation contracts $25MM - $46MM of potential annual cost savings
✔ Laser gathering contract renegotiated early, resulting in savings of $10MM for 2013 Eliminated minimum volume commitment
* Contractual cost savings detail in Appendix of this presentation
WPX Operational Update – Nov. 7, 2013
5
Piceance Highlights – Production Decline Arrested, Continued Efficiencies Increased drilling plan ► ► ►
Currently operating 7 rigs Sequential quarter gas production growth Spud 60 wells in 3Q
Additional disposal capacity reducing LOE ►
►
6,500 bbl/d additional injection capacity in 2013 Eliminated third-party disposal in Ryan Gulch
Efficiencies decreasing well costs ►
►
►
►
Average Valley drilling time reduced to 8 days; 11.5 days in Ryan Gulch for 2013 Two more rigs converted to natural gas, two more by year-end Successfully tested fracturing completion equipment with dual fuel, and plan to have full crew in 2014. New WPX record: 36-well pad
Sufficient takeaway capacity in place to support future plans WPX Operational Update – Nov. 7, 2013
6
Advancing the Niobrara Program Niobrara discovery well drilled in 2012 ►
Produced 2 Bcf in first 10 months ► ►
IP 16 MMcf/d @ 7,300 psi flowing pressure Currently producing 3.5 MMcf/d
Niobrara 2013-planned activity ►
2nd horizontal well producing ► ► ►
►
3rd
Niobrara horizontal well drilled in August
► ► ►
►
►
Accelerated delineation of Rulison Field Well delineates formations and stacked pay potential zones in Rulison Field
5th well spud 3 miles to the north of discovery well ► ►
►
43% reduction in drilling times Unexpected technical issues in the lateral Potential sidetrack well being considered
4th well spud 12 miles northeast of discovery well ►
►
IP 11.8 MMcf/d @ 5,700 psi Choked back to 8 MMcf/d @ 5,400 psi In lowest expected pressure area
Ready to commence drilling operations Well delineates Middle Niobrara to the north of the discovery well
6th well to spud early January 2014 ►
Horizontal step out 3 miles to the east of discovery well
Niobrara/Mancos reserves potential ► ►
180,000 net acres 20 - 30 Tcfe potential resource
WPX’s new Aztec 1000 rig delineating Niobrara – 100% natural gas
WPX Operational Update – Nov. 7, 2013
7
Accelerating Step Out to the East with Vertical Test Valley Acreage and 3D Seismic Coverage
Focused plan ► ►
2013 Spud ►
2013 Spud ►
2013/14
Discovery Well
2014 1st Spud
Valley delineation schedule ►
2013/14 2013/14
Drilled
Proving up acreage Repeatability and improving costs Delineating well spacing and density Evaluating new horizons
► ►
18% of acreage delineated 50% delineated by year-end 10 - 12 wells planned for 2014 ►
Increases delineation to 80%
3D seismic coverage Producing
► ►
New seismic: 30,700 acres Existing seismic: 25,000 acres Drilled wells To-be-drilled wells
► ►
34% of Valley acreage 68% of Valley acreage covered by mid-year 2014 83% of Ryan Gulch acreage Brings total 3D seismic coverage in Valley/Ryan Gulch to 100,000 acres
WPX Operational Update – Nov. 7, 2013
8
Increased Efficiencies Continue to Drive Strong Production Growth in Williston Basin Continued strong production growth ►
►
Produced 14,000 bo/d in 3Q (15,600 boe/d) 13% production growth Q/Q
Three Forks performance exceeding expectations ►
►
12 wells put on 1st sales YTD Expect 16% increase in Three Forks EUR reserve bookings at year-end 2013
13 wells put on 1st sales ► ► ► ►
5 Middle Bakken 8 Three Forks All long laterals Fully transitioned to pad drilling
On target to meet YE exit rate of 16,000 boe/d (15,000 bo/d) ►
Avg daily production expected to grow 25 - 30% Y/Y
WPX Operational Update – Nov. 7, 2013
9
Williston Basin – Ranked by F&D Cost (including WPX) 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
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 – Nov. 7, 2013
10
Technical Expertise Drives Leading Basin Results WPX is #1 in cumulative Middle Bakken production for 1st sales since Jan 2011¹
180- and 365-Day Cumulative Production (Based on productive days)
Currently permitting 6 Middle Bakken and 5 Three Forks wells Encouraging results from well density projects: ► ►
Increased in-fill locations Increase reserves Increase asset value
Leader of completion design technology ►
►
Started using cement liners in May 2012 Identified plug and perf as superior completion method in early 2012 ►
►
Implemented new completion design: ► ► ►
►
Recent 2012-13 well-density project confirms superiority
140,000
Increased number of frac stages Increased perforation clusters Reduced pumping rate
WPX 180 Average WPX 365 Average
Peer180 Average Peer 365 Average
120,000 100,000 80,000 60,000 40,000 20,000 0
Ceramic proppant (65/35) increases EUR
Drilled recent long lateral well in less than 20 days 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 8/1/2013.
WPX ENERGY SLAWSON STATOIL WHITING KODIAK NEWFIELD QEP SM ENERGY EOG BURLINGTON RES HESS DENBURY MARATHON CONTINENTAL RES ZENERGY OASIS HUNT OIL XTO ENERGY PETRO-HUNT MUREX OXY G3 OPERATING SAMSON RES
►
160,000
Cumulative BO Production
►
Avg of CUM. 180
Avg of CUM. 365
WPX Operational Update – Nov. 7, 2013
11
San Juan Mancos Gallup Delivers Strong Results 2013 program ► ►
► ► ► ►
9 wells producing 2 wells expected to begin production next week 1 well currently being drilled 2013 expected exit rate to 3,400 boe/d Record drilling time of 14.6 days Decreased spud-to-rig release days resulting in 15 spuds in 2013
31,040 net acres in oil window ► ►
83.7% NRI Targeting additional acreage
Target metrics ►
► ►
D&C < $5.0MM EURs > 500 Mboe Lateral length: 5,000 feet
Spud-to-Rig Release
Exploration Development
60 40
20 0 114H 147H 191H 168H 228H 225H 221H 224H 175H 143H 115H
WPX Operational Update – Nov. 7, 2013
12
San Juan Mancos Gallup Exceeding Expecations Company wells continue to exceed expectations ► ►
►
San Juan Mancos Gallup Wells Average of Peak Full Month Reported to State*
Current production of 2,343 boe/d Early production indicates EUR > 500 Mboe Above-plan returns
14,000
Producer Avg.
Other operators return to area Offset operator performance validates EUR expectations and returns
WPX drilled and operates 4 of the top 8 producing wells in the Mancos Gallup Continued efficiencies driving improved well results ►
►
►
Zipper frac process beginning in late 4Q ’13 Intend to transition to pad drilling by the end of 2013 Shared surface facilities via multi-well pad drilling in mid-2014
10,000
Peak Bo/d
►
WPX Wells Other Producers
12,000
8,000
6,000
4,000
2,000
0 WPX (5 Wells)
Company A Company B Company C Company D Company E (20 Wells) (5 Wells) (2 Wells) (1 Well) (2 Wells)
*Based only on wells available on the NMOCD website
WPX Operational Update – Nov. 7, 2013
13
Financial Results Rod Sailor, Chief Financial Officer
3rd Quarter Results 3Q
YTD
2013
2012
2013
2012
Gas (MMcf/d)
1,012
1,078
1,013
1,117
Oil (Mbbl/d)
22.4
17.9
21.0
17.5
NGLs (Mbbl/d)
20.1
28.9
21.0
30.2
Equivalent (MMcfe/d)
1,267
1,359
1,265
1,403
Adjusted EBITDAX
174
230
587
744
Adjusted Net Income (Loss) from Continuing Operations
(83)
(47)
(178)
(84)
Capital Expenditures
295
337
843
1,165
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 – Nov. 7, 2013
15
3Q vs. 2Q Adjusted EPS – Key Drivers Lower natural gas realizations partially offset by higher domestic oil volumes and realizations ►
Lower NYMEX pricing ►
►
► ►
Wider natural gas basis; led by wider Dominion basis
Record domestic oil volumes and higher realizations Increase in valuation allowance of net operating loss carryover Marketing seasonality of third-party obligations
-$0.45 ($0.03)
Adjusted Earnings Per Share
-$0.40 ($0.13)
-$0.35
$0.01
$0.02
($0.41)
($0.05) $0.06
-$0.30 -$0.25
($0.03)
($0.04)
($0.22)
-$0.20 -$0.15 -$0.10 -$0.05 $0.00 2Q Adjusted EPS
Natural Gas Price
Natural Gas Volume
Domestic Oil Price
Domestic Oil Volume
Exp. Marketing/ Related Int'l to Higher Oil Volumes
Other
Deferred 3Q Tax Adjusted Valuation EPS Allowance
WPX Operational Update – Nov. 7, 2013
16
Path to Greater Shareholder Value Maintaining disciplined natural gas development ►
Added two rigs in Piceance, arrested production decline
Growing oil production ► ► ► ► ►
46% Williston production growth Leaders in Williston completion design technology SJ Mancos Gallup YE targeted exit rate of 3,400 boe/d Williston efficiencies driving 7 more wells and 10 more spuds than planned 2013 efficiencies drive 2014 production growth
Continuing cost improvements ►
► ► ►
Williston efficiencies drive leading F&D cost position Laser contracts renegotiated early, resulting in $10MM in savings in 2013 Willow Creek improved processing fee and tier margin sharing Piceance gathering rate change
Pursuing new opportunities, including Niobrara discovery and oil exploration ► ►
New discovery in San Juan oil window with resource potential of approximately 66 MMboe Rapid delineation of the Niobrara discovery
Evaluating alternative financial structures, MLP, JV and royalty trust ►
Optimize portfolio over time, which includes the potential sale of a core asset.
WPX Operational Update – Nov. 7, 2013
17
Appendix
Premier WPX Portfolio Piceance Basin
Bakken Shale
Marcellus Shale
San Juan
Powder River
Apco*
3,010 Bcfe Proved 12,039 Bcfe 3P 216,829 Net Acres
80 MMboe Proved 173 MMboe 3P 84,205 Net Acres
322 Bcfe Proved 2,023 Bcfe 3P 114,067 Net Acres
423 Bcfe Proved 1,873 Bcfe 3P 155,472 Net Acres
236 Bcfe Proved 1,044 Bcfe 3P 398,470 Net Acres
25 MMboe Proved 62 MMboe 3P 435,191 Net Acres *Reflects WPX’s 69% ownership
Total Total*Domestic
BAKKEN SHALE
4,650 Bcfe Proved 18,530 Bcfe 3P 1,558,124 Net Acres
POWDER RIVER BASIN PICEANCE BASIN
MARCELLUS SHALE
SAN JUAN BASIN
Natural Gas ARGENTINA
Oil Natural Gas Liquids Note: Acreage, Proved and 3P numbers are as of 12/31/12. *Total includes other acreage not depicted on slide.
WPX Operational Update – Nov. 7, 2013
19
Key Statistics by Basin
Net Acreage (YE2012)
2013 Current Rig Count (Op)¹
2012 Production (MMcfe/d)
Piceance
216,829
7
852
Williston
84,205
4
10.3 Mboe/d
Appalachia
114,067
1
63
San Juan/Mancos-Gallup
155,472
1
133
Total
570,573
13
1,110
Oil/NGL Focused
3P Gross Drilling Locations
Proved Reserves (YE2012 Bcfe)
3P Reserves (YE2012 Bcfe)
Additional Resource Potential
10,424
3,010
12,039
20 - 30 Tcfe
478
80 MMboe
173 MMboe
Evaluating
561
322
2,023
Evaluating
1,914
423
1,873
2- 3 Tcfe/ 66 MMboe
13,377
4,235
16,975
22 - 33 Tcfe
1,945
236
1,044
Evaluating
627
25 MMboe
62 MMboe
Evaluating
1,298
29
141
Primary Areas of Focus X X
X
Exploration Exploration
X
Other Powder River
398,470
0
209
Apco*
435,191
0
9.6 Mboe/d
Other
153,890
0
10
X
*Reflects WPX’s 69% ownership, except 3P drilling locations, which are gross. ¹ As of 9/30/2013 Chart numbers affected by rounding
WPX Operational Update – Nov. 7, 2013
20
2012-13 Daily Production 2012 1Q
2Q
3Q
4Q
Avg Total
1Q
2013 2Q
3Q
Avg Total
Gas (MMcf/d)
1,114
1,123
1,058
1,051
1,086
1,005
989
993
996
NGLs (Mbbl/d)
30.2
30.5
28.4
24.5
28.4
21.2
20.8
19.7
20.6
Oil (Mbbl/d)
10.4
12.3
11.7
13.6
12
13.8
15.1
17.1
15.3
MMcfe/d
1,357
1,380
1,298
1,279
1,328
1,215
1,205
1,214
1,211
Gas (MMcf/d)
19
19
20
19
19
17
18
19
18
NGLs (Mbbl/d)
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
0.5
Oil (Mbbl/d)
5.6
6.2
6.2
5.8
6
5.6
6.1
5.3
5.7
MMcfe/d
56
59
61
57
58
53
57
53
54
Gas (MMcf/d)
1,133
1,142
1,078
1,070
1,105
1,021
1,007
1,012
1,013
NGLs (Mbbl/d)
30.7
31
28.9
25
28.9
21.7
21.3
20.1
21.0
Oil (Mbbl/d)
16 .0
18.5
17.9
19.4
18
19.4
21.2
22.4
21.0
MMcfe/d
1,413
1,439
1,359
1,336
1,386
1,268
1,262
1,267
1,265
Domestic Production
International Production
Total Production
WPX Operational Update – Nov. 7, 2013
21
WPX 2012 Domestic Reported Reserves 2012 year-end reserves before price revisions show strong growth year ► ► ► ►
200% reserve replacement ratio* Proved reserves growth of 10%* $1.74 drilling finding and development cost Liquids increase from 21 to 25%, all from oil growth
Domestic Reserves (Bcfe)
5,500 5,000
-496
4,500 4,000
+634
+6
+848
-498
5,339
4,984.0
4,846 4,350.2
4,350.2
4,492.0
4,491
Revisions
YE2012 SEC Case
4,491.1
3,500 3,000 YE2011 Adjusted for Asset Sale
Production
Extensions Purchases and and Discoveries Transfers
**Price Alternate Price Revisions and Scenario Extensions
*Adjusted for sale of Barnett Shale and Arkoma assets ** Assumes natural gas price of $3.68 per Mcf, oil price of $86.75 and NGL price of $51.83 per barrel Chart numbers affected by rounding
WPX Operational Update – Nov. 7, 2013
22
2013 Consolidated Guidance Annual Production
Low
Base
High
Capital Expenditures (in millions)
Low
Base
High
Gas – MMcf/d Oil – Mbbl/d NGLs – Mbbl/d* Total – MMcfe/d
1,008 21.7 20.5 1,261
1,028 21.7 20.8 1,283
1,039 21.8 20.9 1,295
Piceance Williston Appalachia Core Development
$320 360 85 765
$340 370 125 835
$380 415 130 925
$4.00 95.00 45.00
International Oil Exploration Development of Oil Opportunities Land/Other Total
70 95 40 30 1,000
70 95 40 30 1,070
70 95 55 55 1,200
Piceance Valley Piceance Highlands Total Piceance
3 1 4
4 1 5
6 1 7
Williston Appalachia Exploration Total
4 0 1 9
4 1 1 11
4 1 1 13
POV Natural Gas ($MMbtu) – NYMEX Oil ($/bbl) – WTI NGLs ($/bbl) – Mont Belvieu
$3.20 85.00 38.00
$3.50 92.50 41.00
Annual Rig Count
Expense ($/Mcfe) LOE GP&T DD&A SG&A Production tax
$0.66 0.95 1.98 0.64 0.29
$0.66 0.95 1.98 0.63 0.30
$0.66 0.95 1.98 0.63 0.33
$105 78 (28)
$105 82 (28)
$105 82 (28)
Annual Expense (in millions) Interest expense Exploration Equity earnings Tax provision
33% - 38% 33% - 38% 33% - 38%
*NGL composite barrel - 39% Ethane, 26.5% Propane, 7.9%, Iso-Butane, 6.8% Normal-Butane and 19.8% Natural Gasoline.
Notes: (1) Net realized price ranges as a percentage of NYMEX, WTI and OPIS excluding hedges but including basis differential and revenue adjustments. Natural gas 85% 88%, Oil 80% - 82% and NGL 75% - 80%. (2) Appalachia rig penalties are $9MM per rig annually, 3 rigs currently under contract. (3) Annual unutilized firm transportation of $46MM. (4) Assumes international oil price of $75 per barrel. (5) High case assumes 2 additional rigs in the Piceance . (6) Tax provision excludes unusual adjustments in 3rd quarter 2013.
WPX Operational Update – Nov. 7, 2013
23
Domestic Price Realization for 2013 Gas ($/Mcf)
NGL ($/bbl)
Oil ($/bbl)
1Q ’13
2Q ’13
3Q ’13
1Q ’13
2Q ’13
3Q ’13
1Q ’13
2Q ’13
3Q ’13
$3.12
$3.78
$3.16
$37.27
$37.41
$43.10
$89.23
$88.62
$99.43
(0.27)
(0.33)
(0.44)
(9.06)
(7.20)
(11.91)
0.54
(0.86)
(1.52)
0.05
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
Net Price
$2.90
$3.45
$2.72
$28.21
$30.21
$31.19
$89.77
$87.76
$97.91
Realized Portion of Derivatives Not Designated as Hedges(3)
0.01
(0.28)
0.04
0.00
0.00
0.09
4.03
3.75
(2.63)
$2.91
$3.17
$2.76
$28.21
$30.21
$31.28
$93.80
$91.51
$95.28
1Q ’13
2Q ’13
3Q ’13
Weighted-Average Sales Price (1)
Revenue Adjustments Hedge Impact (2)
Net Price Including All Derivatives
Impact of Rockies Sale-forResale Contract exp. in Nov ’14
$(0.26) ($0.21) ($0.29)
Weighted- Average Sales Price Excluding Rex
$3.17
$3.38
►
3.05
3Q – Rockies sale-for-resale agreement impacted net realized gas price ($0.29). Contract expires in November 2014.
(1) Natural gas revenue adjustments are primarily related to field compression fuel. NGL revenue adjustments include T&F and revenue sharing. Of the Oil revenue adjustments, gathering deductions represent $(1.58). (2) “Net Price” equals income statement product revenues by commodity, divided by volume.
(3) Represents 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 – Nov. 7, 2013
24
2012 Year-End Domestic Reserves Year-End 2012 Before Price Changes*
2012 SEC Case Gas Bcf
NGL Mbbl
Oil Mbbl
Equivalent Bcfe
Gas Bcf
NGL Mbbl
Oil Mbbl
Equivalent Bcfe
2,339
103,094
8,755
3,010
2,773
124,204
11,025
3,584
Bakken Shale
34
6,790
67,463
480
34
6,835
67,911
483
Marcellus Shale
322
̶
̶
322
389
̶
̶
389
Powder River Basin
235
17
110
236
324
17
111
325
San Juan Basin
420
458
78
423
526
565
77
530
Other
19
̶
141
20
27
̶
200
28
3,369
110,359
76,547
4,491
4,073
131,621
79,324
5,339
Piceance Basin
Total Proved Domestic
PV-10 (in millions)
$2,340
$5,072
*Overall average natural gas price of $3.68 per Mcf, oil price of $86.75 and NGL price of $51.83 per barrel. These average prices reflect the 12-month average, first-of-month price during 2011 for the applicable indices for each basin as adjusted for local price differentials and applied to our 2012 SEC case or 2012 year-end reserves PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”), the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas assets. We, and others in the industry, use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
WPX Operational Update – Nov. 7, 2013
25
Hedging Overview
As of 11/4/2013
4Q ’13
2014
2015
470 $3.59
40 $4.35
– –
–
145
–
–
$4.00 - $4.66
–
11,000 $102.11
11,743 $94.78
– –
815 $1.165
– –
– –
815
–
–
$2.265
–
–
Natural Gas Fixed Price Swaps1,4 Volumes (Bbtu/d) Price ($/MMBtu) Collars Volumes (Bbtu/d) Price ($/MMBtu)
Crude Oil Fixed Price Swaps2,4 Volumes (bbl/d) Price ($/bbl)
Natural Gas Liquids Propane Swaps³ Volumes (bbl/d) Price ($/gallon) Natural Gasoline Swaps³ Volumes (bbl/d)
Price ($/gallon) 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. ³Our natural gas liquid hedges consists of swaps executed at Mont Belvieu . The hedged prices correspond to a weighted average composite barrel of $44.86. 4In connection with several natural gas and crude oil swaps entered into, we granted swaptions to the swap counterparties in exchange for receiving premium hedged prices on the swaps. These swaptions grant the counterparty the option to enter into future swaps with us. Details for natural gas and crude oil swaptions can be found in our most recent quarterly report.
WPX Operational Update – Nov. 7, 2013
26
Contractual Cost Structure Improvements Description
Effective Start Date
Financial Run Rate Impact (1)
Income Statement
Willow Creek
Change in fee and margin %
1Q ’13
$25MM - $40MM
Expense (Gathering & Processing)
Piceance Gathering
Contract rate change
1Q ’13
$10MM
Expense (Gathering & Processing )
Van Hook
WPX-built gathering system for Williston
3Q ’13
$12MM - $18MM
Laser
Early renegotiation of contract²
N/A
N/A
Rockies
Sales agreement adjustment
4Q ’14
$80MM - $100MM
Contract
Revenue (Oil Sales) Expense (Gathering & Processing) Revenue (Gas Sales)
Note: (1) Under the financial run rate impact, a point estimate denotes a fixed cost and a range is given for variable costs. (2) Eliminated minimum volume commitments and included flow assurances, capacity allocation, pressure requirements and temporary release clauses.
WPX Operational Update – Nov. 7, 2013
27
Preeminent Piceance Position Superior acreage position Increased drilling plan ► ►
► ►
Currently operating 7 rigs Sequential quarter gas production growth Spud 60 wells in 3Q with 7 rigs Average Valley drilling time reduced to 8 days; 11.5 days in Ryan Gulch for 2013
WPX contrast to offset operators ► ►
►
$2,500
$2,000
38% Less
$1,500
53% Less
38% less D&C capital costs(1) 53% less operating lifting costs(2)
State-of-the-art water management systems ►
WPX vs. Offset Operator Well D&C and Lifting Costs
6,500 bbl/d additional injection capacity 2013 Eliminated third-party disposal in Ryan Gulch
Infrastructure and takeaway capacity in place
$1,000
$500
$0 D&C Well Cost ($M/well)
Notes: (1) Utilizing data from eight 2012 Rulison field non-op wells (2) Utilizing data from 221 Valley non-op wells
Offset Operator WPX Energy
Lifting Cost ($/well/month)
WPX Operational Update – Nov. 7, 2013
28
Piceance Continuous Improvements Major cost savings made in Ryan Gulch ► ► ►
Drilling cycle time improvements Completion design improvements New infrastructure
Continued improvement in Valley ► ►
Ruthless attention to efficiencies High-grading drilling/completion locations
Continued D&C cost reductions ►
►
►
►
7% decrease drilling days for the Valley 22% decrease in drilling days in Ryan Gulch Reduced well costs by 20% in Ryan Gulch Continue to focus on rig efficiencies and areas for further cost reductions
WPX Operational Update – Nov. 7, 2013
29
WPX Positioned for Rapid Growth When Natural Gas Prices Recover We are ready to do it again…
We’ve done it before…
12% CAGR 800
Well Count
700
238 197
500
116
100
251
22
17
250
100
301 10
800
150
650
550
489
81
200
350
200
152
400
300
900
300
+157 Bcfe
600
400
25
26
0
50 0
2004
2005
2006
2007
2008
700
600
400
424
400
370
350
+155 Bcfe
310
450
300
269
250
500 200
400 300
539
150
577
576
573
100
200 100
262 8
16
17
17
17
Year 1
Year 2
Year 3
Year 4
Year 5
0
50 0
Infrastructure built for growth
Current 150-permit inventory
2006 milestone year
Highly experienced team in place
►
First delivery of “new” rigs
Support services available
►
Begin SIMOPS
We are faster, better, smarter
►
Highlands drilling under way
WPX Operational Update – Nov. 7, 2013
30
Net Operated Bcfe
900
1,000
Well Count
Well Count Avg. Rig Count Net Op Bcfe
450
Net Operated Bcfe
1,000
WPX Has Drilled the Top Niobrara Shale Well IP Flow 2,667 boe/d (1) (16 MMcf/d) 1,967 boe/d (1) (11.8 MMcf/d) 1,831 boe/d (367,875 Mcf; 1,770 bo/d) 1,775 boe/d (4.36 MMcf, 1,048 bo/d) 1,770 boe/d (2.4 MMcf, 1,270 bo/d) 1,677 boe/d (4.94 MMcf, 854 bo/d) 1,605 boe/d (3 MMcf, 1,105 bo/d) 1,477 boe/d (2.46 MMcf, 1,067 bo/d) 1,451 boe/d (3.61 MMcf, 849 bo/d) 1,441 boe/d (2.2 MMcf, 1,075 bo/d) 1,321 boe/d (1.56 MMcf, 1,061 bo/d) 1,243 boe/d (7.46 MMcf/d)* 1,110 boe/d (2.15 MMcf, 752 bo/d) 1,178.3 boe/d (7.07 MMcf/d)
Operator WPX Energy
Well # 701-4 HN1 Williams GM
County, State
Location/Basin
Comp. Date
Garfield, Colo.
Piceance
Dec. 2012
WPX Energy
702-23 HN1 Williams GM
Garfield, Colo.
Piceance
Sept. 2013
EOG Resources, Inc.
2-01H Jake
Weld, Colo.
Denver Julesburg
Dec. 2009
Chesapeake
31-33-69-A-3H York Ranch Unit
Converse, Wyo.
Powder River
Mar. 2013
Chesapeake
33-71 25-1H Sims
Converse, Wyo.
Powder River
Aug. 2012
Chesapeake
29-33-70 1H Combs Ranch Unit
Converse, Wyo.
Powder River
May 2012
Chesapeake
23-33-71A 3H Wallis
Converse, Wyo.
Powder River
Sept. 2012
Chesapeake
1-33-69 A 7H Crawford
Converse, Wyo.
Powder River
Mar. 2013
Converse, Wyo.
Powder River
Sept. 2012
Converse, Wyo.
Powder River
Aug. 2012
Weld, Colo.
Denver Julesburg
June 2011
Mesa, Colo.
Piceance
Jan. 2010
Converse, Wyo.
Powder River
Aug. 2012
Moffat, Colo.
SandWash
Nov. 2012
Chesapeake Chesapeake Whiting Oil & Gas Corp. Encana Oil & Gas Chesapeake Axia Energy
Data Source: IHS Inc. - As of *Source: Encana Oil & Gas 1) Barrel of oil equivalent is used for comparison purposes
32-35-71A 1H Box Creek 25-34-71 STA 1H Clausen Ranch 16-13H Wild Horse 20-12H (K20OU) Orchard Unit 26-33-70A 1H York Ranch 5-31H-790 Bulldog
Gas: 6,000 cu. ft. of gas = 1 bbl. of oil equivalent
WPX Operational Update – Nov. 7, 2013
31
Piceance Composite NGL Barrel and Realized Price (3rd Quarter, 2013)
Product Mix
$/Gal
Ethane(1)
36%
.26
Propane
30%
1.05
Iso-Butane
8%
1.39
Normal Butane
8%
1.37
Natural Gasoline
18%
2.21
NGL Product
*Included in revenue as a deduction ** Total NGL sales revenue minus any associated cost, divided by total Piceance gas sales volumes (1) Lower ethane percentage as a component of the composite barrel was driven by reduced ethane recovery
WPX Operational Update – Nov. 7, 2013
32
Piceance Cryo Capacity Willow Creek ►
►
►
Modified processing agreement with a revenue sharing component Mont Belvieu-priced products via Overland Pass Pipeline Volume dedication yields advantaged OPPL T&F rates
Enterprise – Meeker ►
►
Modified processing agreement with a revenue-sharing component Mont Belvieu-priced products via Mid-America Pipeline
Cryo Capacity ► ►
►
Willow Creek, 450 MMcf/d Meeker, 200 MMcf/d (plus 100 300 Mcf of additional interruptible) Echo Springs, 120 MMcf/d
WPX Operational Update – Nov. 7, 2013
33
Piceance Basin Orange: Highlands Yellow: Valley Net acreage: 216,829(1) Average rigs running in 2013: 6.6 Remaining 3P drilling locations: 10,424(1) Composition: 80% gas/20% liquids
(1) Acreage and drilling locations are based on YE 2012
WPX Operational Update – Nov. 7, 2013
34
Williston – Positioned for Continued Growth Efficiencies driving additional spuds in 2013 without increasing rig count ► ► ►
7 additional spuds 10 more wells on 1st sales Oil exit rate increases by ~2,000 bo/d to 15,000 bo/d at year-end
Spud-to-rig release days down 33% 3Q ’12 to 3Q ’13 Quarterly Average Net Production Mboe/d 16.0
15.6 13.9
14.0 12.4
12.6
Q4'12
Q1'13
12.0 10.2
10.5
Q2'12
Q3'12
Mboe/d
10.0 8.1 8.0 6.6
6.7
Q3'11
Q4'11
5.6
6.0 4.0
2.0
1.9
0.0 Q1'11
Q2'11
Q1'12
Q2'13
WPX Operational Update – Nov. 7, 2013
Q3'14
35
Dunn County Middle Bakken Well Performance WPX is one of the top performers in Dunn County with 41.0% of wells in the top quartile 400,000
Well Performance Detail Operator WPX ENERGY WILLISTON LLC CONTINENTAL RESOURCES INCORPORATED KODIAK OIL & GAS USA INCORPORATED G3 OPERATING LIMITED LIABILITY CORP ENERPLUS RESOURCES (USA) CORPORATION XTO ENERGY INCORPORATED QEP ENERGY COMPANY HESS CORPORATION BURLINGTON RESOURCES O&G CO LP (1) OXY USA INC MARATHON OIL COMPANY OTHER Total
350,000
Cumulative Oil Production (MBO)
300,000
250,000
Total Wells
Top Quartile Wells 39 111 42 25 59 72 25 69 52 125 215 49 883
16 41 15 7 16 19 6 16 12 25 40 8 221
% of Wells in Top Quartile 41.0% 36.9% 35.7% 28.0% 27.1% 26.4% 24.0% 23.2% 23.1% 20.0% 18.6% 16.3% 25.0%
200,000
All Operators 150,000
100,000
50,000
0 0
10
20
30
40
50
60
70
80
90
100
Months
(1)
BURLINGTON RESOURCES O&G CO LP
CONTINENTAL RESOURCES INCORPORATED
ENERPLUS RESOURCES (USA) CORPORATION
G3 OPERATING LIMITED LIABILITY CORP
HESS CORPORATION
KODIAK OIL & GAS USA INCORPORATED
MARATHON OIL COMPANY
OXY USA INC
QEP ENERGY COMPANY
WPX ENERGY WILLISTON LLC
XTO ENERGY INCORPORATED
(1) Burlington Resources O&G Co LP refers to holdings by ConocoPhillips
Source: IHS Enerdeq (Data as of 5/31/13)
WPX Operational Update – Nov. 7, 2013
36
Dunn County Three Forks Well Performance 400,000
Well Performance Detail
Cumulative Oil Production (MBO)
350,000
Operator WPX ENERGY WILLISTON LLC KODIAK OIL & GAS USA INCORPORATED CONTINENTAL RESOURCES INCORPORATED EOG RESOURCES INCORPORATED QEP ENERGY COMPANY HESS CORPORATION XTO ENERGY INCORPORATED G3 OPERATING LIMITED LIABILITY CORP BURLINGTON RESOURCES O&G CO LP (1) ENERPLUS RESOURCES (USA) CORPORATION MARATHON OIL COMPANY OXY USA INC Total
300,000 250,000 200,000
Total Wells
Top Quartile Wells 1 7 8 2 11 3 10 6 5 6 9 7 75
1 4 4 1 4 1 3 1 0 0 0 0 19
% of Wells in Top Quartile 100.0% 57.1% 50.0% 50.0% 36.4% 33.3% 30.0% 16.7% 0.0% 0.0% 0.0% 0.0% 25.3%
All Operators 150,000
100,000 50,000 0
0
5
(1)
10
15
20
25
30
35
Months BURLINGTON RESOURCES O&G CO LP EOG RESOURCES INCORPORATED KODIAK OIL & GAS USA INCORPORATED QEP ENERGY COMPANY
CONTINENTAL RESOURCES INCORPORATED G3 OPERATING LIMITED LIABILITY CORP MARATHON OIL COMPANY WPX ENERGY WILLISTON LLC
(1) Burlington Resources O&G Co LP refers to holdings by ConocoPhillips
ENERPLUS RESOURCES (USA) CORPORATION HESS CORPORATION OXY USA INC XTO ENERGY INCORPORATED
Source: IHS Enerdeq (Data as of 5/31/13)
WPX Operational Update – Nov. 7, 2013
37
Williston Netback Price Analysis Estimated Volume % (Oct - Dec 2013)
Sales Outlets Basin-Priced Sales
38%
Rail Deals
50%
Enbridge Capacity
12%
Total Sales Outlets
100%
Assumed 4th quarter total netback of WTI less $10 - $15 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 2013-16 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 beginning in mid 2013, and will receive a Gulf Coast price less associated fees with options to access West Coast, Northeast and Cushing markets.
WPX Operational Update – Nov. 7, 2013
38
Williston Basin (1) (1) Net acreage: 84,205 Acreage: 83,756 Average rigs running in 2013: 4 Average rigs running in 2013: 4 Remaining 3P drilling locations: 478(1) Remaining drilling locations: 478 (1) Composition: Oil focused Composition: Oil focused
(1) Acreage and drilling locations are based on YE 2012.
WPX Operational Update – Nov. 7, 2013
39
Leveraging Experienced San Juan Team to Rapidly Develop the Mancos/Gallup WPX has long history in the basin ► ► ► ►
31 years of continuous operation in the San Juan Basin Drilled and operate 880 wells, hold joint interest in another 2,400 Operations center in Aztec, N.M., with 50 employees and more than 500 years experience Drilled the first two Mancos horizontal gas wells in the basin
Leveraging existing operation ► ► ► ►
Developing play with existing San Juan team Infrastructure already in place Long-term relationships with service companies, vendors Proven permitting process in place
Spud-to-rig release days down 65% from exploration wells Continued efficiencies driving improved well results ► ► ►
Zipper frac process beginning in late 4Q ’13 Intend to transition to pad drilling by the end of 2013 Shared surface facilities via multi-well pad drilling in mid-2014
WPX Operational Update – Nov. 7, 2013
40
San Juan Basin
Green: Oil Yellow: Gas Net Acreage: 159,000 Average rigs running in 2013: 1 Remaining 3P drilling locations: 561(1) Composition: Dry Gas/Oil (1) Acreage and drilling locations are based on YE 2012.
WPX Operational Update – Nov. 7, 2013
41
Appalachia – Growing Production Volumes Production growth with only 1 rig running
Production pressure constrained ~10 MMcf/d 3Q; exploring options to further lower Susquehanna pressures
v
►
Reduced rig count to 1 rig; mostly drilling in our 50% WI area in Westmoreland County
Completed 6-well Duralia pad in north Westmoreland late in the 3Q
►
MARCELLUS SHALE
v
►
v
►
Net production increased 40% Y/Y
vv
►
WPX acreage
Wells initially tested at a gross rate of ~5 MMcf/d each Production impact will be in the 4Q
2013 Susquehanna County
2013 Westmoreland County
Qtr
Wells Spud
Fracture Stimulated
Placed in Service
Awaiting Completion
WOPL
Qtr
Wells Spud
Fracture Stimulated
Placed in Service
Awaiting Completion
WOPL
Q1
4
11
7
8
12
Q1
1
0
0
12
3
Q2
0
2
9
6
5
Q2
2
0
1
14
2
Q3
0
0
3
6
2
Q3
3
6
4
10
4
YTD
4
13
19
YTD
6
6
5
WPX Operational Update – Nov. 7, 2013
42
Pennsylvania
Net acreage: 114,067(1) Average rigs running in 2013: 1 Remaining 3P drilling locations: 561(1) Composition: Dry Gas
(1) Acreage and drilling locations are based on YE 2012.
WPX Operational Update – Nov. 7, 2013
43
Apco Recent Highlights Vaca Muerta Exposure
Argentina
Neuquén Basin activity in progress ►
Two new Vaca Muerta deals announced subsequent to the Chevron/YPF deal ► ►
►
►
►
Wintershall/GyP $115MM Dow Chemicals/YPF $120MM
2013 Neuquén Basin development program is progressing 1st 2013 vertical Coiron Amargo-Vaca Muerta Shale well was drilled in July and is being evaluated
Neuquen 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
2nd 2013 vertical Coiron Amargo-Vaca Muerta Shale well to be drilled by year-end
Colombia exploration program ►
►
►
Block 40 exploration drilling to commence in November
Turpial and Block 32 exploration drilling to restart early 2014 Maniceño field production has surpassed 1 MMbo WPX Operational Update – Nov. 7, 2013
44
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:
26% WI
78% WI Austral Basin
Concession/Contract Basin
WPX Operational Update – Nov. 7, 2013
45
Colombia Asset Map
Valle Medio Del Magdalena Basin
Turpial Block 100,000 acres
Llanos 40 Block 163,000 acres
Llanos Orientales Basin
Llanos 32 Block 111,000 acres
Block Basin
WPX Operational Update – Nov. 7, 2013
46
Two New Vaca Muerta Deals Subsequent to Chevron’s Deal
El Orejano
Wintershall/ GyP Deal $115MM
Dow Chemicals/ YPF Deal $120MM
Entre Lomas Nuequen
Aguada Aguada DelDel Chañar Chañar Entre Lomas Rio Negro
Bajada del Palo Chevron/ YPF Deal $1.2 Billion Loma Campana
Coiron Amargo Agua Amarga
LomaLata La Lomala Lata
Legend Area included in CVX/YPF First Phase of Development for VM Apco Neuquen Properties DOW Chemicals/YPF Deal Wintershall/GyP Deal YPF
WPX Operational Update – Nov. 7, 2013
47
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 – Nov. 7, 2013
49
Reconciliation − Adjusted Income (Loss) from Continuing Operations (Unaudited) 2012
Dollars in million, except per share amounts 1Q
2Q
2013
3Q
Year
4Q
1Q
2Q
3Q
YTD
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders
$
(66) $ (105) $ (245)
$ (116) $
18 $ (114) $ (212)
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) $ (1.06)
Impairment of producing properties and costs of acquired unproved reserves
$
52 $
65 $
‒
$
225
$
‒
$
‒
$
19 $
19
Accrual for litigation
$
‒
‒
‒
$
‒
$
‒
$
‒
$
7 $
7
Unrealized MTM (gain) loss
$
1 $
(60) $
31 $
(4) $
(32)
$
103 $
(98) $
13 $
18
Total pre-tax adjustments
$
53 $
5 $
31 $
104 $
193
$
103 $
(98) $
39 $
44
Less tax effect for above items
$
(19) $
(2) $
(12) $
(38) $
(71)
$
(38) $
36 $
(14) $
(16)
Impact of new Argentine capital tax law (1)
$
‒
‒
$
‒
$
6 $
6
Total adjustments, after-tax
$
34 $
3 $
19 $
122
$
65 $
(62) $
31 $
34
Adjusted income (loss) from continuing operations available to common stockholders
$
(7) $
(30) $
(47) $
(39) $ (123)
$
(51) $
(44) $
Adjusted diluted earnings (loss) per common share
$ (0.04) $ (0.15) $ (0.23) $ (0.20) $ (0.62)
(41) $
(33) $
Pre-tax adjustments:
Diluted weighted-average shares (millions)
198.1
$
$
‒
198.9
$
$
‒
$
199.1
108 $ ‒
‒
$
$
66 $
199.2
198.8
$
‒
(83) $ (178)
$ (0.25) $ (0.22) $ (0.41) $ (0.89) 199.9
203.8
200.7
200.3
(1) This item is presented net of amounts attributable to noncontrolling interests.
WPX Operational Update – Nov. 7, 2013
50
Consolidated Statements of Operations and EBITDAX Reconciliations (Unaudited) Dollars in million, except per share amounts
2012 1Q
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
$
357 106 93 556 337 14 3 910
Cost 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 General and administrative Other - net Total costs and expenses Operating income (loss)
2Q
$
312 122 78 512 187 71 5 775
$
67 135 30 355 19 228 52 68 5 959
$
(49)
$
2013
3Q
4Q
$
331 118 65 514 186 (22) (1) 677
$
67 120 25 194 19 248 65 71 (2) 807
$
68 124 23 200 22 243 ̶ 67 5 752
$
81 127 33 247 23 247 108 81 4 951
$
(32)
$
(75)
$
(124)
$
$
Year
$
364 145 63 572 239 15 1 827
1,364 491 299 $ 2,154 949 78 8 $ 3,189
$
1Q
$
267 139 54 460 261 (94) 4 631
283 506 111 996 83 966 225 287 12 $ 3,469
$
$
2Q
3Q
YTD
$
316 151 58 525 220 78 7 830
75 107 35 243 19 231 ̶ 72 7 789
$
73 111 36 238 20 227 ̶ 74 1 779
(280)
$ (158)
$
51
$ (126)
$ (233)
$
$
$
252 183 57 492 176 (15) 5 658
835 473 169 $ 1,477 642 (31) 16 $ 2,104
$
82 106 36 201 21 241 19 68 10 784
230 324 107 666 60 699 19 214 18 $ 2,337
$
Interest expense Interest capitalized Investment income and other
(26) 2 10
(26) 3 8
(25) 2 7
(25) 1 5
(102) 8 30
(26) 1 7
(28) 1 9
(28) 2 4
(82) 4 20
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
(63) (25) (38) (2) (40) 3 (43)
(47) (18) (29) 23 (6) 4 (10)
(91) (28) (63) 2 (61) 3 (64)
(143) (40) (103) (1) (104) 2 (106)
$
(344) (111) (233) 22 (211) 12 (223)
(176) (63) (113) ̶ (113) 3 $ (116)
33 11 22 ̶ 22 4 18
(148) (32) (116) ̶ (116) (2) $ (114)
(291) (84) (207) ̶ (207) 5 $ (212)
(104) 25 (40) 247 23 151 108 (15) 11 1 256
(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
(116) 28 (32) 241 21 $ 142 19 15 (2) ̶ $ 174
(207) 82 (84) 699 60 $ 550 19 31 (13) ̶ $ 587
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 and costs of acquired unproved reserves Net (gain) loss on derivatives not designated as hedges Realized gain (loss) on derivatives not designated as hedges (Income) loss from discontinued operations Adjusted EBITDAX
$
$
$
(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
$
$
$
$
$
$
WPX Operational Update – Nov. 7, 2013
51
Domestic Segment (Unaudited) Dollars in million, except per share amounts 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
2012
$
$
Cost and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income
2013
1Q
2Q
3Q
4Q
353 80 92 525 337 14 3 879
307 95 77 479 187 71 4 741
327 87 65 479 186 (22) (1) 642
359 114 62 535 239 15 1 790
$
$
$
$
$
$
Year
1,346 376 296 2,018 949 78 7 3,052
$
$
$
$
1Q
2Q
3Q
YTD
263 111 53 427 261 (94) 1 595
310 121 58 489 220 78 1 788
248 154 57 459 176 (15) 3 623
821 386 168 1,375 642 (31) 5 1,991
$
$
$
$
$
$
61 135 25
60 120 18
60 124 17
70 125 27
251 504 87
67 106 29
63 110 30
74 106 30
204 322 89
Gas management, including charges for unutilized pipeline capacity
355
194
200
247
996
243
238
201
666
Exploration Depreciation, depletion and amortization
14 222
16 242
19 236
23 239
72 939
18 224
17 217
21 233
56 674
52
65
̶
108
225
̶
19
19
$
68 ̶ 783
$
203 18 2,251
$
(42)
$
Impairment of producing properties and costs of acquired unproved reserves General administrative Other - net Total costs and expenses
$
65 5 934
Operating income (loss)
$
(55)
Interest expense Interest capitalized Investment income and other Income (loss) from continuing operations before income taxes
(26) 2 2 $
(77)
$
64 4 724
$
(82)
(26) 3 ̶ $
(65)
$
76 3 918
$
$
(128)
$
(25) 2 1 $
(104)
273 12 3,359 (307)
(25) 1 ̶ $
(152)
Summary of Production Volumes Natural gas (MMcf) 101,346 102,163 97,310 96,664 Oil (Mbbl) 948 1,123 1,076 1,247 Natural gas liquids (Mbbl) 2,746 2,779 2,613 2,254 Combined equivalent volumes (MMcfe) (1) 123,511 125,574 119,443 117,670 (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.
̶
$
69 6 762
$
(167)
(102) 8 3 $
(398)
397,483 4,394 10,392 486,198
$
69 4 748
$
65 7 756
$
40
$
(133)
(26) 1 2 $
(190)
90,411 1,242 1,907 109,303
(28) 1 2 $
15
90,022 1,373 1,895 109,628
(260)
(28) 2 ̶ $
(159)
91,392 1,575 1,811 111,707
(82) 4 4 $
(334)
271,825 4,189 5,613 330,638
Realized average price per unit, including the impact of hedges Natural gas (per Mcf) Oil (per barrel) Natural gas liquids (per barrel)
$ 3.48 $ 84.54 $ 33.46
$ 3.01 $ 83.89 $ 27.95
$ 3.35 $ 82.31 $ 24.43
$ 3.71 $ 90.76 $ 28.12
$ 3.38 $ 85.58 $ 28.56
$ 2.90 $ 89.77 $ 28.21
$ 3.45 $ 87.76 $ 30.21
$ 2.72 $ 97.91 $ 31.19
$ 3.02 $ 92.17 $ 29.85
Expenses per Mcfe Lease and facility operating Gathering, processing and transportation Taxes other than income Depreciation, depletion and amortization General and administrative
$ $ $ $ $
0.50 1.09 0.20 1.80 0.52
$ $ $ $ $
0.47 0.95 0.15 1.93 0.54
$ $ $ $ $
0.51 1.04 0.14 1.98 0.53
$ $ $ $ $
0.60 1.06 0.23 2.02 0.65
$ $ $ $ $
0.52 1.04 0.18 1.93 0.56
$ $ $ $ $
0.61 0.98 0.27 2.04 0.62
$ $ $ $ $
0.59 1.00 0.27 1.98 0.64
$ $ $ $ $
0.65 0.94 0.27 2.09 0.58
$ $ $ $ $
0.62 0.97 0.27 2.04 0.61
Unutilized pipeline capacity Total unutilized pipeline capcity in gas management expense
$
11
$
12
$
12
$
11
$
46
$
13
$
14
$
17
$
44
WPX Operational Update – Nov. 7, 2013
52
International Segment (Unaudited) 2012 3Q
Dollars in million, except per share amounts
1Q 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
̶
̶
̶
̶
̶
̶
̶
̶ ̶
̶
$
Operating Income (loss)
$
31 $
6
35 $
35 $
7
37 $
8
̶
11 2 6
5
̶ 7
̶
6
̶
̶
5 6
̶
3 6
̶
3 7
̶
̶
8
̶
3
1Q
18 115 3 136 ̶ ̶ 1 137
2Q
̶
3Q
4 29
̶
̶
̶
̶
$
6 30 36 $ ̶
̶
3 36 $
$
6 42 $
8 1 6
25 $
14 ̶ 110
6 $
10 $
7 $
4 $
27
2 35 $
̶
̶
̶ 3 10
̶
̶
̶
̶
10 1 6
1 7 ̶
5 1 33 $
33 $ ̶
̶
̶
3 1 28 $
YTD
4 28 1 33 $
32 2 24 ̶ 11 27
3 (2) 24 $
̶
8 6
8
̶
$
3 3 28 $
11 ̶ 86
$
9 $
11 $
7 $
27
̶
̶
̶
̶
̶
̶
̶
̶
̶
̶
̶
̶
̶
14 $
1,737 507 45 5,052
8 18 $
1,726 562 44 5,362
6
5
13 $
9 $
54
1,861 573 45 5,569
1,737 536 47 5,235
7,061 2,178 181 21,218
26 2 18 ̶ 4 25
5 (4) 31 $
̶
̶ 27
14 87 1 102 ̶ ̶ 11 113
3 1 27 $
̶ 8 $
5 31 1 37 $
̶
1 34 $
̶
Interest expense Interest capitalized Investment income and other
Summary of Production Volumes (1) Natural gas (MMcf) Oil (Mbbl) Natural gas liquids (Mbbl) Combined equivalent volumes (MMcfe) (2)
4 31
Year
5 27 1 33 $
̶
$
2013 4Q
4 26 1 31 $
$
Cost 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 General and administrative Other - net Total costs and expenses
Income (loss) from continuing operations before income taxes
2Q
5 $
7
14 $
1,485 506 42 4,775
18 $
1,620 553 44 5,202
̶ 4
̶ 16
11 $
43
1,707 484 42 4,862
4,812 1,543 128 14,839
(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 – Nov. 7, 2013
53
