wpx howardweil
Howard Weil 41st Annual Energy Conference Ralph Hill President and Chief Executive Officer March 19, 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.
Howard Weil 41st Annual Energy Conference - March 19, 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.
Howard Weil 41st Annual Energy Conference - March 19, 2013
3
2013 Path to Greater Shareholder Value
Grow oil production
Maintain disciplined natural gas development, poised for rapid growth when prices recover Continue cost improvements Pursue new opportunities, including Niobrara discovery and oil exploration
Howard Weil 41st Annual Energy Conference - March 19, 2013
4
2013 Strategy Driving Shareholder Value Transition to multi-well pads driving Bakken production growth and lower well costs ► ►
Strong annual production growth of approximately 25 - 30% Recent long lateral wells result in 10 - 20% lower cost ► ► ►
►
Multi-well pad drilling Zipper frac completions Spud to rig release days reduced; record well, 25 days
Doing more with less; 29% efficiency gain in wells drilled in 2013 ► ►
2012: Drilled 43 gross wells while averaging 5.7 rigs 2013: Plan to drill approximately 40 gross wells while averaging 4.1 rigs
Focused infrastructure supporting development ►
Van Hook gathering system improves netbacks by $2 - $4 barrel, Unit Rail with East and West Coasts access starts 2Q ’13
Piceance – Unique, world-class position delivers proven track record of attractive returns and long-lived inventory ► ► ►
Significant growth potential with more than 10,000 3P remaining locations(1) Favorable long-term liquids processing contracts with new Willow Creek contract, effective 1/1/13 Continuous operational efficiencies lead to further well-cost reductions
Marcellus – Strong production growth, increasing EURs and lower cost ► ► ►
►
Production growth of 75% - 80% in 2013 Completion cost down 46% from 4Q ’11 to 4Q ’12 Spud to rig release down 60% from 3Q ’10; record 11 days Demonstrating capital flexibility within play by moving rig to improving Westmoreland
(1) The Piceance remaining locations exclude any potential locations related to our recent Niobrara discovery
Howard Weil 41st Annual Energy Conference - March 19, 2013
5
2013 Strategy Driving Shareholder Value
(continued)
First horizontal Niobrara Shale well in Piceance Basin is a major discovery ► ►
20 - 30 Tcfe of resource potential Additional resource that will provide significant ability to rapidly grow production and reserves ►
►
180,000 acres HBP and infrastructure already in place
Plan for 4 horizontal wells in 2013 ► ► ►
Focus on proving adjacent acreage and demonstrating repeatability of play Ability to quickly move to development mode Significant gathering, processing and transportation takeaway already in place
Opened data room to explore monetization of Powder River Basin ►
We continue to review other potential value-creating options including asset-specific joint ventures, MLPs and royalty trust
Howard Weil 41st Annual Energy Conference - March 19, 2013
6
Preeminent Piceance Position Superior acreage position WPX contrast to offset operators ► ►
38% less D&C capital costs (1) 53% less operating lifting costs (2)
State-of-the-art water management systems Infrastructure and takeaway capacity in place New emerging play ►
►
$2,000
Initial IP 16 MMcf/d 30-day average 12 MMcf/d 60-day average @ 10.6 MMcf/d
$1,000
►
Up to 4 new horizontal wells planned in 2013 180,000 net acres held by production 20 - 30 TCF resource potential
WPX Energy
$2,500
$1,500
►
►
Offset Operator
Niobrara discovery well drilled in 2012 ►
►
WPX vs. Offset Operator Well D&C and Lifting Costs
53% Less
38% Less
$500 $0 D&C Well Cost ($M/well)
Lifting Cost ($/well/month)
Notes: (1) Utilizing data from eight 2012 Rulison field non-op wells (2) Utilizing data from 221 Valley non-op wells
Howard Weil 41st Annual Energy Conference - March 19, 2013
7
WPX Positioned for Rapid Growth when Natural Gas Prices Recover We’ve done it before…
We are ready to do it again…
12% CAGR 800
Well Count
700
400
900
350
800
300
+157 Bcfe
600
238 197
500
116
300
251
150
650
550
489
81
200
301 10
25
22
17
250 200
152
400
100
1,000
26
0
2005
2006
2007
2008
600
400
370
350
+155 Bcfe
310
450
300
269
250
500 200
400 300
100
200
50
100
0
2004
700
424
400
262
150
577
576
573
539
100
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
Howard Weil 41st Annual Energy Conference - March 19, 2013
8
Net Operated Bcfe
900
450
Well Count
Well Count Avg. Rig Count Net Op Bcfe
Net Operated Bcfe
1,000
Bakken Creating Value – Improving Well Performance, Lowering Cost and Strong Reserve Growth 28 of 31 wells put on first sales in 2012 were at, or surpassed, our well performance expectations Top 10 performers: 4 - Middle Bakken, 6 - Three Forks Proved Reserves ►
Four Middle Bakken wells averaged ~38% higher than expectations Six Three Forks wells averaged > 14% higher than expectations
Middle Bakken delivering excellent results Independence 2-35HC (Middle Bakken – Long Lateral) ►
9% higher than type well
Three Forks exceeding expectations Kate Soldier 23-14HZ (Three Forks – Long Lateral) ►
90
80.0
80 Proved Reserves, MMboe
►
70 60
47.6
50 40 30
22.9
20
10 0
YE'10
17% higher than type well
D&C cost down 10 - 20% on recent long lateral wells
YE'11
Percent Held by Production 100%
Drilling improvements lowering drilling days New efficiency rigs, experienced personnel and brine fluid system Spud to rig release improvement: ► ► ►
2012 average 1Q 2013 average Black Hawk 1-26HW
43 days 32 days 25 days
YE'12
~98%
90% 80% 70% 60% 50%
36%
40% 30% 20%
16%
10% 0%
YE'10
YE'11
Howard Weil 41st Annual Energy Conference - March 19, 2013
YE'12
9
Appalachia – Strong Production & Reserves Growth, Increasing EURs, Lower Well Cost Strong reserves growth demonstrated by proved reserves
Proved Reserves
Over 1,000% reserve growth since 2010
350
Susquehanna County compression pilots doubled production confirming our type curve Production increased 320% over 2011 to an average of 63 MMcf/d in 2012
Proved Reserves, Bcf
►
300 250 200
142
150 100 50
28
0
Williams field receipt point compression scheduled to come on 1Q 2013 ►
322
YE'10
Currently 30 MMcf/d of net production constrained
YE'11
Average Production by Year
Completion costs continue their downward trend ►
Completion cost down 46% from 4Q ’11 to 4Q ’12
Net Production MMcf/d
70
Westmoreland wells continue to outperform expectations
YE'12
63
60 50 40 30
15
20 10
5
2010
2011
Howard Weil 41st Annual Energy Conference - March 19, 2013
2012
10
Emerging Niobrara Resource Play – Piceance Basin Basin-wide Niobrara activity de-risking play WPX has 20 - 30 Tcf Resource Potential
► ► ►
40 Niobrara horizontals drilled Multiple horizontal pay zones Horizontal EURs 6+ Bcf
WPX Energy activity: 2011
WPX Lease Position
►
180,000 net acres (Deep)
►
►
Drilled vertical test well in 4Q Completed 2 Niobrara zones with promising results Additional potential zones to be tested in 2013
WPX Energy activity: 2012 ►
► ►
Horizontal test well drilled, completed and producing by YE 2012 Obtained 535′ core and specialty logs Has produced for last 60 days ► ► ►
IP 16 MMcf/d @7,300 psi 60 day average – 10.6 MMcf/d @ 6,300 psi First 60 days – 0.64 Bcf produced
Howard Weil 41st Annual Energy Conference - March 19, 2013
11
WPX Has Drilled the Top Niobrara Shale Well (Based on IP Rate) Ranking
Flow
Operator
Well #
County, State
Location/Basin
Comp. Date
1
2,666.67 Boepd (16 MMcfpd)
WPX Energy
GM 701-4 HN1 Garfield, Colo.
Piceance
Dec. 2012
2
1,831.3 Boepd (367,875 Mcf; 1,770 Bopd)
EOG Resources, Inc.
2-01H Jake
Weld, Colo.
Denver Julesburg
Dec. 2009
3
1,770 Boepd (2.4 MMcf, 1,270 Bopd)
Chesapeake
33-71 25-1H Sims
Converse, Wyo.
Powder River
Aug. 2012
4
1,677.3 Boepd (4.94 MMcf, 854 Bopd)
Chesapeake
29-33-70 1H Combs Ranch Unit
Converse, Wyo.
Powder River
May 2012
5
1,605 Boepd (3 MMcf, 1,105 Bopd)
Chesapeake
23-33-71A 3H Wallis
Converse, Wyo.
Powder River
Sept. 2012
6
1,451.3 Boepd (3.61 MMcf, 849 Bopd)
Chesapeake
32-35-71A 1H Box Creek
Converse, Wyo.
Powder River
Sept. 2012
7
1,441.67 Boepd (2.2 MMcf, 1,075 Bopd)
Chesapeake
25-34-71 STA 1H Clausen Ranch
Converse, Wyo.
Powder River
Aug. 2012
8
1,321 Boepd (1.56 MMcf, 1,061 Bopd)
Whiting Oil & Gas Corp.
16-13H Wild Horse
Weld, Colo.
Denver Julesburg
June 2011
9
1,243.3 Boepd (7.46 MMcfpd)*
Encana Oil & Gas
20-12H (K20OU) Orchard Unit
Mesa, Colo.
Piceance
Jan. 2010
10
1,110.3 Boepd (2.15 MMcf, 752 Bopd)
Chesapeake
26-33-70A 1H York Ranch
Converse, Wyo.
Powder River
Aug. 2012
11
1,100 Bopd
EOG Resources, Inc.
10-16H Red Poll
Weld, Colo.
Denver Julesburg
June 2010
12
1,075 Boepd**
SM Energy Co.
1-19H Atlas
Laramie, Wyo.
Denver Julesburg
May 2010
Data Source: HIS Inc. *Source: Encana Oil & Gas
**Source: SM Energy
Gas: 6,000 cu. ft. of gas = 1 bbl. of oil equivalent
Howard Weil 41st Annual Energy Conference - March 19, 2013
12
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
+6 -496
4,500 4,000
+634
+848
-498
5,339
4,984.0
4,846 4,350.2
4,350.2
Production
Extensions & Discoveries
4,492.0
4,491
Revisions
YE2012 SEC Case
4,491.1
3,500 3,000 YE2011 Adjusted for Asset Sale
Purchases and 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
Howard Weil 41st Annual Energy Conference - March 19, 2013
13
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
80.0 MMboe Proved 173.4 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 TotalDomestic 4,650 Bcfe Proved 18,530 Bcfe 3P 1,558,124 Net Acres
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
Howard Weil 41st Annual Energy Conference - March 19, 2013
14
Appendix
Key Statistics by Basin
Net Acreage (YE2012)
2012 Average Rig Count (Operated)
2012 Production (MMcfe/d)
Oil/NGL Focused
3P Gross Drilling Locations
Proved Reserves (YE2012 Bcfe)
3P Reserves (YE2012 Bcfe)
Additional Resource Potential
Primary Areas of Focus Piceance
216,829
5.4
852
X
10,424
3,010
12,039
20 - 30 Tcfe
Bakken
84,205
5.7
10.3 Mboe/d
X
478
80 MMboe
173 MMboe
Evaluating
Marcellus
114,067
2.1
63
561
322
2,023
Evaluating
San Juan
155,472
0
133
1,914
423
1,873
2 - 3 Tcfe
Total
570,573
13
1,110
13,377
4,235
16,975
22 - 33 Tcfe
Exploration
Exploration
X
75 - 100 MMboe
Other Powder River
398,470
0
209
Apco*
435,191
0
9.2 Mboe/d
Other
153,890
0
12
X
1,945
236
1,044
Evaluating
627
25 MMboe
62 MMboe
Evaluating
1,298
29
141
•Reflects WPX’s 69% ownership, except 3P drilling locations which are gross Chart numbers affected by rounding
Howard Weil 41st Annual Energy Conference - March 19, 2013
16
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 $3.68per Mcf, oil price of $86.75and 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.
Howard Weil 41st Annual Energy Conference - March 19, 2013
17
Piceance Basin Continues to Deliver Efficiencies and Lower Costs Prolific resource with 3P Reserves of 12.2 Tcfe with 10,000 locations Drilling efficiencies = More wells with fewer rigs ►
►
►
Spud 42 wells in 4Q with 5 rigs, 208 spuds for 2012 Record well in Valley: 3.7 days, Ryan Gulch 7.7 days Average Valley drilling time reduced to 8 days, 11.5 days in Ryan Gulch
Water infrastructure lowering costs ►
►
Added 8,400 Bpd capacity to existing injection to reduce disposal costs further 100% recycled water utilized for hydraulic fracturing
WPX received 2 awards for environmental protection in 2012 1st Niobrara horizontal well drilled, completed and producing ► ►
► ►
16 MMcf/d @ 7,300 psi 30-day average – 12 MMcf/d @ 6,800 psi FCP 60-day average – 10.6 MMcf/d @ 6,300 psi FCP First 60 days – 0.64 Bcf produced
Drilling Performance Spud to Rig Release (Days)
30
2009
2010
25
2011
2012
2012 Record
20
15
10
5
0 Ryan Gulch
Valley
Howard Weil 41st Annual Energy Conference - March 19, 2013
18
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
Howard Weil 41st Annual Energy Conference - March 19, 2013
19
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 100 200 Mcf of additional interruptible) Echo Springs, 120 MMcf/d Adding new Parachute, 350 MMcf/d (ISD ’14)
Howard Weil 41st Annual Energy Conference - March 19, 2013
20
Piceance Composite NGL Barrel and Realized Price (4th Quarter, 2012) Product Mix
$/Gal
Ethane(1)
50%
.29
Propane
23%
.88
Iso-Butane
7%
1.82
Normal Butane
6%
1.64
Natural Gasoline
14%
2.15
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 in the 4th quarter.
Howard Weil 41st Annual Energy Conference - March 19, 2013
21
Piceance Basin Green: HighlandsYellow: Yellow: Valley Green: Highlands Valley Acreage: 292,000/230,000 (gross/net) Net Acreage: 216,829(1) Average rigs running in 2013: 5 Average rigs running in 9,884 2013: 5 Undrilled locations: Remaining 3P drilling locations:Liquids 10,424(1) Composition: 80% Gas/20% Composition: 80% Gas/20% Liquids
(1) Acreage and drilling locations are based on YE 2012
Howard Weil 41st Annual Energy Conference - March 19, 2013
22
4Q 2012 Bakken Drilling Results Drilling performance improved significantly over prior periods: Spud 11 wells w/5 rigs ►
►
8 Middle Bakken (Green) 3 Three Forks (Dark Green)
Finalizing “One & Gone” drilling ►
7 wells drilled ►
►
4 long laterals ► Average drill days: 33 days 3 short laterals ► Average drill days: 21 days
3 rigs converted to brine drilling fluid system ►
►
1st long lateral well drilled in 27-day average (1 MB and 1 Three Forks) Cost reduced by ~$200k
Howard Weil 41st Annual Energy Conference - March 19, 2013
23
4Q 2012 Bakken Completion Results 14 wells put on 1st sales ► ► ► ►
10 Middle Bakken (Blue) 4 Three Forks (Dark Blue) 10 long laterals 4 short laterals
Finalizing “One & Gone” completions ►
4 completions in 4Q’12 ►
►
4 long laterals
6 completions in 1Q’13 ►
4 long laterals; 2 short laterals
Zipper frac completions successful in reducing costs ►
►
►
3 short lateral wells completed in
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.
Howard Weil 41st Annual Energy Conference - March 19, 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.
Howard Weil 41st Annual Energy Conference - March 19, 2013
3
2013 Path to Greater Shareholder Value
Grow oil production
Maintain disciplined natural gas development, poised for rapid growth when prices recover Continue cost improvements Pursue new opportunities, including Niobrara discovery and oil exploration
Howard Weil 41st Annual Energy Conference - March 19, 2013
4
2013 Strategy Driving Shareholder Value Transition to multi-well pads driving Bakken production growth and lower well costs ► ►
Strong annual production growth of approximately 25 - 30% Recent long lateral wells result in 10 - 20% lower cost ► ► ►
►
Multi-well pad drilling Zipper frac completions Spud to rig release days reduced; record well, 25 days
Doing more with less; 29% efficiency gain in wells drilled in 2013 ► ►
2012: Drilled 43 gross wells while averaging 5.7 rigs 2013: Plan to drill approximately 40 gross wells while averaging 4.1 rigs
Focused infrastructure supporting development ►
Van Hook gathering system improves netbacks by $2 - $4 barrel, Unit Rail with East and West Coasts access starts 2Q ’13
Piceance – Unique, world-class position delivers proven track record of attractive returns and long-lived inventory ► ► ►
Significant growth potential with more than 10,000 3P remaining locations(1) Favorable long-term liquids processing contracts with new Willow Creek contract, effective 1/1/13 Continuous operational efficiencies lead to further well-cost reductions
Marcellus – Strong production growth, increasing EURs and lower cost ► ► ►
►
Production growth of 75% - 80% in 2013 Completion cost down 46% from 4Q ’11 to 4Q ’12 Spud to rig release down 60% from 3Q ’10; record 11 days Demonstrating capital flexibility within play by moving rig to improving Westmoreland
(1) The Piceance remaining locations exclude any potential locations related to our recent Niobrara discovery
Howard Weil 41st Annual Energy Conference - March 19, 2013
5
2013 Strategy Driving Shareholder Value
(continued)
First horizontal Niobrara Shale well in Piceance Basin is a major discovery ► ►
20 - 30 Tcfe of resource potential Additional resource that will provide significant ability to rapidly grow production and reserves ►
►
180,000 acres HBP and infrastructure already in place
Plan for 4 horizontal wells in 2013 ► ► ►
Focus on proving adjacent acreage and demonstrating repeatability of play Ability to quickly move to development mode Significant gathering, processing and transportation takeaway already in place
Opened data room to explore monetization of Powder River Basin ►
We continue to review other potential value-creating options including asset-specific joint ventures, MLPs and royalty trust
Howard Weil 41st Annual Energy Conference - March 19, 2013
6
Preeminent Piceance Position Superior acreage position WPX contrast to offset operators ► ►
38% less D&C capital costs (1) 53% less operating lifting costs (2)
State-of-the-art water management systems Infrastructure and takeaway capacity in place New emerging play ►
►
$2,000
Initial IP 16 MMcf/d 30-day average 12 MMcf/d 60-day average @ 10.6 MMcf/d
$1,000
►
Up to 4 new horizontal wells planned in 2013 180,000 net acres held by production 20 - 30 TCF resource potential
WPX Energy
$2,500
$1,500
►
►
Offset Operator
Niobrara discovery well drilled in 2012 ►
►
WPX vs. Offset Operator Well D&C and Lifting Costs
53% Less
38% Less
$500 $0 D&C Well Cost ($M/well)
Lifting Cost ($/well/month)
Notes: (1) Utilizing data from eight 2012 Rulison field non-op wells (2) Utilizing data from 221 Valley non-op wells
Howard Weil 41st Annual Energy Conference - March 19, 2013
7
WPX Positioned for Rapid Growth when Natural Gas Prices Recover We’ve done it before…
We are ready to do it again…
12% CAGR 800
Well Count
700
400
900
350
800
300
+157 Bcfe
600
238 197
500
116
300
251
150
650
550
489
81
200
301 10
25
22
17
250 200
152
400
100
1,000
26
0
2005
2006
2007
2008
600
400
370
350
+155 Bcfe
310
450
300
269
250
500 200
400 300
100
200
50
100
0
2004
700
424
400
262
150
577
576
573
539
100
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
Howard Weil 41st Annual Energy Conference - March 19, 2013
8
Net Operated Bcfe
900
450
Well Count
Well Count Avg. Rig Count Net Op Bcfe
Net Operated Bcfe
1,000
Bakken Creating Value – Improving Well Performance, Lowering Cost and Strong Reserve Growth 28 of 31 wells put on first sales in 2012 were at, or surpassed, our well performance expectations Top 10 performers: 4 - Middle Bakken, 6 - Three Forks Proved Reserves ►
Four Middle Bakken wells averaged ~38% higher than expectations Six Three Forks wells averaged > 14% higher than expectations
Middle Bakken delivering excellent results Independence 2-35HC (Middle Bakken – Long Lateral) ►
9% higher than type well
Three Forks exceeding expectations Kate Soldier 23-14HZ (Three Forks – Long Lateral) ►
90
80.0
80 Proved Reserves, MMboe
►
70 60
47.6
50 40 30
22.9
20
10 0
YE'10
17% higher than type well
D&C cost down 10 - 20% on recent long lateral wells
YE'11
Percent Held by Production 100%
Drilling improvements lowering drilling days New efficiency rigs, experienced personnel and brine fluid system Spud to rig release improvement: ► ► ►
2012 average 1Q 2013 average Black Hawk 1-26HW
43 days 32 days 25 days
YE'12
~98%
90% 80% 70% 60% 50%
36%
40% 30% 20%
16%
10% 0%
YE'10
YE'11
Howard Weil 41st Annual Energy Conference - March 19, 2013
YE'12
9
Appalachia – Strong Production & Reserves Growth, Increasing EURs, Lower Well Cost Strong reserves growth demonstrated by proved reserves
Proved Reserves
Over 1,000% reserve growth since 2010
350
Susquehanna County compression pilots doubled production confirming our type curve Production increased 320% over 2011 to an average of 63 MMcf/d in 2012
Proved Reserves, Bcf
►
300 250 200
142
150 100 50
28
0
Williams field receipt point compression scheduled to come on 1Q 2013 ►
322
YE'10
Currently 30 MMcf/d of net production constrained
YE'11
Average Production by Year
Completion costs continue their downward trend ►
Completion cost down 46% from 4Q ’11 to 4Q ’12
Net Production MMcf/d
70
Westmoreland wells continue to outperform expectations
YE'12
63
60 50 40 30
15
20 10
5
2010
2011
Howard Weil 41st Annual Energy Conference - March 19, 2013
2012
10
Emerging Niobrara Resource Play – Piceance Basin Basin-wide Niobrara activity de-risking play WPX has 20 - 30 Tcf Resource Potential
► ► ►
40 Niobrara horizontals drilled Multiple horizontal pay zones Horizontal EURs 6+ Bcf
WPX Energy activity: 2011
WPX Lease Position
►
180,000 net acres (Deep)
►
►
Drilled vertical test well in 4Q Completed 2 Niobrara zones with promising results Additional potential zones to be tested in 2013
WPX Energy activity: 2012 ►
► ►
Horizontal test well drilled, completed and producing by YE 2012 Obtained 535′ core and specialty logs Has produced for last 60 days ► ► ►
IP 16 MMcf/d @7,300 psi 60 day average – 10.6 MMcf/d @ 6,300 psi First 60 days – 0.64 Bcf produced
Howard Weil 41st Annual Energy Conference - March 19, 2013
11
WPX Has Drilled the Top Niobrara Shale Well (Based on IP Rate) Ranking
Flow
Operator
Well #
County, State
Location/Basin
Comp. Date
1
2,666.67 Boepd (16 MMcfpd)
WPX Energy
GM 701-4 HN1 Garfield, Colo.
Piceance
Dec. 2012
2
1,831.3 Boepd (367,875 Mcf; 1,770 Bopd)
EOG Resources, Inc.
2-01H Jake
Weld, Colo.
Denver Julesburg
Dec. 2009
3
1,770 Boepd (2.4 MMcf, 1,270 Bopd)
Chesapeake
33-71 25-1H Sims
Converse, Wyo.
Powder River
Aug. 2012
4
1,677.3 Boepd (4.94 MMcf, 854 Bopd)
Chesapeake
29-33-70 1H Combs Ranch Unit
Converse, Wyo.
Powder River
May 2012
5
1,605 Boepd (3 MMcf, 1,105 Bopd)
Chesapeake
23-33-71A 3H Wallis
Converse, Wyo.
Powder River
Sept. 2012
6
1,451.3 Boepd (3.61 MMcf, 849 Bopd)
Chesapeake
32-35-71A 1H Box Creek
Converse, Wyo.
Powder River
Sept. 2012
7
1,441.67 Boepd (2.2 MMcf, 1,075 Bopd)
Chesapeake
25-34-71 STA 1H Clausen Ranch
Converse, Wyo.
Powder River
Aug. 2012
8
1,321 Boepd (1.56 MMcf, 1,061 Bopd)
Whiting Oil & Gas Corp.
16-13H Wild Horse
Weld, Colo.
Denver Julesburg
June 2011
9
1,243.3 Boepd (7.46 MMcfpd)*
Encana Oil & Gas
20-12H (K20OU) Orchard Unit
Mesa, Colo.
Piceance
Jan. 2010
10
1,110.3 Boepd (2.15 MMcf, 752 Bopd)
Chesapeake
26-33-70A 1H York Ranch
Converse, Wyo.
Powder River
Aug. 2012
11
1,100 Bopd
EOG Resources, Inc.
10-16H Red Poll
Weld, Colo.
Denver Julesburg
June 2010
12
1,075 Boepd**
SM Energy Co.
1-19H Atlas
Laramie, Wyo.
Denver Julesburg
May 2010
Data Source: HIS Inc. *Source: Encana Oil & Gas
**Source: SM Energy
Gas: 6,000 cu. ft. of gas = 1 bbl. of oil equivalent
Howard Weil 41st Annual Energy Conference - March 19, 2013
12
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
+6 -496
4,500 4,000
+634
+848
-498
5,339
4,984.0
4,846 4,350.2
4,350.2
Production
Extensions & Discoveries
4,492.0
4,491
Revisions
YE2012 SEC Case
4,491.1
3,500 3,000 YE2011 Adjusted for Asset Sale
Purchases and 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
Howard Weil 41st Annual Energy Conference - March 19, 2013
13
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
80.0 MMboe Proved 173.4 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 TotalDomestic 4,650 Bcfe Proved 18,530 Bcfe 3P 1,558,124 Net Acres
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
Howard Weil 41st Annual Energy Conference - March 19, 2013
14
Appendix
Key Statistics by Basin
Net Acreage (YE2012)
2012 Average Rig Count (Operated)
2012 Production (MMcfe/d)
Oil/NGL Focused
3P Gross Drilling Locations
Proved Reserves (YE2012 Bcfe)
3P Reserves (YE2012 Bcfe)
Additional Resource Potential
Primary Areas of Focus Piceance
216,829
5.4
852
X
10,424
3,010
12,039
20 - 30 Tcfe
Bakken
84,205
5.7
10.3 Mboe/d
X
478
80 MMboe
173 MMboe
Evaluating
Marcellus
114,067
2.1
63
561
322
2,023
Evaluating
San Juan
155,472
0
133
1,914
423
1,873
2 - 3 Tcfe
Total
570,573
13
1,110
13,377
4,235
16,975
22 - 33 Tcfe
Exploration
Exploration
X
75 - 100 MMboe
Other Powder River
398,470
0
209
Apco*
435,191
0
9.2 Mboe/d
Other
153,890
0
12
X
1,945
236
1,044
Evaluating
627
25 MMboe
62 MMboe
Evaluating
1,298
29
141
•Reflects WPX’s 69% ownership, except 3P drilling locations which are gross Chart numbers affected by rounding
Howard Weil 41st Annual Energy Conference - March 19, 2013
16
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 $3.68per Mcf, oil price of $86.75and 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.
Howard Weil 41st Annual Energy Conference - March 19, 2013
17
Piceance Basin Continues to Deliver Efficiencies and Lower Costs Prolific resource with 3P Reserves of 12.2 Tcfe with 10,000 locations Drilling efficiencies = More wells with fewer rigs ►
►
►
Spud 42 wells in 4Q with 5 rigs, 208 spuds for 2012 Record well in Valley: 3.7 days, Ryan Gulch 7.7 days Average Valley drilling time reduced to 8 days, 11.5 days in Ryan Gulch
Water infrastructure lowering costs ►
►
Added 8,400 Bpd capacity to existing injection to reduce disposal costs further 100% recycled water utilized for hydraulic fracturing
WPX received 2 awards for environmental protection in 2012 1st Niobrara horizontal well drilled, completed and producing ► ►
► ►
16 MMcf/d @ 7,300 psi 30-day average – 12 MMcf/d @ 6,800 psi FCP 60-day average – 10.6 MMcf/d @ 6,300 psi FCP First 60 days – 0.64 Bcf produced
Drilling Performance Spud to Rig Release (Days)
30
2009
2010
25
2011
2012
2012 Record
20
15
10
5
0 Ryan Gulch
Valley
Howard Weil 41st Annual Energy Conference - March 19, 2013
18
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
Howard Weil 41st Annual Energy Conference - March 19, 2013
19
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 100 200 Mcf of additional interruptible) Echo Springs, 120 MMcf/d Adding new Parachute, 350 MMcf/d (ISD ’14)
Howard Weil 41st Annual Energy Conference - March 19, 2013
20
Piceance Composite NGL Barrel and Realized Price (4th Quarter, 2012) Product Mix
$/Gal
Ethane(1)
50%
.29
Propane
23%
.88
Iso-Butane
7%
1.82
Normal Butane
6%
1.64
Natural Gasoline
14%
2.15
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 in the 4th quarter.
Howard Weil 41st Annual Energy Conference - March 19, 2013
21
Piceance Basin Green: HighlandsYellow: Yellow: Valley Green: Highlands Valley Acreage: 292,000/230,000 (gross/net) Net Acreage: 216,829(1) Average rigs running in 2013: 5 Average rigs running in 9,884 2013: 5 Undrilled locations: Remaining 3P drilling locations:Liquids 10,424(1) Composition: 80% Gas/20% Composition: 80% Gas/20% Liquids
(1) Acreage and drilling locations are based on YE 2012
Howard Weil 41st Annual Energy Conference - March 19, 2013
22
4Q 2012 Bakken Drilling Results Drilling performance improved significantly over prior periods: Spud 11 wells w/5 rigs ►
►
8 Middle Bakken (Green) 3 Three Forks (Dark Green)
Finalizing “One & Gone” drilling ►
7 wells drilled ►
►
4 long laterals ► Average drill days: 33 days 3 short laterals ► Average drill days: 21 days
3 rigs converted to brine drilling fluid system ►
►
1st long lateral well drilled in 27-day average (1 MB and 1 Three Forks) Cost reduced by ~$200k
Howard Weil 41st Annual Energy Conference - March 19, 2013
23
4Q 2012 Bakken Completion Results 14 wells put on 1st sales ► ► ► ►
10 Middle Bakken (Blue) 4 Three Forks (Dark Blue) 10 long laterals 4 short laterals
Finalizing “One & Gone” completions ►
4 completions in 4Q’12 ►
►
4 long laterals
6 completions in 1Q’13 ►
4 long laterals; 2 short laterals
Zipper frac completions successful in reducing costs ►
►
►
3 short lateral wells completed in
