Operational Update - WPX Energy
May 7, 2014
Operational Update Jim Bender, Chief Executive Officer
Disclaimer The information contained in this summary has been prepared to assist you in making your own evaluation of the Company and does not purport to contain all of the information you may consider important in deciding whether to invest in shares of the Company’s common stock. In all cases, it is your obligation to conduct your own due diligence. All information contained herein, including any estimates or projections, is based upon information provided by the Company. Any estimates or projections with respect to future performance have been provided to assist you in your evaluation but should not be relied upon as an accurate representation of future results. No persons have been authorized to make any representations other than those contained in this summary, and if given or made, such representations should not be considered as authorized. Certain statements, estimates and financial information contained in this summary constitute forward-looking statements or information. Such forward-looking statements or information involve known and unknown risks and uncertainties that could cause actual events or results to differ materially from the results implied or expressed in such forward-looking statements or information. While presented with numerical specificity, certain forward-looking statements or information are based (1) upon assumptions that are inherently subject to significant business, economic, regulatory, environmental, seasonal, competitive uncertainties, contingencies and risks including, without limitation, the ability to obtain debt and equity financings, capital costs, construction costs, well production performance, operating costs, commodity pricing, differentials, royalty structures, field upgrading technology, and other known and unknown risks, all of which are difficult to predict and many of which are beyond the Company's control, and (2) upon assumptions with respect to future business decisions that are subject to change. There can be no assurance that the results implied or expressed in such forward-looking statements or information or the underlying assumptions will be realized and that actual results of operations or future events will not be materially different from the results implied or expressed in such forward-looking statements or information. Under no circumstances should the inclusion of the forward-looking statements or information be regarded as a representation, undertaking, warranty or prediction by the Company or any other person with respect to the accuracy thereof or the accuracy of the underlying assumptions, or that the Company will achieve or is likely to achieve any particular results. The forward-looking statements or information are made as of the date hereof and the Company disclaims any intent or obligation to update publicly or to revise any of the forward-looking statements or information, whether as a result of new information, future events or otherwise. Recipients are cautioned that forward-looking statements or information are not guarantees of future performance and, accordingly, recipients are expressly cautioned not to put undue reliance on forward-looking statements or information due to the inherent uncertainty therein.
WPX Operational Update | May 7, 2014
2
Reserves Disclaimer The SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and governmental regulations. The SEC permits the optional disclosure of probable and possible reserves. We have elected to use in this presentation “probable” reserves and “possible” reserves, excluding their valuation. The SEC defines “probable” reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC defines “possible” reserves as “those additional reserves that are less certain to be recovered than probable reserves.” The Company has applied these definitions in estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s reserves reporting guidelines. Investors are urged to consider closely the disclosure regarding our business that may be accessed through the SEC’s website at www.sec.gov. The SEC’s rules prohibit us from filing resource estimates. Our resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves, (ii) other areas to take into account the low level of certainty of recovery of the resources and (iii) uneconomic proved, probable or possible reserves. Resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon. Resource estimates might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors.
WPX Operational Update | May 7, 2014
3
1st Quarter Highlights Adjusted EBITDAX increased 58% quarter over quarter Spud 68 wells in the Piceance 1st quarter ►
Successful 10-acre density testing in Ryan Gulch
36% quarter-over-quarter oil growth in Williston despite record cold weather ► ►
Added 5th rig in 1st quarter Initiated completions on new downspacing patterns
San Juan Gallup Sandstone results remain very favorable ► ► ►
Production grows to 1.7 Mbbl/d in 1Q Capturing efficiencies from pad drilling Added 2nd rig in 1st quarter
13 rigs running in the 1st quarter Exceeded 1st quarter guidance ► ►
Higher production Lower cost
WPX Operational Update | May 7, 2014
4
Legacy Transaction Particulars Legacy to purchase working interests for $355MM ►
Working interest in Piceance Valley ►
►
Excludes Ryan Gulch, Kokopelli, and the Niobrara and deeper formations
Interest only in producing wells drilled prior to Jan. 1, 2009 ► ► ►
2014: 30% of WPX working interest 2015: 37.5% of WPX working interest 2016 and beyond: 42% of WPX working interest
Transaction does not include interests in undeveloped locations or participation in future drilling Legacy provides WPX an interest in a newly created class of IDR units ►
IDR structure provides incentive for future deals
Anticipated closing in June Piceance Valley transaction metrics ► ► ►
1 Based
9% of total Piceance proved reserves Reserves sold: 279 Bcfe1 Five-year average future production: 71 MMcfe/d
Legacy Transaction
on contractual terms and current commodity price assumptions effective 12/31/2013.
WPX Operational Update | May 7, 2014
5
Legacy Transaction Superior to MLP Legacy Transaction
✓ ✓ ✓ ✓ ✓ ✓
MLP Transaction fills majority of 2014 funding gap, enhancing financial strength Meaningfully accretive to WPX’s current valuation
✓ ✓
Highlights undervalued Piceance asset
✓ ✓
IDR structure provides incentive for future deals
✓
WPX maintains operational control of assets
Provides monetization of gas assets without the ongoing administrative and development concerns of an MLP
WPX Operational Update | May 7, 2014
6
May 7, 2014
Operational Update Bryan Guderian, Sr. VP of Operations
Piceance Highlights 1st-quarter activity ►
Spud 68 wells 8th rig arrived in March
Continuing to drive down D&C cost ►
2013 plan versus actual 2013 July-December ► ►
Valley D&C cost down 10% Ryan Gulch D&C cost down 23%
Improved water handling ►
►
Drilling & Completion Cost ($M)
►
Total Well Cost 2013 3,000
2013 Plan
2013 Jan-Jun
2013 Jul-Dec
2,800 2,357
2,500 2,000 1,500
1,389
1,276 1,246
1,000 500 0 Valley
Water-sharing agreements with other operators Renegotiated chemical, water-hauling and equipment contracts
2,157
Ryan Gulch
Spud-to-Release Performance 30
2009
2010
2011
2012
2013
Record
25
2014 Niobrara program Drilling resumes early May ► ►
►
Spud a horizontal and a vertical well in early May Arrival of new rig with high pressure capability needed for horizontal drilling in the Niobrara
Up to 10 wells planned for 2014
Days
►
20 15 10 5 0
3.8 Grand Valley
5.0 Parachute
6.8 Rulison
8.5
Ryan Gulch
WPX Operational Update | May 7, 2014
8
Long-Term Value: Piceance Ryan Gulch Ryan Gulch offers competitive returns ► ►
Ryan Gulch Drilling Days per Well
Returns are comparable to Valley operations Higher NGLs and EURs compared to Valley
30
26.3
25
Well costs reduced to $2.3MM ► ►
Drilling days continue downward trend Record well in 8.1 days in 2014 Completion costs at $1.2MM in 2013
19.1
20
Days
►
24.7
15.3
15
12.8
11.8
2012
2013
10
9.9
5
EURs increased to >2 Bcfe
0 2008
2009
2010
2011
2014
Water infrastructure improvements ► ►
Increased water-injection capacity Reduced water-handling costs
4.5 4.0
Successful 10-acre density strengthens inventory ► ►
3,682 Bcfe 3P reserves 4,317 undrilled 3P-well locations
$3.55
3.0
($MM)
►
60,992 gross acres 35,640 net acres
$4.03
3.5
Extensive land position ►
Ryan Gulch D&C Well Costs
$3.11
$3.19 $2.54
2.5
$2.26
2.0 1.5 1.0 0.5 0.0 2008
2009
2010
2011
2012
WPX Operational Update | May 7, 2014
2013
9
Well Performance Drives Strong Williston Production Growth Continued strong production growth ►
►
Four Bears Village
Produced 15.6 Mbo/d in 1Q (17.7 Mboe/d) 40% production growth vs. 1Q 2013
Parshall FBIR 13-24HZ FIRST SALES: 3/12/2014 30 DAY IP: 1,533 BOPD
11 wells put on 1st sales ► ► ►
Initial 30-day average of 1,266 bo/d 7 Middle Bakken 4 Three Forks
Added 5th rig in 1Q ► ►
New drilling pattern for all future wells 62 wells planned for 2014
Started completing on tighter density patterns ►
Encouraging results from 3 Alfred Old Dog wells
New Town
ALFRED OLD DOG 19-18HC FIRST SALES: 3/27/2014 30 DAY IP: 1,681 BOPD
OLSON 12-1HD FIRST SALES: 1/20/2014 30 DAY IP: 1,185 BOPD
ALFRED OLD DOG 19-18HY FIRST SALES: 3/30/2014 30 DAY IP: 1,223 BOPD ALFRED OLD DOG 19-18HB FIRST SALES: 3/27/2014 30 DAY IP: 1,163 BOPD
Mandaree
MARTIN FOX 20-17HZ FIRST SALES: 2/19/2014 30 DAY IP: 1,249 BOPD
FBIR 13-24HC FIRST SALES: 3/12/2014 30 DAY IP: 966 BOPD
FBIR 13-24HD FIRST SALES: 3/13/2014 30 DAY IP: 1,398 BOPD OLSON 12-1HY FIRST SALES: 1/21/2014 30 DAY IP: 929 BOPD
MARTIN FOX 20-17HC FIRST SALES: 2/19/2014 30 DAY IP: 1,156 BOPD
MARTIN FOX 20-17HD FIRST SALES: 2/19/2014 30 DAY IP: 1,438 BOPD
Producing Well Middle Bakken Well
Pad development reducing costs ► ► ►
►
Improved cycle times Batch drilling lowers fluid costs Greater utilization of rig-walking capabilities Zipper-frac efficiencies
Three Forks Well Alfred Old Dog Pad WPX Unit
WPX Operational Update | May 7, 2014
10
San Juan Gallup Generating Excellent Results Production exceeds 1Q plan ► ►
Oil production grows to average of 1.7 Mbo/d Total production averaged 2.2 Mboe/d
Development program advancing ► ► ►
7 wells spud 1Q Added 2nd rig 1st multi-well pad average 30-day IP: 420 bo/d1
CHACO 2306 06L #178H FIRST SALES: 3/9/2014 AVG. 30-DAY IP: 433 BOPD CHACO 2308 09A #149H FIRST SALES: 4/16/2014
CHACO 2308 09A #145H FIRST SALES: 4/21/2014
Pursuing well-cost efficiencies ► ►
► ►
Transitioned to pad development Top-setting wells with smaller rig; saves 3 drilling days per well First zipper frac completed on 3-well pad Shared-surface facilities for multi-well pads
CHACO 2306 06L #179H FIRST SALES: 3/6/2014 AVG. 30-DAY IP: 407 BOPD
CHACO 2306 06L #239H FIRST SALES: 3/9/2014 AVG. 30-DAY IP: 420 BOPD
CHACO 2307 12E #169H FIRST SALES: WOC
CHACO 2308 09A #146H FIRST SALES: WOC
CHACO 2307 13L #238H FIRST SALES: WOC
CHACO 2307 13L #174H FIRST SALES: WOC
48,600 net acres in oil window ►
Added additional 4,600 acres since February
2014 outlook ► ► ►
275% Y/Y growth in daily oil production Spud 29 gross wells Average 2 rigs
WPX-Drilling Horizontal Oil Wells WPX-Completed Horizontal Oil Wells WPX Acreage (Shallow/Deep Rights)
1 Based
on the first 30 uninterrupted days of production
WPX Operational Update | May 7, 2014
11
Financial Results
Kevin Vann, Chief Financial Officer
1st Quarter Results Dollars in millions, except production numbers
2014
1Q
2013
Daily Production Gas (MMcf/d)
975
1,021
Oil (Mbbl/d)
24.5
19.4
NGLs (Mbbl/d)
18.1
21.7
Equivalent (MMcfe/d)
1,230
1,268
Adjusted EBITDAX
$320
$203
Adjusted Net Income (Loss) from Continuing Operations
$44
$(51)
$(352)
$(271)
Capital Expenditures
Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant measures included in GAAP is provided in this presentation.
WPX Operational Update | May 7, 2014
13
2014: 2nd Quarter and Full-Year Guidance Production
Natural Gas MMcf/d Oil Mbbl/d NGL Mbbl/d Total MMcfe/d
Cap Ex ($ in Millions)
% of Net Realized Price3
918 - 9257 25.8 - 26.3 18.3 - 18.77 1,183 - 1,195
FY 2014
925 - 934 28.1 - 28.5 18.3 - 18.7 1,203 - 1,217
2Q
FY 2014
Expenses
2Q
Growth Basins Piceance Williston San Juan Gallup Other Appalachia Other1 Land Exploration Total Domestic International2 Total Capital
$115 - $125 140 - 150 40 - 45
$475 - $495 580 - 600 155 - 180
10 - 15 0-5 15 - 20 10 - 15 $330 - $375 25 - 35 $355 - $410
20 - 30 10 - 15 75 - 85 25 - 30 $1,340 - $1,435 80 - 90 $1,420 - $1,525
Number of Rigs
2Q
FY 2014
Piceance Valley Piceance Highlands Piceance Niobrara Total Piceance Williston San Juan Gallup Total Rigs
(Includes Impact of Legacy Transaction)
7 1 1 9 5 2 16
Note: Blue font indicates change from previous guidance
7 1 1 9 5 2 16
Natural Gas - NYMEX Oil - WTI NGL - OPIS/Mt Belvieu5
$ per Mcfe LOE DD&A GP&T SG&A Production Tax $ in Millions Gas Management (Inc)/Exp4 Exploration Interest Expense Equity (Earnings) Loss
Tax Rate Tax Provision
2Q
FY 2014
80% - 85% 81% - 86% 75% - 79%
81% - 87% 81% - 87% 76% - 80%
2Q
FY 2014
$0.74 - $0.76 1.90 - 1.95 0.95 - 1.00 0.66 - 0.68 0.42 - 0.46
$0.73 - $0.75 1.95 - 2.00 0.93 - 0.98 0.63 - 0.67 0.42 - 0.46
$20 - $25 15 - 20 29 - 30 (4) - (6)
$0 - $10 70 - 80 120 - 130 (20) - (25)
2Q
FY 2014
33% - 37%
33% - 37%6
1 Other
includes expenditures for Powder River and Other basins. is a self-funded entity and does not receive any cash from WPX Energy. 3 Percentage of realized price ranges for NYMEX, WTI and OPIS exclude hedges, but include basis differential and revenue adjustments. 4 Gas Management impact is net of revenues and expenses and includes unutilized transport capacity. Includes impact of realized and unrealized hedges on non-equity production. 5 Assumed NGL composite barrel: Ethane 37%, Propane 28%, Isobutane 8%, NormButane 7% and Natural Gasoline 20%. 6 Excludes impact of $9MM tax expense accrual for new legislation in 1Q ’14. 7 Assumes partial- quarter impact of Legacy transaction closing in June. 2 International
WPX Operational Update | May 7, 2014
14
2014 Path to Greater Shareholder Value Legacy transaction in lieu of forming an MLP – generates ~$355MM Stronger commodity prices increasing annual EBITDAX over previous guidance estimate Projected domestic oil growth of 39% year over year Further cost improvements to strengthen cash margin Further rationalization of portfolio being considered 2014 path to greater shareholder value
WPX Operational Update | May 7, 2014
15
Appendix
WPX Portfolio Piceance
Williston
San Juan
Appalachia
Powder River
Apco1
3,019 Bcfe Proved 11,878 Bcfe 3P 221,186 Net Acres
105 MMboe Proved 176 MMboe 3P 80,736 Net Acres
517 Bcfe Proved 1,645 Bcfe 3P 160,825 Net Acres
328 Bcfe Proved 1,555 Bcfe 3P 87,994 Net Acres
245 Bcfe Proved 657 Bcfe 3P 360,002 Net Acres
22 MMboe Proved 58 MMboe 3P 385,796 Net Acres
Total 2Domestic
WILLISTON BASIN
4,905 Bcfe Proved 17,211 Bcfe 3P 1,554,635 Net Acres
POWDER RIVER BASIN PICEANCE BASIN
APPALACHIAN BASIN
SAN JUAN BASIN Natural Gas Oil
ARGENTINA
Natural Gas and Natural Gas Liquids Note: Acreage, proved and 3P numbers are as of 12/31/13. 1 Reflects 2 Total
WPX’s 69% ownership in APCO, as well as additional acreage owned by WPX. includes other reserves and acreage not depicted on slide. WPX Operational Update | May 7, 2014
17
Hedging Overview
As of 5/5/2014
2Q - 4Q 2014 Volumes
2Q - 4Q 2014 Price
2015 Volumes
2015 Price
(BBtu/d)
($MMBtu)
(BBtu/d)
($MMBtu)
Fixed Price Swaps 1,3
315
$4.19
182
$4.35
Collars
190
$4.04 - $4.66
50
$4.00 - $4.50
(bbl/d)
($/bbl)
(bbl/d)
($/bbl)
12,750
$94.62
3,500
$93.33
Natural Gas Liquids
(bbl/d)
($/gallon)
(bbl/d)
($/gallon)
Ethane Swaps
3,273
$0.29
18
–
Propane Swaps
491
$1.17
–
–
Isobutane Swaps
655
$1.37
–
–
Normal Butane Swaps
327
$1.38
–
–
1,636
$2.06
–
–
Natural Gas1
Crude Oil Fixed Price Swaps1,2,3
Natural Gasoline Swaps
1Details
for natural gas basis swaps can be found in our most recent quarterly report. ²Details for crude oil basis swaps can be found in our most recent quarterly report. 3In connection with several natural gas swaps, we entered into swaptions with the swap counterparties granting the counterparty the right but not the obligation to enter into an underlying swap with us in the future. For 2014, we have 50k MMBtu/d capped at a monthly settlement price of $4.24 per MMBtu, and for 2015, we have 50k MMBtu/d of natural gas capped at a settlement price of $4.38 per MMBtu and 5,250 bbl/d of crude oil capped at a settlement price of $95.06.
WPX Operational Update | May 7, 2014
18
Key Statistics by Basin Net Acreage (YE2013)
2014 Average Rig Count (Op)
2013 Production (MMcfe/d)
Oil/NGL Focused
Drillable Locations4
Proved Reserves (YE2013 Bcfe)
3P Reserves (YE2013 Bcfe)
Piceance1
221,186
9
727
X
12,475
3,019
11,878
Williston
80,736
5
14.8 Mboe/d
X
453
San Juan2
160,825
2
123
X
2,966
517
1,645
Appalachia
87,994
0
83
618
328
1,555
Total
550,741
16
1,022
16,512
4,497
16,133
2,872
245
657
664
22 MMboe
58 MMboe
2,820
20
72
Primary Areas of Focus
105.5 MMboe 176 MMboe
Exploration Exploration
X
Other Powder River
360,002
0
174
Apco3
385,796
0
9.0 Mboe/d
Other
258,096
0
8.0
Piceance includes Niobrara acreage, which underlies existing leasehold acreage. Juan Legacy includes both shallow and deep rights. 3 Reflects WPX’s 69% ownership, except 3P drilling locations, which are gross. 4 Includes operated and non-operated gross locations.
X
1
2 San
Chart numbers affected by rounding.
WPX Operational Update | May 7, 2014
19
2013-14 Daily Production 2013 1Q
2Q
3Q
4Q
Avg Total
2014
Gas (MMcf/d)
1,005
989
993
953
985
956
956
Oil (Mbbl/d)
13.8
15.1
17.1
18.9
16.2
19.3
19.3
NGLs (Mbbl/d)
21.2
20.8
19.7
19.7
20.3
17.6
17.6
MMcfe/d
1,215
1,205
1,214
1,184
1,204
1,177
1,177
Gas (MMcf/d)
17
18
19
19
18
19
19
Oil (Mbbl/d)
5.6
6.1
5.3
5.3
5.6
5.2
5.2
NGLs (Mbbl/d)
0.5
0.5
0.5
0.4
0.5
0.5
0.5
MMcfe/d
53
57
53
53
54
53
53
Gas (MMcf/d)
1,021
1,007
1,012
971
1,003
975
975
Oil (Mbbl/d)
19.4
21.2
22.4
24.2
21.8
24.5
24.5
NGLs (Mbbl/d)
21.7
21.3
20.1
20.1
20.8
18.1
18.1
MMcfe/d
1,268
1,262
1,267
1,237
1,258
1,230
1,230
1Q
Avg
Domestic Production
International Production
Total Production
WPX Operational Update | May 7, 2014
20
Growing Higher-Margin Oil 77% oil CAGR since 2010 ►
2014 growth in higher-margin oil
Record oil production in 2013
►
Averaged 16.2 Mbo/d – a 35% increase year over year Discovered and developing San Juan Mancos Gallup
► ►
► ► ►
39% year-over-year domestic oil growth Williston up 30% - 35% San Juan Gallup up 275% Allocated 51% of total capital
Total Domestic Oil Growth 2010-14 9,000 8,000
Annual Domestic Mbbl
7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 2010 Act
2011 Act
2012 Act
2013 Act
2014 Est
WPX Operational Update | May 7, 2014
21
Domestic Price Realization for 2014 Gas ($/Mcf) 1Q ’14 Weighted-Average Sales Price
2Q ’14
3Q ’14
NGL ($/bbl) 4Q ’14
1Q ’14
2Q ’14
3Q ’14
Oil ($/bbl) 4Q ’14
1Q ’14
$4.89
$49.14
$88.40
(0.49)
(10.87)
(2.16)
0.00
0.00
0.00
$4.40
$38.27
86.24
Realized Portion of Derivatives Not Designated as Hedges(3)
(0.52)
(0.48)
(2.30)
Net Price Including All Derivatives
$3.88
$37.79
$83.94
1
Revenue Adjustments Hedge Impact Net Price
(2)
1Q ’14 Impact of Rockies Sale-for-Resale Contract exp. in Nov. ’14
$(0.34)
Weighted-Average Sales Price Excluding Rex
$4.22
2Q ’14
3Q ’14
2Q ’14
3Q ’14
4Q ’14
4Q ’14 ►
1Q: Rockies sale-for-resale agreement impacted net realized gas price ($0.34). Contract expires in November 2014.
1Natural
gas revenue adjustments are primarily related to field compression fuel. NGL revenue adjustments include T&F and revenue sharing. Of the oil revenue adjustments, gathering deductions represent $(1.32).
2“Net
Price” equals income statement product revenues by commodity, divided by volume.
3Represents
the realized cash flows that occurred during each quarter, which are attributable to derivatives that were not designated as hedges for accounting purposes.
WPX Operational Update | May 7, 2014
22
Domestic Price Realization for 2013 Gas ($/Mcf)
NGL ($/bbl)
Oil ($/bbl)
1Q ’13
2Q ’13
3Q ’13
4Q’13
1Q ’13
2Q ’13
3Q ’13
4Q’13
1Q ’13
2Q ’13
3Q ’13
4Q’13
$3.12
$3.78
$3.16
$3.30
$37.27
$37.41
$43.10
$43.32
$89.23
$88.62
$99.43
$87.79
(0.27)
(0.33)
(0.44)
(0.43)
(9.06)
(7.20)
(11.91)
(9.99)
0.54
(0.86)
(1.52)
(2.29)
0.05
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
$2.90
$3.45
$2.72
$2.87
$28.21
$30.21
$31.19
$33.33
$89.77
$87.76
$97.91
$85.50
Realized Portion of Derivatives Not Designated as Hedges(3)
0.01
(0.28)
0.04
0.01
0.00
0.00
0.09
0.23
4.03
3.75
(2.63)
1.71
Net Price Including All Derivatives
$2.91
$3.17
$2.76
$2.88
$28.21
$30.21
$31.28
$33.56
$93.80
$91.51
$95.28
$87.21
1Q ’13
2Q ’13
3Q ’13
4Q ’13
Impact of Rockies Sale-for-Resale Contract exp. in Nov. ’14
$(0.26)
$(0.21)
$(0.29)
$(0.30)
Weighted-Average Sales Price Excluding Rex
$3.17
$3.38
$3.05
$3.18
Weighted-Average Sales Price 1
Revenue Adjustments Hedge Impact Net Price
(2)
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 $(1.35).
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 | May 7, 2014
23
Piceance Basin Orange: Highlands Yellow: Valley 1 Net acreage: 221,186 Current rig count: 9 Drillable locations: 12,4751 Composition: Gas/NGL focused
1 Acreage
and drilling locations are as of 12/31/13
Niobrara Dedicated Rig
WPX Operational Update | May 7, 2014
24
Piceance Composite NGL Barrel and Realized Price (1st Quarter, 2014)
$48.00
Product Mix
$/Gal
Ethane1
32%
.30
Propane
32%
1.28
Isobutane
9%
1.40
NGL Product
Weighted Average NGL $/barrel
$38.56
Net Realized Price
**$0.60 per Mcf NGL Uplift in 1Q 2014
Normal Butane
8%
1.37
Natural Gasoline
19%
2.11
*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 | May 7, 2014
25
Williston Basin Net acreage: 80,7361 Current rig count 2014: 5 Drillable Locations: 4531,2 Composition: Oil focused
1 Acreage 2
and drilling locations are as of 12/31/13 Does not include the impact of downspacing
WPX Operational Update | May 7, 2014
26
WPX is #1 in Middle Bakken Cumulative Production Average 365-day cumulative production per well of 136.8 Mbo, 52% higher than the peer average
1-Yr Cum.Production Oil Production 1-Yr andand 2-Yr 2-Yr Cumulative per Well1 (Based on productive days)
300,000
Average 730-day cumulative production per well of 240.8 Mbo, 66% higher than the peer average
►
►
►
Started using cement liners in May 2012 Identified plug and perf as superior completion method in early 2012 Reviewing new completion design: ► ► ►
►
Increase number of frac stages Increase perforation clusters Reduce pumping rate
Ceramic proppant (65/35) increases EUR
Cumulative Oil Production
Leader in completion design
250,000
WPX 2-Yr Cumulative Production per Well
Peer 2-Yr Cumulative Production per Well
WPX 1-Yr Cumulative Production per Well
Peer 1-Yr Cumulative Production per Well
200,000
150,000
100,000
50,000
0
¹Based on NDIC data for Middle Bakken longs put on 1st sales since January 2011. WPX acquired Williston properties December 2010. Cumulative production as of 12/31/2013.
Peer 2-Yr Avg
Peer 1-Yr Avg
WPX Operational Update | May 7, 2014
27
Williston Netback Price Analysis Sales Outlets
Estimated Volume % (Apr - Jun 2014)
Basin-Priced Sales
56%
Rail Deals
32%
Enbridge Capacity
12%
Total Sales Outlets
100%
Assumed 2Q 2014 total netback of WTI less $10 - $11 per barrel Our current sales agreements consist of the following: ► ► ►
Basin Sales: Arrow CDP WASP and lease sales Rail: Receive Gulf, West and East Coast pricing Enbridge: Receive Enbridge Clearbrook, Minn., price
Our sales agreements in 2014-16 are expected to consist of the following: ► ► ► ►
Basin sales: Receive a basket price from sales to third-party marketers Rail: Receive Gulf, West and East Coast pricing less associated fees Enbridge: Receive Clearbrook, Minn., price less associated fees Unit train rail options: WPX will have up to 14,000 bbl/d of committed unit train capacity through the first quarter of 2014, decreasing to 9,250 bbl/d until mid-2016, receiving West, East or Gulf Coast pricing less associated fees
WPX Operational Update | May 7, 2014
28
San Juan Basin
Green: Deep/Shallow Yellow: Shallow Net Acreage: 160,8251 Current rig count: 2 Drillable locations: 2,9661 Composition: Gas/Oil 1Acreage
and drilling locations are as of 12/31/13
WPX Operational Update | May 7, 2014
29
Apco Highlights Argentina Initiated 7-well Neuquén horizontal drilling program ► ► ►
Early results encouraging Two conventional horizontal wells put on production One well waiting to be completed
Eight development wells spud during 1Q Applied for the government’s gas incentive program to obtain higher gas pricing
Vaca Muerta Exposure Neuquén Basin (Vaca Muerta acreage) ► ► ► ► ►
Entre Lomas Bajada del Palo Agua Amarga Coiron Amargo Charco del Palenque Total
96,000 net acres 59,000 net acres 37,000 net acres 45,000 net acres 12,000 net acres 249,000 net acres
Colombia Six wells spud during first quarter ►
Llanos 32 block ► ►
►
Llanos 40 block ► ► ►
►
Kananaskis-1 well – completion ongoing Carmentea-1 well – waiting to be completed Begonia-1 well – completion ongoing Celtis 1 well – completion ongoing One well completed as a disposal well
Turpial block ►
Turpiales 2 well – waiting to be completed
WPX Operational Update | May 7, 2014
30
Argentina Asset Map Acambuco: Noreste Basin
1.5% WI
Agua Amarga:
Entre Lomas: 23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%)
23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%)
Nequen Basin
Coirón Amargo: 45% WI
Bajada del Palo:
23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%) San Jorge Basin
Tierra del Fuego:
Sur Rio Deseado Este:
26% WI
Austral Basin
44% WI
Concession/Contract Basin
WPX Operational Update | May 7, 2014
31
Colombia Asset Map
Valle Medio Del Magdalena Basin
Turpial Block 50% WI 100,000 acres
Llanos 40 Block 50% WI 163,000 acres
Llanos Orientales Basin
Llanos 32 Block 20% WI 111,000 acres
Block Basin
WPX Operational Update | May 7, 2014
32
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 | May 7, 2014
34
Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited) 2013
2014
(Dollars in millions, except per share amounts)
1Q
2Q
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders
3Q
4Q
$ (116)
$
Income (loss) from continuing operations – diluted earnings per share
$(0.58)
$ 0.09 $(0.57) $(4.85) $(5.91)
18 $ (114)
Year
1Q
$ (973) $ (1,185)
$
2Q
3Q
4Q
18
YTD $
18
$ 0.09
$ 0.09
Pre-tax adjustments: Impairment of producing properties, costs of acquired unproved reserves, leasehold and equity method investment (1)
$
- $
-
$
19 $ 1,361 $ 1,380
$
-
$
-
Gain on sale of Powder River Basin deep rights leasehold
$
- $
- $
- $ (36) $ (36)
$
-
$
-
Accrual for litigation
$
- $
- $
7 $
1 $
8
$
-
$
-
Costs related to chief executive officer separation
$
- $
- $
- $
4 $
4
$
-
$
-
Buyout of transportation agreement
$
- $
- $
- $
9 $
9
$
-
$
-
Unrealized MTM (gain) loss
$ 103 $ (98)
$
13 $
89 $ 107
$
27
$
27
$
$
39 $ 1,428
$
27
$
27
Total pre-tax adjustments
103 $ (98)
$1,472
Less tax effect for above items
$ (38) $
Impact of new Argentine capital tax law (1)
$
- $
- $
6 $
- $
Impact of new state tax law in New York (net of federal benefit)
$
- $
- $
- $
- $
Total adjustments, after-tax
$
Adjusted income (loss) from continuing operations available to common stockholders
$ (51) $ (44)
Adjusted diluted earnings (loss) per common share
$(0.25) $(0.22) $(0.41) $(0.34) $(1.22)
Diluted weighted-average shares (millions)
36 $ (14) $ (521) $ (537)
65 $ (62)
199.9
203.8
$ (10)
$ (10)
6
$
-
$
-
-
$
9
$
9
31 $ 907 $ 941
$
26
$
26
$ (83) $ (66) $ (244)
$
44
$
44
$
200.7
200.9
200.4
$ 0.21
$ 0.21
205.2
205.2
(1) These items are presented net of amounts attributable to noncontrolling interests.
WPX Operational Update | May 7, 2014
35
Consolidated Statements of Operations and EBITDAX Reconciliations (Unaudited) 2013 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 Costs and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income Gas management, including charges for unutilized pipeline capacity Exploration Depreciation, depletion and amortization Impairment of producing properties and costs of acquired unproved reserves Gain on sale of Powder River Basin deep rights leasehold General and administrative Other - net Total costs and expenses Operating income (loss) Interest expense Interest capitalized Investment income, impairment of equity method investment and other
2Q
2014
3Q
4Q
YTD
1Q
2Q
3Q
4Q
YTD
$ 267 139 54 460 261 (94) 4 631
$ 316 151 58 525 205 78 7 815
$ 252 183 57 492 176 (15) 5 658
$ 258 176 61 495 249 (93) 6 657
$ 1,093 649 230 1,972 891 (124) 22 2,761
$ 384 175 61 620 561 (195) 1 987
75 107 35 243 19 231 72 7 789
73 111 36 222 20 227 74 1 764
82 106 36 201 21 241 19 68 10 784
78 109 34 265 371 241 1,036 (36) 75 (1) 2,172
308 433 141 931 431 940 1,055 (36) 289 17 4,509
79 106 47 391 15 207 72 3 920
79 106 47 391 15 207 72 3 920
(158)
51
(126)
(1,515)
(1,748)
67
67
(26) 1 7
(28) 1 9
(28) 2 4
(26) 1 (15)
(108) 5 5
(29) 4
(29) 4
33 11 22 4 18
$ (148) (32) $ (116) (2) $ (114)
(1,555) (571) $ (984) (11) $ (973)
(1,846) (655) $(1,191) (6) $(1,185)
$ 42 23 $ 19 1 $ 18
$
22 28 11 227 20 308 (78) (20) $ 210
$ (116) 28 (32) 241 21 142 19 15 (2) $ 174
$ (984) 26 (571) 241 371 (917) 1,056 (36) 93 (4) $ 192
$ ( 1,191) 108 (655) 940 431 (367) 1,075 (36) 124 (17) $ 779
$ 19 29 23 207 15 293 195 (168) $ 320
$
Income (loss) from continuing operations before income taxes Provision (benefit) for income taxes Net income (loss) Less: Net income (loss) attributable to noncontrolling interests Net income (loss) attributable to WPX Energy, Inc.
$ (176) (63) $ (113) 3 $ (116)
$
Adjusted EBITDAX Reconciliation to net income (loss): Net income (loss) Interest expense Provision (benefit) for income taxes Depreciation, depletion and amortization Exploration expenses EBITDAX Impairment of producing properties, costs of acquired unproved reserves and equity investments (Gain) on sale of Powder River Basin deep rights leasehold Net (gain) loss on derivatives not designated as hedges Net cash received (paid) related to settlement of derivatives not designated as hedges Adjusted EBITDAX
$ (113) 26 (63) 231 19 100 94 9 $ 203
$
$ $
WPX Operational Update | May 7, 2014
$
$ $
384 175 61 620 561 (195) 1 987
42 23 19 1 18
19 29 23 207 15 293 195 (168) $ 320
36
Domestic Segment (Unaudited) (Dollars in millions)
1Q
2013 3Q
2Q
4Q
YTD
1Q
2Q
2014 3Q
4Q
YTD
Revenues: Product revenues: Natural gas sales
$
263
$ 310
$ 248
$ 253
$ 1,074
111
121
154
148
534
149
53
58
57
60
228
61
61
427
489
459
461
1,836
589
589
Gas management
261
205
176
249
891
561
561
Net gain (loss) on derivatives not designated as hedges
(94)
78
(15)
(93)
(124)
(195)
(195)
Oil and condensate sales Natural gas liquid sales Total product revenues
Other Total revenues
$
379
$
379 149
1
1
3
1
6
1
1
595
773
623
618
2,609
956
956
Costs and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income Gas management, including charges for unutilized pipeline capacity Exploration
67
63
74
67
271
71
71
106
110
106
108
430
106
106
29
30
30
28
117
41
41
243
222
201
265
931
391
391
18
17
21
368
424
15
15
224
217
233
232
906
197
197
Impairment of producing properties and costs of acquired unproved reserves
-
-
19
1,033
1,052
-
-
Gain on sale of Powder River Basin deep rights leasehold
-
-
-
(36)
(36)
-
-
69
69
65
72
275
68
68
Depreciation, depletion and amortization
General and administrative Other - net
6
5
7
(1)
17
2
2
762
733
756
2,136
4,387
891
891
(167)
40
(133)
(1,518)
(1,778)
65
65
(26)
(28)
(28)
(26)
(108)
(29)
(29)
Interest capitalized
1
1
2
1
5
-
-
Investment income, impairment of equity method investment and other
2
2
-
(20)
(16)
2
2
15
$ (159)
$ (1,563)
$ (1,897)
Total costs and expenses Operating income (loss) Interest expense
Income (loss) from continuing operations before income taxes
$ (190)
$
$
38
$
38
Summary of Production Volumes Natural gas (MMcf)
90,411
90,022
91,392
87,638
359,463
85,988
85,988
Oil (Mbbl)
1,242
1,373
1,575
1,738
5,928
1,738
1,738
Natural gas liquids (Mbbl)
1,907
1,895
1,811
1,808
7,421
1,587
1,587
109,303
109,628
111,707
108,916
439,554
105,936
105,936
Combined equivalent volumes (MMcfe)(1)
(1) Oil and natural gas liquids were converted to MMcfe using the ratio of one barrel of oil, condensate or natural gas liquids to six thousand cubic feet of natural gas. Realized average price per unit, including the impact of hedges Natural gas (per Mcf)
$
2.90
$ 3.45
$ 2.72
$ 2.87
$
Oil (per barrel)
$ 89.77
$ 87.76
$97.91
$85.50
$ 90.21
2.99
$ 86.24
$
4.40
$ 86.24
$
4.40
Natural gas liquids (per barrel)
$ 28.21
$ 30.21
$31.19
$33.33
$ 30.70
$ 38.27
$ 38.27
Lease and facility operating
$
0.61
$ 0.59
$ 0.65
$ 0.63
$
0.62
$
0.67
$
0.67
Gathering, processing and transportation
$
0.98
$ 1.00
$ 0.94
$ 1.00
$
0.98
$
1.00
$
1.00
Taxes other than income
$
0.27
$ 0.27
$ 0.27
$ 0.26
$
0.27
$
0.39
$
0.39
Depreciation, depletion and amortization
$
2.04
$ 1.98
$ 2.09
$ 2.13
$
2.06
$
1.86
$
1.86
General and administrative
$
0.62
$ 0.64
$ 0.58
$ 0.66
$
0.62
$
0.65
$
0.65
$
13
$
$
$
$
61
$
16
$
16
Expenses per Mcfe
Unutilized pipeline capacity Total unutilized pipeline capacity in gas management expense
14
17
17
WPX Operational Update | May 7, 2014
37
International Segment (Unaudited) (Dollars in millions)
1Q
2013 3Q
2Q
4Q
YTD
1Q
2Q
2014 3Q
4Q
YTD
Revenues: Product revenues: Natural gas sales Oil and condensate sales Natural gas liquid sales
$
4
$
28
6
$
30
4
$
29
5
$
28
19
$
115
5
$
26
5 26
1
-
-
1
2
-
-
33
36
33
34
136
31
31
Gas management
-
-
-
-
-
-
-
Net gain (loss) on derivatives not designated as hedges
-
-
-
-
-
-
-
Other
3
6
2
5
16
-
-
36
42
35
39
152
31
31
Lease and facility operating
8
10
8
11
37
8
8
Gathering, processing and transportation
1
1
-
1
3
-
-
Taxes other than income
6
6
6
6
24
6
6 -
Total product revenues
Total revenues Costs and expenses:
Gas management, including charges for unutilized pipeline capacity
-
-
-
-
-
-
Exploration
1
3
-
3
7
-
-
Depreciation, depletion and amortization
7
10
8
9
34
10
10
Impairment of producing properties
-
-
-
3
3
-
-
Gain on sale of Powder River Basin deep rights
-
-
-
-
-
-
-
General and administrative
3
5
3
3
14
4
4
Other-net
1
(4)
3
-
-
1
1
27
31
28
36
122
29
29
Operating income (loss)
9
11
7
3
30
2
2
Interest expense
-
-
-
-
-
-
-
Interest capitalized
-
-
-
-
-
-
-
Investment income and other
5
7
4
5
21
2
2
Total costs and expenses
Income (loss) from continuing operations before income taxes
$ 14
$
18
$
11
$
8
$
51
$
4
$
4
Summary of Net Production Volumes (1) Natural gas (MMcf) Oil (Mbbl) Natural gas liquids (Mbbl) Combined equivalent volumes (MMcfe)(2)
1,485
1,620
1,707
1,723
6,534
1,723
1,723
506
553
484
489
2,032
466
466
42
44
42
40
167
41
41
4,775
5,202
4,862
4,894
19,733
4,766
4,766
(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 | May 7, 2014
38
Operational Update Jim Bender, Chief Executive Officer
Disclaimer The information contained in this summary has been prepared to assist you in making your own evaluation of the Company and does not purport to contain all of the information you may consider important in deciding whether to invest in shares of the Company’s common stock. In all cases, it is your obligation to conduct your own due diligence. All information contained herein, including any estimates or projections, is based upon information provided by the Company. Any estimates or projections with respect to future performance have been provided to assist you in your evaluation but should not be relied upon as an accurate representation of future results. No persons have been authorized to make any representations other than those contained in this summary, and if given or made, such representations should not be considered as authorized. Certain statements, estimates and financial information contained in this summary constitute forward-looking statements or information. Such forward-looking statements or information involve known and unknown risks and uncertainties that could cause actual events or results to differ materially from the results implied or expressed in such forward-looking statements or information. While presented with numerical specificity, certain forward-looking statements or information are based (1) upon assumptions that are inherently subject to significant business, economic, regulatory, environmental, seasonal, competitive uncertainties, contingencies and risks including, without limitation, the ability to obtain debt and equity financings, capital costs, construction costs, well production performance, operating costs, commodity pricing, differentials, royalty structures, field upgrading technology, and other known and unknown risks, all of which are difficult to predict and many of which are beyond the Company's control, and (2) upon assumptions with respect to future business decisions that are subject to change. There can be no assurance that the results implied or expressed in such forward-looking statements or information or the underlying assumptions will be realized and that actual results of operations or future events will not be materially different from the results implied or expressed in such forward-looking statements or information. Under no circumstances should the inclusion of the forward-looking statements or information be regarded as a representation, undertaking, warranty or prediction by the Company or any other person with respect to the accuracy thereof or the accuracy of the underlying assumptions, or that the Company will achieve or is likely to achieve any particular results. The forward-looking statements or information are made as of the date hereof and the Company disclaims any intent or obligation to update publicly or to revise any of the forward-looking statements or information, whether as a result of new information, future events or otherwise. Recipients are cautioned that forward-looking statements or information are not guarantees of future performance and, accordingly, recipients are expressly cautioned not to put undue reliance on forward-looking statements or information due to the inherent uncertainty therein.
WPX Operational Update | May 7, 2014
2
Reserves Disclaimer The SEC requires oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, under existing economic conditions, operating methods, and governmental regulations. The SEC permits the optional disclosure of probable and possible reserves. We have elected to use in this presentation “probable” reserves and “possible” reserves, excluding their valuation. The SEC defines “probable” reserves as “those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC defines “possible” reserves as “those additional reserves that are less certain to be recovered than probable reserves.” The Company has applied these definitions in estimating probable and possible reserves. Statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas recovered. Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s reserves reporting guidelines. Investors are urged to consider closely the disclosure regarding our business that may be accessed through the SEC’s website at www.sec.gov. The SEC’s rules prohibit us from filing resource estimates. Our resource estimations include estimates of hydrocarbon quantities for (i) new areas for which we do not have sufficient information to date to classify as proved, probable or even possible reserves, (ii) other areas to take into account the low level of certainty of recovery of the resources and (iii) uneconomic proved, probable or possible reserves. Resource estimates do not take into account the certainty of resource recovery and are therefore not indicative of the expected future recovery and should not be relied upon. Resource estimates might never be recovered and are contingent on exploration success, technical improvements in drilling access, commerciality and other factors.
WPX Operational Update | May 7, 2014
3
1st Quarter Highlights Adjusted EBITDAX increased 58% quarter over quarter Spud 68 wells in the Piceance 1st quarter ►
Successful 10-acre density testing in Ryan Gulch
36% quarter-over-quarter oil growth in Williston despite record cold weather ► ►
Added 5th rig in 1st quarter Initiated completions on new downspacing patterns
San Juan Gallup Sandstone results remain very favorable ► ► ►
Production grows to 1.7 Mbbl/d in 1Q Capturing efficiencies from pad drilling Added 2nd rig in 1st quarter
13 rigs running in the 1st quarter Exceeded 1st quarter guidance ► ►
Higher production Lower cost
WPX Operational Update | May 7, 2014
4
Legacy Transaction Particulars Legacy to purchase working interests for $355MM ►
Working interest in Piceance Valley ►
►
Excludes Ryan Gulch, Kokopelli, and the Niobrara and deeper formations
Interest only in producing wells drilled prior to Jan. 1, 2009 ► ► ►
2014: 30% of WPX working interest 2015: 37.5% of WPX working interest 2016 and beyond: 42% of WPX working interest
Transaction does not include interests in undeveloped locations or participation in future drilling Legacy provides WPX an interest in a newly created class of IDR units ►
IDR structure provides incentive for future deals
Anticipated closing in June Piceance Valley transaction metrics ► ► ►
1 Based
9% of total Piceance proved reserves Reserves sold: 279 Bcfe1 Five-year average future production: 71 MMcfe/d
Legacy Transaction
on contractual terms and current commodity price assumptions effective 12/31/2013.
WPX Operational Update | May 7, 2014
5
Legacy Transaction Superior to MLP Legacy Transaction
✓ ✓ ✓ ✓ ✓ ✓
MLP Transaction fills majority of 2014 funding gap, enhancing financial strength Meaningfully accretive to WPX’s current valuation
✓ ✓
Highlights undervalued Piceance asset
✓ ✓
IDR structure provides incentive for future deals
✓
WPX maintains operational control of assets
Provides monetization of gas assets without the ongoing administrative and development concerns of an MLP
WPX Operational Update | May 7, 2014
6
May 7, 2014
Operational Update Bryan Guderian, Sr. VP of Operations
Piceance Highlights 1st-quarter activity ►
Spud 68 wells 8th rig arrived in March
Continuing to drive down D&C cost ►
2013 plan versus actual 2013 July-December ► ►
Valley D&C cost down 10% Ryan Gulch D&C cost down 23%
Improved water handling ►
►
Drilling & Completion Cost ($M)
►
Total Well Cost 2013 3,000
2013 Plan
2013 Jan-Jun
2013 Jul-Dec
2,800 2,357
2,500 2,000 1,500
1,389
1,276 1,246
1,000 500 0 Valley
Water-sharing agreements with other operators Renegotiated chemical, water-hauling and equipment contracts
2,157
Ryan Gulch
Spud-to-Release Performance 30
2009
2010
2011
2012
2013
Record
25
2014 Niobrara program Drilling resumes early May ► ►
►
Spud a horizontal and a vertical well in early May Arrival of new rig with high pressure capability needed for horizontal drilling in the Niobrara
Up to 10 wells planned for 2014
Days
►
20 15 10 5 0
3.8 Grand Valley
5.0 Parachute
6.8 Rulison
8.5
Ryan Gulch
WPX Operational Update | May 7, 2014
8
Long-Term Value: Piceance Ryan Gulch Ryan Gulch offers competitive returns ► ►
Ryan Gulch Drilling Days per Well
Returns are comparable to Valley operations Higher NGLs and EURs compared to Valley
30
26.3
25
Well costs reduced to $2.3MM ► ►
Drilling days continue downward trend Record well in 8.1 days in 2014 Completion costs at $1.2MM in 2013
19.1
20
Days
►
24.7
15.3
15
12.8
11.8
2012
2013
10
9.9
5
EURs increased to >2 Bcfe
0 2008
2009
2010
2011
2014
Water infrastructure improvements ► ►
Increased water-injection capacity Reduced water-handling costs
4.5 4.0
Successful 10-acre density strengthens inventory ► ►
3,682 Bcfe 3P reserves 4,317 undrilled 3P-well locations
$3.55
3.0
($MM)
►
60,992 gross acres 35,640 net acres
$4.03
3.5
Extensive land position ►
Ryan Gulch D&C Well Costs
$3.11
$3.19 $2.54
2.5
$2.26
2.0 1.5 1.0 0.5 0.0 2008
2009
2010
2011
2012
WPX Operational Update | May 7, 2014
2013
9
Well Performance Drives Strong Williston Production Growth Continued strong production growth ►
►
Four Bears Village
Produced 15.6 Mbo/d in 1Q (17.7 Mboe/d) 40% production growth vs. 1Q 2013
Parshall FBIR 13-24HZ FIRST SALES: 3/12/2014 30 DAY IP: 1,533 BOPD
11 wells put on 1st sales ► ► ►
Initial 30-day average of 1,266 bo/d 7 Middle Bakken 4 Three Forks
Added 5th rig in 1Q ► ►
New drilling pattern for all future wells 62 wells planned for 2014
Started completing on tighter density patterns ►
Encouraging results from 3 Alfred Old Dog wells
New Town
ALFRED OLD DOG 19-18HC FIRST SALES: 3/27/2014 30 DAY IP: 1,681 BOPD
OLSON 12-1HD FIRST SALES: 1/20/2014 30 DAY IP: 1,185 BOPD
ALFRED OLD DOG 19-18HY FIRST SALES: 3/30/2014 30 DAY IP: 1,223 BOPD ALFRED OLD DOG 19-18HB FIRST SALES: 3/27/2014 30 DAY IP: 1,163 BOPD
Mandaree
MARTIN FOX 20-17HZ FIRST SALES: 2/19/2014 30 DAY IP: 1,249 BOPD
FBIR 13-24HC FIRST SALES: 3/12/2014 30 DAY IP: 966 BOPD
FBIR 13-24HD FIRST SALES: 3/13/2014 30 DAY IP: 1,398 BOPD OLSON 12-1HY FIRST SALES: 1/21/2014 30 DAY IP: 929 BOPD
MARTIN FOX 20-17HC FIRST SALES: 2/19/2014 30 DAY IP: 1,156 BOPD
MARTIN FOX 20-17HD FIRST SALES: 2/19/2014 30 DAY IP: 1,438 BOPD
Producing Well Middle Bakken Well
Pad development reducing costs ► ► ►
►
Improved cycle times Batch drilling lowers fluid costs Greater utilization of rig-walking capabilities Zipper-frac efficiencies
Three Forks Well Alfred Old Dog Pad WPX Unit
WPX Operational Update | May 7, 2014
10
San Juan Gallup Generating Excellent Results Production exceeds 1Q plan ► ►
Oil production grows to average of 1.7 Mbo/d Total production averaged 2.2 Mboe/d
Development program advancing ► ► ►
7 wells spud 1Q Added 2nd rig 1st multi-well pad average 30-day IP: 420 bo/d1
CHACO 2306 06L #178H FIRST SALES: 3/9/2014 AVG. 30-DAY IP: 433 BOPD CHACO 2308 09A #149H FIRST SALES: 4/16/2014
CHACO 2308 09A #145H FIRST SALES: 4/21/2014
Pursuing well-cost efficiencies ► ►
► ►
Transitioned to pad development Top-setting wells with smaller rig; saves 3 drilling days per well First zipper frac completed on 3-well pad Shared-surface facilities for multi-well pads
CHACO 2306 06L #179H FIRST SALES: 3/6/2014 AVG. 30-DAY IP: 407 BOPD
CHACO 2306 06L #239H FIRST SALES: 3/9/2014 AVG. 30-DAY IP: 420 BOPD
CHACO 2307 12E #169H FIRST SALES: WOC
CHACO 2308 09A #146H FIRST SALES: WOC
CHACO 2307 13L #238H FIRST SALES: WOC
CHACO 2307 13L #174H FIRST SALES: WOC
48,600 net acres in oil window ►
Added additional 4,600 acres since February
2014 outlook ► ► ►
275% Y/Y growth in daily oil production Spud 29 gross wells Average 2 rigs
WPX-Drilling Horizontal Oil Wells WPX-Completed Horizontal Oil Wells WPX Acreage (Shallow/Deep Rights)
1 Based
on the first 30 uninterrupted days of production
WPX Operational Update | May 7, 2014
11
Financial Results
Kevin Vann, Chief Financial Officer
1st Quarter Results Dollars in millions, except production numbers
2014
1Q
2013
Daily Production Gas (MMcf/d)
975
1,021
Oil (Mbbl/d)
24.5
19.4
NGLs (Mbbl/d)
18.1
21.7
Equivalent (MMcfe/d)
1,230
1,268
Adjusted EBITDAX
$320
$203
Adjusted Net Income (Loss) from Continuing Operations
$44
$(51)
$(352)
$(271)
Capital Expenditures
Note: Adjusted EBITDAX and adjusted net income are non-GAAP measures. A reconciliation to relevant measures included in GAAP is provided in this presentation.
WPX Operational Update | May 7, 2014
13
2014: 2nd Quarter and Full-Year Guidance Production
Natural Gas MMcf/d Oil Mbbl/d NGL Mbbl/d Total MMcfe/d
Cap Ex ($ in Millions)
% of Net Realized Price3
918 - 9257 25.8 - 26.3 18.3 - 18.77 1,183 - 1,195
FY 2014
925 - 934 28.1 - 28.5 18.3 - 18.7 1,203 - 1,217
2Q
FY 2014
Expenses
2Q
Growth Basins Piceance Williston San Juan Gallup Other Appalachia Other1 Land Exploration Total Domestic International2 Total Capital
$115 - $125 140 - 150 40 - 45
$475 - $495 580 - 600 155 - 180
10 - 15 0-5 15 - 20 10 - 15 $330 - $375 25 - 35 $355 - $410
20 - 30 10 - 15 75 - 85 25 - 30 $1,340 - $1,435 80 - 90 $1,420 - $1,525
Number of Rigs
2Q
FY 2014
Piceance Valley Piceance Highlands Piceance Niobrara Total Piceance Williston San Juan Gallup Total Rigs
(Includes Impact of Legacy Transaction)
7 1 1 9 5 2 16
Note: Blue font indicates change from previous guidance
7 1 1 9 5 2 16
Natural Gas - NYMEX Oil - WTI NGL - OPIS/Mt Belvieu5
$ per Mcfe LOE DD&A GP&T SG&A Production Tax $ in Millions Gas Management (Inc)/Exp4 Exploration Interest Expense Equity (Earnings) Loss
Tax Rate Tax Provision
2Q
FY 2014
80% - 85% 81% - 86% 75% - 79%
81% - 87% 81% - 87% 76% - 80%
2Q
FY 2014
$0.74 - $0.76 1.90 - 1.95 0.95 - 1.00 0.66 - 0.68 0.42 - 0.46
$0.73 - $0.75 1.95 - 2.00 0.93 - 0.98 0.63 - 0.67 0.42 - 0.46
$20 - $25 15 - 20 29 - 30 (4) - (6)
$0 - $10 70 - 80 120 - 130 (20) - (25)
2Q
FY 2014
33% - 37%
33% - 37%6
1 Other
includes expenditures for Powder River and Other basins. is a self-funded entity and does not receive any cash from WPX Energy. 3 Percentage of realized price ranges for NYMEX, WTI and OPIS exclude hedges, but include basis differential and revenue adjustments. 4 Gas Management impact is net of revenues and expenses and includes unutilized transport capacity. Includes impact of realized and unrealized hedges on non-equity production. 5 Assumed NGL composite barrel: Ethane 37%, Propane 28%, Isobutane 8%, NormButane 7% and Natural Gasoline 20%. 6 Excludes impact of $9MM tax expense accrual for new legislation in 1Q ’14. 7 Assumes partial- quarter impact of Legacy transaction closing in June. 2 International
WPX Operational Update | May 7, 2014
14
2014 Path to Greater Shareholder Value Legacy transaction in lieu of forming an MLP – generates ~$355MM Stronger commodity prices increasing annual EBITDAX over previous guidance estimate Projected domestic oil growth of 39% year over year Further cost improvements to strengthen cash margin Further rationalization of portfolio being considered 2014 path to greater shareholder value
WPX Operational Update | May 7, 2014
15
Appendix
WPX Portfolio Piceance
Williston
San Juan
Appalachia
Powder River
Apco1
3,019 Bcfe Proved 11,878 Bcfe 3P 221,186 Net Acres
105 MMboe Proved 176 MMboe 3P 80,736 Net Acres
517 Bcfe Proved 1,645 Bcfe 3P 160,825 Net Acres
328 Bcfe Proved 1,555 Bcfe 3P 87,994 Net Acres
245 Bcfe Proved 657 Bcfe 3P 360,002 Net Acres
22 MMboe Proved 58 MMboe 3P 385,796 Net Acres
Total 2Domestic
WILLISTON BASIN
4,905 Bcfe Proved 17,211 Bcfe 3P 1,554,635 Net Acres
POWDER RIVER BASIN PICEANCE BASIN
APPALACHIAN BASIN
SAN JUAN BASIN Natural Gas Oil
ARGENTINA
Natural Gas and Natural Gas Liquids Note: Acreage, proved and 3P numbers are as of 12/31/13. 1 Reflects 2 Total
WPX’s 69% ownership in APCO, as well as additional acreage owned by WPX. includes other reserves and acreage not depicted on slide. WPX Operational Update | May 7, 2014
17
Hedging Overview
As of 5/5/2014
2Q - 4Q 2014 Volumes
2Q - 4Q 2014 Price
2015 Volumes
2015 Price
(BBtu/d)
($MMBtu)
(BBtu/d)
($MMBtu)
Fixed Price Swaps 1,3
315
$4.19
182
$4.35
Collars
190
$4.04 - $4.66
50
$4.00 - $4.50
(bbl/d)
($/bbl)
(bbl/d)
($/bbl)
12,750
$94.62
3,500
$93.33
Natural Gas Liquids
(bbl/d)
($/gallon)
(bbl/d)
($/gallon)
Ethane Swaps
3,273
$0.29
18
–
Propane Swaps
491
$1.17
–
–
Isobutane Swaps
655
$1.37
–
–
Normal Butane Swaps
327
$1.38
–
–
1,636
$2.06
–
–
Natural Gas1
Crude Oil Fixed Price Swaps1,2,3
Natural Gasoline Swaps
1Details
for natural gas basis swaps can be found in our most recent quarterly report. ²Details for crude oil basis swaps can be found in our most recent quarterly report. 3In connection with several natural gas swaps, we entered into swaptions with the swap counterparties granting the counterparty the right but not the obligation to enter into an underlying swap with us in the future. For 2014, we have 50k MMBtu/d capped at a monthly settlement price of $4.24 per MMBtu, and for 2015, we have 50k MMBtu/d of natural gas capped at a settlement price of $4.38 per MMBtu and 5,250 bbl/d of crude oil capped at a settlement price of $95.06.
WPX Operational Update | May 7, 2014
18
Key Statistics by Basin Net Acreage (YE2013)
2014 Average Rig Count (Op)
2013 Production (MMcfe/d)
Oil/NGL Focused
Drillable Locations4
Proved Reserves (YE2013 Bcfe)
3P Reserves (YE2013 Bcfe)
Piceance1
221,186
9
727
X
12,475
3,019
11,878
Williston
80,736
5
14.8 Mboe/d
X
453
San Juan2
160,825
2
123
X
2,966
517
1,645
Appalachia
87,994
0
83
618
328
1,555
Total
550,741
16
1,022
16,512
4,497
16,133
2,872
245
657
664
22 MMboe
58 MMboe
2,820
20
72
Primary Areas of Focus
105.5 MMboe 176 MMboe
Exploration Exploration
X
Other Powder River
360,002
0
174
Apco3
385,796
0
9.0 Mboe/d
Other
258,096
0
8.0
Piceance includes Niobrara acreage, which underlies existing leasehold acreage. Juan Legacy includes both shallow and deep rights. 3 Reflects WPX’s 69% ownership, except 3P drilling locations, which are gross. 4 Includes operated and non-operated gross locations.
X
1
2 San
Chart numbers affected by rounding.
WPX Operational Update | May 7, 2014
19
2013-14 Daily Production 2013 1Q
2Q
3Q
4Q
Avg Total
2014
Gas (MMcf/d)
1,005
989
993
953
985
956
956
Oil (Mbbl/d)
13.8
15.1
17.1
18.9
16.2
19.3
19.3
NGLs (Mbbl/d)
21.2
20.8
19.7
19.7
20.3
17.6
17.6
MMcfe/d
1,215
1,205
1,214
1,184
1,204
1,177
1,177
Gas (MMcf/d)
17
18
19
19
18
19
19
Oil (Mbbl/d)
5.6
6.1
5.3
5.3
5.6
5.2
5.2
NGLs (Mbbl/d)
0.5
0.5
0.5
0.4
0.5
0.5
0.5
MMcfe/d
53
57
53
53
54
53
53
Gas (MMcf/d)
1,021
1,007
1,012
971
1,003
975
975
Oil (Mbbl/d)
19.4
21.2
22.4
24.2
21.8
24.5
24.5
NGLs (Mbbl/d)
21.7
21.3
20.1
20.1
20.8
18.1
18.1
MMcfe/d
1,268
1,262
1,267
1,237
1,258
1,230
1,230
1Q
Avg
Domestic Production
International Production
Total Production
WPX Operational Update | May 7, 2014
20
Growing Higher-Margin Oil 77% oil CAGR since 2010 ►
2014 growth in higher-margin oil
Record oil production in 2013
►
Averaged 16.2 Mbo/d – a 35% increase year over year Discovered and developing San Juan Mancos Gallup
► ►
► ► ►
39% year-over-year domestic oil growth Williston up 30% - 35% San Juan Gallup up 275% Allocated 51% of total capital
Total Domestic Oil Growth 2010-14 9,000 8,000
Annual Domestic Mbbl
7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 2010 Act
2011 Act
2012 Act
2013 Act
2014 Est
WPX Operational Update | May 7, 2014
21
Domestic Price Realization for 2014 Gas ($/Mcf) 1Q ’14 Weighted-Average Sales Price
2Q ’14
3Q ’14
NGL ($/bbl) 4Q ’14
1Q ’14
2Q ’14
3Q ’14
Oil ($/bbl) 4Q ’14
1Q ’14
$4.89
$49.14
$88.40
(0.49)
(10.87)
(2.16)
0.00
0.00
0.00
$4.40
$38.27
86.24
Realized Portion of Derivatives Not Designated as Hedges(3)
(0.52)
(0.48)
(2.30)
Net Price Including All Derivatives
$3.88
$37.79
$83.94
1
Revenue Adjustments Hedge Impact Net Price
(2)
1Q ’14 Impact of Rockies Sale-for-Resale Contract exp. in Nov. ’14
$(0.34)
Weighted-Average Sales Price Excluding Rex
$4.22
2Q ’14
3Q ’14
2Q ’14
3Q ’14
4Q ’14
4Q ’14 ►
1Q: Rockies sale-for-resale agreement impacted net realized gas price ($0.34). Contract expires in November 2014.
1Natural
gas revenue adjustments are primarily related to field compression fuel. NGL revenue adjustments include T&F and revenue sharing. Of the oil revenue adjustments, gathering deductions represent $(1.32).
2“Net
Price” equals income statement product revenues by commodity, divided by volume.
3Represents
the realized cash flows that occurred during each quarter, which are attributable to derivatives that were not designated as hedges for accounting purposes.
WPX Operational Update | May 7, 2014
22
Domestic Price Realization for 2013 Gas ($/Mcf)
NGL ($/bbl)
Oil ($/bbl)
1Q ’13
2Q ’13
3Q ’13
4Q’13
1Q ’13
2Q ’13
3Q ’13
4Q’13
1Q ’13
2Q ’13
3Q ’13
4Q’13
$3.12
$3.78
$3.16
$3.30
$37.27
$37.41
$43.10
$43.32
$89.23
$88.62
$99.43
$87.79
(0.27)
(0.33)
(0.44)
(0.43)
(9.06)
(7.20)
(11.91)
(9.99)
0.54
(0.86)
(1.52)
(2.29)
0.05
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
0.00
$2.90
$3.45
$2.72
$2.87
$28.21
$30.21
$31.19
$33.33
$89.77
$87.76
$97.91
$85.50
Realized Portion of Derivatives Not Designated as Hedges(3)
0.01
(0.28)
0.04
0.01
0.00
0.00
0.09
0.23
4.03
3.75
(2.63)
1.71
Net Price Including All Derivatives
$2.91
$3.17
$2.76
$2.88
$28.21
$30.21
$31.28
$33.56
$93.80
$91.51
$95.28
$87.21
1Q ’13
2Q ’13
3Q ’13
4Q ’13
Impact of Rockies Sale-for-Resale Contract exp. in Nov. ’14
$(0.26)
$(0.21)
$(0.29)
$(0.30)
Weighted-Average Sales Price Excluding Rex
$3.17
$3.38
$3.05
$3.18
Weighted-Average Sales Price 1
Revenue Adjustments Hedge Impact Net Price
(2)
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 $(1.35).
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 | May 7, 2014
23
Piceance Basin Orange: Highlands Yellow: Valley 1 Net acreage: 221,186 Current rig count: 9 Drillable locations: 12,4751 Composition: Gas/NGL focused
1 Acreage
and drilling locations are as of 12/31/13
Niobrara Dedicated Rig
WPX Operational Update | May 7, 2014
24
Piceance Composite NGL Barrel and Realized Price (1st Quarter, 2014)
$48.00
Product Mix
$/Gal
Ethane1
32%
.30
Propane
32%
1.28
Isobutane
9%
1.40
NGL Product
Weighted Average NGL $/barrel
$38.56
Net Realized Price
**$0.60 per Mcf NGL Uplift in 1Q 2014
Normal Butane
8%
1.37
Natural Gasoline
19%
2.11
*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 | May 7, 2014
25
Williston Basin Net acreage: 80,7361 Current rig count 2014: 5 Drillable Locations: 4531,2 Composition: Oil focused
1 Acreage 2
and drilling locations are as of 12/31/13 Does not include the impact of downspacing
WPX Operational Update | May 7, 2014
26
WPX is #1 in Middle Bakken Cumulative Production Average 365-day cumulative production per well of 136.8 Mbo, 52% higher than the peer average
1-Yr Cum.Production Oil Production 1-Yr andand 2-Yr 2-Yr Cumulative per Well1 (Based on productive days)
300,000
Average 730-day cumulative production per well of 240.8 Mbo, 66% higher than the peer average
►
►
►
Started using cement liners in May 2012 Identified plug and perf as superior completion method in early 2012 Reviewing new completion design: ► ► ►
►
Increase number of frac stages Increase perforation clusters Reduce pumping rate
Ceramic proppant (65/35) increases EUR
Cumulative Oil Production
Leader in completion design
250,000
WPX 2-Yr Cumulative Production per Well
Peer 2-Yr Cumulative Production per Well
WPX 1-Yr Cumulative Production per Well
Peer 1-Yr Cumulative Production per Well
200,000
150,000
100,000
50,000
0
¹Based on NDIC data for Middle Bakken longs put on 1st sales since January 2011. WPX acquired Williston properties December 2010. Cumulative production as of 12/31/2013.
Peer 2-Yr Avg
Peer 1-Yr Avg
WPX Operational Update | May 7, 2014
27
Williston Netback Price Analysis Sales Outlets
Estimated Volume % (Apr - Jun 2014)
Basin-Priced Sales
56%
Rail Deals
32%
Enbridge Capacity
12%
Total Sales Outlets
100%
Assumed 2Q 2014 total netback of WTI less $10 - $11 per barrel Our current sales agreements consist of the following: ► ► ►
Basin Sales: Arrow CDP WASP and lease sales Rail: Receive Gulf, West and East Coast pricing Enbridge: Receive Enbridge Clearbrook, Minn., price
Our sales agreements in 2014-16 are expected to consist of the following: ► ► ► ►
Basin sales: Receive a basket price from sales to third-party marketers Rail: Receive Gulf, West and East Coast pricing less associated fees Enbridge: Receive Clearbrook, Minn., price less associated fees Unit train rail options: WPX will have up to 14,000 bbl/d of committed unit train capacity through the first quarter of 2014, decreasing to 9,250 bbl/d until mid-2016, receiving West, East or Gulf Coast pricing less associated fees
WPX Operational Update | May 7, 2014
28
San Juan Basin
Green: Deep/Shallow Yellow: Shallow Net Acreage: 160,8251 Current rig count: 2 Drillable locations: 2,9661 Composition: Gas/Oil 1Acreage
and drilling locations are as of 12/31/13
WPX Operational Update | May 7, 2014
29
Apco Highlights Argentina Initiated 7-well Neuquén horizontal drilling program ► ► ►
Early results encouraging Two conventional horizontal wells put on production One well waiting to be completed
Eight development wells spud during 1Q Applied for the government’s gas incentive program to obtain higher gas pricing
Vaca Muerta Exposure Neuquén Basin (Vaca Muerta acreage) ► ► ► ► ►
Entre Lomas Bajada del Palo Agua Amarga Coiron Amargo Charco del Palenque Total
96,000 net acres 59,000 net acres 37,000 net acres 45,000 net acres 12,000 net acres 249,000 net acres
Colombia Six wells spud during first quarter ►
Llanos 32 block ► ►
►
Llanos 40 block ► ► ►
►
Kananaskis-1 well – completion ongoing Carmentea-1 well – waiting to be completed Begonia-1 well – completion ongoing Celtis 1 well – completion ongoing One well completed as a disposal well
Turpial block ►
Turpiales 2 well – waiting to be completed
WPX Operational Update | May 7, 2014
30
Argentina Asset Map Acambuco: Noreste Basin
1.5% WI
Agua Amarga:
Entre Lomas: 23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%)
23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%)
Nequen Basin
Coirón Amargo: 45% WI
Bajada del Palo:
23% WI, 40.7% Stock Interest in Petrolera (Effective Interest – 52.8%) San Jorge Basin
Tierra del Fuego:
Sur Rio Deseado Este:
26% WI
Austral Basin
44% WI
Concession/Contract Basin
WPX Operational Update | May 7, 2014
31
Colombia Asset Map
Valle Medio Del Magdalena Basin
Turpial Block 50% WI 100,000 acres
Llanos 40 Block 50% WI 163,000 acres
Llanos Orientales Basin
Llanos 32 Block 20% WI 111,000 acres
Block Basin
WPX Operational Update | May 7, 2014
32
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 | May 7, 2014
34
Reconciliation-Adjusted Income (Loss) from Continuing Operations (Unaudited) 2013
2014
(Dollars in millions, except per share amounts)
1Q
2Q
Income (loss) from continuing operations attributable to WPX Energy, Inc. available to common stockholders
3Q
4Q
$ (116)
$
Income (loss) from continuing operations – diluted earnings per share
$(0.58)
$ 0.09 $(0.57) $(4.85) $(5.91)
18 $ (114)
Year
1Q
$ (973) $ (1,185)
$
2Q
3Q
4Q
18
YTD $
18
$ 0.09
$ 0.09
Pre-tax adjustments: Impairment of producing properties, costs of acquired unproved reserves, leasehold and equity method investment (1)
$
- $
-
$
19 $ 1,361 $ 1,380
$
-
$
-
Gain on sale of Powder River Basin deep rights leasehold
$
- $
- $
- $ (36) $ (36)
$
-
$
-
Accrual for litigation
$
- $
- $
7 $
1 $
8
$
-
$
-
Costs related to chief executive officer separation
$
- $
- $
- $
4 $
4
$
-
$
-
Buyout of transportation agreement
$
- $
- $
- $
9 $
9
$
-
$
-
Unrealized MTM (gain) loss
$ 103 $ (98)
$
13 $
89 $ 107
$
27
$
27
$
$
39 $ 1,428
$
27
$
27
Total pre-tax adjustments
103 $ (98)
$1,472
Less tax effect for above items
$ (38) $
Impact of new Argentine capital tax law (1)
$
- $
- $
6 $
- $
Impact of new state tax law in New York (net of federal benefit)
$
- $
- $
- $
- $
Total adjustments, after-tax
$
Adjusted income (loss) from continuing operations available to common stockholders
$ (51) $ (44)
Adjusted diluted earnings (loss) per common share
$(0.25) $(0.22) $(0.41) $(0.34) $(1.22)
Diluted weighted-average shares (millions)
36 $ (14) $ (521) $ (537)
65 $ (62)
199.9
203.8
$ (10)
$ (10)
6
$
-
$
-
-
$
9
$
9
31 $ 907 $ 941
$
26
$
26
$ (83) $ (66) $ (244)
$
44
$
44
$
200.7
200.9
200.4
$ 0.21
$ 0.21
205.2
205.2
(1) These items are presented net of amounts attributable to noncontrolling interests.
WPX Operational Update | May 7, 2014
35
Consolidated Statements of Operations and EBITDAX Reconciliations (Unaudited) 2013 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 Costs and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income Gas management, including charges for unutilized pipeline capacity Exploration Depreciation, depletion and amortization Impairment of producing properties and costs of acquired unproved reserves Gain on sale of Powder River Basin deep rights leasehold General and administrative Other - net Total costs and expenses Operating income (loss) Interest expense Interest capitalized Investment income, impairment of equity method investment and other
2Q
2014
3Q
4Q
YTD
1Q
2Q
3Q
4Q
YTD
$ 267 139 54 460 261 (94) 4 631
$ 316 151 58 525 205 78 7 815
$ 252 183 57 492 176 (15) 5 658
$ 258 176 61 495 249 (93) 6 657
$ 1,093 649 230 1,972 891 (124) 22 2,761
$ 384 175 61 620 561 (195) 1 987
75 107 35 243 19 231 72 7 789
73 111 36 222 20 227 74 1 764
82 106 36 201 21 241 19 68 10 784
78 109 34 265 371 241 1,036 (36) 75 (1) 2,172
308 433 141 931 431 940 1,055 (36) 289 17 4,509
79 106 47 391 15 207 72 3 920
79 106 47 391 15 207 72 3 920
(158)
51
(126)
(1,515)
(1,748)
67
67
(26) 1 7
(28) 1 9
(28) 2 4
(26) 1 (15)
(108) 5 5
(29) 4
(29) 4
33 11 22 4 18
$ (148) (32) $ (116) (2) $ (114)
(1,555) (571) $ (984) (11) $ (973)
(1,846) (655) $(1,191) (6) $(1,185)
$ 42 23 $ 19 1 $ 18
$
22 28 11 227 20 308 (78) (20) $ 210
$ (116) 28 (32) 241 21 142 19 15 (2) $ 174
$ (984) 26 (571) 241 371 (917) 1,056 (36) 93 (4) $ 192
$ ( 1,191) 108 (655) 940 431 (367) 1,075 (36) 124 (17) $ 779
$ 19 29 23 207 15 293 195 (168) $ 320
$
Income (loss) from continuing operations before income taxes Provision (benefit) for income taxes Net income (loss) Less: Net income (loss) attributable to noncontrolling interests Net income (loss) attributable to WPX Energy, Inc.
$ (176) (63) $ (113) 3 $ (116)
$
Adjusted EBITDAX Reconciliation to net income (loss): Net income (loss) Interest expense Provision (benefit) for income taxes Depreciation, depletion and amortization Exploration expenses EBITDAX Impairment of producing properties, costs of acquired unproved reserves and equity investments (Gain) on sale of Powder River Basin deep rights leasehold Net (gain) loss on derivatives not designated as hedges Net cash received (paid) related to settlement of derivatives not designated as hedges Adjusted EBITDAX
$ (113) 26 (63) 231 19 100 94 9 $ 203
$
$ $
WPX Operational Update | May 7, 2014
$
$ $
384 175 61 620 561 (195) 1 987
42 23 19 1 18
19 29 23 207 15 293 195 (168) $ 320
36
Domestic Segment (Unaudited) (Dollars in millions)
1Q
2013 3Q
2Q
4Q
YTD
1Q
2Q
2014 3Q
4Q
YTD
Revenues: Product revenues: Natural gas sales
$
263
$ 310
$ 248
$ 253
$ 1,074
111
121
154
148
534
149
53
58
57
60
228
61
61
427
489
459
461
1,836
589
589
Gas management
261
205
176
249
891
561
561
Net gain (loss) on derivatives not designated as hedges
(94)
78
(15)
(93)
(124)
(195)
(195)
Oil and condensate sales Natural gas liquid sales Total product revenues
Other Total revenues
$
379
$
379 149
1
1
3
1
6
1
1
595
773
623
618
2,609
956
956
Costs and expenses: Lease and facility operating Gathering, processing and transportation Taxes other than income Gas management, including charges for unutilized pipeline capacity Exploration
67
63
74
67
271
71
71
106
110
106
108
430
106
106
29
30
30
28
117
41
41
243
222
201
265
931
391
391
18
17
21
368
424
15
15
224
217
233
232
906
197
197
Impairment of producing properties and costs of acquired unproved reserves
-
-
19
1,033
1,052
-
-
Gain on sale of Powder River Basin deep rights leasehold
-
-
-
(36)
(36)
-
-
69
69
65
72
275
68
68
Depreciation, depletion and amortization
General and administrative Other - net
6
5
7
(1)
17
2
2
762
733
756
2,136
4,387
891
891
(167)
40
(133)
(1,518)
(1,778)
65
65
(26)
(28)
(28)
(26)
(108)
(29)
(29)
Interest capitalized
1
1
2
1
5
-
-
Investment income, impairment of equity method investment and other
2
2
-
(20)
(16)
2
2
15
$ (159)
$ (1,563)
$ (1,897)
Total costs and expenses Operating income (loss) Interest expense
Income (loss) from continuing operations before income taxes
$ (190)
$
$
38
$
38
Summary of Production Volumes Natural gas (MMcf)
90,411
90,022
91,392
87,638
359,463
85,988
85,988
Oil (Mbbl)
1,242
1,373
1,575
1,738
5,928
1,738
1,738
Natural gas liquids (Mbbl)
1,907
1,895
1,811
1,808
7,421
1,587
1,587
109,303
109,628
111,707
108,916
439,554
105,936
105,936
Combined equivalent volumes (MMcfe)(1)
(1) Oil and natural gas liquids were converted to MMcfe using the ratio of one barrel of oil, condensate or natural gas liquids to six thousand cubic feet of natural gas. Realized average price per unit, including the impact of hedges Natural gas (per Mcf)
$
2.90
$ 3.45
$ 2.72
$ 2.87
$
Oil (per barrel)
$ 89.77
$ 87.76
$97.91
$85.50
$ 90.21
2.99
$ 86.24
$
4.40
$ 86.24
$
4.40
Natural gas liquids (per barrel)
$ 28.21
$ 30.21
$31.19
$33.33
$ 30.70
$ 38.27
$ 38.27
Lease and facility operating
$
0.61
$ 0.59
$ 0.65
$ 0.63
$
0.62
$
0.67
$
0.67
Gathering, processing and transportation
$
0.98
$ 1.00
$ 0.94
$ 1.00
$
0.98
$
1.00
$
1.00
Taxes other than income
$
0.27
$ 0.27
$ 0.27
$ 0.26
$
0.27
$
0.39
$
0.39
Depreciation, depletion and amortization
$
2.04
$ 1.98
$ 2.09
$ 2.13
$
2.06
$
1.86
$
1.86
General and administrative
$
0.62
$ 0.64
$ 0.58
$ 0.66
$
0.62
$
0.65
$
0.65
$
13
$
$
$
$
61
$
16
$
16
Expenses per Mcfe
Unutilized pipeline capacity Total unutilized pipeline capacity in gas management expense
14
17
17
WPX Operational Update | May 7, 2014
37
International Segment (Unaudited) (Dollars in millions)
1Q
2013 3Q
2Q
4Q
YTD
1Q
2Q
2014 3Q
4Q
YTD
Revenues: Product revenues: Natural gas sales Oil and condensate sales Natural gas liquid sales
$
4
$
28
6
$
30
4
$
29
5
$
28
19
$
115
5
$
26
5 26
1
-
-
1
2
-
-
33
36
33
34
136
31
31
Gas management
-
-
-
-
-
-
-
Net gain (loss) on derivatives not designated as hedges
-
-
-
-
-
-
-
Other
3
6
2
5
16
-
-
36
42
35
39
152
31
31
Lease and facility operating
8
10
8
11
37
8
8
Gathering, processing and transportation
1
1
-
1
3
-
-
Taxes other than income
6
6
6
6
24
6
6 -
Total product revenues
Total revenues Costs and expenses:
Gas management, including charges for unutilized pipeline capacity
-
-
-
-
-
-
Exploration
1
3
-
3
7
-
-
Depreciation, depletion and amortization
7
10
8
9
34
10
10
Impairment of producing properties
-
-
-
3
3
-
-
Gain on sale of Powder River Basin deep rights
-
-
-
-
-
-
-
General and administrative
3
5
3
3
14
4
4
Other-net
1
(4)
3
-
-
1
1
27
31
28
36
122
29
29
Operating income (loss)
9
11
7
3
30
2
2
Interest expense
-
-
-
-
-
-
-
Interest capitalized
-
-
-
-
-
-
-
Investment income and other
5
7
4
5
21
2
2
Total costs and expenses
Income (loss) from continuing operations before income taxes
$ 14
$
18
$
11
$
8
$
51
$
4
$
4
Summary of Net Production Volumes (1) Natural gas (MMcf) Oil (Mbbl) Natural gas liquids (Mbbl) Combined equivalent volumes (MMcfe)(2)
1,485
1,620
1,707
1,723
6,534
1,723
1,723
506
553
484
489
2,032
466
466
42
44
42
40
167
41
41
4,775
5,202
4,862
4,894
19,733
4,766
4,766
(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 | May 7, 2014
38
