Hart Energy 2014 DUG Permian Basin Conference Midland Basin's ...
Hart Energy 2014 DUG Permian Basin Conference Midland Basin’s Spraberry/Wolfcamp: Most Active Play in the World and Accelerating Growth May 21, 2014
Forward-Looking Statements Except for historical information contained herein, the statements, charts and graphs in this presentation are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer's actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, completion of planned divestitures, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to complete the Company's operating activities, access to and availability of transportation, processing, fractionation and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer's credit facility and derivative contracts and the purchasers of Pioneer's oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, the risks associated with the ownership and operation of the Company’s industrial sand mining and oilfield services businesses and acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission. In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.
2
Pioneer At A Glance Total Enterprise Value ($B) 2014 Drilling Capex ($B) Q1 2014 Production (MBOEPD) 2013 Reserves (BBOE) 2013 Reserves + Resource (BBOE)
~$30 $3.0 172 0.8 >11.0
Top U.S. Fields By Rig Count1 313
(Pioneer Operated Count in Green – 43 rigs) 218 204
Resource-focused strategy, with activity concentrated in 2 of the most active U.S. fields
182 84
35
76
64
53
45
35
8
36
24
Best performing energy stock in S&P 500 since 2009 Operating in core Spraberry/Wolfcamp asset since early 1980s
– PXD holds ~825,000 acres in Spraberry/Wolfcamp – Largest producer in Spraberry/Wolfcamp
1) Baker Hughes Rig Count (5/9/14) and PXD Internal
Spraberry/Wolfcamp Gross Production By Operator
93
(MBOEPD)1
– Preeminent, low-cost operator benefitting from vertical integration strategy Attractive derivative positions protect margins – ~80% of Spraberry/Wolfcamp oil production
51 37
28
27
20
19
18
16
15
protected against volatility in Midland-Cushing oil price differential Strong investment grade financial position 1) November 2013 IHS data, gross reported oil and wet gas
3
Share Price Performance of Permian Basin Operators since 20091 Since 2009, the combined enterprise value for Permian-weighted companies listed has increased from $20 billion to $55 billion 1,200%
1,000%
800%
600%
400%
200%
Jan-09
PXD
Jan-10
CXO
LPI
Jan-11
FANG
XEC
Jan-12
AREX
EGN
1) LPI, FANG and RSPP’s price performance based on IPO price since respective IPO occurred after 1/1/2009
Jan-13
ATHL
RSPP
Jan-14
S&P 500
4
Geologic Provinces of the Permian Basin
Spraberry/ Wolfcamp Shale
Midland
Ozona Platform KS NM
OK TX
20 Miles
Permian Basin is composed of multiple uplifts and basins that formed during the Pennsylvanian and early Permian ages Spraberry/Wolfcamp Shale and deeper intervals are located in the Midland Basin of the Permian Basin Spraberry/Wolfcamp field was discovered in 1943 with production commencing in 1949 5
Wolfcamp Depositional Model – Midland Basin Platform Carbonate
Midland Basin
CBP
Platform Carbonate
Land
Shelf Edge Carbonate
Clastic Detrital
Slope Sediments & Reef Talus
Fluvial - Deltaic
Carbonate Debris Flows
Delta
Carbonate Gravity Flows
Clastic Slope Sediments
Basinal Sediments
Clastic Gravity Flows
Land
Pelagic Sediments Silt Cloud in Suspension Anaerobic Zone (Organic-rich Sediments)
Midland
Marathon Thrust Belt Land
Marathon Thrust Belt
Pelagic Sed.
Glasscock Nose
Clastic Slope
Land
Wolfcamp Map Carbonate Slope
Platform Carbonate
Clastic Gravity Flow
Debris Flow
Older Wolfcamp Clastics
Carb Gravity Flow
North Basin Platform San Simon Channel
North Source: Adapted from Handford, 1981
6
Midland Basin: Stacked Play Potential Clear Fork
U. Spraberry M. Spraberry Shale Jo Mill Shale L. Spraberry Shale Dean Wolfcamp A Wolfcamp B
“Delta log R” (excess electrical resistance) Red intervals indicate hydrocarbons Petrophysical analysis indicates significantly more oil-in-place in the Wolfcamp and Spraberry Shale intervals in the Midland Basin compared to other major U.S. shale oil plays Midland Basin: 13 horizontal play intervals identified (so far) — 10 intervals have been tested successfully — 3 additional intervals remain to be tested Eagle Ford Condensate
Barnett Combo
Niobrara
Bakken
Marcellus
200 ft
Midland Basin
Wolfcamp C Wolfcamp D “Cline” Strawn Atoka Barnett Miss Lime Woodford
Source: PXD
7
Drilling Results Confirming Pioneer’s Midland Basin Sweet Spot PXD Wolfcamp B Prospectivity Map (Early 2013) Tier 1
Tier 2
2014 ITG Research Report Wolfcamp Test Rates Higher
Pioneer Land
Pioneer Wolfcamp B wells Wolfcamp B depth contour
Test Rate (BOEPD/1000’ lateral)
Source: ITG Investment Research
Lower
Source: Internal Pioneer developed in early 2013
8
Pioneer’s Original Two Horizontal Giddings Wells (Average)1 Updated end of April
1,000
Giddings #2041H & Giddings #2073H – Wolfcamp B wells in southern Wolfcamp JV area (Upton County) ~5,300′ laterals; average cumulative production per well: 212 MBOE (70% oil)
BOEPD
500
800 MBOE 650 MBOE
100 0
100
200
300
400
Days
500
600
700
800
900
More than two years of production data for the original two 5,300′ Giddings Wolfcamp B horizontal wells supports an average EUR of 725 MBOE (equates to an average EUR of 950 MBOE for 7,000′ laterals) 1) Daily production normalized for operational shut-ins
9
Pioneer’s First 6 Northern Horizontal Wolfcamp B and Wolfcamp A Shale Wells1 E.T. O'Daniel #1H – Wolfcamp B (Midland County); 9,229′ lateral Cumulative production: 165 MBOE (76% oil)
Updated end of April
Scharbauer Ranch #202H – Wolfcamp B (Martin County); 8,342′ lateral Cumulative production: 83 MBOE (74% oil) DL Hutt C #3H – Wolfcamp B (Midland County); 7,142′ lateral Cumulative production: 122 MBOE (73% oil)
3,000
DL Hutt C #2H – Wolfcamp A (Midland County); 7,380′ lateral Cumulative production: 174 MBOE (76% oil)
2,000
Mabee K #1H – Wolfcamp B (Martin County); 6,671′ lateral Cumulative production: 120 MBOE (73% oil)2
BOEPD
1,000
DL Hutt C #1H – Wolfcamp B (Midland County); 7,380′ lateral Cumulative production: 217 MBOE (73% oil)
500 1 MMBOE 800 MBOE
100 0
30
60
90
120
150
180
210 Days
240
270
300
330
360
390
420
Production data from these first 6 wells and 7 subsequent wells supports EURs for wells with ~7,000′ lateral lengths of: 1 MMBOE for Wolfcamp B wells in Midland County 800 MBOE for Wolfcamp A wells in Midland County and Wolfcamp B wells in Martin County 1) Daily production normalized for operational shut-ins 2) Mabee K #1H shut-in for offset frac; recently placed back on production and currently cleaning up; oil production is recovering to pre-frac levels
10
Pioneer’s First 4 Northern Horizontal Wolfcamp D Shale Wells1 University 7-43 #10H – Wolfcamp D (Andrews County); 7,382′ lateral Cumulative production: 76 MBOE (69% oil)
Updated end of April
E.T. O’Daniel #2H – Wolfcamp D (Midland County); 9,112′ lateral Cumulative production: 128 MBOE (70% oil)
3,000
Scharbauer Ranch #201H – Wolfcamp D (Martin County); 7,862′ lateral Cumulative production: 76 MBOE (60% oil)
2,000 DL Hutt C #4H – Wolfcamp D (Midland County); 6,962′ lateral Cumulative production: 95 MBOE (71% oil)
BOEPD
1,000
500 800 MBOE 650 MBOE
100 0
30
60
90
120 Days
150
180
210
240
Production data from these wells supports EURs of 650 MBOE to 800 MBOE for Wolfcamp D wells in Midland, Martin and Andrews counties with ~7,000′ lateral lengths 1) Daily production normalized for operational shut-ins
11
Pioneer’s First 5 Northern Horizontal Lower Spraberry Shale Wells1 Flanagan 14 Lloyd A #21H (Glasscock County); 7,212′ lateral Cumulative production: 88 MBOE (84% oil)
Updated end of April
Hutt C #21H (Midland County); 6,662′ lateral Cumulative production: 43 MBOE (77% oil) University 7-43 #16H (Andrews County); 7,502′ lateral Cumulative production: 73 MBOE (83% oil) Mabee K #10H (Martin County); 4,982′ lateral Cumulative production: 57 MBOE (89% oil)2
2,000
Scharbauer Ranch #501H (Martin County); 7,502′ lateral Cumulative production: 83 MBOE (83% oil)
BOEPD
1,000
500 1 MMBOE 800 MBOE 575 MBOE Shut-in due to severe weather
Lower Spraberry Shale wells typically take 30 – 60 days to reach a peak rate
100 0
30
60
90
Days 120
150
180
210
Lower Spraberry Shale interval contains highest oil-in-place of all Spraberry/Wolfcamp Shale intervals Production data from these wells and 1 subsequent well suggests EURs for Lower Spraberry Shale wells with 7,000′ lateral lengths will be 575 MBOE to 1 MMBOE 1) All wells on artificial lift, either ESPs or gas lift; daily production normalized for operational shut-ins 2) Mabee K #10H tracks above 800 MBOE EUR type curve if normalized to 7,000′ lateral
12
Northern Horizontal Well Economics1,2 BTAX IRR 100+% 45% - 100+%
100+% 45% - 95%
Lower Spraberry Shale
Wolfcamp D
Midland County Wolfcamp A & Martin County Wolfcamp B
Midland County Wolfcamp B
EUR (MBOE)
575 – 1,000
650 - 800
800
1,000
D&C Cost ($MM)
$7.5
$8.5
$8.0
$8.0
Payout Years
1.0 - 2.5
1.3 - 2.4
1.1
1.0
1) Pricing: $90/BBL for oil and $4/MCF for gas 2) Reflects 7,000′ lateral length, single well drilling cost and no “science”
13
Midland Basin Horizontal Resource Potential Continues to Grow 75 BBOE Recoverable Resource Potential (Up from 50 BBOE in 2013)
Wolfcamp C 2 BBOE
Wolfcamp D 13 BBOE
Wolfcamp B 27 BBOE
Spraberry Shales 14 BBOE
Wolfcamp A 19 BBOE
75 BBOE recoverable resource potential in shale intervals where successful horizontal wells have been drilled Assumes 140-acre spacing on 75% of acreage and downspacing to 100-acres on 25% of acreage; additional down-spacing potential exists Additional horizontal potential from other intervals (e.g. Clearfork, Middle Spraberry 14 Shale, Atoka, Woodford)
Largest U.S. Oil Fields Estimated Recoverable Resource (BBOE)1 0
25
50
75
Spraberry/Wolfcamp Eagle Ford Shale Prudhoe Bay, AK Bakken Shale Delaware Basin East Texas Basin Midway-Sunset, CA Wilmington, CA Kuparuk River, AK Kern River, CA Thunder Horse, GOM Yates, West TX Belridge South, CA Wasson, West TX Elk Hills, CA Panhandle, TX
Spraberry/Wolfcamp is the largest oil field in the U.S. 1) Cumulative production + estimated remaining recoverable resource Source: DOE, EIA, ITG and other sources
15
Pioneer’s Significant Proved Reserves and Recoverable Resource Potential1 Proved Reserves + Estimated Net Recoverable Resource Potential of >11 BBOE >22,000 Horizontal Drilling Locations 12/31/13 Proved Reserves: 845 MMBOE2 Rockies 119 MMBOE Eagle Ford Shale 131 MMBOE 130 PUD locations
Additional Net Recoverable Resource Potential: 10.2 BBOE3
Mid-Continent 93 MMBOE
Other 70 MMBOE
Spraberry/Wolfcamp 432 MMBOE 640 PUD locations
Horizontal Spraberry/Wolfcamp4,5,6,7 9.6 BBOE 20,500 locations
Other9 180 MMBOE
Expect to add 600+ MMBOE of Spraberry/Wolfcamp horizontal reserves during 2014 - 2016 1) All drilling locations shown on a gross basis 2) Proved reserves use SEC pricing of $96.82/BBL for oil and $3.67/MMBTU for gas (NYMEX) 3) Net recoverable resource potential assumes $90/BBL for oil and $5/MMBTU for gas 4) On PXD’s northern acreage, assumes (i) average EURs of 800 MBOE per well for Wolfcamp A and B intervals, 650 MBOE for Wolfcamp D interval and 575 MBOE for Spraberry Shale intervals (Lower Spraberry Shale and Jo Mill Shale), (ii) 100-acre spacing on 50% of total acreage and (iii) 90% WI and 15% royalty 5) On PXD’s southern JV acreage, assumes (i) average EUR of 575 MBOE per well, (ii) 207,000 net acres, (iii) 100-acre spacing on 50% of total acreage, (iv) laterals in Wolfcamp A, B, C & D intervals, Lower Spraberry Shale interval and Jo Mill Shale interval and (v) 25% royalty and Pioneer’s 60% share 6) Excludes horizontal resource potential from additional intervals (e.g. Clearfork, Middle Spraberry Shale, Atoka, Woodford) and further downspacing opportunities 7) Vertical resource potential that was not converted to horizontal resource potential (e.g. Strawn, Atoka) is not included as PXD has no plans to drill vertical wells in the future except to meet continuous drilling obligations 8) Reflects primarily Upper Eagle Ford Shale potential and 500 additional locations from downspacing to ~300’ 9) Other net recoverable resource potential excludes Alaska and Barnett Shale
16
Spraberry/Wolfcamp Rig Count Counties: Andrews, Borden, Crockett, Dawson, Ector, Gaines, Glasscock, Howard, Irion, Martin, Midland, Mitchell, Reagan, Schleicher, Scurry, Sterling, Tom Green and Upton 350
58% Vertical Rigs 300
96% Vertical Rigs
250
200
Vertical Rigs
42% Horizontal Rigs (up from 23% in early 2013)
150
100
4% Horizontal Rigs 50
0
Source: Rig count data provided by Baker Hughes, 5/9/14
Horizontal Rigs
17
Production Growth Profiles For 3 Largest U.S. Oil Shale Plays Includes Horizontal Wells Only
10,000,000
Eagle Ford 196 Horizontal Rigs (down from 218 rigs in early 2013)
Gross Production (BOEPD)
1,000,000
Bakken 168 Horizontal Rigs (down from 176 rigs in early 2013)
100,000
Spraberry/Wolfcamp 131 Horizontal Rigs (up from 60 rigs in early 2013)
10,000
1,000
100 0
12
24
36
48
60
72
84
96
108
120
132
Months
Spraberry/Wolfcamp horizontal growth trajectory similar to Bakken and Eagle Ford Note: Production data is from IHS and represents incremental production for the play beginning when horizontal drilling activity began in earnest; Rig count data from Baker Hughes as of 5/9/14; Spraberry/Wolfcamp includes selected counties identified on slide titled “Spraberry/Wolfcamp Rig Count”; Initial month is November 2010 for Spraberry/Wolfcamp, April 2008 for Eagle Ford and January 2003 for Bakken
18
Spraberry/Wolfcamp Production History Includes Vertical and Horizontal Wells
650,000 600,000 585,000
550,000
500,000
Spraberry/Wolfcamp production has increased ~425,000 BOEPD since 2009
400,000 350,000 300,000 250,000
Production (BOEPD)
450,000
200,000 150,000 100,000
Monthly Production
50,000
2013
2011
2009
2007
2005
2003
2001
1999
1997
1995
1993
1991
1989
1987
1985
1983
1981
1979
1977
1975
1973
1971
1969
1967
1965
-
From 2009 to 2012, production growth primarily attributable to increased vertical activity Post 2012, production growth expected to be driven by horizontal activity Source: IHS Energy through January 2014 for the Spraberry, Credo East, Garden City South and Lin Fields; 2-stream production data
19
Pace of Eagle Ford Production Growth is Slowing
Source: Credit Suisse, E&P Performance Monitor, April 28, 2014
20
Pace of Bakken Production Growth is Slowing North Dakota Daily Oil Production (MBOPD) 1,000
Daily Oil Production (MBOPD)
900
800 700 600 500 400 300 200 100 0 Jan-10
Jan-11
Jan-12
Source: North Dakota Industrial Commission, Department of Mineral Resources, Oil and Gas Division
Jan-13
Jan-14
21
Spraberry/Wolfcamp Horizontal Production Growth Profile
3.50
3.50
3.00
3.00
2.50 2.00 1.50
Other Operators2,3
1.00 0.50
2014
2016
2018
2020
2022
2.50
2.00
Other Operators2,3
1.50 1.00
Pioneer3,4
0.50
Pioneer3,4
0.00 1) 2) 3) 4)
PXD’s 120 HZ Rig Growth Scenario PXD adds ~10 HZ rigs/year for 10 years Assumes flat $95 oil & $4.50 gas
Gross Daily Production (MMBOEPD)
Gross Daily Production (MMBOEPD)
PXD’s 80 HZ Rig Growth Scenario PXD adds ~5 HZ rigs/year for 10 years Assumes strip pricing for oil & gas1
2024
0.00 2014
2016
2018
2020
As of 5/15/2014; oil price declines from $100 in 2014 to $81 in 2019+; gas price increases from $4.50 in 2014 to $5.00 in 2021+ Assumes PXD operates 1/3 of horizontal rigs in Spraberry/Wolfcamp and other operators account for 2/3 of horizontal rigs Assumes indicative EURs and lateral lengths across PXD acreage Includes royalty volumes, joint venture partner’s share of production in southern Wolfcamp and volumes for other small working interest owners
2022
2024
22
ITG’s Permian Basin Oil Growth Forecast 1-1.8 MMbbl/d Total Permian Growth by 2025 High Case 3.2 MMbbl/d by 2025
3,500
3,000
Wellhead Oil (MBbl/d)
2,500
Current 1.5 MMbbl/d
2,000
Base Case 2.5 MMbbl/d by 2025
1,500
Midland Basin
1,000
Delaware Basin
500
Other Permian
Source: ITG Investment Research
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
-
23
Primary Sources of Domestic Oil Growth
Bakken
Niobrara
Permian
Delaware Basin
Midland Basin Spraberry/Wolfcamp 75 BBOE Recoverable Resource Potential Eagle Ford Deepwater Gulf of Mexico 24
U.S. Production Forecast by Grade History
Forecast
12
10
Production (MMBPD)
~8 MMBPD 8
Light
6
4
2
Medium 0 2009
Heavy 2010
2011
2012 Heavy
Source: Turner, Mason & Company
2013
2014
Medium
2015 Light
2016
2017
2018
2019
2020
Condensate
25
U.S. Rig Activity Since 1990 1,800 1,600 1,400 1,200
U.S. Gas Rig Count
1,000 800
600 400
U.S. Oil Rig Count
200 Jan-90
Jan-94
Jan-98
Jan-02
Jan-06
Jan-10
Jan-14
26
Historical WTI and Brent Price Relationship Historical WTI and Brent Prices
WTI - Brent Price Differential
$30
$150
Brent
Relationship broke in January 2011
$20
$125
$100
$75
WTI
Oil Price ($/BBL)
Oil Price ($/BBL)
$10
-
$(10)
$(20)
($17/bbl)
$50
($23/bbl)
$(30)
$25 2006 Source: EIA
2007
2008
2009
2010
2011
2012
2013
2014
$(40) 2006 Source: EIA
($30/bbl)
2007
2008
2009
2010
2011
2012
2013
2014 27
U.S. PADD III (Gulf Coast) Crude Imports Since 2005 Majority of the light crude imports have been displaced, but mediums may be “stickier,” which could put a ceiling on U.S. production growth Oil Imports to PADD 3 7,000
Average API gravity of imported crude decreasing (right axis)
6,000
32.0
30.0
5,000
Light (API > 32°)
4,000
26.0 3,000
Intermediate (28° < API < 32°)
API Gravity
Oil (MBBL/D)
28.0
24.0 2,000
0 Jan-05 Source: EIA
22.0
Heavy (API < 28°)
1,000
20.0 Jan-06
Jan-07
Jan-08
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
28
Increased U.S. Petroleum Product Exports Over 10 Years U.S. Petroleum Product Exports (million barrels per day)
Product exports reached 4.3 MM in 12/2013
4.5 4.0
Gasoline 3.5
Kerosene & distillates driving growth
3.0 2.5
Kerosene & Distillates
2.0
Residual Fuel
1.5
LPG 1.0
Coke
0.5
Other 0.0 Jan-04
Jan-05
Jan-06
Jan-07
Jan-08
Jan-09
Source: EIA Other includes pentane plus, gasoline blending components and other products
Jan-10
Jan-11
Jan-12
Jan-13
29
WTI, Brent and PADD 3 Gasoline Price History 350
Gasoline prices are more closely tied to Brent than WTI
PADD 3 Gasoline Price
Price (Cents per Gallon)
300
Brent Price
250
200
WTI Price 150
100
50 Jan-06 Source: EIA
Jan-07
Jan-08
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
30
The Export Ban Threatens to Strand U.S. Crude Downstream industry is responding to increased light production — Announced refinery and splitter investments, increased refinery utilization — Product exports are booming — Increased exports of crude to Canada for refining
But production will soon outpace downstream industry responses — Nearly all light sweet imports have been displaced — Crude imports from Canada are increasing (including for re-export) — Heavy or medium to light refining slate adjustments economically limited
The Gulf Coast is becoming saturated with domestic production
Similar to Cushing in 2012, the U.S. will become a globally stranded location unless there is export relief — Producers will likely experience large price differentials to Brent — Supply glut will drive prices below costs for large number of producers
— A far-reaching discount blow-out clearly looms on the horizon
31
The Foreseeable Consequences of Inaction Producers will be forced to lay down rigs
Production growth will stall and production will quickly decline A substantial portion of domestic natural gas production is associated with oil production – as crude production declines, so will natural gas supplies Hundreds of thousands of jobs at risk – Industry supports 9.8 MM jobs and will create up to 1.7 million new jobs by 2020 (McKinsey)
Less tax revenue for federal, state and local governments – Industry delivers $85 million per day in revenue to the federal government
U.S. trade deficit will widen as foreign light crude oil imports resume – If ban is lifted, oil and gas trade balance forecasted to improve from $354 billion deficit in 2011 to $5 billion surplus in 2020 (Citi)
Reduced gasoline prices to the U.S. consumer (Resources for the Future)
32
Banned Commodities Exports Only 3 commodities are included in the Export Administration Regulations’ “Short Supply Control” list1
Crude Oil
Unprocessed Western Red Cedar
Horses Exported by Sea
Source: BIS Short Supply Controls Part 754 1) Certain other items not on the “Short Supply Control” are prohibited for exports due to national security and foreign policy reasons
33
Certain Reserve Information Cautionary Note to U.S. Investors --The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. In this news release, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource potential,” “net recoverable resource potential,” “resource base,” “estimated ultimate recovery,” “EUR,” “oil-in-place” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer. U.S. investors are urged to consider closely the disclosures in the Company’s periodic filings with the SEC. Such filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations, and the Company’s website at www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.
34
Forward-Looking Statements Except for historical information contained herein, the statements, charts and graphs in this presentation are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer's actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, completion of planned divestitures, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to complete the Company's operating activities, access to and availability of transportation, processing, fractionation and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer's credit facility and derivative contracts and the purchasers of Pioneer's oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, the risks associated with the ownership and operation of the Company’s industrial sand mining and oilfield services businesses and acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission. In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.
2
Pioneer At A Glance Total Enterprise Value ($B) 2014 Drilling Capex ($B) Q1 2014 Production (MBOEPD) 2013 Reserves (BBOE) 2013 Reserves + Resource (BBOE)
~$30 $3.0 172 0.8 >11.0
Top U.S. Fields By Rig Count1 313
(Pioneer Operated Count in Green – 43 rigs) 218 204
Resource-focused strategy, with activity concentrated in 2 of the most active U.S. fields
182 84
35
76
64
53
45
35
8
36
24
Best performing energy stock in S&P 500 since 2009 Operating in core Spraberry/Wolfcamp asset since early 1980s
– PXD holds ~825,000 acres in Spraberry/Wolfcamp – Largest producer in Spraberry/Wolfcamp
1) Baker Hughes Rig Count (5/9/14) and PXD Internal
Spraberry/Wolfcamp Gross Production By Operator
93
(MBOEPD)1
– Preeminent, low-cost operator benefitting from vertical integration strategy Attractive derivative positions protect margins – ~80% of Spraberry/Wolfcamp oil production
51 37
28
27
20
19
18
16
15
protected against volatility in Midland-Cushing oil price differential Strong investment grade financial position 1) November 2013 IHS data, gross reported oil and wet gas
3
Share Price Performance of Permian Basin Operators since 20091 Since 2009, the combined enterprise value for Permian-weighted companies listed has increased from $20 billion to $55 billion 1,200%
1,000%
800%
600%
400%
200%
Jan-09
PXD
Jan-10
CXO
LPI
Jan-11
FANG
XEC
Jan-12
AREX
EGN
1) LPI, FANG and RSPP’s price performance based on IPO price since respective IPO occurred after 1/1/2009
Jan-13
ATHL
RSPP
Jan-14
S&P 500
4
Geologic Provinces of the Permian Basin
Spraberry/ Wolfcamp Shale
Midland
Ozona Platform KS NM
OK TX
20 Miles
Permian Basin is composed of multiple uplifts and basins that formed during the Pennsylvanian and early Permian ages Spraberry/Wolfcamp Shale and deeper intervals are located in the Midland Basin of the Permian Basin Spraberry/Wolfcamp field was discovered in 1943 with production commencing in 1949 5
Wolfcamp Depositional Model – Midland Basin Platform Carbonate
Midland Basin
CBP
Platform Carbonate
Land
Shelf Edge Carbonate
Clastic Detrital
Slope Sediments & Reef Talus
Fluvial - Deltaic
Carbonate Debris Flows
Delta
Carbonate Gravity Flows
Clastic Slope Sediments
Basinal Sediments
Clastic Gravity Flows
Land
Pelagic Sediments Silt Cloud in Suspension Anaerobic Zone (Organic-rich Sediments)
Midland
Marathon Thrust Belt Land
Marathon Thrust Belt
Pelagic Sed.
Glasscock Nose
Clastic Slope
Land
Wolfcamp Map Carbonate Slope
Platform Carbonate
Clastic Gravity Flow
Debris Flow
Older Wolfcamp Clastics
Carb Gravity Flow
North Basin Platform San Simon Channel
North Source: Adapted from Handford, 1981
6
Midland Basin: Stacked Play Potential Clear Fork
U. Spraberry M. Spraberry Shale Jo Mill Shale L. Spraberry Shale Dean Wolfcamp A Wolfcamp B
“Delta log R” (excess electrical resistance) Red intervals indicate hydrocarbons Petrophysical analysis indicates significantly more oil-in-place in the Wolfcamp and Spraberry Shale intervals in the Midland Basin compared to other major U.S. shale oil plays Midland Basin: 13 horizontal play intervals identified (so far) — 10 intervals have been tested successfully — 3 additional intervals remain to be tested Eagle Ford Condensate
Barnett Combo
Niobrara
Bakken
Marcellus
200 ft
Midland Basin
Wolfcamp C Wolfcamp D “Cline” Strawn Atoka Barnett Miss Lime Woodford
Source: PXD
7
Drilling Results Confirming Pioneer’s Midland Basin Sweet Spot PXD Wolfcamp B Prospectivity Map (Early 2013) Tier 1
Tier 2
2014 ITG Research Report Wolfcamp Test Rates Higher
Pioneer Land
Pioneer Wolfcamp B wells Wolfcamp B depth contour
Test Rate (BOEPD/1000’ lateral)
Source: ITG Investment Research
Lower
Source: Internal Pioneer developed in early 2013
8
Pioneer’s Original Two Horizontal Giddings Wells (Average)1 Updated end of April
1,000
Giddings #2041H & Giddings #2073H – Wolfcamp B wells in southern Wolfcamp JV area (Upton County) ~5,300′ laterals; average cumulative production per well: 212 MBOE (70% oil)
BOEPD
500
800 MBOE 650 MBOE
100 0
100
200
300
400
Days
500
600
700
800
900
More than two years of production data for the original two 5,300′ Giddings Wolfcamp B horizontal wells supports an average EUR of 725 MBOE (equates to an average EUR of 950 MBOE for 7,000′ laterals) 1) Daily production normalized for operational shut-ins
9
Pioneer’s First 6 Northern Horizontal Wolfcamp B and Wolfcamp A Shale Wells1 E.T. O'Daniel #1H – Wolfcamp B (Midland County); 9,229′ lateral Cumulative production: 165 MBOE (76% oil)
Updated end of April
Scharbauer Ranch #202H – Wolfcamp B (Martin County); 8,342′ lateral Cumulative production: 83 MBOE (74% oil) DL Hutt C #3H – Wolfcamp B (Midland County); 7,142′ lateral Cumulative production: 122 MBOE (73% oil)
3,000
DL Hutt C #2H – Wolfcamp A (Midland County); 7,380′ lateral Cumulative production: 174 MBOE (76% oil)
2,000
Mabee K #1H – Wolfcamp B (Martin County); 6,671′ lateral Cumulative production: 120 MBOE (73% oil)2
BOEPD
1,000
DL Hutt C #1H – Wolfcamp B (Midland County); 7,380′ lateral Cumulative production: 217 MBOE (73% oil)
500 1 MMBOE 800 MBOE
100 0
30
60
90
120
150
180
210 Days
240
270
300
330
360
390
420
Production data from these first 6 wells and 7 subsequent wells supports EURs for wells with ~7,000′ lateral lengths of: 1 MMBOE for Wolfcamp B wells in Midland County 800 MBOE for Wolfcamp A wells in Midland County and Wolfcamp B wells in Martin County 1) Daily production normalized for operational shut-ins 2) Mabee K #1H shut-in for offset frac; recently placed back on production and currently cleaning up; oil production is recovering to pre-frac levels
10
Pioneer’s First 4 Northern Horizontal Wolfcamp D Shale Wells1 University 7-43 #10H – Wolfcamp D (Andrews County); 7,382′ lateral Cumulative production: 76 MBOE (69% oil)
Updated end of April
E.T. O’Daniel #2H – Wolfcamp D (Midland County); 9,112′ lateral Cumulative production: 128 MBOE (70% oil)
3,000
Scharbauer Ranch #201H – Wolfcamp D (Martin County); 7,862′ lateral Cumulative production: 76 MBOE (60% oil)
2,000 DL Hutt C #4H – Wolfcamp D (Midland County); 6,962′ lateral Cumulative production: 95 MBOE (71% oil)
BOEPD
1,000
500 800 MBOE 650 MBOE
100 0
30
60
90
120 Days
150
180
210
240
Production data from these wells supports EURs of 650 MBOE to 800 MBOE for Wolfcamp D wells in Midland, Martin and Andrews counties with ~7,000′ lateral lengths 1) Daily production normalized for operational shut-ins
11
Pioneer’s First 5 Northern Horizontal Lower Spraberry Shale Wells1 Flanagan 14 Lloyd A #21H (Glasscock County); 7,212′ lateral Cumulative production: 88 MBOE (84% oil)
Updated end of April
Hutt C #21H (Midland County); 6,662′ lateral Cumulative production: 43 MBOE (77% oil) University 7-43 #16H (Andrews County); 7,502′ lateral Cumulative production: 73 MBOE (83% oil) Mabee K #10H (Martin County); 4,982′ lateral Cumulative production: 57 MBOE (89% oil)2
2,000
Scharbauer Ranch #501H (Martin County); 7,502′ lateral Cumulative production: 83 MBOE (83% oil)
BOEPD
1,000
500 1 MMBOE 800 MBOE 575 MBOE Shut-in due to severe weather
Lower Spraberry Shale wells typically take 30 – 60 days to reach a peak rate
100 0
30
60
90
Days 120
150
180
210
Lower Spraberry Shale interval contains highest oil-in-place of all Spraberry/Wolfcamp Shale intervals Production data from these wells and 1 subsequent well suggests EURs for Lower Spraberry Shale wells with 7,000′ lateral lengths will be 575 MBOE to 1 MMBOE 1) All wells on artificial lift, either ESPs or gas lift; daily production normalized for operational shut-ins 2) Mabee K #10H tracks above 800 MBOE EUR type curve if normalized to 7,000′ lateral
12
Northern Horizontal Well Economics1,2 BTAX IRR 100+% 45% - 100+%
100+% 45% - 95%
Lower Spraberry Shale
Wolfcamp D
Midland County Wolfcamp A & Martin County Wolfcamp B
Midland County Wolfcamp B
EUR (MBOE)
575 – 1,000
650 - 800
800
1,000
D&C Cost ($MM)
$7.5
$8.5
$8.0
$8.0
Payout Years
1.0 - 2.5
1.3 - 2.4
1.1
1.0
1) Pricing: $90/BBL for oil and $4/MCF for gas 2) Reflects 7,000′ lateral length, single well drilling cost and no “science”
13
Midland Basin Horizontal Resource Potential Continues to Grow 75 BBOE Recoverable Resource Potential (Up from 50 BBOE in 2013)
Wolfcamp C 2 BBOE
Wolfcamp D 13 BBOE
Wolfcamp B 27 BBOE
Spraberry Shales 14 BBOE
Wolfcamp A 19 BBOE
75 BBOE recoverable resource potential in shale intervals where successful horizontal wells have been drilled Assumes 140-acre spacing on 75% of acreage and downspacing to 100-acres on 25% of acreage; additional down-spacing potential exists Additional horizontal potential from other intervals (e.g. Clearfork, Middle Spraberry 14 Shale, Atoka, Woodford)
Largest U.S. Oil Fields Estimated Recoverable Resource (BBOE)1 0
25
50
75
Spraberry/Wolfcamp Eagle Ford Shale Prudhoe Bay, AK Bakken Shale Delaware Basin East Texas Basin Midway-Sunset, CA Wilmington, CA Kuparuk River, AK Kern River, CA Thunder Horse, GOM Yates, West TX Belridge South, CA Wasson, West TX Elk Hills, CA Panhandle, TX
Spraberry/Wolfcamp is the largest oil field in the U.S. 1) Cumulative production + estimated remaining recoverable resource Source: DOE, EIA, ITG and other sources
15
Pioneer’s Significant Proved Reserves and Recoverable Resource Potential1 Proved Reserves + Estimated Net Recoverable Resource Potential of >11 BBOE >22,000 Horizontal Drilling Locations 12/31/13 Proved Reserves: 845 MMBOE2 Rockies 119 MMBOE Eagle Ford Shale 131 MMBOE 130 PUD locations
Additional Net Recoverable Resource Potential: 10.2 BBOE3
Mid-Continent 93 MMBOE
Other 70 MMBOE
Spraberry/Wolfcamp 432 MMBOE 640 PUD locations
Horizontal Spraberry/Wolfcamp4,5,6,7 9.6 BBOE 20,500 locations
Other9 180 MMBOE
Expect to add 600+ MMBOE of Spraberry/Wolfcamp horizontal reserves during 2014 - 2016 1) All drilling locations shown on a gross basis 2) Proved reserves use SEC pricing of $96.82/BBL for oil and $3.67/MMBTU for gas (NYMEX) 3) Net recoverable resource potential assumes $90/BBL for oil and $5/MMBTU for gas 4) On PXD’s northern acreage, assumes (i) average EURs of 800 MBOE per well for Wolfcamp A and B intervals, 650 MBOE for Wolfcamp D interval and 575 MBOE for Spraberry Shale intervals (Lower Spraberry Shale and Jo Mill Shale), (ii) 100-acre spacing on 50% of total acreage and (iii) 90% WI and 15% royalty 5) On PXD’s southern JV acreage, assumes (i) average EUR of 575 MBOE per well, (ii) 207,000 net acres, (iii) 100-acre spacing on 50% of total acreage, (iv) laterals in Wolfcamp A, B, C & D intervals, Lower Spraberry Shale interval and Jo Mill Shale interval and (v) 25% royalty and Pioneer’s 60% share 6) Excludes horizontal resource potential from additional intervals (e.g. Clearfork, Middle Spraberry Shale, Atoka, Woodford) and further downspacing opportunities 7) Vertical resource potential that was not converted to horizontal resource potential (e.g. Strawn, Atoka) is not included as PXD has no plans to drill vertical wells in the future except to meet continuous drilling obligations 8) Reflects primarily Upper Eagle Ford Shale potential and 500 additional locations from downspacing to ~300’ 9) Other net recoverable resource potential excludes Alaska and Barnett Shale
16
Spraberry/Wolfcamp Rig Count Counties: Andrews, Borden, Crockett, Dawson, Ector, Gaines, Glasscock, Howard, Irion, Martin, Midland, Mitchell, Reagan, Schleicher, Scurry, Sterling, Tom Green and Upton 350
58% Vertical Rigs 300
96% Vertical Rigs
250
200
Vertical Rigs
42% Horizontal Rigs (up from 23% in early 2013)
150
100
4% Horizontal Rigs 50
0
Source: Rig count data provided by Baker Hughes, 5/9/14
Horizontal Rigs
17
Production Growth Profiles For 3 Largest U.S. Oil Shale Plays Includes Horizontal Wells Only
10,000,000
Eagle Ford 196 Horizontal Rigs (down from 218 rigs in early 2013)
Gross Production (BOEPD)
1,000,000
Bakken 168 Horizontal Rigs (down from 176 rigs in early 2013)
100,000
Spraberry/Wolfcamp 131 Horizontal Rigs (up from 60 rigs in early 2013)
10,000
1,000
100 0
12
24
36
48
60
72
84
96
108
120
132
Months
Spraberry/Wolfcamp horizontal growth trajectory similar to Bakken and Eagle Ford Note: Production data is from IHS and represents incremental production for the play beginning when horizontal drilling activity began in earnest; Rig count data from Baker Hughes as of 5/9/14; Spraberry/Wolfcamp includes selected counties identified on slide titled “Spraberry/Wolfcamp Rig Count”; Initial month is November 2010 for Spraberry/Wolfcamp, April 2008 for Eagle Ford and January 2003 for Bakken
18
Spraberry/Wolfcamp Production History Includes Vertical and Horizontal Wells
650,000 600,000 585,000
550,000
500,000
Spraberry/Wolfcamp production has increased ~425,000 BOEPD since 2009
400,000 350,000 300,000 250,000
Production (BOEPD)
450,000
200,000 150,000 100,000
Monthly Production
50,000
2013
2011
2009
2007
2005
2003
2001
1999
1997
1995
1993
1991
1989
1987
1985
1983
1981
1979
1977
1975
1973
1971
1969
1967
1965
-
From 2009 to 2012, production growth primarily attributable to increased vertical activity Post 2012, production growth expected to be driven by horizontal activity Source: IHS Energy through January 2014 for the Spraberry, Credo East, Garden City South and Lin Fields; 2-stream production data
19
Pace of Eagle Ford Production Growth is Slowing
Source: Credit Suisse, E&P Performance Monitor, April 28, 2014
20
Pace of Bakken Production Growth is Slowing North Dakota Daily Oil Production (MBOPD) 1,000
Daily Oil Production (MBOPD)
900
800 700 600 500 400 300 200 100 0 Jan-10
Jan-11
Jan-12
Source: North Dakota Industrial Commission, Department of Mineral Resources, Oil and Gas Division
Jan-13
Jan-14
21
Spraberry/Wolfcamp Horizontal Production Growth Profile
3.50
3.50
3.00
3.00
2.50 2.00 1.50
Other Operators2,3
1.00 0.50
2014
2016
2018
2020
2022
2.50
2.00
Other Operators2,3
1.50 1.00
Pioneer3,4
0.50
Pioneer3,4
0.00 1) 2) 3) 4)
PXD’s 120 HZ Rig Growth Scenario PXD adds ~10 HZ rigs/year for 10 years Assumes flat $95 oil & $4.50 gas
Gross Daily Production (MMBOEPD)
Gross Daily Production (MMBOEPD)
PXD’s 80 HZ Rig Growth Scenario PXD adds ~5 HZ rigs/year for 10 years Assumes strip pricing for oil & gas1
2024
0.00 2014
2016
2018
2020
As of 5/15/2014; oil price declines from $100 in 2014 to $81 in 2019+; gas price increases from $4.50 in 2014 to $5.00 in 2021+ Assumes PXD operates 1/3 of horizontal rigs in Spraberry/Wolfcamp and other operators account for 2/3 of horizontal rigs Assumes indicative EURs and lateral lengths across PXD acreage Includes royalty volumes, joint venture partner’s share of production in southern Wolfcamp and volumes for other small working interest owners
2022
2024
22
ITG’s Permian Basin Oil Growth Forecast 1-1.8 MMbbl/d Total Permian Growth by 2025 High Case 3.2 MMbbl/d by 2025
3,500
3,000
Wellhead Oil (MBbl/d)
2,500
Current 1.5 MMbbl/d
2,000
Base Case 2.5 MMbbl/d by 2025
1,500
Midland Basin
1,000
Delaware Basin
500
Other Permian
Source: ITG Investment Research
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
2014
2013
2012
2011
2010
2009
2008
2007
2006
2005
-
23
Primary Sources of Domestic Oil Growth
Bakken
Niobrara
Permian
Delaware Basin
Midland Basin Spraberry/Wolfcamp 75 BBOE Recoverable Resource Potential Eagle Ford Deepwater Gulf of Mexico 24
U.S. Production Forecast by Grade History
Forecast
12
10
Production (MMBPD)
~8 MMBPD 8
Light
6
4
2
Medium 0 2009
Heavy 2010
2011
2012 Heavy
Source: Turner, Mason & Company
2013
2014
Medium
2015 Light
2016
2017
2018
2019
2020
Condensate
25
U.S. Rig Activity Since 1990 1,800 1,600 1,400 1,200
U.S. Gas Rig Count
1,000 800
600 400
U.S. Oil Rig Count
200 Jan-90
Jan-94
Jan-98
Jan-02
Jan-06
Jan-10
Jan-14
26
Historical WTI and Brent Price Relationship Historical WTI and Brent Prices
WTI - Brent Price Differential
$30
$150
Brent
Relationship broke in January 2011
$20
$125
$100
$75
WTI
Oil Price ($/BBL)
Oil Price ($/BBL)
$10
-
$(10)
$(20)
($17/bbl)
$50
($23/bbl)
$(30)
$25 2006 Source: EIA
2007
2008
2009
2010
2011
2012
2013
2014
$(40) 2006 Source: EIA
($30/bbl)
2007
2008
2009
2010
2011
2012
2013
2014 27
U.S. PADD III (Gulf Coast) Crude Imports Since 2005 Majority of the light crude imports have been displaced, but mediums may be “stickier,” which could put a ceiling on U.S. production growth Oil Imports to PADD 3 7,000
Average API gravity of imported crude decreasing (right axis)
6,000
32.0
30.0
5,000
Light (API > 32°)
4,000
26.0 3,000
Intermediate (28° < API < 32°)
API Gravity
Oil (MBBL/D)
28.0
24.0 2,000
0 Jan-05 Source: EIA
22.0
Heavy (API < 28°)
1,000
20.0 Jan-06
Jan-07
Jan-08
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
28
Increased U.S. Petroleum Product Exports Over 10 Years U.S. Petroleum Product Exports (million barrels per day)
Product exports reached 4.3 MM in 12/2013
4.5 4.0
Gasoline 3.5
Kerosene & distillates driving growth
3.0 2.5
Kerosene & Distillates
2.0
Residual Fuel
1.5
LPG 1.0
Coke
0.5
Other 0.0 Jan-04
Jan-05
Jan-06
Jan-07
Jan-08
Jan-09
Source: EIA Other includes pentane plus, gasoline blending components and other products
Jan-10
Jan-11
Jan-12
Jan-13
29
WTI, Brent and PADD 3 Gasoline Price History 350
Gasoline prices are more closely tied to Brent than WTI
PADD 3 Gasoline Price
Price (Cents per Gallon)
300
Brent Price
250
200
WTI Price 150
100
50 Jan-06 Source: EIA
Jan-07
Jan-08
Jan-09
Jan-10
Jan-11
Jan-12
Jan-13
Jan-14
30
The Export Ban Threatens to Strand U.S. Crude Downstream industry is responding to increased light production — Announced refinery and splitter investments, increased refinery utilization — Product exports are booming — Increased exports of crude to Canada for refining
But production will soon outpace downstream industry responses — Nearly all light sweet imports have been displaced — Crude imports from Canada are increasing (including for re-export) — Heavy or medium to light refining slate adjustments economically limited
The Gulf Coast is becoming saturated with domestic production
Similar to Cushing in 2012, the U.S. will become a globally stranded location unless there is export relief — Producers will likely experience large price differentials to Brent — Supply glut will drive prices below costs for large number of producers
— A far-reaching discount blow-out clearly looms on the horizon
31
The Foreseeable Consequences of Inaction Producers will be forced to lay down rigs
Production growth will stall and production will quickly decline A substantial portion of domestic natural gas production is associated with oil production – as crude production declines, so will natural gas supplies Hundreds of thousands of jobs at risk – Industry supports 9.8 MM jobs and will create up to 1.7 million new jobs by 2020 (McKinsey)
Less tax revenue for federal, state and local governments – Industry delivers $85 million per day in revenue to the federal government
U.S. trade deficit will widen as foreign light crude oil imports resume – If ban is lifted, oil and gas trade balance forecasted to improve from $354 billion deficit in 2011 to $5 billion surplus in 2020 (Citi)
Reduced gasoline prices to the U.S. consumer (Resources for the Future)
32
Banned Commodities Exports Only 3 commodities are included in the Export Administration Regulations’ “Short Supply Control” list1
Crude Oil
Unprocessed Western Red Cedar
Horses Exported by Sea
Source: BIS Short Supply Controls Part 754 1) Certain other items not on the “Short Supply Control” are prohibited for exports due to national security and foreign policy reasons
33
Certain Reserve Information Cautionary Note to U.S. Investors --The SEC prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. In this news release, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource potential,” “net recoverable resource potential,” “resource base,” “estimated ultimate recovery,” “EUR,” “oil-in-place” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer. U.S. investors are urged to consider closely the disclosures in the Company’s periodic filings with the SEC. Such filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations, and the Company’s website at www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.
34
