 Investor
Presentation January 2013
Exhibit 99.1 |
 2
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, including joint venture
agreements, with third parties on mutually acceptable terms, 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 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 an
industrial sand mining business 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. Please
see
the
appendix
slides
included
in
this
presentation
for
other
important
information. |
 3
U.S. asset base
High oil exposure from proved reserves + estimated net resource
potential of >7 BBOE
Drilling
program
focused
in
three
liquids
and
resource
rich
core
assets
in Texas
–
Spraberry Vertical
–
Horizontal Wolfcamp Shale
•
Joint venture accelerates future development
–
Eagle Ford Shale
Strong production growth profile
Vertical integration substantially improving returns
Attractive derivative positions protect margins
Strong investment grade financial position
Investment Highlights |
 Strong
drilling and well performance in Spraberry vertical,
horizontal Wolfcamp Shale and
Eagle Ford Shale driving production
growth
4
Strong Production Growth in 2012
MBOEPD
117
140
1)
Reflects
Tunisia,
South
Africa
and
Barnett
Shale
as
discontinued
operations
58%
Liquids
52%
Liquids
101
2012 E
148 –
149 MBOEPD
FY Guidance
47%
Liquids
143
59%
Liquids
153
61%
Liquids
154
158
2010
2011
Q1
Q2
Q3
Q4E
1
- |
 Capital
program components: –
Drilling capital
2.5
–
Vertical integration
0.5
•
Includes $100 MM for field facilities
accelerated into 2012
3.0
Capital program funded from:
–
Operating cash flow
1.8
–
Equity offering proceeds
0.5
–
Liquidated derivatives
and
inventory reduction
0.2
–
Credit facility borrowings
0.4
–
South Africa divestiture
and
South Texas acreage sale
0.1
3.0
NYMEX Oil Price ($/BBL)
$85/bbl oil and $3.50/mcf gas
Sensitivity to Commodity Prices ($ MM)
5
2012E
Capital
Spending
and
Cash
Flow
1
1)
Capital spending excludes acquisitions, asset retirement obligations, capitalized
interest and G&G G&A $B |
 6
12/31/11
Proved
Reserves:
1.1
BBOE
2
Additional
Net
Resource
Potential:
6.7
BBOE
1)
All drilling locations shown on a gross basis
2)
SEC pricing of $96.13/BBL for oil and $4.12/MMBTU for gas (NYMEX)
3)
Primarily reflects Alaska, Raton and South Texas
4)
Includes vertical well potential from Wolfcamp and deeper intervals
5)
Assumes
average
EUR
of
575
MBOE
per
well,
>8,000
locations,
>400,000
acres,
140-acre
spacing,
laterals in all intervals (A, B, C & D) and 75% NRI
Permian 5.6 BBOE
Spraberry
609 MMBOE
4,700 PUD locations
Raton
170 MMBOE
150 PUD locations
Other
107 MMBOE
120 PUD locations
Mid-Continent
107 MMBOE
Spraberry
40-ac Drilling
4
600 MMBOE
5,200 locations
Spraberry
20-ac
Drilling
4
1.2 BBOE
13,500 high-graded locations
Spraberry Waterflood
300 MMBOE
40% acreage
Eagle Ford Shale
600 MMBOE
1,700 locations
Eagle
Ford Shale
70 MMBOE
120 PUD locations
Horizontal
Wolfcamp
5
3.5 BBOE
8,000 locations
6
Significant Proved Reserves and Resource Potential
1
Proved Reserves + Estimated Net Resource Potential of >7 BBOE and 35,000 Drilling
Locations |
 7
Wolfcamp Shale JV Opportunity
Offering 33% to 50% of Pioneer’s
working interest in ~200,000 acres in
southern portion of Midland Basin
Large, contiguous acreage position located in
Upton, Reagan, Irion and Crockett counties
Includes all intervals (A, B, C & D)
>4,000 potential horizontal
development locations excluding
downspacing potential
>2.0 billion barrel gross resource
potential
Liquids content: ~90%
EUR: ~575 MBOE for 7,000’
lateral
~45% before-tax IRR
$85 oil and $4 gas
~$7 MM well cost
Proposed JV Area
Accelerated development enhances
net asset value and project returns |
 8
Horizontal Wolfcamp Shale Results Meeting Expectations
Giddings #2041H: 897 BOEPD
Giddings #2073H: 792 BOEPD
University 3-31 #4H: 485 BOEPD
University 3-32 #4H: 451 BOEPD
University 3-32 #5H: 759 BOEPD
University 4-20 #2H: 466 BOEPD
University 4-20 #3H: 518 BOEPD
University 4-19 #3H: 312 BOEPD
University 1-18 #2H: 358 BOEPD
University 10-13 #5H: 987 BOEPD
University 10-14 #5H: 660 BOEPD
University 10-17 #1H: 536 BOEPD
University 10-17 #2H: 675 BOEPD
University 10-19 #4H: 671 BOEPD
University 10-20 #4H: 454 BOEPD
University 10-20 #6H:
585 BOEPD
Wolfcamp A well
University 10-3 #4H: 156 BOEPD
Wolfcamp A well; drilled into fault
Rocker B N #73H: 657 BOEPD
Rocker B N #74H: 1,338 BOEPD
University 1-30 #2H: 938 BOEPD
University 1-32 #6H: 737 BOEPD
University 3-31 #5H: 877 BOEPD
39 horizontal Wolfcamp wells drilled in southern ~200,000 acres through Q4 2012
22 wells on production, of which 5 were added in Q4; 4 additional flowing back
Of the 22 wells on production, 20 drilled in the Upper B interval and 2 in the A
interval 24-hour IP rates |
 9
Horizontal
Wolfcamp
Upper
B
Well
Performance
Through
Q3
1
575 MBOE Type Curve
for 7,000’
lateral
(oil portion only)
Giddings Area
(2 wells)
University
Lands
Area
(12
wells)
1)
mechanical problems
Wells unloading
fracture stimulation fluid
Average daily production from Wolfcamp Upper B
wells at or above 575 MBOE type curve
Giddings #2041H: 135 MBOE 12-month cumulative production
Giddings #2073H: 105 MBOE 10-month cumulative production
Average daily oil production through October normalized to 7,000’ lateral length
for all Upper B wells placed on production through Q3, except for 1 well with |
 10
PXD Has Multiple Horizontal Target Intervals
Miss/Atoka
5,000’
–
10,000’
Wolfcamp Horizontals
Jo Mill
U. Spraberry
M. Spraberry
L. Spraberry
L. Spraberry
Shale
Wolfcamp A
Wolfcamp Lower B
Wolfcamp C1
Wolfcamp C2
Wolfcamp D
Wolfcamp Upper B
Drilled 2 successful ~2,500’
lateral
horizontal Jo Mill wells with 24-hour
IP rates of 601 BOEPD and 404
BOEPD (80% oil)
A
Upper
Lower
C
D
Strawn
Jo Mill Sand
Dean
Shale
B
B |
 Horizontal Wolfcamp Shale Drilling Activity
11
Northern Activity Underway
Southern Drilling Focus Area
Currently focused on holding ~50,000 acres in
southern part of play during 2012 and 2013
Expect to drill 90 wells by YE 2013 to hold acreage
•
39 wells of the 90 wells drilled through Q4 2012
•
22 on production through Q4 2012
o
4 additional flowing back
5 rigs running during Q4 2012
4 rigs drilling in southern area
5th rig focused on delineating northern acreage in
Midland, Martin and Gaines counties
•
Substantial portion of Pioneer’s acreage position in
these counties could be prospective
Increasing to 7 rigs early Q1 2013
Currently targeting ~7,000’
laterals; testing
longer laterals
Recently drilled first two 10,000’
laterals
Early “development”
well results confirm
7,000’
laterals can be drilled for ~$7 MM
Utilizing 85% Brady Brown
®
sand on all wells |
 Spraberry
Vertical Deeper Drilling Continues to Drive Strong Performance 12
Dean
Limestone Pay
Sandstone Pay
Non-Organic Shale Non-Pay
Organic Rich Shale Pay
Current Spraberry 40-acre type curve EUR including Wolfcamp: 140 MBOE
Deeper drilling provides potential to add up to 100 MBOE
Deeper drilling accounted for ~65% of 2012 vertical drilling program
Commingled
Wells Placed on
Production in Q3
Average 24-hour
IP (BOEPD)
1
Potential
Incremental EUR
(MBOE)
Prospective PXD
Acreage
Strawn
43
175
30
~70%
Atoka
27
167
50 –
70
40% -
50%
Mississippian
31
118
15 –
40
~20%
1)
Compares to average 24-hour IP of 90 BOEPD for 140 MBOE EUR type curve well in the
Wolfcamp |
 Continuing to Successfully Grow Spraberry Production
13
Spraberry Net Production
(MBOEPD)
1) Includes production from Strawn, Atoka and Mississippian in vertical wells and
horizontal Wolfcamp Shale wells 2) Q3 production benefited by ~1,800 BPD from
partial NGL inventory drawdown at Mont Belvieu; offset by production loss of ~4,000 BOEPD due to continuing 3rd
3) Production from horizontal Wolfcamp Shale forecast at ~2,000 BOEPD in 2012; expect
to exit 2012 at ~5,000 BOEPD 45
62
2012
3
64
63 –
67 MBOEPD
FY Guidance
Spraberry gas processing facilities nearing
capacity in Q4 due to greater-than-anticipated
PXD and industry production growth
Negative impact to PXD’s Q4 production of 1,000
BOEPD –
2,000 BOEPD due to reduced ethane
recoveries
Addition of new Driver plant provides 100 MMCFPD
capacity starting late March/early April 2013
69
69
71
66 –
67
Top end of
guidance range
2
2011
Q1
Q2
Q3
Q4E
1
party fractionation capacity constraints at Mont Belvieu (fractionation constraints
resolved in early October) -
Remaining NGL inventory of 90 Mbls from Q2 Mont
Belvieu
3
party
fractionator
downtime
expected
to be drawn down during Q4, but offset by line fill
requirements for new Lone Star NGL pipeline
rd |
 Eagle
Ford Shale Operational Update 14
Drilled 38 wells in Q3 2012; 35 wells placed on production
2012 drilling program
–
~125 wells
–
Focused on liquids-rich drilling with only 10% of the wells
designated to hold strategic dry gas acreage
Expanding use of white sand proppant to deeper areas to
further define its performance limits (~50% of program)
–
~74 wells stimulated using white sand through Q3; early well
performance similar to direct offset ceramic-stimulated wells
–
7 dry gas wells fraced with white sand during 2012
–
Reduces frac cost by ~$700 M
11 CGPs on line |
 Drilling
Efficiency Improving 15
Average drilling cost per foot has decreased 18% and average
drilling feet per day has increased 28% from Q2 2011 to Q3 2012
|
 Pad
Drilling Expected To Increase in 2013 16
9 Months 2012
2013
Expected to reduce drilling and completion
costs by $600 M to $700 M per well |
 Eagle
Ford Shale Continues to Set New Production Records 17
Eagle Ford Shale Net Production
1
(MBOEPD)
1)Reflects Pioneer’s ~35% share of total gross production
2)Based on public wellhead production data from IHS; does not include NGL uplift
25 –
29 MBOEPD
FY Guidance
27 –
28
Strong well performance continues
to drive production growth and
achieve record production levels
50% of PXD wells are in the top
quartile of industry EURs across the
entire Eagle Ford Shale
2
80% of PXD wells are above the
industry median EUR
2 |
 >1,100 total locations
Barnett Shale Planned Divestiture
18
~120,000
net
acres
Two-thirds
of
acreage
located
in
the
liquids-
rich
Barnett
Shale
Combo
Play
Q3
production
of
7
MBOEPD;
currently
>8
MBOEPD
55%
liquids
(oil
and
NGLs)
and
45%
dry
gas
181
wells
on
production
1
rig
currently
operating
Operated
gathering
system;
expandable
with
production
growth
Allows strategic reallocation of
capital to Pioneer’s higher-return
core Texas assets
Combo Play Area
~82,000 net acres
79 producing wells
Marble
Falls
&
Barnett
Development
~8,000
net
acres
No
Operated
Production
Dry
Gas
Area
~
30,000
net
acres
103
producing
wells |
 19
Alaska
Q3 net production: ~4.5 MBOPD
1-rig development program
continues from the Oooguruk island
drill site targeting Nuiqsut and Torok
intervals
Following first successful mechanically
diverted frac on a Nuiqsut well in early
2012, 3 Nuiqsut wells and 1 Torok well
prepared for similar fracs during
upcoming winter drilling season
2
nd
onshore Torok appraisal well to
be drilled during upcoming winter
drilling season; progressing onshore
development FEED study
Successful winter exploration program in
2012 added 50 MMBO resource potential
from initial onshore Torok well
PXD Acreage
Island
Development
Area
Island drill site
(Oooguruk)
Second
onshore
Torok
appraisal
well
Torok
onshore
drill
site
Torok Area
1 well to be
frac’d from island
drill site and 1
well to be frac’d
from onshore drill
site
Nuiqsut Area
3 wells to be frac’d
from island drill site
Nuiqsut Wells
Torok Wells |
 20
Why Invest In PXD?
Significant Upside Potential From:
High
oil
exposure
from
proved
reserves
+
estimated
resource
potential of >7 BBOE and 35,000 drilling locations
Aggressive Spraberry & Eagle Ford Shale drilling program
Extensive horizontal Wolfcamp Shale potential
Joint Venture accelerates future development
Strong returns from vertical integration
Margin protection from attractive derivatives
Strong balance sheet |
 Appendix |
 Pioneer
Operations 22
Eagle Ford Shale
West Panhandle
Raton
Hugoton
Spraberry Vertical
Barnett Shale Combo
Horizontal Wolfcamp Shale
Operating Areas
North Slope |
 23
Liquidity Position (9/30/12)
1
Net debt (net of cash balance of $334 MM):
$3.2 B
Unsecured Credit Facility availability:
$0.9 B
Net Debt-to-Book Capitalization:
36%
1)
Excludes $88 MM of borrowings under PSE’s $300 MM credit facility that matures in
May 2017 2)
Excludes net discounts and deferred hedge losses of ~$56 MM
3)
Convertible senior notes due 2038, with first put/call in 2013
4)
Excludes ~$2 MM of outstanding letters of credit on credit facility
5)
Reflects credit facility amendment completed in December 2012
Maturities and Balances
2
2012
2016
$600 MM
3.95%
2017
5
$455 MM
5.875%
2022
$450 MM
6.875%
$360 MM
4
of
$1.5 B Unsecured Credit Facility
5
2018
$485 MM
6.65%
2013
$480 MM
2.875%
$450 MM
7.50%
2020
$250 MM
7.20%
2028
Unsecured
credit
facility
matures
in
2017
5
Investment grade rated
Expect to call convertible senior notes due 2038 for redemption during 2013
3 |
 24
Derivative Philosophy
Continue to use derivatives to mitigate commodity price
exposure in order to insure funding for development
programs and to maintain strong financial position
–
Target >50% on rolling 3 year basis
Continue to use a variety of derivative instruments, but
focus will be on providing floor protection while retaining
upside; primary derivative instruments will be:
–
Collars
–
Collars with short puts (three-way collars)
–
Puts
Enter derivative agreements only with counterparties that
are “A”
rated or better
Actively monitor credit exposure to each counterparty and
counterparty credit trends
No margin requirements with counterparties |
 25
Oil
Q4 2012
2013
2014
2015
Swaps –
WTI (BPD)
11,000
3,000
-
-
NYMEX WTI Price ($/BBL)
$ 89.34
$ 81.02
-
-
Collars -
(BPD)
2,000
-
-
-
NYMEX Call Price ($/BBL)
$ 127.00
-
-
-
NYMEX Put Price ($/BBL)
$ 90.00
-
-
-
53,110
71,029
60,000
26,000
NYMEX Call Price ($/BBL)
$ 118.85
$ 119.76
$ 117.06
$ 104.45
NYMEX Put Price ($/BBL)
$ 85.09
$ 92.27
$ 92.67
$ 95.00
NYMEX Short Put Price ($/BBL)
$ 69.44
$ 74.28
$ 76.58
$ 80.00
% Total Oil Production
~100%
TBD
TBD
TBD
Natural Gas Liquids
Q4 2012
2013
2014
2015
Swaps –
(BPD)
2,750
-
-
-
Blended Index Price ($/BBL)
$ 67.85
-
-
-
Three Way Collars –
(BPD)
3,000
1,064
1,000
-
NYMEX Call Price ($/BBL)
$ 79.99
$ 105.28
$ 109.50
-
NYMEX Put Price ($/BBL)
$ 67.70
$ 89.30
$ 95.00
-
NYMEX Short Put Price ($/BBL)
$ 55.76
$ 75.20
$ 80.00
-
% Total NGL Production
~20%
TBD
TBD
TBD
% Total Liquids
~70%
TBD
TBD
TBD
PXD Open Commodity Derivative Positions as of 11/29/2012 (includes PSE)
Oil Basis Protection
Q4 2012
2013
2014
2015
Spraberry Swaps (BPD)
20,000
-
-
-
Price Differential ($/BBL)
$ (1.15)
-
-
-
Spraberry Fixed Differential
22,000
27,000
33,000
35,000
Price Differential ($/BBL)
$ (1.75)
$ (1.75)
$ (1.75)
$ (1.75)
2
3
1) When NYMEX price is above Call price, PXD receives Call price. When NYMEX price
is between Put price and Call price, PXD receives NYMEX price. When NYMEX price is between the Put price and the Short
Put price, PXD receives Put price. When NYMEX price is below the Short Put price,
PXD receives NYMEX price plus the difference between the Short Put price and Put price
3) Market transaction; not a derivative
Three
Way
Collars
–
(BPD)
2) Represents weighted average index price of each NGL component price per barrel
1
1 |
 26
Gas
Q4 2012
2013
2014
2015
Swaps -
(MMBTUPD)
275,000
162,500
105,000
-
NYMEX Price ($/MMBTU)
1
$ 4.97
$ 5.13
$ 4.03
-
Collars -
(MMBTUPD)
65,000
150,000
-
-
NYMEX Call Price ($/MMBTU)
1
$ 6.60
$ 6.25
-
-
NYMEX Put Price ($/MMBTU)
1
$ 5.00
$ 5.00
-
-
Three Way Collars –
(MMBTUPD)
-
-
25,000
225,000
NYMEX Call Price ($/MMBTU)
-
-
$4.70
$ 5.09
NYMEX Put Price ($/MMBTU)
-
-
$4.00
$ 4.00
NYMEX Short Put Price ($/MMBTU)
-
-
$3.00
$ 3.00
% U.S. Gas Production
~90%
TBD
TBD
TBD
PXD Open Commodity Derivative Positions as of 11/29/2012 (includes PSE)
1)
2) When NYMEX price is above Call price, PXD receives Call price. When NYMEX
price is between Put price and Call price, PXD receives NYMEX price. When NYMEX price is between
the Put price and the Short Put price, PXD receives Put price. When NYMEX price
is below the Short Put price, PXD receives NYMEX price plus the difference between Short Put
price and Put price
Gas Basis Swaps
Q4 2012
2013
2014
2015
Spraberry
(MMBTUPD)
32,500
52,500
-
-
Price Differential ($/MMBTU)
$ (0.38)
$ (0.23)
-
-
Mid-Continent
(MMBTUPD)
50,000
30,000
-
-
Price Differential ($/MMBTU)
$ (0.53)
$ (0.38)
-
-
Gulf
Coast
(MMBTUPD)
53,500
60,000
-
-
Price Differential ($/MMBTU)
$ (0.15)
$ (0.14)
-
-
Represents the NYMEX Henry Hub index price or approximate NYMEX price based on
historical differentials to the index price at the time the derivative was entered into
1,2 |
 27
Oil
Q4 2012
2013
2014
2015
Swaps
(BPD)
3,000
3,000
-
-
NYMEX Price ($/BBL)
$79.32
$81.02
-
-
Three-Way
Collars
(BPD)
1,500
1,750
5,000
-
NYMEX Call Price ($/BBL)
$109.00
$116.00
$124.00
-
NYMEX Put Price ($/BBL)
$85.00
$88.14
$90.00
-
NYMEX Short Put Price ($/BBL)
$70.00
$73.14
$72.00
-
% Oil Production
~90%
~85%
~85%
-
Natural Gas Liquids
Swaps
(BPD)
750
-
-
-
Blended Index Price ($/BBL)
$35.03
-
-
-
% NGLs Production
~50%
-
-
-
Gas
Swaps
(MMBTUPD)
5,000
2,500
5,000
-
NYMEX Price ($/MMBTU)
$6.43
$6.89
$4.00
-
Three-Way
Collars
(MMBTUPD)
-
-
-
5,000
NYMEX Call Price ($/MMBTU)
-
-
-
$5.00
NYMEX Put Price ($/MMBTU)
-
-
-
$4.00
NYMEX Short Put Price ($/MMBTU)
-
-
-
$3.00
% Gas Production
~75%
~35%
~70%
~65%
% Total Production
~80%
~65%
~70%
~10%
Gas Basis Swaps
Q4 2012
2013
2014
2015
Spraberry
(MMBTUPD)
2,500
2,500
-
-
Price Differential ($/MMBTU)
(0.30)
(0.31)
-
-
PSE Derivative Position as of 11/29/2012
1
2
3
1, 3
1) When NYMEX price is above Call price, PSE receives Call price. When NYMEX
price is between Put price and Call price, PSE receives NYMEX price. When NYMEX price is between the Put price and the Short Put price,
PSE receives Put
price. When NYMEX price is below the Short Put price, PSE receives NYMEX price plus
the difference between the Shot Put price and Put price 2) Represents the
weighted average index price of each NGL component price per Bbl 3) Approximate
NYMEX price based on differentials to index prices at the date the derivative was entered into |
 Three-Way Collars ($75 by $90 by $135 example)
Realize $90/BBL
Realize NYMEX price
Realize $135/BBL
Short put at $75/BBL
Long put at $90/BBL
Realized Price
NYMEX Price
Three way collars protect downside while providing better
upside exposure than traditional collars or swaps
28
$50.00
$60.00
$70.00
$80.00
$90.00
$100.00
$110.00
$120.00
$130.00
$140.00
$150.00
$160.00
$50.00
$60.00
$70.00
$80.00
$90.00
$100.00
$110.00
$120.00
$130.00
$140.00
$150.00
$160.00
NYMEX Oil ($/BBL)
Unhedged realization
Hedged realization
Short call at $135/BBL
Realize NYMEX price
plus $15/BBL
(difference between long put
and short put)
Potential
Opportunity Loss |
 Spraberry
5 vertical frac fleets (~20,000 HP each)
2 horizontal frac fleets (~35,000 HP each)
15 drilling rigs
Well service equipment
1
Eagle Ford Shale
2 frac fleets
(50,000 HP each)
2 coiled tubing units
29
PXD’s Vertical Integration Reduces Costs and Enhances Execution
Current frac capacity: ~300,000 HP
13
th
largest pressure pumping company in North America
1)
Includes pulling units, frac tanks, hot oilers, water trucks, blowout preventers,
construction equipment and fishing tools Barnett Shale Combo
1 frac fleet
(30,000 HP)
1 coiled tubing unit
Brady sand mine |
   Permian
Basin is composed of multiple uplifts and basins that formed during the Pennsylvanian and early Permian
The Spraberry Trend, which includes the Wolfcamp interval, is located in the Midland
Basin of the Permian Basin It was discovered in 1948 and commenced production in
1949 It contains 40 BBO in-place in Spraberry-Dean interval
Much more oil in-place in deeper zones of Wolfcamp, Strawn, Atoka and
Mississippian OZONA
PLATFORM
30
Geologic Provinces of the Permian Basin
PEDERNAL UPLIFT &
ROOSEVELT POSITIVE
DEVIL’S
RIVER
UPLIFT
Basin
Basement
Uplift
Shelf
Thrust Belt
Spraberry Trend |
 31
Platform Carbonate
Shelf Edge Carbonate
Slope Sediments & Reef Talus
Carbonate Debris Flows
Carbonate Gravity Flows
Land
Clastic Detrital
Clastic Slope Sediments
Clastic Gravity Flows
Delta
Pelagic Sediments
Silt Cloud in Suspension
Anaerobic Zone
(Organic-rich Sediments)
Wolfcamp Facies Map
Schematic Block Diagram of
Wolfcamp Facies
In Midland Basin
Fluvial -
Deltaic
North
Simultaneous deposition of organic-rich carbonate
and clastic sediments in an anaerobic basin results in
hydrocarbon-rich, interbedded, conventional
and unconventional reservoirs
Wolfcamp Facies & Depositional Model
Basinal Sediments |
 Wolfcamp
Comparison to Other Plays 32
Wolfcamp compares favorably to other major oil shale plays
Major Oil Shale Play Characteristics
Attribute
Units
Wolfcamp Shale
1
Eagle Ford
2
(Oil Window)
Barnett Shale
3
(Combo Play)
Niobrara
4
Bakken
5
Age
Permian
Cretaceous
Mississippian
Cretaceous
Devonian/Mississippian
Basin
Midland
South Texas
Fort Worth
Denver
Williston
TVD Depth
ft
5,500 -
11,000
7,500 -
11,000
5,000 -
8,000
4,000 -
8,000
9,000 -
11,000
Thickness
ft
1,500 –
2,600
50 -
350
200 -
400
250 -
600
25 -
125
OOIP/Section
MMBO
80 –
220
30 -
90
70 -
90
20 -
40
10 -
20
Porosity
%
2 –
10
4 -
11
4 -
5
4 -
14
5 -
8
Quartz
%
20 –
50
10 -
25
25 -
40
30 -
60
Carbonate
%
10 –
60
60 -
75
6 -
25
~70
30 -
80
Clay
%
10 -
45
10 -
40
25 -
50
25
Permeability
nd
10 -
3,000
40 -
1,300
150 -
200
<10,000
50,000 -
500,000
Pressure Gradient
psi/ft
0.55 -
0.70
0.65 -
0.70
0.54
0.43 -
0.55
0.43 -
0.75
Recovery Factor
%
3 -
15
3 -
10
4
5 -
10
8 -
15
1)
Pioneer internal research (modified according to recent core and petrophysical data) 2) EOG Analyst Conference April 2010 3) AAPG Bulletin April 2007, Hart Energy Databank December
2011, HIS, REPSI, EOG February 2010 Investor Presentation
4)
Hart Energy Databank December 2011, Oil & Gas Investor June and August 2011 5) Tudor, Pickering, Holt, “The Bakken Momentum
Continues” November 2011, Hart Energy Bakken Playbooks 2008 and 2010, Jarvie – AAPG Section Meeting 2008 |
 33
Horizontal
Wolfcamp
Shale
Target
Intervals
PXD has an extensive Midland Basin geologic
database:
Over 70,000 logs of which 9,000 are digital,
allow for excellent structural control and
detailed petrophysics
Growing 3-D seismic database (currently at
1,400+ square miles) ensures appropriate well
placement
Access to ~4,000 feet of whole core provides
increased confidence in petrophysical models
and supports repeatable results
Petrophysical analysis has identified multiple
prospective horizontal Wolfcamp Shale
intervals with substantial resource potential
PXD Has Multiple Horizontal Wolfcamp Shale Target Intervals
Miss/Atoka
U. Spraberry
M. Spraberry
Shale
L. Spraberry
Jo Mill Sand
L. Spraberry
Shale
Dean
Wolfcamp A
Lower Wolfcamp
B
Wolfcamp C1
Wolfcamp C2
Wolfcamp D
Strawn
Upper Wolfcamp
B |
 Southern
Horizontal Wolfcamp Players PXD
PXD
PXD
COP
Devon
El Paso
El Paso
EOG
Approach
Laredo
Apache
Apache
BHP
Horizontal Permits
Horizontal Wells |
 Horizontal Wolfcamp 960-Acre Development Block
35
Up to 55 wells per 960-acre section
(20-acre field rules)
41 vertical wells in Spraberry-Wolfcamp
Up to 14 horizontal Wolfcamp wellbores
•
7 horizontal wells in Wolfcamp A
•
7 horizontal wells in Wolfcamp B
Additional horizontal wellbores possible in B, C
and D intervals
960-acre section metrics (55 wells)
Capital required: $ 180 MM
Resource potential: ~15 MMBOE
F&D cost: ~$15 / BOE
Spacing
Vertical wells
•
900’
from other vertical wells
•
360’
from horizontal wells
Horizontal wells
•
725’
from other horizontals in same interval
•
Stacked horizontals within 300’
in map-view
count as one location for spacing purposes
5,280 ft
Horizontal wells in same
interval spaced at ~725’
960
acres
467’
from lease line
100’
from
lease line
Vertical Well
Horizontal “A”
Well
Horizontal “B”
Well |
 Spraberry
20-Acre Vertical Well Update 36
20-Acre Drilling (~13,500 locations)
Drilled 39 wells through Q3 2012
Results to date indicate production near type
curve for a 40-acre Lower Wolfcamp well (EUR
of 140 MBOE)
Spraberry Drilling Rig
–
Most wells drilled to the Lower Wolfcamp with
a few drilled to the Strawn |
 37
Upper
Spraberry Base
Production
(151 wells)
Upper
Spraberry Base
Production
Forecast
Strong waterflood production
wedge from flooded zone;
Now seeing response in wells
outside of original project area
Original project: 7,000 acres in Spraberry
12 injectors and 110 producers in original
project area
Injecting 4,100 BWPD
$6 -
$7 MM capital cost
LOE savings from water handling
0
100
200
300
400
500
600
700
Aug-10
Aug-11
Aug-12
Aug-13
Water injection
begins
Continuing to see uptick in production; Upper Spraberry production increased ~30% during
Q3 in total
response
area
compared
to
base
production
decline;
further
increase
expected
•
Response now being observed outside original
project area; now 11,000 acres total response area
•
39 wells now responding to injection; up from 19
Spraberry Waterflood Continuing to Perform |
 140 MBOE
Spraberry 40-Acre Vertical Well Type Curve 38
Month
Strawn / Atoka / Mississippian Potential Not Included
140 MBOE
Spraberry/Dean/Full Wolfcamp
(70% oil, 20% NGLs, 10% gas)
110 MBOE
Spraberry/Dean/Upper Wolfcamp
(70% oil, 20% NGLs, 10% gas)
Deeper drilling in Spraberry increasing EURs
-
10
20
30
40
50
60
70
80
90
0
12
24
36
48
60 |
 1)
All drilling locations shown on a gross basis
2)
Includes vertical well potential from shalt/silt, Wolfcamp and deeper intervals
3)
Assumes average EUR of 575 MBOE per well, >8,000 locations, >400,000 acres ,
140 acre spacing, laterals in all intervals (A, B, C & D) and 75%
NRI 4)
Total PXD Proved Reserves + Estimated Net Resource Potential of >3 BBOE in 2010 and
>7 BBOE in 2012 Drilling deeper vertical wells, capturing non-traditional
shale/silt intervals and drilling horizontally into the Wolfcamp Shale has
increased Pioneer’s Permian resource potential by ~400% since 2010 39
Pioneer’s
Permian
Resource
Potential
Continues
To
Grow
1
2010 Permian Resource Potential:
1.15 BBOE
4
2012 Permian Resource Potential:
5.6 BBOE
4
+400%
Spraberry
20-ac Drilling
500 MMBOE
Spraberry
40-ac Drilling
350 MMBOE
Spraberry Waterflood
300 MMBOE
Spraberry
40-ac Drilling
2
600 MMBOE
Spraberry
20-ac Drilling
2
1.2 BBOE
Spraberry Waterflood
300 MMBOE
Horizontal Wolfcamp
3
3.5 BBOE |
 Permian
Oil Production Transport Options 40
Permian Basin Crude Takeaway
Current
Operator
Destination
Name
Capacity
Time Frame
Plains
Cushing
Basin
450,000
Sunoco
Nederland
West Texas Gulf
400,000
Kinder Morgan
El Paso
Wink
100,000
Local Refiners
Local
200,000
Rail
20,000
TOTAL
1,170,000
Planned
Operator
Destination
Name
Capacity
Time Frame
Magellan
Houston
Longhorn (phase I)
135,000
early-2013
Magellan
Houston
Longhorn (phase II)
90,000
mid-2013
TOTAL
225,000
Possible
Operator
Destination
Name
Capacity
Time Frame
Magellan/Oxy
Houston
BridgeTex
278,000
mid-2014
Sunoco
Nederland
Permian Express II
200,000
mid-2014
TOTAL
478,000 |
 Growing
Midstream Infrastructure to Support Production Growth 41
Gas Processing
Midkiff / Benedum
Current
capacity:
260
MMCFD
PXD production makes up ~40%
of throughput
Sale Ranch
New plant started up Q4 2012:
120
MMCFD
PXD production makes up ~40%
of throughput
Planned Driver Plant
Planned startup: late 1Q 2013
Initial capacity: 100 MMCFD
1,2
Q4 2013 expansion: +100
MMCFD additional capacity
Expect Capacity Additions
in the Benedum Area for
2014
Pipeline NGL Takeaway
to Mont Belvieu
Chaparral & West Texas
Pipelines
PXD production throughput of
~12 MBPD in Q3 2012
New Lone Star Pipeline
4 MBPD to PXD in late-2012
increasing to 16 MBPD by 2020
Will connect to all PXD gas
processing plants
Expect >425 MBPD, or
~50%, increase in
fractionation capacity at
Mont Belvieu in 2013
Expanding processing capacity and contracted takeaway to support
Pioneer’s aggressive production growth
1) Wet gas stream with ~160 BBL/MMSCF NGL yield
1
1 |
 Eagle
Ford Shale: A Burgeoning Liquids-Rich Shale Play 42
Gross
resource
potential
of
play:
~25
BBOE
(~150
TCFE)
1
Estimated
gross
production
of
~3.5
MMBOEPD
by
2020
2
~270 rigs currently running in the play
Oil Window
Map source: PXD
1)
Source: Tudor, Pickering, Holt & Co.
2)
Source: FBR
PXD
Acreage
Area |
 Rich
Condensate 35% of Acreage
(200 BBL/MMSCF)
Lean Condensate
45% of Acreage
(60 BBL/MMSCF)
Dry
Gas
20% of Acreage
43
Eagle Ford Shale Resource Breakdown
30%
NGL*
50%
Gas
20%
Condensate
20%
NGL*
30%
Gas
100%
Gas
50%
Condensate
*NGLs are 50% ethane, 25% propane, 15% butanes and 10% heavier liquids
~
~
~ |
 Example
of Choke Management Effectiveness 44
22/64”
Choke
12/64”
Choke
16/64”
Choke
Cumulative Production Per Lateral Foot
1)
Wells are geologically similar
Cumulative production from wells operating under choke
management crosses over cumulative production from wells
operating
at
higher
choke
sizes
within
6
months
Choke management benefits:
Reduces well production declines and increases well EURs
Higher sustained wellhead pressure and extended stable flow regime
1 |
 45
Production
(MBOEPD)
1
Q3 ’11
Q4 ’11
Q1 ’12
Q2 ’12
Q3 ’12
Spraberry
47
53
62
64
2
69
3
Eagle Ford Shale
14
20
22
24
29
Raton
27
26
26
25
25
South Texas
8
7
7
6
6
Mid-Continent
19
19
18
18
18
Alaska
4
4
4
5
5
Other
1
2
1
1
1
Total
120
131
140
143
153
1)
2)
Q2 ‘12 production negatively impacted by ~4,800 BOEPD due to unplanned third party
fractionation capacity shortfalls at Mont Belvieu 3)
Q3
’12
production
benefited
by
~1,800
BPD
from
partial
NGL
inventory
drawdown
at
Mont
Belvieu,
but
offset
by
a
production
loss
of
~4,000
BOEPD
due
to
continuing
ethane
rejection
and
3
party
fractionation
capacity
constraints
at
Mont
Belvieu
rd
All periods presented have been restated to exclude discontinued operations |
 46
PXD Production By Commodity By Area
1
All periods presented have been restated to exclude discontinued operations 1) |
 $0.61
47
Production Costs (per BOE)
1
Production
&
Ad Valorem Taxes
VPP-Adjusted
Workovers
LOE
Third Party
Transportation
Production Cost
Q3 production cost increase vs. Q2
primarily due to the following LOE
items:
–
Higher salt water disposal costs
(primarily water hauling costs)
–
Higher electricity costs associated with
the increase in gas prices
–
Higher repair and maintenance costs
–
Higher per BOE costs as a result of
~4,000 BOEPD of lost sales volumes
Natural Gas
Processing
Q3 ’11
$13.25
$0.14
$13.66
Q4 ’11
$13.64
$13.26
Q1 ’12
$0.32
$13.51
$0.25
$13.18
Q2 ’12
$14.49
$14.15
$0.67
Q3 ’12
$16.03
$15.68
1)
All periods presented have been restated to exclude discontinued operations 2) See supplemental information slides |
 48
VPP
–
Adjusted
Production
Costs
Pioneer presents VPP-Adjusted Production Costs (per BOE) to assist
investors in considering the Company’s costs in relation to the total BOEs
(reported sales volumes plus VPP delivered volumes) in connection with
which those costs were incurred. VPP-Production Costs (per BOE) are
calculated as follows:
Q3 ’11
Q4 ’11
Q1 ’12
Q2 ’12
Q3 ’12
Production costs as reported (thousands)
$ 150,374
$ 164,227
$ 172,696
$ 189,211
$ 225,752
Production (MBOE):
As reported
11,003
12,038
12,784
13,054
14,077
VPP deliveries
345
345
319
319
322
VPP-adjusted production
11,348
12,383
13,103
13,373
14,399
Production costs per BOE:
As reported
$ 13.66
$ 13.64
$ 13.51
$ 14.49
$ 16.03
VPP-adjusted
$ 13.25
$ 13.26
$ 13.18
$ 14.15
$ 15.68
1) All periods presented have been restated to exclude discontinued operations
1 |
 49
VPP Expirations
VPP Oil
Obligation
3.5
MBOPD
VPP commitment expired at the end of
2012
Provided
3.5
MBOPD
increase
in
production
on
1/1/2013
(MMBBLS)
Q1
Q2
Q3
Q4
Total
2012
0.3
0.3
0.3
0.3
1.2
Schedule of Oil VPP Volumes |
 –
Reflects significant drilling campaigns in Spraberry, Eagle
Ford Shale and Barnett Shale Combo plays
Added 148 MMBOE from the drillbit, or 313% of full-
year production, at F&D cost of $13.83 per BOE
All-in reserve replacement of 124 MMBOE, or 256%
of full-year production, at F&D cost of $17.51 per
BOE
Reserve mix
Proved Reserves / Production: ~22 years
PD Reserves / Production: ~13 years
50
Strong 2011 Reserve Additions
Year-end ’11
Proved Reserves
(MMBOE)
Spraberry
609
Raton
170
Mid-Continent
107
Eagle Ford
70
South Texas
36
Barnett Shale
33
Alaska
30
Other
8
Total
1,063
1)
Reflects 2011 SEC pricing (12-month average) of $96.13/BBL for oil and $4.12/MMBTU
for gas (NYMEX) as compared to 2010 SEC pricing of $79.28/BBL for oil and
$4.37/MMBTU for gas (NYMEX) 1
–
Includes negative pricing revisions of 28 MMBOE primarily
attributable to moving Raton dry gas PUDs that are not
expected to be drilled in next 5 years to probable reserves
–
99+% U.S.
–
60% liquids / 40% gas
–
58% PD / 42% PUD |
 51
Annual Sales
Capacity
(M tons)
Resource (MM tons)
Proved
R/P
Resource
R/P
Location
Proved
Reserves
1
Resource
Potential
2
Brady, TX
1,000
36
33
36
69
Wisconsin
(Possible Start-up 2014)
1,000
23
-
23
23
Other Mines
400 -
600
8
8
18
34
Total
67
41
Proved Reserves (MM tons)
Brady
(36)
Wisconsin
(23)
Other
(8)
1)
Proved reserve figures have been calculated in compliance with the SEC’s Industry
Guide 7 and are based on an independent review by mining and geological
consultants engaged by CIS in 2011
2)
Resource potential figures have been estimated by PXD
Premier Silica Provides 30+ Years of Proved Reserves |
 Oil/Gas
Price Ratio Trending Up Since 2006 52
Oil Price
Gas Price
Oil/Gas Ratio
Oil/Gas price ratio has increased
from 5:1 in 2006 to ~30:1 recently |
 53
Reserves Audit, F&D Costs and Reserve Replacement
An audit of proved reserves follows the general principles set forth in the standards
pertaining to the estimating and auditing of oil and gas reserve information
promulgated by the Society of Petroleum Engineers ("SPE"). A reserve audit
as defined by the SPE is not the same as a financial audit. Please see the Company's Annual Report on Form 10-
K for a general description of the concepts included in the SPE's definition of a reserve
audit. "Finding and development cost per BOE," or “all-in F&D
cost per BOE,” means total costs incurred divided by the
summation of annual proved reserves, on a BOE basis, attributable to revisions of
previous estimates, purchases of minerals-in-place, discoveries and
extensions and improved recovery. Consistent with industry practice, future
capital costs to develop proved undeveloped reserves are not included in costs
incurred. "Drillbit finding and development cost per BOE," or
“drillbit F&D cost per BOE,” means the summation of exploration
and development costs incurred divided by the summation of annual proved reserves,
on a BOE basis, attributable to technical revisions of previous estimates,
discoveries and extensions and improved recovery. Consistent with industry
practice, future capital costs to develop proved undeveloped reserves are not included in
costs incurred. “Reserve replacement”
is the summation of annual proved reserves, on a BOE basis, attributable to revisions of
previous estimates, purchases of minerals-in-place, discoveries and
extensions and improved recovery divided by annual production of oil, NGLs and
gas, on a BOE basis. “Drillbit reserve replacement”
is the summation of annual proved reserves, on a BOE basis, attributable to technical
revisions of previous estimates, discoveries and extensions and improved recovery
divided by annual production of oil, NGLs and gas, on a BOE basis.
|
 54
Certain Reserve Information
Cautionary Note to U.S. Investors --The U.S. Securities and Exchange Commission
(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 presentation,
Pioneer includes estimates of quantities of oil and gas using certain terms, such
as “resource,” “resource potential,” “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. |