Investor Presentation -January 2013

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

and

cost

capital,

the

financial

strength

counterparties

Pioneer's

credit

facility and derivative contracts and the purchasers of Pioneer's oil, NGL and gas production,

uncertainties

about

estimates

reserves

and

resource

potential

and

the

ability

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

this

presentation

for

other

important

information.

U.S. asset base

High oil exposure from proved reserves + estimated net resource

potential of >7 BBOE

Drilling

program

focused

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

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)

2012E

Capital

Spending

and

Cash

Flow

Capital spending excludes acquisitions, asset retirement obligations, capitalized interest and G&G G&A

12/31/11

Proved

Reserves:

1.1

BBOE

Additional

Net

Resource

Potential:

6.7

BBOE

All drilling locations shown on a gross basis

SEC pricing of $96.13/BBL for oil and $4.12/MMBTU for gas (NYMEX)

Primarily reflects Alaska, Raton and South Texas

Includes vertical well potential from Wolfcamp and deeper intervals

Assumes

average

EUR

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

600 MMBOE

5,200 locations

Spraberry

20-ac

Drilling

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

3.5 BBOE

8,000 locations

Significant Proved Reserves and Resource Potential

Proved Reserves + Estimated Net Resource Potential of >7 BBOE and 35,000 Drilling Locations

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

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

Horizontal

Wolfcamp

Upper

Well

Performance

Through

575 MBOE Type Curve

for 7,000’

lateral

(oil portion only)

Giddings Area

(2 wells)

University

Lands

Area

(12

wells)

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

Horizontal Wolfcamp Shale Drilling Activity

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

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)

Potential

Incremental EUR

(MBOE)

Prospective PXD

Acreage

Strawn

175

~70%

Atoka

167

50 –

40% -

50%

Mississippian

118

15 –

~20%

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

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

2012

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

66 –

Top end of

guidance range

2011

Q4E

party fractionation capacity constraints at Mont Belvieu (fractionation constraints resolved in early October)

Remaining NGL inventory of 90 Mbls from Q2 Mont

Belvieu

party

fractionator

downtime

expected

to be drawn down during Q4, but offset by line fill

requirements for new Lone Star NGL pipeline

Eagle Ford Shale Operational Update

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

Eagle Ford Shale Continues to Set New Production Records

Eagle Ford Shale Net Production

(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 –

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

80% of PXD wells are above the

industry median EUR

>1,100 total locations

Barnett Shale Planned Divestiture

~120,000

net

acres

Two-thirds

acreage

located

the

liquids-

rich

Barnett

Shale

Combo

Play

production

MBOEPD;

currently

MBOEPD

55%

liquids

(oil

and

NGLs)

and

45%

dry

gas

181

wells

production

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

Operated

Production

Dry

Gas

Area

30,000

net

acres

103

producing

wells

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

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

Liquidity Position (9/30/12)

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%

Excludes $88 MM of borrowings under PSE’s $300 MM credit facility that matures in May 2017

Excludes net discounts and deferred hedge losses of ~$56 MM

Convertible senior notes due 2038, with first put/call in 2013

Excludes ~$2 MM of outstanding letters of credit on credit facility

Reflects credit facility amendment completed in December 2012

Maturities and Balances

2012

2016

$600 MM

3.95%

2017

$455 MM

5.875%

2022

$450 MM

6.875%

$360 MM

$1.5 B Unsecured Credit Facility

2018

$485 MM

6.65%

2013

$480 MM

2.875%

$450 MM

7.50%

2020

$250 MM

7.20%

2028

Unsecured

credit

facility

matures

2017

Investment grade rated

Expect to call convertible senior notes due 2038 for redemption during 2013

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

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

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

% Total Liquids

~70%

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) 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

Gas

Q4 2012

2013

2014

2015

Swaps -

(MMBTUPD)

275,000

162,500

105,000

NYMEX Price ($/MMBTU)

$ 4.97

$ 5.13

$ 4.03

Collars -

(MMBTUPD)

65,000

150,000

NYMEX Call Price ($/MMBTU)

$ 6.60

$ 6.25

NYMEX Put Price ($/MMBTU)

$ 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

PXD Open Commodity Derivative Positions as of 11/29/2012 (includes PSE)

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

Oil

Q4 2012

2013

2014

2015

Swaps

(BPD)

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%

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

Price Differential ($/MMBTU)

(0.30)

(0.31)

PSE Derivative Position as of 11/29/2012

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

$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

Eagle Ford Shale

2 frac fleets

(50,000 HP each)

2 coiled tubing units

PXD’s Vertical Integration Reduces Costs and Enhances Execution

Current frac capacity: ~300,000 HP

largest pressure pumping company in North America

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

Geologic Provinces of the Permian Basin

PEDERNAL UPLIFT &

ROOSEVELT POSITIVE

DEVIL’S

RIVER

UPLIFT

Basin

Basement

Uplift

Shelf

Thrust Belt

Spraberry Trend

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

Wolfcamp compares favorably to other major oil shale plays

Major Oil Shale Play Characteristics

Attribute

Units

Wolfcamp Shale

Eagle Ford

(Oil Window)

Barnett Shale

(Combo Play)

Niobrara

Bakken

Age

Permian

Cretaceous

Mississippian

Cretaceous

Devonian/Mississippian

Basin

Midland

South Texas

Fort Worth

Denver

Williston

TVD Depth

5,500 -

11,000

7,500 -

11,000

5,000 -

8,000

4,000 -

8,000

9,000 -

11,000

Thickness

1,500 –

2,600

50 -

350

200 -

400

250 -

600

25 -

125

OOIP/Section

MMBO

80 –

220

30 -

70 -

20 -

10 -

Porosity

2 –

4 -

5 -

Quartz

20 –

10 -

25 -

30 -

Carbonate

10 –

60 -

6 -

~70

30 -

Clay

10 -

25 -

Permeability

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 -

5 -

8 -

Pioneer internal research (modified according to recent core and petrophysical data)

EOG Analyst Conference April 2010

AAPG Bulletin April 2007, Hart Energy Databank December 2011, HIS, REPSI, EOG February 2010 Investor Presentation

Hart Energy Databank December 2011, Oil & Gas Investor June and August 2011

Tudor, Pickering, Holt, “The Bakken Momentum Continues” November 2011, Hart Energy Bakken Playbooks 2008 and 2010, Jarvie – AAPG Section Meeting 2008

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

Wolfcamp C1

Wolfcamp C2

Wolfcamp D

Strawn

Upper Wolfcamp

Horizontal Wolfcamp 960-Acre Development Block

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

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

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

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

All drilling locations shown on a gross basis

Includes vertical well potential from shalt/silt, Wolfcamp and deeper intervals

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

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

Pioneer’s

Permian

Resource

Potential

Continues

Grow

2010 Permian Resource Potential:

1.15 BBOE

2012 Permian Resource Potential:

5.6 BBOE

+400%

Spraberry

20-ac Drilling

500 MMBOE

Spraberry

40-ac Drilling

350 MMBOE

Spraberry Waterflood

300 MMBOE

Spraberry

40-ac Drilling

600 MMBOE

Spraberry

20-ac Drilling

1.2 BBOE

Spraberry Waterflood

300 MMBOE

Horizontal Wolfcamp

3.5 BBOE

Permian Oil Production Transport Options

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

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

Example of Choke Management Effectiveness

22/64”

Choke

12/64”

Choke

16/64”

Choke

Cumulative Production Per Lateral Foot

Wells are geologically similar

Cumulative production from wells operating under choke

management crosses over cumulative production from wells

operating

higher

choke

sizes

within

months

Choke management benefits:

Reduces well production declines and increases well EURs

Higher sustained wellhead pressure and extended stable flow regime

Production

(MBOEPD)

Q3 ’11

Q4 ’11

Q1 ’12

Q2 ’12

Q3 ’12

Spraberry

Eagle Ford Shale

Raton

South Texas

Mid-Continent

Alaska

Other

Total

120

131

140

143

153

Q2 ‘12 production negatively impacted by ~4,800 BOEPD due to unplanned third party fractionation capacity shortfalls at Mont Belvieu

’12

production

benefited

~1,800

BPD

from

partial

NGL

inventory

drawdown

Mont

Belvieu,

but

offset

production

loss

~4,000

BOEPD

due

continuing

ethane

rejection

and

party

fractionation

capacity

constraints

Mont

Belvieu

All periods presented have been restated to exclude discontinued operations

$0.61

Production Costs (per BOE)

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

All periods presented have been restated to exclude discontinued operations

See supplemental information slides

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

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

–

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

Strong 2011 Reserve Additions

Year-end ’11

Proved Reserves

(MMBOE)

Spraberry

609

Raton

170

Mid-Continent

107

Eagle Ford

South Texas

Barnett Shale

Alaska

Other

Total

1,063

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)

–

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

Annual Sales

Capacity

(M tons)

Resource (MM tons)

Proved

R/P

Resource

R/P

Location

Proved

Reserves

Resource

Potential

Brady, TX

1,000

Wisconsin

(Possible Start-up 2014)

1,000

Other Mines

400 -

600

Total

Proved Reserves (MM tons)

Brady

(36)

Wisconsin

(23)

Other

(8)

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

Resource potential figures have been estimated by PXD

Premier Silica Provides 30+ Years of Proved Reserves

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.

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.