EX-99.1

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, satisfaction of

the conditions to the closing of the Company’s agreement to sell its Alaska subsidiary, 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

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 of reserves and resource potential and the ability to add proved reserves in the

future,

the

assumptions

underlying

production

forecasts,

quality

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

currently

unforeseen

risks

that

may

have

materially

adverse

impact

it.

Pioneer

undertakes

duty

publicly

update

these

statements

except

required

law.

Please

see

the

Appendix

slides

included

this

presentation

for

other

important

information.

Resource-focused strategy, with activity

concentrated in 3 of the most active U.S. fields

Best performing energy stock in S&P 500 since 2009

Second largest oil producer in Texas

Operating in core Spraberry/Wolfcamp asset since

early 1980s

Attractive derivative positions and vertical

integration protect margins

Strong investment grade financial position

Pioneer At A Glance

1) Year-end 2012 IHS data, gross reported oil and wet gas

Spraberry/Wolfcamp Gross

Production By Operator

(MBOEPD)

Top U.S. Fields By Rig Count

(Pioneer

Operated

Count

Green

–

rigs)

Total Enterprise Value ($B)

$28

2013 Drilling Capex ($B)

$2.8

Q3 2013 Production (MBOEPD)

173

2012 Reserves (BBOE)

1.1

2012 Reserves + Resource (BBOE)

>9.0

1) Baker Hughes Rig Count (11/15/13) and PXD Internal

–

PXD holds ~900,000 acres in Spraberry/Wolfcamp

–

Largest producer in Spraberry/Wolfcamp with 28

rigs operating (13 horizontal and 15 vertical) and

7,000+ producing wells

–

Preeminent, low-cost operator benefitting from

vertical integration strategy

272

223

177

168

NYMEX Oil Price ($/Bbl)

Sensitivity to Commodity Prices ($ MM)

2013E Capital Spending and Cash Flow

Capital spending includes land capital and excludes asset retirement obligations, capitalized interest and G&G G&A

Drilling Capital: $2.75 B

–

$1,225 MM northern Wolfcamp/Spraberry area

o

$400 MM for horizontal program

o

$625 MM for vertical program

o

$200 MM for infrastructure & automation

–

$425 MM southern Wolfcamp joint venture area

–

$575 MM Eagle Ford Shale

–

$185 MM Barnett Shale Combo

–

$190 MM Alaska

–

$150 MM Other (includes land capital for

existing assets)

$240 MM Other Capital (vertical

integration, buildings and offices)

Capital program funded from:

–

Operating cash flow of ~$2.3 B

–

Cash on hand ($744 MM at the end of Q3)

2013E Average Price

$98/Bbl oil and $3.70/MCF gas

Capital program remains at $3.0 B

Pioneer Focusing Capex in Highest Margin Assets

Peer

Average

$34.50/BOE

2013E

% Liquids

Production

>50%

<50%

PXD

2013E Cash Margins ($/BOE ex-hedges)

1,2

Assumes

$98.00/BBL

WTI

Crude

and

$3.70/MCF

Gas

Source: 2013E analyst estimates from Citi, JP Morgan, Simmons & Co, ISI and Credit Suisse; PXD internal 2013E margins for Permian horizontal assets

Cash margin is revenue excluding hedges minus production costs, taxes and G&A on a BOE basis

Excludes PXD and PXD assets

Production Outlook

151

~70%

Liquids

167

59%

Liquids

116

58%

Liquids

62%

Liquids

172

62%

Liquids

179 -

184

168

64%

Liquids

172 –

173 MBOEPD

FY Guidance

(Reflects Alaska as Discontinued Operations)

2011

2012

Q4E

2014E

2015E

Q3 impacted by production

conveyed to Sinochem and Eagle

Ford pad drilling

Q4 severe weather event in

Spraberry/Wolfcamp expected to

result in production falling below

Q4 and FY 2013 guidance ranges

2013E

All periods reflect Alaska as discontinued operations, comprising 4,432 BOEPD for 2011, 4,269 BOEPD for 2012, 3,707 BOEPD for Q1 '13, 4,209 BOEPD for Q2 '13

and 4,723 BOEPD for Q3 '13; Q4 severe weather event in Spraberry/Wolfcamp expected to result in production falling below FY 2013 growth guidance of ~14%

High end of 2013-2015 growth range assumes $100 oil / $4.25 gas; low end assumes $85 oil / $3.25 gas

Excludes production attributable to the 40% joint venture transaction with Sinochem in the southern Wolfcamp area after the May 31, 2013 closing date

Spraberry/Wolfcamp production negatively impacted by reduced ethane recoveries of ~2,700 BOEPD in Q1, ethane rejection of ~1,400 BOEPD in Q2 and ~1,000

BOEPD in Q3; no ethane rejection assumed in Q4

Liquidity Position (09/30/13)

Net debt (net of cash balance of $744 MM):

$2.1 B

Unsecured credit facility availability:

$1.5 B

Net debt-to-book capitalization:

21%

Excludes $201 MM of borrowings under PSE’s $300 MM credit facility that matures in March 2017

Excludes net discounts and deferred hedge losses of ~$40 MM

Maturities

and

Balances

1,2

Unsecured credit facility matures in 2017

Investment grade rated

2016

$600 MM

3.95%

2017

$455 MM

5.875%

2022

$450 MM

6.875%

Undrawn $1.5 B unsecured credit facility

2018

$485 MM

6.65%

$450 MM

7.50%

2020

$250 MM

7.20%

2028

12/31/12 Proved Reserves: 1.1 BBOE

Additional

Net

Recoverable

Resource

Potential:

BBOE

All drilling locations shown on a gross basis

SEC pricing of $94.84/Bbl for oil and $2.76/MMBtu for gas (NYMEX)

Primarily reflects Alaska, Raton and South Texas

Includes vertical well potential from Wolfcamp and deeper intervals

Assumes average EUR of 500 MBOE per well, >600,000 gross acres, 140-acre spacing, Wolfcamp

A, B & D and Jo Mill intervals (excludes Spraberry Shale interval potential) and 20% royalty

Assumes average EUR of 575 MBOE per well, 5,600 locations, 207,000 net acres , 140-acre

spacing, laterals in all intervals (A, B, C & D), 25% royalty and Pioneer’s 60% share (reduced by

~1 BBOE associated with joint interest transaction)

Permian >7 BBOE

Spraberry

627 MMBOE

3,350 PUD locations

Rockies

119 MMBOE

55 PUD

locations

Other

123 MMBOE

140 PUD locations

Mid-Continent

101 MMBOE

Vertical Spraberry

40-ac Drilling

900 MMBOE

6,800 locations

Vertical Spraberry

20-ac Drilling

1.5 BBOE

14,650 high-graded locations

Spraberry Waterflood

300 MMBOE

40% acreage

Eagle Ford Shale

340 MMBOE

1,100 locations

Eagle

Ford Shale

116 MMBOE

190 PUD locations

Southern Horizontal Wolfcamp

Joint Interest Area

1.6 BBOE

5,600 locations

Proved Reserves + Estimated Net Recoverable Resource Potential of >9 BBOE and >40,000 Drilling Locations

Pioneer’s

Significant

Proved

Reserves

and

Recoverable

Resource

Potential

Northern Horizontal

Wolfcamp/Jo Mill

3.0 BBOE

8,000 locations

Expect to continue operating 8 horizontal

rigs in 2014

2014 drilling plan calls for ~115 horizontal

wells compared to ~100 horizontal wells

in 2013

–

Average lateral length will be increased by 13% from

8,300 feet in 2013 to 9,400 feet in 2014

Expect to utilize 3-well pads for most of

the program

Expect to drill ~2/3 Wolfcamp B interval

wells; remainder is a mix of Wolfcamp A,

C and D interval wells

2014 drilling program more focused on

higher-return areas in northern Upton and

Reagan counties (includes Giddings and

University Block 2)

Expect to continue to improve drilling and

completion times

Best Wolfcamp B interval

IP in Midland Basin

PXD –

University 2-20 #12

(Wolfcamp Upper B)

24-hr IP: 3,176 BOEPD (83% oil)

9,542’

lateral length

Joint Venture Area

(Wolfcamp and deeper intervals)

Gun Barrel View:

480’

Downspacing Test Underway in Southern JV Area

~200’

Wolfcamp

Upper B

Lower B

720’

310’

Began

testing

downspacing

from

720’

(116-acre

spacing)

480’

(77-acre spacing) in the Giddings area

Tested 12 wells on 3-well pads using zipper fracs

Wells staggered between Upper Wolfcamp B and Lower

Wolfcamp B intervals

All 12 wells currently on production

—

Average peak 24-hour IP rate of 1,016 BOEPD

—

Compares favorably to initial two Giddings B interval

wells which averaged 830 BOEPD at similar lateral

lengths

Expect early results on initial downspacing test and further

downspacing

310’

(50-acre

spacing)

mid-2014

77-Acre Spacing per

Interval

116-Acre Spacing per

Interval

50-Acre Spacing per

Interval

Based on

7,000’

lateral

Joint Venture Area

(Wolfcamp and deeper intervals)

Giddings

October 2013

Mid-2014

U. Spraberry

M. Spraberry

Shale

Jo Mill Silt

L. Spraberry

Shale

Dean

Wolfcamp A

Wolfcamp Lower B

Wolfcamp C1

Wolfcamp C2

Wolfcamp D

Strawn

Wolfcamp Upper B

Northern Spraberry/Wolfcamp Targeted Horizontal Drilling Intervals

Miss/Atoka

Wolfcamp

Jo Mill

M. Spraberry

Shale

L. Spraberry

Shale

Delineating multiple prospective

horizontal targets with

substantial oil in place across

>600,000 gross acres

Targeting $7.5 MM -

$8.5 MM

average well cost for 7,000’

laterals depending on depth

Jo Mill Shale

Wolfcamp

–

Excludes science and facilities capital

Pioneer’s Northern Horizontal Wolfcamp D Shale Wells

800 MBOE

500 MBOE

100

500

1,000

2,000

3,000

120

150

180

Days

University 7-43 10H –

Wolfcamp D (Andrews County); 7,382’

lateral

24-hour peak IP rate of 3,605 BOEPD (74% oil)

E.T. O’Daniel #2H –

Wolfcamp D (Midland County); 9,112’

lateral

24-hour peak IP rate of 3,156 BOEPD (69% oil)

Scharbauer Ranch #201H –

Wolfcamp D (Martin County); 7,862’

lateral

24-hour peak IP rate of 1,509 BOEPD

Peak 30-day avg. rate of 662 BOEPD (60% oil)

DL Hutt C #4H –

Wolfcamp D (Midland County); 6,962’

lateral

24-hour peak IP rate of 2,128 BOEPD

Peak 30-day avg. rate of 856 BOEPD (69% oil)

Best IP of any interval

in the Midland Basin

Early production data suggests EURs for these wells will equal or exceed

average industry Wolfcamp D results to date

Pioneer’s Wolfcamp D Wells Extend Play 60 Miles West

LPI

Sugg-A—142

24-hr IP: 944 BOEPD

30-day IP: 764 BOEPD

6,695’

lateral length

LPI

–

Glass-Glass

10-153H

24-hr IP: 1,886 BOEPD

30-day IP:

1,052

BOEPD

6,933’

lateral length

LPI

–

Bearkat

150

24-hr IP: 1,380 BOEPD

30-day IP: 1,007 BOEPD

7,282’

lateral length

LPI

–

Cox

Bundy

#3H

24-hr IP: 1,227 BOEPD

30-day IP: 922 BOEPD

4,382’

lateral length

PXD –

DL Hutt C #4H

24-hr IP: 2,128 BOEPD

30-day IP: 856 BOEPD

6,962’

lateral length

PXD –

Scharbauer Ranch #201H

24-hr IP: 1,509 BOEPD

30-day IP: 662 BOEPD

7,862’

lateral length

APA

–

Barracuda

45-4H

24-hr IP: 695 BOEPD

30-day IP: 511 BOEPD

4,560’

lateral length

PXD –

E.T. O’Daniel #2H

24-hr IP: 3,156 BOEPD

9,112’

lateral length

PXD –

University 7-43 10H

24-hr IP: 3,605 BOEPD

7,382’

lateral length

APA

–

Barracuda

45-2H

24-hr IP: 810 BOEPD

30-day IP: 623 BOEPD

3,780’

lateral length

U. Spraberry

M. Spraberry

Shale

Jo Mill Silt

L. Spraberry

Shale

Dean

Wolfcamp A

Wolfcamp C1

Wolfcamp C2

Wolfcamp D

Strawn

Wolfcamp B

Miss/Atoka

Jo Mill Shale

Pioneer’s Northern Horizontal Wolfcamp B and Wolfcamp A Shale Wells¹

Hutt

#1H

–

Wolfcamp

(Midland

County);

7,380’

lateral

Cumulative production: 170 MBOE in 9 months (73% oil)

1 MMBOE

800 MBOE

500 MBOE

Hutt

#3H

–

Wolfcamp

(Midland

County);

7,142’

lateral

24-hour peak IP rate of 2,227 BOEPD; Peak 30-day avg. rate of 1,087 BOEPD (75% oil)

Mabee

#1H

–

Wolfcamp

(Martin

County);

6,671’

lateral

Cumulative production: 100 MBOE in 6 months (73% oil)

Daily production normalized for operational shut-ins

DL Hutt

#2H

–

Wolfcamp

(Midland

County);

7,380’

lateral

Cumulative production: 115 MBOE in 5 months (74% oil)

Production data suggests that EURs for these Wolfcamp B and A wells are expected to exceed 800 MBOE

Scharbauer

Ranch

#202H

–

Wolfcamp

(Martin

County);

8,342’

lateral

24-hour peak IP rate of 979 BOEPD; Peak 30-day rate of 783 BOEPD (73% oil)

E.T.

O'Daniel

–

Wolfcamp

(Midland

County);

9,229’

lateral

24-hour peak IP rate of 2,801 BOEPD (75% oil)

Best Wolfcamp B interval IP in

Pioneer’s northern acreage

Notable Industry Wolfcamp A, B & C and Spraberry Shale Horizontal Results

RSP (L. Spraberry Shale)

24-hr IP: 630 BOEPD

~4,800’

lateral length

U. Spraberry

M. Spraberry

Shale

Jo Mill Silt

L. Spraberry

Shale

Dean

Wolfcamp A

Wolfcamp C1

Wolfcamp C2

Wolfcamp D

Strawn

Wolfcamp B

Miss/Atoka

Jo Mill Shale

PXD -

2 Jo Mill Wells

Avg. 24-hr IP: 483 BOEPD

2,500’

avg. lateral length

PXD -

DL Hutt C #1H (WC B)

24-hr IP: 1,693 BOEPD

7,380’

lateral length

FANG -

UL III 4 1-H (WC B)

24-hr IP: 613 BOEPD

4,050’

lateral length

FANG (4 WC B wells)

Avg. 24-hr IP: 872 BOEPD

~4,340’

avg. lateral length

PXD -

DL Hutt C #2H (WC A)

24-hr IP: 1,712 BOEPD

7,380’

lateral length

LPI -

Sugg-A-143-4HU (WC A)

24-hr IP: 1,904 BOEPD

7,033’

lateral length

EGN -

Lavaca 38 #101H (WC B)

24-hr IP: 861 BOEPD

4,250’

lateral length

LPI -

Sugg-C-27-1HM (WC B)

24-hr IP: 1,409 BOEPD

7,745’

lateral length

RSP (M. Spraberry Shale)

24-hr IP: 733 BOEPD

~5,040’

lateral length

SM –

Dorcus 3035H (WC B)

24-hr IP: 1,571 BOEPD

4,960’

lateral length

PXD -

DL Hutt C #3H (WC B)

24-hr IP: 2,227 BOEPD

7,142’

lateral length

PXD –

Scharbauer #202H (WC B)

24-hr IP: 979 BOEPD

8,342’

lateral length

PXD -

Mabee K #1H (WC B)

24-hr IP: 1,572 BOEPD

6,671’

lateral length

PXD -

E.T. O'Daniel 1H (WC B)

24-hr IP: 2,801 BOEPD

9,229’

lateral length

PXD -

University 2-20 #12 (WC B)

Avg. 24-hr IP: 3,176 BOEPD

9,542’

avg. lateral length

PXD -

2 Giddings Wells (WC B)

Avg. 24-hr IP: 845 BOEPD

5,300’

avg. lateral length

LPI –

Lane Trust C/E 42-2HL (WC C)

24-hr IP: 2,147 BOEPD

7,571’

lateral length

Pioneer’s Northern

Spraberry/Wolfcamp

Activity

20 horizontal wells on production with 8

of these currently flowing back

6 wells awaiting completion

8 horizontal rigs drilling

Pioneer’s Northern

Spraberry/Wolfcamp Acreage

Joint Venture Area

(Wolfcamp and Deeper Intervals)

As of end-December 2013

Producing

Completing

Drilling

~65 mi

–

Includes 14 Wolfcamp Shale wells and 6 Spraberry

Shale wells in Midland, Martin, Upton and Andrews

counties

–

Includes 2 Wolfcamp Shale wells and 4 Spraberry

Shale wells in Midland and Glasscock counties

Northern Spraberry/Wolfcamp: Focused on Growing Production in 2014

Ramping up from 5 horizontal rigs to 10+ horizontal rigs in early 2014

–

Vertical rig count being reduced from 15 rigs to 12 rigs or less

Expect to utilize 3-well pads for most of the program

–

Results in “lumpy”

production growth

Expect to drill 90%+ Wolfcamp A, B and D interval wells

Minimal “science”

activity planned

Drilling times being reduced

Targeting a reduction in spud-to-POP times from 120-150 days in 2013 (2-well

pads including “science”

time) to ~145 days in 2014 (3-well pads with no

“science”)

–

Equivalent reduction from 65 days per well to 50 days per well

–

Includes benefits from zipper fracs

2013 Spraberry/Wolfcamp Shale Production Growth Range

Spraberry/Wolfcamp Net Production

(MBOEPD)

1) Includes production from Spraberry vertical wells and horizontal Wolfcamp Shale and Spraberry Shale wells

2) Production reduced after May 31st to reflect the divested volumes associated with the closing of the southern Wolfcamp joint venture transaction

3) Production negatively impacted by reduced ethane recoveries of ~2,700 BOEPD in Q1, ethane rejection into the gas stream of ~1,400 BOEPD in Q2 and ~1,000

BOEPD in Q3 due to low ethane prices; assumes no ethane rejection in Q4

2,3

2013

80 –

81 MBOEPD

FY Guidance

85 -

Horizontal

Q4 severe weather event

expected to result in

production falling below

Q4 and FY 2013 guidance

ranges

2011

2012

Q4E

Vertical

Eagle Ford Shale Downspacing Results (500’

Well Spacing Tests)

Dry Gas Window

Condensate Window

Oil Window

Downspacing from 1,000’

(120-acre spacing) to 500’

(60-acre

spacing) between wells across liquids-rich acreage position

(~90 miles)

—

Added ~300 locations in liquids-rich areas

Tested 50+ wells on 3-well to 4-well pads using zipper fracs

Average EUR for zipper frac’d pad wells increased 20% vs.

offset single wells (1.2 MMBOE vs. 1.0 MMBOE)

—

Stimulation of pad wells provides improved fracture network

500’

Downspacing

Areas

LaSalle

Dewitt

Atascosa

Reducing 2013 Eagle Ford Shale Production Growth Range

Eagle Ford Shale Net Production

(MBOEPD)

37 –

38 MBOEPD

FY Guidance

Reflects Pioneer’s ~35% share of gross production

Assumes no ethane rejection in Q4 2013

2-well to 6-well pads (Spud to POP averaging 100 –

125 days

for 3-well pads)

Saves $600 M to $700 M per well

Delays in placing wells on production related to increased

pad drilling (~2,000 BOEPD)

High level of shut-in wells for offset frac activity related to

downspacing tests (~1,000 BOEPD)

Comparable to Lower Eagle Ford Shale wells

~25% of acreage prospective for this interval

2011

2012

Q4E

39 -

2013

~80% pad drilling in 2013, up from 45% in 2012

Q3 production declined 3 MBOEPD due to:

Wells POP’d towards the end of Q3 and an

aggressive Q4 POP schedule expected to

significantly ramp up Q4 production

Successfully completed first Upper Eagle Ford Shale

well

with

24-hour peak IP rate of 1,620 BOEPD

PXD Production By Commodity By Area

Q3 '12

Q4 '12

Q1 '13

Q2 '13

Q3 '13

Spraberry/Wolfcamp

Oil (BOPD)

45,239

46,540

52,694

52,595

51,904

NGL (BOEPD)

14,138

11,262

12,864

13,919

16,199

Gas (MCFD)

57,095

64,607

58,653

83,021

62,892

Total (BOEPD)

68,893

68,570

75,333

80,351

78,585

Eagle Ford

Oil (BOPD)

10,087

11,671

12,741

13,868

12,399

NGL (BOEPD)

8,549

9,462

10,133

10,212

10,080

Gas (MCFD)

65,048

81,823

86,305

82,765

74,468

Total (BOEPD)

29,477

34,770

37,257

37,874

34,889

Raton

Oil (BOPD)

NGL (BOEPD)

Gas (MCFD)

148,188

144,245

138,358

136,093

133,933

Total (BOEPD)

24,698

24,041

23,060

22,682

22,323

Mid-Continent

Oil (BOPD)

3,243

3,063

3,202

2,902

3,081

NGL (BOEPD)

7,223

7,466

6,511

6,740

7,359

Gas (MCFD)

46,914

41,398

41,250

39,874

40,535

Total (BOEPD)

18,285

17,429

16,589

16,288

17,195

Barnett

Oil (BOPD)

1,217

1,574

1,445

1,364

1,547

NGL (BOEPD)

2,472

3,289

3,038

3,184

3,354

Gas (MCFD)

19,132

25,168

24,159

24,061

21,396

Total (BOEPD)

6,878

9,058

8,510

8,558

8,467

South Texas

Oil (BOPD)

233

NGL (BOEPD)

Gas (MCFD)

36,495

34,037

31,609

31,208

31,509

Total (BOEPD)

6,173

5,740

5,349

5,273

5,486

Alaska

Oil (BOPD)

4,404

4,102

3,707

4,209

4,723

NGL (BOEPD)

Gas (MCFD)

Total (BOEPD)

4,404

4,102

3,707

4,209

4,723

Other

Oil (BOPD)

NGL (BOEPD)

441

458

441

360

370

Gas (MCFD)

3,493

3,539

3,502

3,306

3,090

Total (BOEPD)

1,085

1,101

1,095

975

943

Total

Oil (BOPD)

64,342

67,069

73,939

75,073

73,943

NGL (BOEPD)

32,824

31,938

32,989

34,416

37,362

Gas (MCFD)

376,365

394,817

383,836

400,328

367,823

Total (BOEPD)

159,893

164,810

170,900

176,210

172,611

Production Costs (per BOE)

Production &

Ad Valorem Taxes

Workovers

LOE

Third Party

Transportation

Natural Gas

Processing

Q3 ’13

Q3 ’12

$0.09

$14.56

Q4 ’12

$0.59

Q1 ’13

$0.42

Q2 ’13

$0.17

$15.61

$14.62

Q3 2013 production costs

increased slightly compared to

Q2 2013

—

LOE increase attributable to

higher saltwater disposal and

labor expenses

—

party transportation increase

primarily due to one-time charges

associated with transportation of

Eagle Ford Shale production

$14.52

$(0.15)

$14.81

$9.61

$8.68

$8.34

$8.20

$8.59

$1.28

$1.40

$1.67

$1.57

$1.98

$3.38

$3.14

$3.53

$3.36

$3.40

$0.75

$0.98

$0.81

$1.34

$0.99

Continue to use derivatives to mitigate commodity price

exposure in order to ensure 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

Derivative Philosophy

Oil

Q4 2013

2014

2015

2016

Swaps –

WTI (BPD)

9,750

10,000

NYMEX WTI Price ($/BBL)

$ 95.57

$ 93.87

Three Way Collars –

(BPD)

69,000

85,000

25,000

NYMEX Call Price ($/BBL)

$ 120.55

$ 114.05

$ 98.98

$ 93.30

NYMEX Put Price ($/BBL)

$ 91.39

$ 93.70

$ 88.06

$ 85.00

NYMEX Short Put Price ($/BBL)

$ 74.22

$ 77.61

$ 73.06

$ 70.00

% Total Oil Production

~95%

~85%

~65%

~15%

Open Commodity Derivative Positions as of 10/31/2013 (includes PSE)

Oil Basis Protection

Q4 2013

2014

2015

2016

Cushing to LLS Swaps (BPD)

3,000

Price Differential ($/BBL)

$ 8.53

Spraberry Fixed Differential

30,000

33,000

35,000

Price Differential ($/BBL)

$ (1.75)

Oil coverage: ~95% in 2013, ~85% in 2014 and ~65% in 2015

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

Market transaction representing Cushing to Midland differential; not a derivative

Natural Gasoline

Q4 2013

2014

2015

2016

Three Way Collars –

(BPD)

1,064

1,000

Mont Belvieu Call Price ($/BBL)

$ 105.28

$ 109.50

Mont Belvieu Put Price ($/BBL)

$ 89.30

$ 95.00

Mont Belvieu Short Put Price ($/BBL)

$ 75.20

$ 80.00

% Total NGL Production

<5%

Open Commodity Derivative Positions as of 10/31/2013 (includes PSE)

Ethane

Q4 2013

2014

2015

2016

Collars –

(BPD)

2,500

3,000

Mont Belvieu Call Price ($/BBL)

$ 12.68

$ 13.72

Mont Belvieu Put Price ($/BBL)

$ 10.50

$ 10.78

% Total NGL Production

<5%

% Total Liquids

~65%

~60%

~45%

~10%

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

Represent collar contracts with short puts that reduce price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu,

Texas-posted prices

Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices

Gas

Q4 2013

2014

2015

2016

Swaps -

(MMBTUPD)

165,870

175,000

20,000

NYMEX

Price

($/MMBTU)

$ 5.10

$ 4.02

$ 4.31

Collars -

(MMBTUPD)

152,500

NYMEX

Call

Price

($/MMBTU)

$ 6.22

NYMEX

Put

Price

($/MMBTU)

$ 4.98

Three

Way

Collars

–

(MMBTUPD)

115,000

285,000

20,000

NYMEX Call Price ($/MMBTU)

$ 4.70

$ 5.07

$ 5.36

NYMEX Put Price ($/MMBTU)

$ 4.00

NYMEX Short Put Price ($/MMBTU)

$ 3.00

% Total Gas Production

~85%

~70%

<5%

Open Commodity Derivative Positions as of 10/31/2013 (includes PSE)

Gas Basis Swaps

Q4 2013

2014

2015

2016

Spraberry

(MMBTUPD)

52,500

10,000

Price Differential ($/MMBTU)

$ (0.23)

$ (0.15)

$ (0.13)

Mid-Continent

(MMBTUPD)

50,000

75,082

20,000

Price Differential ($/MMBTU)

$ (0.30)

$ (0.20)

$ (0.21)

Gulf Coast

(MMBTUPD)

60,000

Price Differential ($/MMBTU)

$ (0.14)

Gas coverage: ~85% in 2013, ~70% in 2014 and ~70% in 2015

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

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

Oil

Q4 2013

2014

2015

Swaps

(BPD)

4,750

NYMEX Price ($/BBL)

$ 87.83

Three-Way

Collars

(BPD)

5,000

NYMEX Call Price ($/BBL)

$ 105.74

NYMEX Put Price ($/BBL)

$ 100.00

NYMEX Short Put Price ($/BBL)

$ 80.00

% Oil Production

~85%

Gas

Q4 2013

2014

2015

Swaps

(MMBTUPD)

2,500

5,000

NYMEX Price ($/MMBTU)

$ 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

Collars

(MMBTUPD)

2,500

NYMEX Call Price ($/MMBTU)

$ 4.50

NYMEX Put Price ($/MMBTU)

$ 4.00

% Gas Production

~70%

~65%

% Total Production

~70%

~10%

Gas Basis Swaps

Q4 2013

2014

2015

Spraberry

(MMBTUPD)

2,500

Price Differential ($/MMBTU)

$ (0.31)

PSE Derivative Position as of 10/31/2013

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 short put price and put price

Three-Way Collars ($75 by $90 by $135 example)

Three way collars protect downside while providing better

upside exposure than traditional collars or swaps

Potential

Opportunity Loss

Realize NYMEX price

plus $15/BBL

(difference between long put

and short put)

Realize $90/BBL

Realize NYMEX price

Realize $135/BBL

Short put at $75/BBL

Long put at $90/BBL

Short call at $135/BBL

Realized Price

NYMEX Price

$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

Experienced Senior Management Team

Scott Sheffield

Chairman and Chief Executive Officer

Tim Dove

President and Chief Operating Officer

Rich Dealy

Executive Vice President and Chief Financial Officer

Mark Berg

Executive Vice President and General Counsel

Chris Cheatwood

Danny Kellum

Bill Hannes

Joey Hall

Ken Sheffield

Years of Experience

Years at Pioneer /

Predecessor Companies

Senior management team has an average of 30 years of experience

and

has

worked

together

Pioneer

and

predecessor

companies

for

20 years

Executive Vice President – Business Development & Geoscience

Executive Vice President – Permian Operations

Executive Vice President – Southern Wolfcamp Operations

Senior Vice President – South Texas Operations

Senior Vice President – Operations and Engineering

Strong Stock Price Performance Demonstrates Successful Strategy Shift

Pioneer

S&P 500 Oil & Gas Index

S&P 500 Oil & Gas E&P Index (XOP): 75 E&P’s including all of Pioneer’s peers; Index composition is 70% upstream, 20% refining & marketing and 10% integrated

100

200

300

400

500

Jul-06

Jul-07

Jul-08

Jul-09

Jul-10

Jul-11

Jul-12

Jul-13

Pioneer raised $8 billion of capital during the Company’s transformation

period to accelerate development in unconventional plays:

Pioneer has been the top performing energy stock in the S&P 500 since 2009

Ranked #6 in the overall S&P 500 over this period

Economic Downturn

Onshore U.S. Liquids Focus

Restructuring

Portfolio

Onshore U.S.

Focus

–

$3 billion from the sale of conventional assets

–

$5 billion from 2 JVs and equity issuance

Added 161 MMBOE from the drillbit, or 264% of full-year

production, at a drillbit F&D cost of $17.72 per BOE

All-in reserve replacement of 87 MMBOE, or 144% of full-

year production at an all-in F&D cost of $34.46 per BOE,

including:

Reserve mix

Proved Reserves / Production: ~18 years

PD Reserves / Production: ~10 years

Strong 2012 Reserve Additions¹

Year-end ’12

Proved Reserves

(MMBOE)

Spraberry

627

Raton

119

Eagle Ford

116

Mid-Continent

101

Barnett Shale

Alaska

South Texas

Other

Total

1,086

Reflects 2012 SEC pricing (12-month average) of $94.84/Bbl for oil and $2.76/MMBtu for gas (NYMEX) as compared to 2011 SEC pricing of $96.13/Bbl for oil and

$4.12/MMBtu for gas (NYMEX)

Reflects significant drilling campaigns in horizontal

Wolfcamp Shale, Spraberry vertical, Eagle Ford Shale

and Barnett Shale Combo plays

100% U.S.

Negative technical revisions of 27 MMBOE; performance

improvements of 53 MMBOE offset by 80 MMBOE of vertical

Spraberry PUDs moved to the probable category as the

Company shifts to more horizontal drilling in the

Spraberry field based on successful horizontal Wolfcamp

Shale drilling results

Negative pricing revisions of 82 MMBOE due to significant

decline in gas prices

45%

oil

21%

NGLs

34%

gas

58% PD / 42% PUD

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)

Basinal Sediments

Wolfcamp Map

San Simon

Channel

North Basin

Platform

Glasscock

Nose

Marathon

Thrust Belt

Fluvial -

Deltaic

Platform

Carbonate

Clastic

Slope

Land

Carbonate Slope

Debris

Flow

Carb

Gravity Flow

Clastic

Gravity Flow

Pelagic Sed.

Platform

Carbonate

Land

CBP

Midland

Basin

Marathon

Thrust Belt

North

Older

Wolfcamp

Clastics

Source: Adapted from Handford, 1981

Wolfcamp

Depositional

Model

–

Midland

Basin

Midland

Progression

Spraberry/Wolfcamp

Field

Development

Source: IHS Energy

October 8, 1951. OIL: The Spraberry Trend, retrieved from http://www.time.com/time/magazine/article/0,9171,859404,00.html

1940s –

Discovery

1960s –

Field extension

1970s –

Dramatic expansion

Independents including

Parker & Parsley (Pioneer’s

predecessor Company)

become large players; less

emphasis by Majors

Independents become the

dominant player

Independents continue to

dominate the landscape

driven by Pioneer

2010s –

Deeper and horizontals

Major oil company

development; principally

Texaco, Phillips and Mobil

1951 –

Time

(2)

magazine

cites

as most active oil field in

U.S.

1953 –

Considered “largest

uneconomic oil field in the

world”

1949 –

Seaboard #2-D

Lee drilled by Seaboard

Oil Company IP’d at 319

BOPD

1943 –

Trace oil found

from well drilled on the

Abner Spraberry farm in

Dawson County

Independents lead the

charge going deeper;

Horizontal oil shale

activity expanding

Continued development by

Majors and Independents

Continued development by

Majors with a few minor

Independents

1950s –

Early Development

1990s –

Infill and efficiency

1980s –

Expansion & Infill

2000s –

Infill and efficiency

History of Spraberry/Wolfcamp Completions

2010

2000 -

1980 -

90s

1950 -

70s

Limestone Pay

Sandstone Pay

Non-Organic Shale Non-Pay

Organic Rich Shale Pay

2011-12

5,000’

–

10,000’

Horizontal Wolfcamp A, B and D

2013+

5,000’

–

7,000’

Horizontal Spraberry Shales

5,000’

–

7,000’

Horizontal Jo Mill

5,000’

–

10,000’

Horizontal Wolfcamp A, B, C and D

Horizontal drilling in Spraberry/Wolfcamp

further improves recoveries and capital

efficiency

Fracture

stimulation

stages

Drilling deeper and adding fracture

stimulation stages have added production

and improved recoveries

Dean

Jo Mill

Major U.S. Shale Play Comparisons

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

Barnett

Miss Lime

Woodford

Wolfcamp D

“Cline”

Wolfcamp A

Wolfcamp B

L. Spraberry

M. Spraberry

Clear Fork

JoMill

Source: PXD

Dean

Wolfcamp C

U. Spraberry

Atoka

Strawn

Midland Basin

Eagle Ford

Condensate

Barnett

Combo

Niobrara

Bakken

Marcellus

How big is the resource?

Wolfcamp Comparison to Other Major U.S. Oil Shale Plays

Major U.S. Oil Shale Play Characteristics

Attribute

Units

Wolfcamp

Shale

Eagle

Ford

(Oil Window)

Bakken

Age

Permian

Cretaceous

Devonian/Mississippian

Basin

Midland

South Texas

Williston

TVD Depth

5,500 -

11,000

7,500 -

11,000

9,000 -

11,000

Thickness

1,500 –

2,600

50 -

350

25 -

125

OOIP/Section

MMBO

80 –

220

30 -

10 -

Porosity

2 –

4 -

5 -

Quartz

20 –

10 -

30 -

Carbonate

10 –

60 -

30 -

Clay

10 -

TOC

2 –

1 –

2 -

Permeability

10 -

3,000

40 -

1,300

50,000 -

500,000

Pressure Gradient

psi/ft

0.55 -

0.70

0.65 -

0.70

0.43 -

0.75

Recovery Factor

3 -

8 -

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

EOG Analyst Conference April 2010

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

Wolfcamp geology compares favorably to other major oil shale plays

Wolfcamp B Interval Prospectivity Map

Tier 1

Tier 2

Pioneer Acreage

Pioneer Wolfcamp B wells

Competitor Wolfcamp B wells

Wolfcamp B depth contour

Tier 1 is highest prospectivity

acreage, as determined by several

geologic properties, including:

Original oil in place (OOIP)

Kerogen content

Thermal maturity

Porosity

Brittle mineral fraction (fracability,

low clay content)

Geologic maps based on:

>70,000 logs

>2,600 square miles of 3-D seismic

>14,500 feet of core

Industry Wolfcamp B Prospectivity

4.8 MM risked acres (Upper B and

Lower B)

>34,000 potential well locations on

140-acre spacing

450 MBOE to 1 MMBOE EUR per well

22 BBOE Resource Potential

Scharbauer

Ranch

#202H

24-hr IP: 979 BOEPD

Peak 30-day avg. rate: 783 BOEPD

~73% oil

8,342’

lateral length

Mabee K #1H

24-hr IP: 1,572 BOEPD

Peak 30-day avg. rate: 1,040 BOEPD

~76% oil

6,671’

lateral length

E.T. O’Daniel #1H

24-hr IP: 2,801 BOEPD

~75% oil

9,229’

lateral length

DL Hutt C #3H

24-hr IP: 2,227 BOEPD

Peak 30-day avg. rate: 1,087 BOEPD

~75% oil

7,142’

lateral length

DL Hutt C #1H

24-hr IP: 1,693 BOEPD

Peak 30-day avg. rate: 1,402 BOEPD

~75% oil

7,380’

lateral length

Giddings

Wells

Avg. 24-hr IP: 845 BOEPD

Peak 30-day avg. rate: 669 BOEPD

>75% oil

5,300’

avg. lateral length

University

2-20

#12H

Avg. 24-hr IP: 3,176 BOEPD

9,542’

avg. lateral length

–

50 BBOE

recoverable

resource

potential

industry

four

shale

intervals

where

successful horizontal wells have been drilled

Additional

horizontal

potential

two

Spraberry

intervals,

Strawn,

Atoka

and

Barnett/Woodford intervals

Assumes 140-acre spacing; down-spacing potential exists

50 BBOE Recoverable Resource Potential by Industry

Midland Basin Wolfcamp and Jo Mill Shales

Source: Pioneer estimates

Jo Mill

7 BBOE

Wolfcamp A

13 BBOE

Wolfcamp B

22 BBOE

Wolfcamp D

8 BBOE

50 BBOE Recoverable Resource Potential in Midland Basin Wolfcamp and Jo Mill Shales

Largest Oil Fields Worldwide

1) Total recoverable reserves includes oil and gas for all fields

Source: Wood Mackenzie for international fields; Spraberry/Wolfcamp from Pioneer

Spraberry/Wolfcamp

the

largest

oil

field

the

world

160

Ghawar, Saudi Arabia

Spraberry/Wolfcamp, USA

Burgan, Kuwait

Safaniyah, Saudi Arabia

Samotlorskoye, Russia

Shaybah, Saudi Arabia

Romashkinskoye, Russia

ADCO, UAE

Zuluf, Saudi Arabia

Cantarell, Mexico

Total

Recoverable

Resource

(BBOE)

Largest U.S. Oil Fields

Cumulative production + estimated recoverable resource

Source: DOE, EIA, ITG and other sources

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

Estimated

Recoverable

Resource

(BBOE)

Spraberry/Wolfcamp is the largest oil field in the U.S.

Spraberry/Wolfcamp Production History

From 2009 to 2012, production growth primarily attributable to increased vertical activity

Post

2012,

production

growth

expected

driven

horizontal

activity

Production

Producing Wells

Source: IHS Energy through May 2013 for the Spraberry, Credo East, Garden City South and Lin Fields

Includes Vertical and Horizontal Wells

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

22,000

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

550,000

Production Growth Profiles For 3 Largest U.S. Oil Shale Plays

Eagle Ford

197 Horizontal Rigs

Bakken

156 Horizontal Rigs

Spraberry/Wolfcamp

86 Horizontal Rigs

Spraberry/Wolfcamp horizontal growth trajectory similar to Bakken and Eagle Ford

Includes Horizontal Wells Only

100

1,000

10,000

100,000

1,000,000

10,000,000

108

120

Months

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 11/15/13 for selected counties identified on slide 44 for Spraberry/Wolfcamp; Initial month is November 2010 for Spraberry/Wolfcamp,

April 2008 for Eagle Ford and January 2003 for Bakken

Spraberry/Wolfcamp Horizontal Drilling Production Growth Profile

Potential impediments to achieving this forecast include oil price, capital, infrastructure (Midland and oil field) and people

Assumes industry rig count ramps up from ~65 horizontal rigs currently to ~120 rigs per year in 2018 and thereafter (excludes Pioneer’s portion)

Includes royalties and joint interest partner’s share of production in southern Wolfcamp

Other Operators

(~200 Independent Operators)

Pioneer

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

2.25

2.50

2.75

2013

2018

2023

2028

2033

Assumes Pioneer’s rig count increases from 12 rigs

currently to 50 rigs in 2018 and thereafter

Market

Wink

Permian

Basin

Cushing

Crude Pipeline Capacity to Gulf Coast

Operator

Origin

Destination

Name

Capacity

Time Frame

Plains

Permian

Cushing

Basin

450,000

Oxy

Permian

Cushing

Centurion

75,000

Sunoco

Permian

West Texas Gulf

400,000

Kinder Morgan

Permian

El Paso

Wink

120,000

Magellan

Permian

Longhorn

225,000

Total

1,270,000

Magellan

Permian

Longhorn-add

50,000

mid 2014

Magellan

Permian

BridgeTex

278,000

3Q 2014

Plains

Permian

Corpus

Cactus

200,000

2Q 2015

Possible

Sunoco

Permian

Permian Express II

200,000

4Q 2015

Operator

Origin

Destination

Name

Capacity

Time Frame

Current

Enbridge/Enterprise

Cushing

Seaway

400,000

Enbridge/Enterprise

Cushing

Seaway-add

450,000

1Q 2014

Transcanada

Cushing

Gulf Coast

700,000

1Q 2014

Planned

Permian Basin Crude Takeaway Capacity

Planned

Current

Cushing to Gulf Coast Pipeline Takeaway

Growing Midstream Infrastructure to Support Production Growth

Benedum

Sale Ranch

Gas Processing

Midkiff / Benedum / Driver

–

Current capacity: 460 MMCFD

–

PXD production makes up ~40%

of throughput

–

Includes 200 MMCFD

Driver

Plant which came online April

2013

Sale Ranch

–

Current capacity: 120 MMCFD

–

Jameson Plant interconnect

adds 40 MMCFD

–

PXD production makes up ~15%

of Sale Ranch throughput

Capacity Addition of 200

MMCFD announced for the

Benedum Area for late

2014 / 2015

Pipeline NGL Takeaway

to Mont Belvieu

Chaparral & West Texas

Pipelines

–

PXD production throughput of

~9 MBPD

Lone Star Pipeline

–

4 MBPD to PXD increasing to

16 MBPD by 2020

–

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

PXD Acreage

Spraberry Field

Midkiff

1) Wet gas stream with ~160 BBL/MMSCF NGL yield

Driver

Plant

Existing NGL Pipeline

Pioneer in the Spraberry/Wolfcamp Shale

Largest acreage position in the Midland Basin

–

High oil exposure from proved reserves + net recoverable resource potential of >7.5 BBOE

Technology leader

–

Sophisticated geologic maps from >70,000 logs, >2,600 square miles of 3-D seismic and

>14,500 feet of core

Improving capital efficiency by successfully transitioning from vertical drilling to

horizontal drilling

Successful joint venture in southern Wolfcamp area

–

Reflects value of Pioneer acreage

–

Drilling program is cash flow positive

Accelerating northern drilling plan

–

Increasing northern rig count from 5 rigs currently to 10+ rigs in early 2014 in response to

successful results to date

Building out infrastructure required to support future growth from horizontal

drilling program

Focused on delivering continued strong production growth in 2014

Spraberry

3 vertical frac fleets (~20,000 HP each)

3 horizontal frac fleets (~35,000 HP each)

15 vertical 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

13 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

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,”

“recoverable 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.