8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported):  October 3, 2011

PIONEER NATURAL RESOURCES COMPANY

(Exact name of registrant as specified in its charter)

Delaware	1-13245	75-2702753
(State or other jurisdiction of incorporation)	(Commission File Number)	(I.R.S. Employer Identification No.)
5205 N. O'Connor Blvd., Suite 200, Irving, Texas		75039
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code:  (972) 444-9001

Not applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the Registrant under any of the following provisions:

[  ] Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

[  ] Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

[  ] Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

[  ] Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02. Results of Operations and Financial Condition

Pioneer Natural Resources Company (the “Company”) hereby furnishes the portions, if any, of the presentation included as Exhibit 99.1 to this report (the “Presentation”) that constitute material non-public information regarding the Company’s results of operations or financial condition for a completed quarterly or annual period.

Item 7.01. Regulation FD Disclosure

On October 3, 2011, the Company will post the Presentation on the Company’s website, www.pxd.com. A copy of the Presentation can be reviewed at the website by first selecting “Investors,” then “Investor Presentations.”

Item 9.01. Financial Statements and Exhibits

(d) Exhibits

99.1 -- Investor Presentation —October  2011.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	PIONEER NATURAL RESOURCES COMPANY
	By:	/s/ Frank W. Hall
		Frank W. Hall,
		Vice President and Chief
		Accounting Officer
Dated:  October 3, 2011

EXHIBIT INDEX

PIONEER NATURAL RESOURCES COMPANY

EXHIBIT INDEX

Exhibit No. Description

99.1(a) Investor Presentation — October  2011.

___________

(a) Furnished herewith.

EX-99.1

Investor Presentation

October 2011

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 with third parties on mutually acceptable terms, litigation, the
costs and results of drilling and operations, availability of equipment, services 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, international operations 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

§>20,000 liquids-rich drilling locations in low-risk resource plays

§2011 drilling program focused in the Spraberry and Eagle Ford
Shale

–Funded from cash flow and redeployment of Tunisia sale
proceeds

§Vertical integration substantially improves drilling returns

§Forecasting 18+% compound annual production growth through
2014

§Forecasted production growth generates ~30% compound annual
operating cash flow growth for 2011 - 2014

§Attractive derivative positions protect margins; 75% or greater
coverage for oil and gas through 2012

§Strong financial position

Investment Highlights

4

Targeting 18+% Compound Annual Production Growth For 2011 - 2014

§Forecasting annual production growth of 15+% from 2010 to 2011 and
20+% from 2011 to 2012

§Targeting compound annual production growth of 18+% for 2011 - 2014

§Liquids production increases from ~50% currently to 60% in 2014

109

2)South Africa GTL plant returned to operation and production recommenced as anticipated

3)Reflects Tunisia as discontinued operations

3

125-1312

125 - 130

Expect to be toward
low end of range1

5

2011 Capital Budget by Asset1,2

2011 Capital Budget

$2.1 B

Spraberry

$1.3 B

Barnett

$210 MM

Other

$100 MM

Alaska

$100 MM

Eagle

Ford Shale

$120 MM

Vertical

Integration &

Facilities

$0.3 B

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

2)Eagle Ford Shale midstream development activities are conducted through an unconsolidated affiliate; infrastructure build-out funded from external
debt sources beginning in June 2011

Capital program funded from:

§Operating cash flow of $1.4 B - $1.5 B

§Redeployment of Tunisia sale proceeds

NYMEX Oil Price ($/BBL)

Sensitivity to Commodity Prices ($ MM)

6

2011 Operating Cash Flow

Substantial Operating Cash Flow Growth1

Billions

7

1)Based on early October strip pricing for remainder of 2011 and $100/bbl and $5/mcf thereafter; includes derivative positions as of August 2, 2011

2)Excludes $0.4 B (from reported cash flow of $1.3 B) attributable to deepwater GOM refunds, insurance recoveries and Tunisia operations

$0.92

8

Liquidity Position (06/30/11)1

Net debt (net of cash balance of $352 MM):$2.2 B

Unsecured Senior Credit Facility availability:$1.2 B

Net Debt-to-Book Capitalization:31%

1)Excludes $87 MM of borrowings under PSE’s $300 MM Credit Facility that matures in May 2013

2)Excludes net discounts and deferred hedge losses of ~$86 MM

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

4)Excludes ~$65 MM of outstanding letters of credit on Senior Credit Facility

Maturities and Balances2

Unsecured Senior Credit Facility matures in 2016

No bond maturities until 2013

2011

2012

2016

$250 MM

7.20%

2017

$455 MM

5.875%

2028

$450 MM

6.875%

$0 MM4 of

$1.25 B Unsecured Senior Credit Facility

2018

$485 MM

6.65%

2013

$480 MM3

2.875%

$450 MM

7.50%

2020

PXD - Largest Spraberry Acreage Holder, Driller and Producer

PXD Acreage

(~900,000 Acres;
~75% HBP)

PERMIAN

BASIN

24 MM acres

20,000+ Future Drilling Locations

1) Based on 2010 data from Railroad Commission of Texas

9

Spraberry Field

Deeper Drilling in Spraberry Increasing EURs

10

Dean

Limestone Pay

Sandstone Pay

Non-Organic Shale Non-Pay

Organic Rich Shale Pay

Deeper Drilling Plans

§Strawn: Completing in ~25% of 2011 wells; commingling with upper
intervals immediately

§Atoka: Testing interval in ~10 wells during 2011; will commingle with
upper intervals following ~6 month test

§Mississippian: ~10 wells in 2011; targeting 24 wells to test play

	Wells Completed	Incremental Cost	Single-Zone Peak Rate	Potential Incremental EUR	Prospective PXD Acreage
Strawn	85	$60 M	70 BOEPD	20 - 40 MBOE	40%
Atoka	2	$250 M - $750 M	150 BOEPD	50 - 70 MBOE	25% - 50%
Mississippian	1	$150 M - $250 M	105 BOEPD	15 - 30 MBOE	10% - 20%

Potential to add up to 110 MBOE to EUR from deeper drilling

Current Spraberry 40-acre type curve EUR including Lower Wolfcamp: 140 MBOE

Zones Below Lower Wolfcamp

20-Acre And Waterflood Update

11

20-Acre Drilling (~13,000 locations)

§Drilled 24 wells since 2010; all on production

§Capturing pay from Lower Wolfcamp, Strawn and
shale/silt intervals

§Early results indicate production outperforming previous
110 MBOE type curve for a 40-acre Spraberry/Dean well

§Plan to drill 10 - 20 additional wells in 2011

Waterflood Project

§Full-scale project underway over 7,000 acres

—Commenced Upper Spraberry water injection Q3 2010

—12 injectors and 110 producers

—Injecting 4,100 BWPD

—$6 - $7 MM capital cost

—LOE savings from water handling

§Early results encouraging

–Production decline of project area continues to flatten

–Early production response observed in several wells

–No premature water breakthrough

§Ultimate uptick in production expected to be at least
50% from flooded zone (Upper Spraberry)

Waterflood Facilities

Spraberry Drilling Rig

Spraberry Horizontal R&D Program

12

Dean

Lower

Spraberry
Shale

Upper
Wolfcamp

Wolfcamp
Shale

Lower
Wolfcamp

Strawn

Middle
Wolfcamp

Tippett Shale

Leonard Shale

Jo Mill

§Planning to continue 1-rig horizontal R&D program to test
multiple formations in the Spraberry field

–Expect to drill additional 4-5 wells in Wolfcamp Shale
zones by year end

§Testing first Tippett Shale horizontal

—~6,000 foot lateral with 30-stage completion

§Encouraging results in nearby competitor wells with
longer laterals in the Tippett Shale

PXD Horizontal Targets

IRION

CROCKETT

STERLING

13

Vertical Integration and Attractive Service Contracts Contribute To Strong Spraberry Returns

§Vertical Integration (Company-owned services)

–Rigs, frac fleets, pulling units and other well services

§Sand supply in place through 2015

§Contracted tubulars and pumping units through 2012

§Contractedcementing services through 2016

§2011 blended Pioneer and third-party well cost of $1.5
- $1.6 MM

§~45% IRR before tax1

—Excludes benefit of Strawn, Atoka and Mississippian

1) Commodity prices of $100/bbl and $5/mcf

Rigs 30 35 Increasing to 45 by Year End

Spraberry - Bringing Wells On Production As Expected

14

2011 Spraberry Wells Put On Production Per Quarter

1) Includes 3 Company-owned and 1 dedicated third-party

2) Includes 4 Company-owned and 2 dedicated third-party

3) Includes 5 Company-owned and 2 dedicated third-party

§Increased frac fleets
from 4 to 6in May2

§146 wells put on
production as expected

Adding 7th
frac fleet in
Q43

4 frac
fleets1

Continuing to Accelerate Spraberry Development

15

Spraberry Net Production1
(MBOEPD)

54 - 59

68 - 74

1) Includes expiration of VPP commitments (3 MBOEPD @ YE 2010 and 4 MBOEPD @ YE 2012)

Rigs 30 @ YE 35 @ mid year 45 45 45

45 - 47

Oil transport truck shortfall
reduced production by ~2
MBOEPD

2011E

(43 - 46 MBOEPD Avg.)

77 - 84

Adding incremental oil
transportation capacity in
Q3

Eagle Ford Shale: A Burgeoning Liquids-Rich Shale Play

16

§Gross resource potential of play: ~25 BBOE(~150
TCFE)1

§Estimated Gross Production of ~3.5 MMBOEPD by 20202

§~180 rigs currently running in the play

Oil Window

Map source: PXD

1)Source: Tudor, Pickering, Holt & Co.

2)Source: FBR

PXD Acreage Area

Eagle Ford Shale Operational Update

§Running 12 rigs

—Current gross well cost: $7 MM - $8 MM

—Before tax IRRs1: 100+% for rich condensate and ~75% for lean
condensate (excludes carry benefit)

§Average lateral length ~5,500 feet

§New and existing well performance continues as
expected

§Testing white sand proppant in shallower areas

—17 wells stimulated using white sand; early well performance
similar to direct offset ceramic-stimulated wells

—Reduces frac cost by ~$700 M

§7 CGPs completed; 8th CGP in Q4

1) Commodity prices of $100/bbl and $5/mcf

Rigs 8 10 12 12

Eagle Ford Shale - Bringing Wells On Production As Expected

18

2011 Eagle Ford Shale Wells Put On Production Per Quarter

1) Includes 1 Company-owned and 1 dedicated third-party

2) Includes 2 Company-owned and 1 dedicated third-party

§Initiated 2 frac fleetsin April1

§18 wells put on
production as
expected

§Adding 3rd frac
fleet2

§8th CGP online

6th and 7th CGPs
online

Ramping Up Eagle Ford Shale Development

19

Eagle Ford Net Production
(MBOEPD)

26 - 30

40 - 45

5

Rigs 7 @ YE 12 currently 14 16 19

14 - 17

2011E

(12 - 15 MBOEPD Avg.)

54 - 60

Barnett Shale Combo

§Current acreage: ~72 M net acres

—>600 drilling locations

—Continuing to grow leasehold position

§Acquired ~160 square miles of 3-D
seismic

—Permitting additional ~190 square miles

§2 rigs currently drilling

—14 wells put on production in Q2

•Average 7-day IP ~350 BOEPD1

—Lateral length: 3,500 ft - 6,000 ft

—Well cost: ~$3 MM

—Gross EUR: ~320 MBOE

—~45% IRR before tax2

§Commenced operating Company-
owned frac fleet in Q2

§Planning to be at 4 rigs in 2012

Barnett Shale Liquids-Rich Area

(42% gas, 42% NGLs, 16% oil)

1) Wet gas stream estimated

2) Commodity prices of $100/bbl and $5/mcf

20

Combo Play Activity 2008-Present

Ramping Up Barnett Shale Combo Development

21

Barnett Shale Net Production1
(MBOEPD)

9 - 12

18 - 22

Rigs 1 @ year end 2 4 4 4

2

2011E

(4 - 5 MBOEPD Avg.)

3

Initiated first
Company-
owned frac
fleet

1) 2010 production reflects legacy Barnett Shale gas production; production growth in 2011 - 2014 driven by Barnett Shale Combo development

4 - 6

26 - 31

22

Pioneer’s Vertical Integration Improves Returns and Enhances Execution

Eagle Ford Shale

1 frac fleet

(adding 2nd fleet Q4)

1 coiled tubing unit

(adding 2nd unit Q4)

Spraberry

4 frac fleets

(adding 5th fleet Q4)

14 drilling rigs

Other service equipment1

Year-End 2011

Total Vertical Integration Investment:$440 MM2

Total Frac Horsepower:225 M

1)Includes pulling units, frac tanks, hot oilers, water trucks, blowout preventers, construction equipment and fishing tools

2)Includes spending in 2011 for additional frac fleets to be delivered mid-2012

Barnett Shale Combo

1 frac fleet

1 coiled tubing unit

SpraberryEagle Ford ShaleBarnett Shale
Combo

Frac Fleets

Current411

By Year-End 2011521

Fracs/Fleet/Year~115~55~60

Savings Per Frac1$0.35 MM$1.70 MM$0.75 MM

Annual Savings2,3$200 MM$185 MM$45 MM

Rigs and Other Services4

Annual Savings1$30 MM--

Total Annualized Cash Savings

At Year-End 2011 Run Rate$230 MM$185 MM$45 MM

Vertical Integration Significantly Reduces Well Costs

23

1)Generally reflects current savings vs. longer term contract rates

2)Excludes savings from frac fleets scheduled for delivery in mid-2012

3)Includes direct savings to PXD and charges to third-parties

4)Includes 14 rigs and other service equipment including pulling units, frac tanks, hot oilers, water trucks, blowout preventers, construction equipment and fishing tools

Total PXD Annualized Year-End 2011 Cash Savings: $460 MM

24

Why Invest In PXD?

Significant Upside Potential From:

§Oil exposure with large drilling inventory

§Aggressive Spraberry & Eagle Ford Shale drilling program

§18+% compound annual production growth for 2011 - 2014

§30+% compound annual operating cash flow growth for 2011 - 2014

§Strong returns from vertical integration

§Margin protection from attractive derivatives

§Strong balance sheet

Appendix

Pioneer Operations

North Slope

South Africa

Eagle Ford Shale

West Panhandle

Raton

Hugoton

Spraberry

Barnett

2011 Operating Areas

Total Enterprise Value ($B) $12

2011 Capital Budget ($B)$2.1

YE 2010 Proved Reserves (BBOE)~1

YE 2010 Proved + Resource (BBOE)~3

1H 2011 Production - 48% Liquids/52% Gas (MBOEPD)115

Note: 2010 metrics include Tunisia assets sold Q1 2011; operating cash flow includes $0.4 B attributable to deepwater GOM refunds, insurance recoveries and Tunisia operations.

27

Production (MBOEPD)1

	Q2 ’10	Q3 ’10	Q4 ’10	Q1 ’11	Q2 ’11
Spraberry	32	35	38	40	41
Raton	28	28	28	27	27
Eagle Ford Shale	2	1	2	5	8
South Texas	8	9	9	8	8
Mid-Continent	21	21	20	182	212
Barnett	3	2	2	2	3
Alaska	7	7	6	5	5
Other U.S.	1	1	1	2	1
Total N. America	102	104	106	107	114
S. Africa	6	6	5	4	5
Total	108	110	111	111	119

1)All periods presented have been restated to exclude discontinued operations

2)~1 MBPD of NGLs inventoried in Q1 due to third-party fractionator downtime and sold in Q2

28

Production (MBOEPD)1

1)All periods presented have been restated to exclude discontinued operations

29

Production Costs (per BOE)1

Production &
Ad Valorem Taxes

VPP-Adjusted3

Workovers

LOE

Third Party
Transportation

Q2 ’10

Production Cost

Q4 ’10

Q3 ’10

$12.88

Q2 ’11 vs. Q1 ’11 Comparison

§Q2 natural gas processing benefited
from increased third-party
throughput volumes, higher NGL
price realizations on third-party
volumes and lower gathering system
operating costs

Natural Gas
Processing

Q1 ’11

$11.44

1)All periods presented have been restated to exclude discontinued operations

2)Q4 LOE benefited from a non-recurring $10 MM Alaska processing fee recovery (~$1.00/BOE benefit in LOE)

3)See supplemental information slides

$12.48

$0.31

Q2 ’11

$0.39

$10.33

$12.17

($0.13)

$12.43

$13.27

$0.39

($0.25)

$10.94

$13.31

$12.82

30

VPP - Adjusted Production Costs1

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:

Q2 ’10Q3 ’10Q4 ’10Q1 ’11Q2 ’11

Production costs as reported (thousands)$ 119,352$ 133,757$ 112,014$ 133,228$ 138,319

Production (MBOE):

As reported9,81310,09110,22510,00910,791

VPP deliveries624627622338341

VPP-adjusted production10,43710,71810,84710,34711,132

Production costs per BOE:

As reported$ 12.17$ 13.27$ 10.94$ 13.31$ 12.82

VPP-adjusted$ 11.44$ 12.48$ 10.33$ 12.88$ 12.43

1) All periods presented have been restated to exclude discontinued operations

Source: Credit Suisse

2010 Cash Costs ($ / BOE)1

1)Includes production costs, production taxes, G&A (excluding capitalized G&A for full-cost companies), and interest expense

2)Includes Tunisia production volumes and costs

3)Credit Suisse gas-focused companies include APC, CHK, CRK, CRZO, DVN, EOG, EQT, FST, GMXR, HK, KOG, KWK, NFX, PETD, PVA, ROSE, RRC, SD & UPL

4)Credit Suisse oil-focused companies include APA, BEXP, BRY, DNR, MUR, NBL, OXY, PXD, PXP, REXX, SFY, VQ & WLL

$18.00

G&A

Interest

$18.60

Prod Costs

$22.77

2

3

4

PXD Cash Costs Competitive vs. Peers For 2010

31

§Year-end 2010 proved reserves of 1,011 MMBOE2

§2010 drillbit F&D of $9.96/BOE excluding price revisions

§2010 all-in F&D of $7.30/BOE including price revisions

32

2010 Reserves1 and F&D

	SEC Year-end ’10 Proved Reserves (MMBOE)
Spraberry	549
Raton	209
Mid-Continent	106
South Texas	44
Alaska	25
Eagle Ford	24
Barnett Shale	21
Tunisia	24
Other	9
Total	1,0112

1)Reflects 2010 SEC pricing (12-month average) of $79.28/BBL for oil and $4.37/MMBTU for gas (NYMEX) as compared to 2009 SEC pricing of
$61.14/BBL for oil and $3.87/MMBTU for gas (NYMEX)

2)56% liquids / 44% gas; 57% PD / 43% PUD

33

Oil	Q3 2011	Q4 2011	2012	2013	2014	2015
Swaps - WTI (BPD)	750	750	3,000	3,000	-	-
NYMEX WTI Price ($/BBL)	$ 77.25	$ 77.25	$ 79.32	$ 81.02	-	-
Collars - (BPD)	2,000	2,000	2,000	-	-	-
NYMEX Call Price ($/BBL)	$ 170.00	$ 170.00	$ 127.00	-	-	-
NYMEX Put Price ($/BBL)	$ 115.00	$ 115.00	$ 90.00	-	-	-
Three Way Collars - (BPD)1	32,000	32,000	36,000	31,250	22,000	-
NYMEX Call Price ($/BBL)	$ 99.33	$ 99.33	$ 117.99	$ 120.62	$129.76	-
NYMEX Put Price ($/BBL)	$ 73.75	$ 73.75	$ 80.42	$ 83.32	$88.86	-
NYMEX Short Put Price ($/BBL)	$ 59.31	$ 59.31	$ 65.00	$ 65.76	$70.23	-
% Total Oil Production	~85%	~80%	~75%	~50%	~25%	-
Natural Gas Liquids	Q3 2011	Q4 2011	2012	2013	2014	2015
Swaps - (BPD)	1,150	1,150	750	-	-	-
Blended Index Price ($/BBL)2	$ 51.50	$ 51.50	$ 35.03	-	-	-
Collars - (BPD)	2,650	2,650	-	-	-	-
NYMEX Call Price ($/BBL)	$ 64.23	$ 64.23	-	-	-	-
NYMEX Put Price ($/BBL)	$ 53.29	$ 53.29	-	-	-	-
% Total NGL Production	~15%	~15%	<5%	-	-	-
% Total Liquids	~60%	~55%	~50%	~30%	~15%	-

PXD Open Commodity Derivative Positions as of 8/2/2011 (includes PSE)

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

2) Represents weighted average index price of each NGL component price per barrel

34

Gas	Q3 2011	Q4 2011	2012	2013	2014	2015
Swaps - (MMBTUPD)	117,500	117,500	105,000	67,500	50,000	-
NYMEX Price ($/MMBTU)1	$ 6.13	$ 6.13	$ 5.82	$ 6.11	$6.05	-
Collars - (MMBTUPD)	-	-	65,000	150,000	140,000	50,000
NYMEX Call Price ($/MMBTU)1	-	-	$ 6.60	$ 6.25	$ 6.44	$ 7.92
NYMEX Put Price ($/MMBTU)1	-	-	$ 5.00	$ 5.00	$ 5.00	$ 5.00
Three Way Collars - (MMBTUPD)1,2	200,000	200,000	190,000	45,000	50,000	-
NYMEX Call Price ($/MMBTU)	$ 8.55	$ 8.55	$ 7.96	$ 7.49	$ 8.08	-
NYMEX Put Price ($/MMBTU)	$ 6.32	$ 6.32	$ 6.12	$ 6.00	$ 6.00	-
NYMEX Short Put Price ($/MMBTU)	$ 4.88	$ 4.88	$ 4.55	$ 4.50	$4.50	-
% U.S. Gas Production	~90%	~85%	~80%	~50%	~40%	~5%

PXD Open Commodity Derivative Positions as of 8/2/2011 (includes PSE)

1) 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

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	Q3 2011	Q4 2011	2012	2013	2014	2015
Spraberry (MMBTUPD)	20,000	20,000	32,500	2,500	-	-
Price Differential ($/MMBTU)	(0.30)	(0.30)	$ (0.38)	$ (0.31)	-	-
Mid-Continent (MMBTUPD)	100,000	100,000	40,000	10,000	-	-
Price Differential ($/MMBTU)	$ (0.71)	$ (0.71)	$ (0.58)	$ (0.71)	-	-
Gulf Coast (MMBTUPD)	23,500	23,500	53,500	40,000	20,000	-
Price Differential ($/MMBTU)	$ (0.16)	$ (0.16)	$ (0.15)	$ (0.13)	$ (0.14)	-

35

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 Short 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

Oil	Q3 2011	Q4 2011	2012	2013	2014
Swaps (BPD)	750	750	3,000	3,000	-
NYMEX Price ($/BBL)	$77.25	$77.25	$79.32	$81.02	-
Collars (BPD) NYMEX Call Price ($/BBL)	2,000 $170.00	2,000 $170.00	- -	- -	- -
NYMEX Put Price ($/BBL)	$115.00	$115.00	-	-	-
Three-Way Collars (BPD)1	1,000	1,000	1,000	1,000	2,000
NYMEX Call Price ($/BBL)	$99.60	$99.60	$103.50	$111.50	$133.00
NYMEX Put Price ($/BBL)	$70.00	$70.00	$80.00	$83.00	$90.00
NYMEX Short Put Price ($/BBL)	$55.00	$55.00	$65.00	$68.00	$75.00
% Oil Production	~90%	~90%	~90%	~85%	~40%
Natural Gas Liquids
Swaps (BPD)	750	750	750	-	-
Blended Index Price ($/BBL)2	$34.65	$34.65	$35.03	-	-
% NGLs Production	~50%	~50%	~50%	-	-
Gas
Swaps (MMBTUPD)	2,500	2,500	5,000	2,500	-
NYMEX Price ($/MMBTU)3	$6.65	$6.65	$6.43	$6.89	-
% Gas Production	~40%	~40%	~80%	~40%	-
% Total Production	~70%	~70%	~80%	~60%	~25%

PSE Derivative Position as of 8/2/2011

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

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

Three way collars protect downside while providing better
upside exposure than traditional collars or swaps

36

37

Future Amortization of Deferred Gains - Discontinued Commodity Hedges1

1) Deferred gains will increase oil revenues for the periods shown.Excludes deferred hedge losses associated with derivatives terminated in
conjunction with the VPPs

OilGas NGL

Total (Cash / Noncash)Total (Cash / Noncash)Total (Cash / Noncash)

3rd Qtr 20119 [9 / -]- -

4th Qtr 20119 [9 / -]- -

($ Millions)

38

VPP Expirations

VPP Oil
Obligation

4

MBOEPD

4

By the end of 2012, the entire VPP commitment will expire and provide
a 4 MBOEPD increase in production with no capital requirement

(MMBBLS)Q1 Q2 Q3 Q4Total

20110.30.30.40.41.4

20120.30.30.30.31.2

Schedule of Oil VPP Volumes

140 MBOE Spraberry 40-Acre Type Curve

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

40

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

~

~

~

41

Alaska - Oooguruk

§1-rig drilling program continues
targeting Kuparuk and Nuiqsut
intervals

§Second rig to test Torok zone and a
deeper Ivishak zone (main
producing zone in Prudhoe Bay)
during upcoming winter drilling
season

Torok
Wells

Island Drill
Site

Initial
Development
Area

PXD Acreage

Torok
Area

Torok
Onshore Drill
Site

Ivishak Drill Site

Ivishak Area

Oil/Gas Ratio Trending Up Since 2006

42

Oil Price

Gas Price

Oil/Gas Ratio

Oil/Gas ratio has increased from
5:1 in 2006 to >20:1 recently

43

F&D Costs and Reserve Replacement

"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.

44

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 potential,” “resource,” “EUR” 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.