Investor Presentation February 2015
Dec 21, 2015
Investor
Presentation
February 2015
Forward-Looking Statements
Except for historical information contained herein, the statements, charts and graphs in this
presentation are forward-looking statements that are made pursuant to the Safe Harbor Provisions
of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the
business prospects of Pioneer are subject to a number of risks and uncertainties that may cause
Pioneer's actual results in future periods to differ materially from the forward-looking statements.
These risks and uncertainties include, among other things, volatility of commodity prices, product
supply and demand, competition, the ability to obtain environmental and other permits and the
timing thereof, other government regulation or action, the ability to obtain approvals from third
parties and negotiate agreements with third parties on mutually acceptable terms, completion of
planned divestitures, litigation, the costs and results of drilling and operations, availability of
equipment, services, resources and personnel required to perform the Company's drilling and
operating activities, access to and availability of transportation, processing, fractionation and
refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its
development activities as scheduled, access to and cost of capital, the financial strength of
counterparties to Pioneer's credit facility and derivative contracts and the purchasers of Pioneer's
oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and
the ability to add proved reserves in the future, the assumptions underlying production forecasts,
quality of technical data, environmental and weather risks, including the possible impacts of
climate change, the risks associated with the ownership and operation of the Company’s industrial
sand mining and oilfield services businesses and acts of war or terrorism. These and other risks are
described in Pioneer's 10-K and 10-Q Reports and other filings with the Securities and Exchange
Commission. In addition, Pioneer may be subject to currently unforeseen risks that may have a
materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements
except as required by law.
Please see the appendix slides included in this presentation for other important information.
2
Spraberry/Wolfcamp Gross
Production By Operator3
(MBOEPD)
Pioneer At A Glance
Top U.S. Fields By Rig Count2
(Pioneer Operated Count in Green – 16 rigs)
1) Reflects Alaska, Barnett Shale and Hugoton production as discontinued operations
Best performing E&P stock in S&P 500
since 2009
Strong hedge positions through 2016
Investment grade
~$24 BCurrent
Enterprise
Value
$1.85 B2015 Planned
CapEx
>11 BBOEProved
Reserves +
Net Resource
Potential
33) December 2014 DrillingInfo data, gross reported oil and wet gas
2) Baker Hughes Rig Count (02/13/15) and PXD Internal; includes horizontal and vertical rigs
201
MBOEPDQ4 2014
Production1
Oil50%
Gas29%
NGL21%
*max rig count in 2014
4
2015 Outlook
In response to the current low oil price environment and reduced margins,
Pioneer is significantly reducing spending and is focusing on optimizing returns,
capital efficiency and production by high-grading drilling activity in the best
areas of the Spraberry/Wolfcamp and Eagle Ford Shale
− Preserves strong cash position and balance sheet until margins improve
Pioneer is reducing horizontal drilling activity in the Spraberry/Wolfcamp and
Eagle Ford Shale to 16 rigs by the end of February (~50% reduction)
− 6 rigs in northern Spraberry/Wolfcamp, 4 rigs in southern Wolfcamp JV and 6 rigs in Eagle
Ford Shale
− Shutting down vertical drilling program in Spraberry/Wolfcamp by the end of February
Infrastructure development projects, including construction of the
Spraberry/Wolfcamp water system and expansion of the Brady sand mine, will
be slowed down
Reduction in drilling activity and infrastructure build-out results in planned
capital expenditures of $1.85 B for 2015
− ~45% reduction from 2014 capital spending for continuing operations
− $1.6 B for drilling and $0.25 B for water infrastructure, vertical integration and facilities
− Capital program funded from operating cash flow of $1.7 B and cash on hand of $1.0 B
5
2015 Outlook (cont.)
Forecasting 2015 annual production growth from continuing operations of 10%+ based on
$1.85 B capital budget and high-graded drilling program
− Growth primarily first-half weighted with Q4 2015 production essentially flat with Q4 2014
− Forecasting oil growth of 20%+
Aggressively improving margins through efficiency gains and cost reductions from service
companies and suppliers
− Already realizing ~10% decrease in drilling costs in 2015 compared to 2014
− Expect costs to decline at least 20% by year-end 2015 compared to 2014
Prepared to add horizontal rigs later in 2015 in response to reduced costs and/or
improved oil price environment
Continuing to pursue divestment of Eagle Ford Shale Midstream business
Cash flow protected by:
− Derivative coverage for forecasted oil production of ~90% for 2015, with most volumes protected by
swaps at $71 per barrel; also have significant portion of 2016 oil production covered by 3-way collars
with attractive downside protection
− Derivative coverage for forecasted gas production of ~90% for 2015, principally with 3-way collars with
attractive downside protection
Strong balance sheet, planned EFS Midstream sale and strong derivatives position
provide Pioneer with the financial flexibility to prudently manage through a protracted
oil price downturn or quickly ramp up drilling activity if margins improve significantly
1.00
2.00
3.00
4.00
5.00
6.00
30.00 40.00 50.00 60.00 70.00 80.00 90.00
NYMEX Oil Price ($/BBL)
NY
MEX G
as
Pri
ce (
$/M
CF)
Sensitivity to Commodity Prices ($ MM)
6
2015E Capital Spending and Cash Flow1
1) Capital spending excludes asset retirement obligations, capitalized interest and G&G G&A
Drilling Capital: $1.6 B
– $1,050 MM northern Spraberry/Wolfcamp (65% of total)
o $735 MM for horizontal drilling program
o $20 MM for vertical drilling program
o $225 MM for infrastructure and land
o $70 MM for gas processing facilities
– $120 MM southern Wolfcamp joint venture area
(net of carry)
o $90 MM for horizontal drilling program
o $30 MM for infrastructure and land
– $390 MM Eagle Ford Shale
o $335 MM for horizontal drilling program
o $55 MM for infrastructure and land
– $40 MM Other Assets
Other Capital (water infrastructure, vertical
integration and facilities): $250 MM
Capital program funded from:
– Operating cash flow of $1.7 B
– Cash on hand ($1.0 B at the end of Q4 2014)
2015E Average Price
$55/BBL oil and $3.00/MCF gas
Capital program of $1.85 B
$5/BBL oil price change = ~$40 MM of cash flow
$0.50/MCF gas price change = ~$10 MM of cash flow
155
166176
186
201
2013 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
7
45% Oil
1) All periods exclude Alaska, Barnett Shale and Hugoton production as discontinued operations 2) FY 2015 production expected to be negatively impacted by ~5 MBOEPD compared to 2014; negative production impact reflects loss of ~4 MBOEPD due to ethane
rejection in Spraberry/Wolfcamp and Eagle Ford Shale and ~1 MBOEPD due to downtime associated with the severe winter weather in January in Spraberry/Wolfcamp (~3 MBOEPD in Q1)
182 MBOEPD
201448% Oil
Forecasting 2015 Production Growth Range of 10%+1
2015E~53% Oil
Prepared to add rigs
if margins improve
200+ MBOEPD2
192-197
Impacted by severe weather in
Q1 and FY ethane rejection2
8
Liquidity Position (12/31/14)
Net debt (net of cash balance of $1,025 MM): $1.6 B
Unsecured credit facility availability: $1.5 B
Net debt-to-book capitalization: 16%
1) Excludes issuance discounts and deferred hedge losses of ~$25 MM
Maturities and Balances1
Unsecured credit facility matures in 2017
Investment grade rated
2016
$600 MM
3.950%
2017
$455 MM
5.875%
2022
$450 MM
6.875%
$1.5 B unsecured credit facility
2018
$485 MM6.650%
$450 MM
7.500%
2020
$250 MM
7.200%
2028
(undrawn as of 12/31/14)
Pioneer’s Q4 2014 Northern Spraberry/Wolfcamp Program
Placed 36 horizontal Wolfcamp Shale
wells on production during Q4
– For each interval, Q4 wells are outperforming the
average of all previously drilled wells in that interval
Placed 4 horizontal Lower Spraberry Shale
wells on production during Q4
– Early production data similar to previously drilled Lower
Spraberry Shale wells
– 80% oil content; average lateral length of ~5,600 feet
Placed 1 Jo Mill Shale well and 2 Middle
Spraberry Shale wells on production in Q4
– Jo Mill Shale well delivered Pioneer’s highest 24-hour
peak IP rate to date for this interval of 914 BOEPD with
81% oil content and lateral length of ~4,850 feet
– 2 Middle Spraberry Shale wells had an average 24-hour
peak IP rate of 417 BOEPD with 76% oil content and an
average lateral length of ~6,000 feet
Q4 Wolfcamp POPs Interval
20 Wolfcamp B
11 Wolfcamp A
5 Wolfcamp D
9
9
3
5
2
5
8
2
2
2
3
Jo Mill
Lower Spraberry
Wolfcamp A
Wolfcamp B
Wolfcamp D
Middle Spraberry
2
Production data continues to support strong
EURs in the northern Spraberry/Wolfcamp area
Pioneer’s Northern Spraberry/Wolfcamp Acreage
-
20
40
60
80
0 30 60 90
Days On Production
-
20
40
60
80
0 30 60 90
Days On Production
-
20
40
60
80
0 30 60 90
Days On Production
Average 24-hour peak IP rate of 36
Q4 Wolfcamp wells:
~1,700 BOEPD with 76% oil content
Horizontal Wolfcamp Production Data: Q4 vs. Historical Wells
10
Wolfcamp A Wolfcamp B
Wolfcamp D
Q4 wells (11)avg. lateral: ~8,700 feet
Q4 wells (20)avg. lateral: ~8,550 feet
Historical wells (33)avg. lateral: ~7,700 feet
Q4 wells (5)avg. lateral: ~9,300 feet
Historical wells (11)avg. lateral: ~7,300 feet
Cum
ula
tive P
roducti
on (
MBO
E)
Historical wells (12)avg. lateral: ~6,950 feet
Cum
ula
tive P
roducti
on (
MBO
E)
Cum
ula
tive P
roducti
on (
MBO
E)
For each interval, Q4 wells outperforming
average of all previously drilled wells in that
interval
Reflects longer average lateral lengths and
improved knowledge of the play
Q4 Wolfcamp A and B wells expected to be
representative of high-graded 2015 drilling
program
Northern Spraberry/Wolfcamp: High-Grading Drilling Activity in 2015
Reducing horizontal rig count to 6 rigs by the end
of February
High-grading drilling activity to areas and intervals
with the highest EURs and net revenue interests
– Focusing on locations where horizontal tank batteries
exist
Expect to place 85 to 90 horizontal wells on
production during 2015 compared to 97
horizontal wells in 2014
– 70% Wolfcamp B wells; remainder split between
Wolfcamp A, Wolfcamp D and Lower Spraberry Shale
wells
– Average D&C cost per well: ~$9 MM assuming average
lateral lengths of ~9,000 feet and an average 10% cost
reduction compared to 2014
– Expected to generate EURs averaging ~900 MBOE with
before-tax IRRs up to 55% at current strip prices
(average oil price of $55 per barrel during 2015)
Shutting down vertical drilling program by the end
of February
Pioneer’s Northern Spraberry/Wolfcamp 2015 Drilling Areas
11
Plan to spud ~60 wells in 2015 utilizing
2-well and 3-well pads
~90% Wolfcamp B; ~10% Wolfcamp A
Southern Wolfcamp JV: High-Grading Drilling Activity in 2015
Reducing horizontal rig count to 4 rigs by
the end of February
High-grading drilling activity to areas and
intervals with the highest EURs and net
revenue interests
– Focusing on locations where horizontal tank batteries
exist
Expect to place 75 to 80 horizontal wells
on production during 2015 compared to
113 horizontal wells in 2014
– 75% Wolfcamp B wells; remainder split between
Wolfcamp A and Wolfcamp D wells
– Average D&C cost per well: ~$8 MM assuming average
lateral lengths of ~9,000 feet and an average 10% cost
reduction compared to 2014
– Expected to generate EURs averaging ~750 MBOE with
before-tax IRRs up to 55% (excludes carry) at current
strip prices (average oil price of $55 per barrel during
2015)
Pioneer’s Southern Wolfcamp JV Area2015 Drilling Areas
Plan to spud ~45 wells in 2015 utilizing
2-well and 3-well pads
>90% Wolfcamp B
12
918
2237
54
2013 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Continuing to Grow Spraberry/Wolfcamp Production
Spraberry/Wolfcamp Net Production (MBOEPD)1
1) Includes horizontal and vertical production from Pioneer’s northern acreage and the southern Wolfcamp joint venture area (60% Pioneer/40% Sinochem) 2) Q1 production negatively impacted by ~3 MBOEPD due to downtime associated with severe winter weather (~1 MBOEPD FY impact)3) Ethane rejection of ~2 MBOEPD expected throughout 2015 due to low ethane prices
69 horizontal wells placed on production in Q4
− 43 in northern acreage and 26 in southern Wolfcamp
joint venture area
− Also placed 30 vertical wells on production
Q4 production: 115 MBOEPD
− Up 12 MBOEPD compared to Q3 as horizontal
production growth (+17 MBOEPD) more than offset
declines in vertical production (-5 MBOEPD)
− Oil production up 10 MBOPD compared to Q3
2015 production outlook
− Expect production to increase by 20%+
o Growth first-half weighted
o Q4 2015 production expected to be flat vs. Q4 2014
− FY 2015 production reduced by ~3 MBOEPD due to
ethane rejection and Q1 severe winter weather
79
Vertical
Horizontal
2014
99 MBOEPD
86
92
103
115
2015E
119+ MBOEPD2,3
Prepared to add rigs
if margins improve
13
Impacted by severe
weather in Q1 and FY
ethane rejection2,3
Field Infrastructure – Tank Batteries & Gas Processing
Tank Batteries / Saltwater Disposal
Slowing pace of construction of new large-scale tank batteries and
saltwater disposal facilities in response to the slowdown in
horizontal drilling
2015 capital program includes ~$215 MM for facilities to support the
high-graded program
Gas Processing
Atlas remains committed to complete a new 200 MMCFPD plant in
Martin County (Buffalo), but has deferred start-up from Q3 2015 to
2016; the additional plant scheduled for 2016 has been deferred
indefinitely
2015 capital program includes ~$70 MM for the Buffalo plant and
gathering system investments for both the Atlas and WTG systems
Brady Sand Mine Expansion
As a result of Pioneer’s reduced proppant requirements due to the
drilling slowdown, expansion of the Brady plant capacity from 750
M tons per year to 2.1 MM tons per year is being deferred until at
least 2016
2015 capital program includes ~$25 MM for maintenance, continued
engineering work and site preparation
DL Hutt Tank Battery
Atlas Edward Gas Processing Plant
Brady Sand Mine
14
Slowing Down Water Project Construction
15
Plans originally called for the initial phase of Pioneer’s
field-wide water transport system to commence in 2015
As a result of the slowdown in Pioneer’s drilling
program, 2015 capital spending is expected to be
$100 MM with activity limited to:
– Construction of feeder line and associated mainline segment
which will move water from an existing third-party Santa
Rosa Aquifer source to Pioneer’s high-graded drilling acreage
in the southern Wolfcamp JV
o Reduces well costs in this area by ~$150 M per well
– Continued engineering and ROW acquisition
Working with the City of Odessa to allow Pioneer to
defer offtake of effluent water
Discussions are continuing with City of Midland to
purchase effluent water when drilling activity increases
Frac Pond
Subsystem
Feeder line
from Midland
Feeder line
from Odessa
Feeder line from 3rd party source (Reagan County)
Main
line
2015
Activity
2015 activity will allow Pioneer to be
prepared for additional construction in
2016 if commodity prices improve
150
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80 7770 70 68 65 63 62
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Eagle Ford Shale WellsAverage 150-Day Cumulative Production (MBOE)
Eagle Ford Shale JV: High-Grading Drilling Activity in 2015
Reducing horizontal rig count to 6 rigs by the
end of February
High-grading drilling activity to areas with the
highest EURs
– Focus will be in Karnes and DeWitt counties where
Pioneer has been drilling the most productive wells
in the Eagle Ford Shale
– Pioneer placed 128 wells on production in 2014
o 78 wells were in Lower targets and 50 wells were in
Upper targets
o Upper targets continue to show similar production to
offset Lower targets
Expect to place 95 to 100 horizontal wells on
production during 2015
– Average D&C cost per well: $7 MM - $8 MM
assuming average lateral lengths of ~5,000 feet and
an average 10% cost reduction compared to 2014
– Expect to generate EURs averaging ~1.3 MMBOE
with before-tax IRRs up to 70% at current strip
prices (average oil price of $55 per barrel during
2015) 16Source: Credit Suisse and HDPI data for wells drilled since July 2013
6 Month Cum Peak BOE> 200,000
150,000 – 200,000
100,000 – 150,000
50,000 – 100,000
< 50,000
JV Acreage
Central Gathering Point
Pipeline Infrastructure
2015 Drilling
Areas
Plan to spud ~85 wells in 2015
utilizing 2-well to 5-well pads
50% Upper / 50% Lower
38
43 47 47 49
2013 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4
Continuing to Grow Eagle Ford Shale Production
Eagle Ford Shale Net Production (MBOEPD)1
1) Reflects Pioneer’s ~35% share of gross production
2) Commenced ethane rejection in January due to low ethane prices; expected to continue through year-end as a result of weak market conditions; impact on
FY 2015 production forecasted to be ~2 MBOEPD
46 MBOEPD
2014
Eagle Ford Shale net production of 49 MBOEPD
in Q4
− Placed 30 liquids-rich wells on production in Q4
− Production impacted by unplanned CGP downtime,
POP timing and greater-than-anticipated shut-in
production due to offset fracs
2015 production outlook
− Expect production to increase by 9%+
o Production relatively flat throughout the year reflecting
timing of POPs
− FY 2015 production reduced by ~2 MBOEPD compared
to 2014 due to ethane rejection2015E
Prepared to add rigs
if margins improve
50+ MBOEPD2
17
Impacted by ethane rejection2
Eagle Ford Shale Condensate Exports
US Department of Commerce confirmed that
condensate processed through a distillation unit
(stabilizer) at PXD’s Eagle Ford Shale central
gathering plants is a petroleum product that may
be exported without a license
Exported ~10 MBOPD gross (~3.5 MBOPD net) of
Eagle Ford Shale condensate during the second
half of 2014 with significantly improved pricing
compared to domestic condensate sales
~20 MBOPD gross (~7 MBOPD net) of condensate
has been committed for export in 2015 under
two contracts with further improved pricing
Processed Eagle Ford Shale condensate has been
sold to Asian and European refining and
petrochemical companies
Distillation Unit
(Stabilizer)
Central Gathering Plant in Karnes County, TX
First Condensate Export Cargo 18
Optimizing Returns in a Lower Oil Price Environment
Cost Reductions Aggressively soliciting cost reductions from suppliers and service companies, including:
– Materials (e.g. casing and tubing, drilling mud, chemicals and guar)
– Freight (e.g. rates and fuel charges)
– Fuel (e.g. rig, fleet and equipment diesel)
– Drilling rig contracts
– Rental equipment (e.g. blowout preventers, coil tubing, etc.)
– Wireline services
Efficiencies Continuing completion optimization testing in the Spraberry/Wolfcamp area for program-wide
implementation
– Increasing clusters per stage
– Optimizing fluid chemistry and proppant concentration
Testing modified 3-string and 2-string casing design in the Upper Wolfcamp B and Wolfcamp A intervals
in southern Wolfcamp joint venture area
– Potential savings of $500 M to $1 MM per well
– Evaluating application on Pioneer’s northern Spraberry/Wolfcamp acreage
Testing dissolvable plug technologies in the Spraberry/Wolfcamp and Eagle Ford Shale areas to reduce
or eliminate coil tubing drill outs after fracture stimulations
– Potential savings of $300 M per well
Already realizing ~10% reduction in drilling costs in 2015 compared to 2014 Expect costs to decline at least 20% by year-end 2015 compared to 2014
19
20
U.S. asset base
High oil exposure from proved reserves + estimated net resource
potential of >11 BBOE
Drilling program focused in core Texas assets
– Spraberry/Wolfcamp Shale
– Eagle Ford Shale
Attractive derivative positions protect cash flow
Strong balance sheet provides financial flexibility to:
– prudently manage through a protracted oil price downturn, or
– quickly ramp up drilling activity if margins improve significantly
PXD Investment Highlights
21
Appendix
Pioneer’s Areas of Operations
22
Eagle Ford Shale
Raton
Northern Spraberry/Wolfcamp
Operating Areas
Southern Wolfcamp JV AreaDallas Headquarters
Current Total Enterprise Value ($B) ~$24
Q4 2014 Production – 50% Oil (MBOEPD) 201
2015E Total Capital Spend, Net ($B) ~$1.85
2015E Cash Flow ($B) ~$1.70
2014 Horizontal Drillbit F&D ($/BOE) $15.51
2014 Reserve Replacement (%) 239%
YE 2014 Proved Reserves (BBOE) 0.8
West Panhandle
Added 177 MMBOE from the drillbit, or 239% of full-
year production, at a drillbit F&D cost of $19.65 per
BOE2
– Reflects significant drilling campaigns in horizontal
Spraberry/Wolfcamp Shale and Eagle Ford Shale
plays
– Drillbit F&D cost for horizontal additions of 157
MMBOE was $15.51 per BOE
Reserve mix
– 100% U.S.
– 44% oil / 21% NGLs / 35% gas
– 81% PD / 19% PUD
Proved Reserves / Production: ~11 years
PD Reserves / Production: ~9 years
23
Pioneer’s Year-End 2014 Proved Reserves1
1) Reflects 2014 SEC pricing (12-month average) of $94.98/BBL for oil and $4.35/MMBTU for gas (NYMEX) as compared to 2013 SEC pricing of $96.82/BBL for oil
and $3.67/MMBTU for gas (NYMEX)2) Excludes PUD reserves removed as a result of vertical Spraberry/Wolfcamp wells no longer expected to be drilled (39 MMBOE), positive price revisions
(12 MMBOE) and reserves added from acquisitions (2 MMBOE)
Year-end 2014 Proved Reserves
(MMBOE)
Spraberry/Wolfcamp 476
Eagle Ford 142
Raton 121
Other 60
Total 799
24
$8.88 $8.45 $8.32 $7.83$8.50
$1.04 $1.68 $1.89$1.66
$1.52
$3.11$3.68 $3.52
$3.35$2.78
$0.55
$0.76 $0.59$0.63 $0.65
Production Costs (per BOE)1
Production & Ad Valorem
Taxes
Workovers
LOE
Third Party Transportation
Natural Gas
Processing
Q3 ’14
$(0.27)
Q4 ’13 Q1 ’14 Q2 ’14
$(0.19)
Q4 2014 production costs
increased slightly compared to
Q3 2014
— LOE increased primarily due to
timing of invoices
— Natural gas processing expense is
primarily related to lower NGL
price realizations on volumes
retained under percentage of
proceeds contracts with third
parties
— Production and ad valorem tax
payments lower due to decline in
commodity prices$(0.42)
$13.39
$14.30
$(0.30)
Q4 ’14
1) All periods presented have been restated to exclude discontinued operations associated with Alaska, Barnett Shale and Hugoton activities
$0.16
$13.90
$13.17 $13.61
25
Pioneer’s Production By Commodity By Area
Q4 '13 Q1 '14 Q2 '14 Q3 '14 Q4 '14Spraberry/Wolfcamp Oil (BOPD) 52,957 58,307 57,893 66,425 76,894
NGL (BOEPD) 16,251 16,693 19,754 21,734 23,956 Gas (MCFD) 65,863 66,770 83,368 86,412 87,630
Total (BOEPD) 80,186 86,128 91,542 102,561 115,455 Eagle Ford Oil (BOPD) 15,922 16,787 17,664 18,038 18,697
NGL (BOEPD) 11,252 12,017 13,803 14,179 14,093 Gas (MCFD) 78,448 82,849 90,537 90,215 94,975
Total (BOEPD) 40,248 42,611 46,556 47,253 48,619 Raton Oil (BOPD) - - - - -
NGL (BOEPD) - - - - - Gas (MCFD) 130,077 126,451 125,079 124,451 121,312
Total (BOEPD) 21,679 21,075 20,847 20,742 20,219 West Panhandle Oil (BOPD) 2,896 3,066 2,955 2,481 2,963
NGL (BOEPD) 3,977 4,370 4,635 3,484 4,083 Gas (MCFD) 13,687 14,122 13,817 13,175 15,632
Total (BOEPD) 9,154 9,790 9,892 8,161 9,651 South Texas Oil (BOPD) 299 380 1,199 1,970 1,943
NGL (BOEPD) 4 7 11 99 282 Gas (MCFD) 28,438 27,597 28,856 27,024 26,283
Total (BOEPD) 5,043 4,987 6,020 6,573 6,605 Other Oil (BOPD) 55 50 69 60 35
NGL (BOEPD) 335 409 369 322 168 Gas (MCFD) 2,994 3,613 3,231 2,433 1,203
Total (BOEPD) 889 1,062 977 788 404 Total Continuing Ops Oil (BOPD) 72,129 78,589 79,780 88,973 100,532
NGL (BOEPD) 31,818 33,497 38,572 39,819 42,582 Gas (MCFD) 319,508 321,403 344,889 343,711 347,035
Total (BOEPD) 157,199 165,653 175,834 186,077 200,953
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:
– Swaps
– Collars with short puts (three-way collars)
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
26
27
Oil Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016
Swaps – WTI (BPD) 82,000 82,000 82,000 82,000 -
NYMEX WTI Price ($/BBL) $71.18 $71.18 $71.18 $71.18 -
Three Way Collars – (BPD)1,2 10,000 15,000 15,000 15,000 73,000
NYMEX Call Price ($/BBL) $94.54 $97.69 $97.69 $97.69 $80.67
NYMEX Put Price ($/BBL) $81.95 $82.97 $82.97 $82.97 $70.70
NYMEX Short Put Price ($/BBL) $67.00 $69.67 $69.67 $69.67 $49.41
% Total Oil Production ~90% ~90% ~90% ~90% N/A3
Open Commodity Derivative Positions as of 2/6/2015
1) When NYMEX price is above call price, Pioneer receives call price. When NYMEX price is between put price and call price, Pioneer receives NYMEX price. When NYMEX price is between the put price and the short put price, Pioneer receives put price. When NYMEX price is below the short put price, Pioneer receives NYMEX price plus the difference between the put price and short put price
2) Counterparties have the option to extend 5,000 BPD of 2015 collar contracts with short puts for an additional year with a call price of $100.08/BBL, a put price of $90.00/BBL and a short put price of $80.00/BBL. The option to extend is exercisable by the counterparties on December 31, 2015
3) Forecasted oil production for 2016 and related coverage level dependent on future market conditions4) Not a derivative5) Transaction volumes tied to production from specific leases; current oil production (net to Pioneer) associated with these leases is >20 MBOPD
Midland-Cushing Fixed Oil Differential Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016
#1 Market Transaction4 35,000 35,000 35,000 35,000 35,000
Price Differential ($/BBL) $(1.75) $(1.75) $(1.75) $(1.75) $(1.75)
#2 Market Transaction4 Based on specific lease production volumes5
Price Differential ($/BBL) $(1.04) $(1.04) $(1.04) $(1.04) $(1.04)
Oil coverage: ~90% in 2015
28
Open Commodity Derivative Positions as of 2/6/2015
1) Represent swap contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices2) Represent swap contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices3) Forecasted NGL and liquid production for 2016 and related coverage level dependent on future market conditions
Ethane Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016
Swaps – (BPD)1 3,278 5,000 5,000 5,000 4,000
Mont Belvieu Swap Price ($/BBL) $7.83 $7.83 $7.83 $7.83 $12.29
Propane Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016
Swaps – (BPD)2 5,572 8,500 8,500 8,500 2,000
Mont Belvieu Swap Price ($/BBL) $21.48 $21.48 $21.48 $21.48 $21.63
% Total NGL Production ~25% ~35% ~35% ~35% N/A3
% Total Liquids ~75% ~75% ~75% ~75% N/A3
29
Gas Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016
Swaps - (MMBTUPD) 20,000 20,000 20,000 20,000 70,000
NYMEX Price ($/MMBTU)1 $4.31 $4.31 $4.31 $4.31 $4.06
Three Way Collars – (MMBTUPD)1,2 285,000 285,000 285,000 285,000 20,000
NYMEX Call Price ($/MMBTU) $5.07 $5.07 $5.07 $5.07 $5.36
NYMEX Put Price ($/MMBTU) $4.00 $4.00 $4.00 $4.00 $4.00
NYMEX Short Put Price ($/MMBTU) $3.00 $3.00 $3.00 $3.00 $3.00
% Total Gas Production ~90% ~90% ~90% ~90% N/A3
Open Commodity Derivative Positions as of 2/6/2015
1) Represents the NYMEX Henry Hub index price or approximate NYMEX price based on historical differentials to the index price at the time the derivative was entered into
2) When NYMEX price is above call price, Pioneer receives call price. When NYMEX price is between put price and call price, Pioneer receives NYMEX price. When NYMEX price is
between the put price and the short put price, Pioneer receives put price. When NYMEX price is below the short put price, Pioneer receives NYMEX price plus the difference
between put price and short put price
3) Forecasted gas production for 2016 and related coverage level dependent on future market conditions
Gas Basis Swaps Q1 2015 Q2 2015 Q3 2015 Q4 2015 2016
Spraberry (MMBTUPD) 10,000 10,000 10,000 10,000 -
Price Differential to NYMEX ($/MMBTU) $(0.13) $(0.13) $(0.13) $(0.13) -
Eagle Ford (MMBTUPD) 20,000 20,000 20,000 20,000 -
Price Differential to NYMEX ($/MMBTU) $(0.00) $(0.00) $(0.00) $(0.00) -
Mid-Continent/Rocky Mountain (MMBTUPD) 95,000 95,000 95,000 95,000 15,000
Price Differential to NYMEX ($/MMBTU) $(0.24) $(0.24) $(0.24) $(0.24) $(0.32)
Gas coverage: ~90% for 2015
$30
$40
$50
$60
$70
$80
$90
$100
$30 $40 $50 $60 $70 $80 $90 $100
Realized P
rice (
$/B
BL)
NYMEX Oil Price ($/BBL)
NYMEX Oil Three-Way Collar Realization
Three-Way Collars ($50 by $70 by $80 Example)
Three way collars protect downside while providing upside exposure30
Short-Put at
$50/BBL
Long-Put at
$70/BBLShort-Call at
$80/BBL
Potential
Gain
Realize NYMEX plus $20/BBL
(difference between long-put
and short-put) Realize $70/BBL
Realize
NYMEX Price
Realize $80/BBL
Potential
Opportunity
Loss
OZONA
PLATFORM
31
Geologic Provinces of the Permian Basin
PEDERNAL UPLIFT &
ROOSEVELT POSITIVE
DEVIL’S
RIVER
UPLIFT
Permian Basin is composed of multiple uplifts and basins that formed during the Pennsylvanian and early Permian ages
Spraberry/Wolfcamp Shale and deeper intervals are located in the Midland Basin of the Permian Basin
Spraberry/Wolfcamp field was discovered in 1943 with production commencing in 1949
Basin
Basement
Uplift
Shelf
Thrust Belt
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
Land
CBP
Midland
Basin
Marathon
Thrust Belt
North
Older
Wolfcamp
Clastics
Wolfcamp Depositional Model – Midland Basin
Midland
Source: Adapted from Handford, 1981 32
Regional Cross Section D-D’
Spraberry
Spraberry
WC B,C1
WC-D
LSSLSS
Strawn
Miss
Woodford
Woodford
WC-D
Horseshoe
Atoll
SouthNorth
WC-AWC-A
WC-Upper B
WC-C
Ozona Platform
Atoka
Jo Mill Shale Jo Mill Shale
Successful Horizontal Wells in the Play
Future Horizontal Play
13 horizontal play intervals identified (so far)
10 intervals have been tested successfully
3 additional intervals remain to be tested
D D’
Big Lake Fault
Calvin Fault
Barnettford
WC-Lower B
Miss
Woodford
Clear Fork
MSSMSS
33
Midland Basin: Stacked Play Potential
“Delta log R” (excess electrical resistance)
Red intervals indicate hydrocarbons
Petrophysical analysis indicates significantly more oil in place
in the Wolfcamp and Spraberry Shale intervals in the Midland
Basin compared to other major U.S. shale oil plays
200 f
tEagle Ford
Condensate
Barnett
ComboMarcellus
Barnett
Miss Lime
Woodford
Wolfcamp D
“Cline”
Wolfcamp A
Wolfcamp B
L. Spraberry
Shale
M. Spraberry
Shale
Clear Fork
Bakken
Jo Mill Shale
Midland Basin
Source: PXD
Dean
Wolfcamp C
U. Spraberry
Atoka
Strawn
Niobrara
34
Spraberry/Wolfcamp Rig Count
Source: Rig count data provided by Baker Hughes, 02/13/15
Vertical Rigs
Horizontal Rigs
Counties: Andrews, Borden, Crockett, Dawson, Ector, Gaines, Glasscock, Howard, Irion, Martin,
Midland, Mitchell, Reagan, Schleicher, Scurry, Sterling, Tom Green and Upton
96% Vertical Rigs
41% Vertical Rigs
(dropped over 100 vertical
rigs since mid-2014)
4% Horizontal Rigs 59% Horizontal Rigs
(peaked at 162 rigs in
late-2014)
35
Production Growth Profiles For 3 Largest U.S. Oil Shale Plays
Eagle Ford
161 Horizontal Rigs
(down from max of 203 rigs in 2014)
Bakken
127 Horizontal Rigs
(down from max of 179 rigs in 2014)
Spraberry/Wolfcamp
115 Horizontal Rigs
(down from max of 162 rigs in 2014)
Spraberry/Wolfcamp initial horizontal growth trajectory similar to Bakken and Eagle Ford
Note: Production data is from IHS and represents incremental production for the play beginning when horizontal drilling activity began in earnest; Rig count data
from Baker Hughes as of 02/13/15; Spraberry/Wolfcamp includes selected counties identified on slide titled “Spraberry/Wolfcamp Rig Count”; Initial month is
November 2010 for Spraberry/Wolfcamp, April 2008 for Eagle Ford and January 2003 for Bakken
Includes Horizontal Wells Only
36
Spraberry/Wolfcamp Production History
From 2009 to 2012, production growth primarily attributable to increased vertical activity
Post 2012, production growth expected to be driven by horizontal activity
Source: IHS Energy monthly data through October 2014 for the Spraberry, Credo East, Garden City South and Lin Fields; 2-stream production data
Includes Vertical and Horizontal Wells
37
Spraberry/Wolfcamp production has
increased ~630,000 BOEPD since 2009
Drilling Results Confirming Pioneer’s Midland Basin Sweet Spot
38
PXD Wolfcamp B Prospectivity Map (Early 2013)
Source: ITG Investment Research
2014 ITG Research Report
Wolfcamp (All Zones) Test Rates
Test R
ate
(BO
EPD
/1000’ la
tera
l)
Tier 1 Tier 2 Pioneer Land
Pioneer Wolfcamp B wells
Wolfcamp B depth contour
Lower
Higher
Source: Internal Pioneer developed in early 2013
GC
Market
Wink
Seaw
ay
Keysto
ne S
outh
Permian
Basin
Cushing
Crude Pipeline Capacity to Gulf Coast
39
Operator Origin Destination Name Capacity Time Frame
Plains Permian Cushing Basin 450,000
Oxy Permian Cushing Centurion 75,000
Sunoco Permian GC West Texas Gulf 400,000
Kinder Morgan Permian El Paso Wink 120,000
Magellan Permian GC Longhorn 250,000
Magellan Permian GC BridgeTex 300,000
Total 1,595,000
Magellan Permian GC Longhorn-add 25,000 2Q 2015
Plains Permian Corpus Cactus 200,000 2Q 2015
Sunoco Permian GC Permian Express II 200,000 3Q 2015
Total 425,000
Operator Origin Destination Name Capacity Time Frame
ENB/Enterprise Cushing GC Seaway 850,000
Transcanada Cushing GC Gulf Coast 830,000
Total 1,680,000
Permian Basin Crude Takeaway Capacity
Cushing to Gulf Coast Pipeline Takeaway
Current
Current
Planned
Spraberry/Wolfcamp Midstream Infrastructure
40
Gas Processing
Atlas System
− PXD has ~27% interest
− Current capacity: 655 MMCFD1
o Includes new Edward plant
online Q3 2014 (+200
MMCFD)
− PXD production makes up ~37%
of throughput
− Buffalo Plant in Martin County
deferred to 2016 (+200 MMCFD)
Sale Ranch (WTG)
− PXD has ~30% interest
− Current capacity: 320 MMCFD2
o Includes new Martin County
Plant online Q1 2015
(+200 MMCFD)
− PXD production makes up ~13%
of Sale Ranch throughput
Pipeline NGL Takeaway
to Mont Belvieu
Chaparral & West Texas
Pipelines
− PXD production throughput of
~13 MBPD
Lone Star Pipeline
− PXD production throughput of
~14 MBPD
− Connect to all PXD gas
processing plants
Mont Belvieu fractionation
capacity at ~1.7 MMBPD
− Capacity additions of
~0.5 - 1.0 MMBPD planned
during 2015 – 2018
Processing and takeaway capacity sufficient to
support Pioneer’s production in the Midland Basin
1) Wet gas stream with ~160 BBL/MMSCF NGL yield
2) Wet gas stream with ~135 BBL/MMSCF NGL yield
Existing NGL Pipeline
Benedum/Edward
Sale Ranch
PXD Acreage
Spraberry Field
Midkiff
Driver
Buffalo
Existing NGL Pipeline
41
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.
"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
discoveries and extensions (excludes purchases of minerals-in-place) and revisions of previous estimates. Revisions
of previous estimates excludes vertical Spraberry/Wolfcamp PUDs removed and price revisions. Consistent with
industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.
“Drillbit reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to
discoveries and extensions (excludes purchases of minerals-in-place) and revisions of previous estimates divided by
annual production of oil, NGLs and gas, on a BOE basis. Revisions of previous estimates excludes vertical
Spraberry/Wolfcamp PUDs removed and price revisions.
42
Certain Reserve Information
Cautionary Note to U.S. Investors --The SEC prohibits oil and gas companies, in their
filings with the SEC, from disclosing estimates of oil or gas resources other than
“reserves,” as that term is defined by the SEC. In this news release, Pioneer includes
estimates of quantities of oil and gas using certain terms, such as “resource potential,”
“net recoverable resource potential,” “estimated ultimate recovery,” “EUR,” “oil-in-
place” or other descriptions of volumes of reserves, which terms include quantities of
oil and gas that may not meet the SEC’s definitions of proved, probable and possible
reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in
filings with the SEC. These estimates are by their nature more speculative than
estimates of proved reserves and accordingly are subject to substantially greater risk
of being recovered by Pioneer. In addition, the SEC permits U.S. companies with mining
operations, in their filings with the SEC, to disclose only “reserves,” which are mineral
deposits that a company can economically and legally extract or produce. The SEC
normally only permits users to report mineralization that does not constitute reserves
as in-place tonnage and grade without reference to unit measures. U.S. investors are
cautioned not to assume that Pioneer’s estimates of resource potential of mineral
deposits reflect economically recoverable quantities. Any inaccuracy in our estimates
related to our mineral reserves and non-reserve mineral deposits could result in lower
than expected sales and higher than expected costs. 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.