Citi_E&P Valuation Primer

Table of Contents

Additional Resources

6.

Glossary

5.

E&P Ratio Analysis

4.

Understanding the Upstream P&L

3.

E&P Valuation

2.

Introduction

What are Hydrocarbons?

Fossil Fuels Crude Oil Petroleum Coal NGL Natural Gas Sour Wet Dry/Sweet Oil Sands Heavy Oil Conventional Oil Condensate NGL APL Range 20-40° APL Range > 40° APL Range < 18°

Rock Methane (CH4) Ethane (C2H4)

Propane (C3H8) Buthane (C4H10) Contains Hydrogen Sulfide (H10) 1



Fuels made from one barrel of crude (42 Gallons)

–

Gasoline

–

Diesel

–

Jet Fuel

–

Other



Other products made from oil

–

Ink

–

Plastics

–

Dishwashing liquids

–

Deodorant

–

DVDs

–

Tires

Common Uses for Hydrocarbons



Also used to produce

–

Glass

–

Paper

–

Brick

–

Paints

–

Fertilizer

–

Plastics

–

Antifreeze

–

Explosives

Hydrocarbons: Organic compounds of hydrogen and carbon atoms providing the basis of all petroleum

products. Hydrocarbons exist in a solid, liquid, or gaseous state.

Crude Oil = Primary Transportation Fuel

Natural Gas = Electricity Generation

Spindletop, TX, 1901: The Birth of Modern Energy

http://www.priweb.org/ed/pgws/history/spindletop/spindletop.html

Energy Value Chain

Exploration

Production

Production

Processing

Transportation

Refining

Transportation

Marketing

Marketing

Midstream

Downstream

Upstream

Crude Oil Natural Gas

Illustrative Well Production Profile

0

1,000

2,000

3,000

4,000

5,000

2

52

102

152

202

252

302

Months

D

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ily

P

ro

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ti

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(M

M

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fe

/

d

)

Initial Drilling & Completion (D&C) Cost: $5.00 million

Initial Production Rate (IP): 4.5 MMcfe/d Estimated Ultimate Recovery (EUR): 6.5 Bcfe PV-0: $10.3 million

PV-10: $3.7 million

Internal Rate of Return: 57%

Net Finding & Development Cost (F&D): $0.96 / Mcfe

An E&P company owns declining assets that generate attractive cash-on-cash returns. Effective

redeployment of that cash is the key to generating return for shareholders.

Oil and Gas Reserve Classification

Oil and Gas

Reserves Developed (PD) Unproved Proved (1P) Undeveloped (PUD) Probable Possible Producing (PDP) Non-Producing (PDNP) Shut-In (PDSI) Behind-Pipe (PDBP)

Four Classes of Reserves

 Proved, probable, possible and potential

 Main difference between classifications involves level of certainty

that such reserves will be produced as well as costs involved to develop them

 Proved reserves is only class where one definition has developed

general acceptance among petroleum engineers

$0 $30 $60 $90 $120 $150 11/01/01 07/02/03 03/02/05 11/01/06 07/01/08 03/02/10 11/01/11 0.0x 5.0x 10.0x 15.0x 20.0x 25.0x

WTI 1-Yr FWD HH 1-Yr FW D Oil / Gas R atio

Commodity Prices Over Time

7 O il P ri c e ($ / B b l) O il / G a s R a ti o G a s P ri c e ($ / M c fe )

Historical relationships between oil and gas prices changed beginning in 2008 due to the emergence of

shale gas.

Gas to Oil Energy Equivalent Conversion

Conversion

 6 Mcf of gas = 1 Boe: Usual ratio adopted to convert gas to oil and vice versa

 Because of differences in heating value and liquids content of gas, there is no one right oil/gas conversion ratio

 However, using 1,000 BTU per Mcf convention, ratio most often used for dry gas is 6,000 cf per barrel of oil equivalent or 6 Mcf/Boe

Table of Gas / Oil Conversions

= = = = 6 TCF 1 TCF 6 BCF 1 BCF Gas Volume 1.0 MBoe 166.7 Boe 1.0 Boe 0.1667 Boe Oil Equivalent = = = = 6 MMcf 1 MMcf 6 Mcf 1 Mcf Gas Volume 1 BBoe 166.7 MMBoe 1 MMBoe 166,667 Boe Oil Equivalent

 10 MCF = 1 Boe Convention: Occasionally, companies will convert their gas to oil equivalent using a ratio other than a 6:1 ratio

– Historically, 10:1 has been used to better reflect the economic equivalence of gas to oil (i.e. gas less valuable)

– 6:1 reflects strict calorific equivalence

Proved Reserves Disclosure

Illustrative Valuation Exercise

($ in millions, except per-unit amounts)

Share Price

$81.09

Shares

116.800

% of 52-Week High

76%

% of 52-Week Low

146

Equity V alue

$9,471

Plus: Debt

2,563

Less: Cash

(521)

Other A djustments

109.4

Firm V alue

$11,623

Operating Metrics

Proved Reserves (MMBoe)

987

PV -10

$4,894

V aluation Metrics

($ / Boe)

$11.77

SEC PV-10 Disclosure

Valuation Overview

Firm Value

Future Development

Opportunities Value

Wide Range of Valuation Methodologies

M

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F

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NAV / DCF Financial Multiples $ / Boe of Reserves $ / Net Acre FV / EBITDA

Method Typical Market Focus Suitability

 E&P sector focus

 Core value to defined field and risked exploration / prospect upside

 Reserve report may provide material guidance

 Widely understood and used in traditional industries with high earnings

visibility

 Used a cross – check to NAV

 Not for E&P companies

 Used instead of PE due to accounting differences between companies

 Scoping value methodology

 Often used on risked basis for upside value

 Comparability dependent on reserves classification

 Can be used with precedent transactions to value emerging plays

 Should be calculated net of any associated production value

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P / E P / CFPS

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14

Valuation Methodologies

NAV / DCF analysis incorporates operating characteristics of upstream assets, and is the most commonly used valuation methodology; multiple-based valuation provides market-based reference points.

▼ Applicability limited to M&A transactions due to inclusion of acquisition premium

▼ Does not factor in specific operating or risk characteristics of the asset

▲ Good proxy in M&A transactions; factors acquisition premium

Precedent

▼ Not applicable in M&A transactions; does not factor in acquisition premium

▼ Does not factor in specific operating or risk characteristics of the asset

▼ Comparables universe difficult to determine

▲ Reflects asset value as an ongoing operation

▲ Proxy for value based on industry average

Trading Comparables

▼ Requires considerable data gathering, e.g. host government, geophysicists, petroleum

engineers, tax advisors, etc

▼ Estimation of expected production profile and revenues involves a certain degree of

uncertainty and risk

▲ Allows incorporation of operating characteristics of the asset, based on granular and detailed analysis

▲ Factors any associated risks into the value of the asset

▲ Enables sensitivity analysis based on specific parameters

NAV / DCF

NAV Methodology: Assumptions

 Citi evaluated the net asset value (NAV) of Ultra Petroleum’s oil and gas assets in the Marcellus Shale and the Pinedale and Jonah Fields in Wyoming

– Well economics drilled in Jonah assumed to be the same as Pinedale wells

 The calculated NAV of each asset is based on the assumption shown to the right

– NAV calculated based on a development plan built up from a projected rig count, current acreage, and applying an assumed type curve and well-level assumptions

 Current PDP based on historical drilling to more accurately capture PDP decline curve versus a linear decline

 Resource potential based on public guidance

 Capex assumption based on public guidance

 NAV to be modeled in real terms (no inflation)

 Further adjustments to account for the hedge program, the decrease in value attributable to G&A needs of a going concern, non-drilling capex, and income taxes

 Base case price assumption based on 4/15/11 NYMEX strip for 2011-15, held constant in 2016 and beyond

Methodology

Assumptions

(1) Weighted average of North and South assuming ~65% North composition. (2) Includes $0.25/mcfe of gathering expense.

(3) REX transportation cost reflected at the corporate level. (4) Based on company disclosed net wells / gross wells.

(5) Pinedale wells based on company disclosed total gross wells as of 12/31/09 less wells brought online in 2010. Marcellus gross well locations based on 3,000 net locations and a 45% working interest.

3/7/11 Investor Presentation and peer decline rates --HPDI --Type Curve UPL 4Q10 Transcript Net Wells / Working Interest UPL 3Q10 Transcript Company 10K UPL 3Q10 Transcript 11/4/10 UBS Research 1/12/11 Investor Presentation 3/7/11 Investor Presentation UPL 3Q10 Transcript UPL 3Q10 Transcript Peer assumption 3/7/11 Investor Presentation --3/7/11 Investor Presentation Source 1/12/11 Investor Presentation 1/12/11 Investor Presentation 5-10 acres; UPL 4Q10 Transcript Company 10K 3/7/11 Investor Presentation UPL 2008 Reserve Report 1/12/11 Investor Presentation 3/7/11 Investor Presentation UPL 3Q10 Transcript UPL 3Q10 Transcript UPL 3Q10 Transcript 3/7/11 Investor Presentation UPL 2008 Reserve Report HPDI Source 3,000 2,964

Net Remaining Well Locations

6,667 5,335

Gross Well Locations(5)

260,000 44,000

Undeveloped Net Acreage

80 10 86% 45.0% $4.8(1) Included in LOE and Capex

$0.24 5% 102% --4.2(1) Marcellus $0.29(3) Gathering and Transportation

Cost ($ / Mcfe)

17 Spud to Spud (days)

Pinedale / Jonah

EUR (Bcfe) 4.8

Oil Differential to WTI ($) ($14.50) Gas Differential to HH (%) 92% Production Taxes (% of Rev) 12%

LOE ($ / Mcfe)(2) _$0.46

Gross Well Cost ($mm) $4.6

Working Interest (%) 55.5%(4)

NRI (8 / 8ths) 80%

Well Spacing (Acres) 7

2011 2012 2013 2014 2015 >2016

Oil $110.77 $109.41 $105.81 $103.53 $102.46 $102.46

Gas 4.44 4.93 5.31 5.65 6.03 6.03

Pinedale 52% Marcellus 48% Total = 22,381 Pinedale 45% Marcellus 55%

Development Plan by Play

Annual Production Profile by Play (Bcfe)

NAV Methodology: Development Profile

Total Net Drilling Locations (Targeted Development)

Future Resource Potential (Targeted Development) 200 400 600 800 1,000 1,200 1,400 1,600 PDP Pinedale Marcellus N e t P ro d u c ti o n (M M c fe /d ) (1) Total = 6,007 (2) (2) Total (Bcfe) 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 >2020 Total Ne t We lls Drille d Pinedale 119 119 119 119 119 119 119 119 119 119 1,814 3,006 Marcellus 82 82 82 82 82 82 82 82 82 82 2,178 3,000

Total Net Wells 201 201 201 201 201 201 201 201 201 201 3,992 6,007

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 >2020 Total

Ne t Production by Are a (Bcfe )

PDP 163 100 75 69 63 60 57 55 53 51 999 1,744

Pinedale 54 119 161 193 219 242 261 279 295 310 9,412 11,545

Marcellus 33 71 94 112 127 140 151 161 171 180 9,597 10,837

Total Net Prod. 250 290 329 373 409 441 470 495 518 541 20,008 24,125

UPL Guidance 250 290 330 -- -- -- -- -- -- -- --

--(2)

NAV Methodology: Financial Summary

($ in millions) 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Net Production (MMcfe)

Oil (MBbl) 1,570 1,608 1,746 1,969 2,155 2,328 2,486 2,629 2,762 2,888 3,008 Gas (MMcf) 240,957 280,426 318,939 361,673 396,318 427,258 454,622 479,174 501,837 523,302 543,232 Total Net Production (MMcfe) 250,376 290,077 329,413 373,489 409,250 441,227 469,537 494,948 518,407 540,633 561,281

Company Guidance 250,000 290,000 330,000

Daily Production (MMcfe/d) 686 795 903 1,023 1,121 1,209 1,286 1,356 1,420 1,481 1,538 % Growth 17.2% 15.9% 13.6% 13.4% 9.6% 7.8% 6.4% 5.4% 4.7% 4.3% 3.8%

NYMEX Price Deck

Oil ($ / Bbl) $110.77 $109.41 $105.81 $103.53 $102.46 $102.46 $102.46 $102.46 $102.46 $102.46 $102.46 Gas ($ / Mcf) 4.44 4.93 5.31 5.65 6.03 6.03 6.03 6.03 6.03 6.03 6.03 Realized Sales Proved $754 $508 $403 $391 $382 $361 $345 $332 $319 $311 $306 Pinedale 250 596 855 1,083 1,304 1,440 1,558 1,664 1,761 1,851 1,933 Marcellus 149 357 510 646 780 860 930 993 1,051 1,105 1,155

Total Oil and Gas Revenue $1,153 $1,460 $1,769 $2,120 $2,467 $2,661 $2,834 $2,989 $3,132 $3,267 $3,393

Hedging Revenue 148 9 0 0 0 0 0 0 0 0 0

Total Revenue $1,302 $1,470 $1,769 $2,120 $2,467 $2,661 $2,834 $2,989 $3,132 $3,267 $3,393

$/mcfe (excl hedges) $4.61 $5.07 $5.37 $5.68 $6.03 $6.03 $6.04 $6.04 $6.04 $6.04 $6.05 $/mcfe (incl hedges) 5.20 5.07 5.37 5.68 6.03 6.03 6.04 6.04 6.04 6.04 6.05

Operating Costs

Production and Property Taxes $162 $105 $81 $77 $74 $70 $67 $64 $62 $60 $59

LOE 70 161 225 278 327 361 390 416 441 463 483

Corporate Transportation Costs 61 63 68 75 81 87 92 96 100 104 108

G&A 24 24 24 24 24 24 24 24 24 24 24

Total Operating Costs $318 $353 $398 $455 $506 $542 $573 $601 $627 $652 $675

Total Op Costs $/mcfe $1.27 1.22 1.21 1.22 1.24 1.23 1.22 1.21 1.21 1.21 1.20

EBITDA $983 $1,116 $1,371 $1,666 $1,960 $2,119 $2,261 $2,387 $2,505 $2,615 $2,718

EBITDA Margin 76% 76% 78% 79% 79% 80% 80% 80% 80% 80% 80% $/mcfe $3.93 $3.85 $4.16 $4.46 $4.79 $4.80 $4.81 $4.82 $4.83 $4.84 $4.84

Less: Interest $89 $88 $87 $87 $84 $79 $74 $65 $53 $33 $20

$/mcfe $0.35 $0.30 $0.26 $0.23 $0.21 $0.18 $0.16 $0.13 $0.10 $0.06 $0.04

Less: Cash Taxes $0 $38 $118 $216 $318 $371 $420 $467 $511 $555 $596

$/mcfe $0.00 $0.13 $0.36 $0.58 $0.78 $0.84 $0.90 $0.94 $0.99 $1.03 $1.06

Capex

Pinedale D&C $547 $552 $547 $549 $549 $549 $549 $547 $549 $549 $549

Marcellus D&C 393 395 395 393 395 395 393 395 393 395 395

Total Capex $940 $947 $942 $942 $945 $945 $942 $942 $942 $945 $945

Free Cash Flow ($45) $43 $224 $420 $613 $725 $824 $913 $998 $1,083 $1,158

Cash Balance $71 $71 $293 $713 $1,226 $1,889 $2,597 $3,310 $4,135 $4,696 $5,854

Total Debt $1,605 $1,562 $1,560 $1,560 $1,460 $1,398 $1,282 $1,082 $909 $387 $387

Debt / EBITDA 1.6x 1.4x 1.1x 0.9x 0.7x 0.7x 0.6x 0.5x 0.4x 0.1x 0.1x

$6,124 $4,916 $1,489 $244 $1,593 $2,870 $142 $2,870 $8,993 $13,909 $13,909 $12,319 $12,420 $10,726 $12,562 $10,726 $0 $4,000 $8,000 $12,000 $16,000 P DP (P V-10) Ro ckies (P V-10) M arcellus (P V-10) Total Resource Value

Net Debt Hedges G&A Income Taxes Net Asset Value

Valuation Metrics PDP Rockies Marcellus Total

PV 10 / 2011E Production ($ / mcfe/d) $6,422 $41,144 $54,432 $20,276 PV-10 / Resources ($ / mcfe) $1.65 $0.53 $0.45 $0.58 PV-10 / Risked Resources ($ / mcfe) $1.65 $0.38 $0.33 $0.48 PV-10 / Acre ($ / acre) NA $139,171 $18,907 NA Rockies (excl PDP) 44% Marcellus (excl PDP) 35% Total PDP 21%

NAV Methodology: Net Asset Value

Base Price Case: PV-10 based on Strip Price Deck(1)

Net Resource

(Bcfe) 1,744 11,545 10,837 24,125

Current Price (04/15/11) $48.12

(2) (3)

Base Price Case PV-10 Base Case Valuation Metrics

(4) Implied Share Price $70.01 Relative to Current 45%

10 100 1,000 10,000

1 51 101 151 201 251 301

NAV Methodology: Single-Well Analysis

Single Well Profile (8/8ths)

Type Curve Profile

Return Sensitivities

Months

IRR ROI

Source: Company filings, investor presentations. Note: Reflects NYMEX strip pricing as of 4/15/11. (1) Terminal decline rate = ~5%.

(2) Based on average IP rate of producing wells as of 12/31/10. 2010 average 1-day IP rate of 6.4MMcfe/d and 5.66MMcfe/d based on early Marcellus well per company investor presentation.

Marcellus Months

1 12 24 36 48 60

Avg. Daily Prod. 5,015 1,325 881 685 571 495

Decline Rate -- (74%) (34%) (22%) (17%) (13%)(1)

Gross EUR (Bcfe) 4.20

% Oil, Gas, NGL 0% / 100% / 0%

1-day IP Rate (MMcfe/d) 6.03

Differential (Oil) $0.00

Differential (Gas) 102.0%

Com pany Working Interest 45.0%

Net Revenue Interest 86.0%

Gross Capex per Well ($ in thousands) $4,800

Net F&D Costs ($/m cfe) $1.33

Net LOE ($/m cfe) 0.24

Production Taxes 5.0%

IRR (NYMEX strip) 40.1%

PV-0 ($ in thousands) $6,213

PV-10 ($ in thousands) 2,072

PV-10 /(MMcfe) $0.49

Capex per Well ($ in thousands)

$3,800 $4,300 $4,800 $5,300 $5,800 $70.00 / $4.00 42.8% 32.3% 25.2% 20.1% 16.3% $80.00 / $4.50 57.1 43.0 33.5 26.7 21.8 $90.00 / $5.00 73.9 55.4 43.1 34.4 28.0 $100.00 / $5.50 93.6 69.9 54.2 43.2 35.2 $110.00 / $6.00 116.8 86.6 66.9 53.2 43.3 $120.00 / $6.50 143.7 105.8 81.3 64.5 52.4 Strip 64.5% 50.0% 40.1% 32.9% 27.5% C o m m o d it y P ri c e ($ /B b l / $ /M M B tu )

Capex per Well ($ in thousands)

$3,800 $4,300 $4,800 $5,300 $5,800 $70.00 / $4.00 3.5x 3.1x 2.7x 2.5x 2.3x $80.00 / $4.50 3.9 3.5 3.1 2.8 2.6 $90.00 / $5.00 4.4 3.9 3.5 3.1 2.9 $100.00 / $5.50 4.8 4.3 3.8 3.5 3.2 $110.00 / $6.00 5.3 4.7 4.2 3.8 3.5 $120.00 / $6.50 5.8 5.1 4.6 4.1 3.8 Strip 4.9x 4.3x 3.9x 3.5x 3.2x C o m m o d it y P ri c e ($ /B b l / $ /M M B tu )

Well EUR (Bcfe)

3.200 3.700 4.200 4.700 5.200 $70.00 / $4.00 13.4% 18.8% 25.2% 32.5% 40.9% $80.00 / $4.50 18.0 25.1 33.5 43.2 54.5 $90.00 / $5.00 23.2 32.3 43.1 55.8 70.5 $100.00 / $5.50 29.2 40.6 54.2 70.3 89.3 $110.00 / $6.00 35.9 49.9 66.9 87.1 111.2 $120.00 / $6.50 43.3 60.5 81.3 106.5 136.7 Strip 21.1% 31.1% 40.1% 50.3% 61.9% C o m m o d it y P ri c e ($ /B b l / $ /M M B tu )

Well EUR (Bcfe)

3.200 3.700 4.200 4.700 5.200 $70.00 / $4.00 2.1x 2.4x 2.7x 3.1x 3.4x $80.00 / $4.50 2.4 2.7 3.1 3.5 3.8 $90.00 / $5.00 2.6 3.1 3.5 3.9 4.3 $100.00 / $5.50 2.9 3.4 3.8 4.3 4.7 $110.00 / $6.00 3.2 3.7 4.2 4.7 5.2 $120.00 / $6.50 3.5 4.0 4.6 5.1 5.6 Strip 2.8x 3.4x 3.9x 4.3x 4.8x C o m m o d it y P ri c e ($ /B b l / $ /M M B tu ) P ro d u c ti o n (M c fe / d ) (2) 20

NAV Methodology: Consolidated Reserve Summary

($m), unless otherwise noted

Gross Net Net Production Total Net Benchm ark Com m odity Prices Realized Com m odity Prices

Wells Wells Oil Natural Gas Production Oil Natural Gas Oil Natural Gas NGL

Year Drilled Drilled (MBbls) (MMcf) (MMcfe) ($/bbl) ($/mcf) ($/bbl) ($/mcf) ($/bbl)

2011 396 201 1,570 240,957 250,376 $110.77 $4.44 $96.27 $4.16 $0.00 2012 399 202 1,608 280,426 290,077 109.41 4.93 94.91 4.66 0.00 2013 397 201 1,746 318,939 329,413 105.81 5.31 91.31 5.05 0.00 2014 397 201 1,969 361,673 373,489 103.53 5.65 89.03 5.38 0.00 2015 398 202 2,155 396,318 409,250 102.46 6.03 87.96 5.75 0.00 2016 398 202 2,328 427,258 441,227 102.46 6.03 87.96 5.75 0.00 2017 397 201 2,486 454,622 469,537 102.46 6.03 87.96 5.75 0.00 2018 397 201 2,629 479,174 494,948 102.46 6.03 87.96 5.75 0.00 2019 397 201 2,762 501,837 518,407 102.46 6.03 87.96 5.76 0.00 2020 398 202 2,888 523,302 540,633 102.46 6.03 87.96 5.76 0.00 2021 398 202 3,008 543,232 561,281 102.46 6.03 87.96 5.76 0.00 2022 397 201 3,118 561,800 580,509 102.46 6.03 87.96 5.76 0.00 2023 397 201 3,217 578,731 598,032 102.46 6.03 87.96 5.76 0.00 2024 399 202 3,312 595,244 615,115 102.46 6.03 87.96 5.76 0.00 2025 396 201 3,394 609,750 630,112 102.46 6.03 87.96 5.76 0.00 Rem. 6,120 2,985 73,519 16,581,507 17,022,618 102.46 6.03 96.27 5.86 0.00 Total 12,081 _- 6,007 _- 111,709 23,454,769 24,125,025

Revenue Total Production Lease Transpo Field Level Drilling and Field Level Discounted CF

Oil Natural Gas Revenue Taxes Op Expense Costs EBITDA Com pletion Cash Flow PV-10

Year ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) 2011 $151,132 $1,001,975 $1,153,108 $125,961 $106,563 $61,259 $859,324 $939,793 ($80,469) ($78,769) 2012 152,652 1,307,783 1,460,435 149,111 117,088 62,573 1,131,663 947,063 184,600 159,410 2013 159,391 1,609,219 1,768,610 175,616 130,280 67,519 1,395,195 941,953 453,241 356,090 2014 175,319 1,945,167 2,120,486 208,448 146,723 75,250 1,690,065 942,348 747,717 534,900 2015 189,585 2,277,006 2,466,590 240,648 159,987 81,421 1,984,534 944,508 1,040,026 676,739 2016 204,780 2,456,421 2,661,201 258,501 171,887 86,990 2,143,823 944,508 1,199,315 709,492 2017 218,663 2,615,035 2,833,698 274,381 182,448 91,955 2,284,912 942,348 1,342,564 722,156 2018 231,252 2,757,393 2,988,645 288,620 191,913 96,392 2,411,720 941,953 1,469,767 718,798 2019 242,929 2,888,816 3,131,745 301,759 200,644 100,480 2,528,862 942,348 1,586,514 705,367 2020 254,061 3,013,239 3,267,300 314,248 208,938 104,382 2,639,732 944,508 1,695,224 685,030 2021 264,598 3,128,667 3,393,265 325,921 216,678 108,052 2,742,613 944,508 1,798,105 660,616 2022 274,265 3,236,307 3,510,573 336,721 223,849 111,421 2,838,582 942,348 1,896,234 633,371 2023 282,965 3,334,566 3,617,531 346,486 230,342 114,437 2,926,266 941,953 1,984,313 602,548

Public Comparables Methodology: Overview

Peer

($ in millions) UPL Median SWN HK RRC EQT QEP COG XCO

Share Price (as of 04/15/11) $48.21 $39.64 $26.29 $53.40 $46.96 $38.34 $53.23 $20.74

Equity Value $7,377 $13,897 $8,046 $8,674 $7,034 $6,797 $5,551 $4,546 Plus: Debt 1,560 1,094 2,607 1,061 2,003 1,531 975 1,310 Less: Cash (71) (16) (56) (3) 0 0 (56) (206) Other Adjustments 0 0 217 155 191 97 0 379 Enterprise Value $8,866 $14,975 $10,815 $9,887 $9,228 $8,425 $6,470 $6,029 Operating Metrics

2011E Cash Flow per Share $6.17 $4.66 $3.53 $4.49 $5.09 $6.48 $5.40 $2.62

2012E Cash Flow per Share 6.85 5.94 4.93 5.72 6.08 7.87 7.29 3.71

2011E Cash Flow $941 $1,622 $1,068 $721 $759 $1,143 $564 $559

2012E Cash Flow 1,045 2,064 1,492 919 907 1,388 760 793

2011E EBITDA $1,024 $1,684 $1,378 $827 $835 $1,255 $642 $599

2012E EBITDA 1,141 2,079 1,779 1,022 1,011 1,489 837 840

Proved Reserves (Bcfe) 4,390 4,937 3,392 4,442 5,220 3,031 2,701 1,499

% Proved Developed 40% 53% 55% 35% 49% 49% 53% 64% 55%

% Gas 96 97 100 92 80 100 86 98 97

Current Production (MMcfe/d) 622 1,211 762 428 438 678 407 385

2011E Production (MMcfe/d) 705 1,624 877 560 477 717 481 500

2012E Production (MMcfe/d) 840 1,530 1,080 705 567 816 564 679

Proved R / P 19.3x 12.2x 11.2x 12.2x 28.4x 32.7x 12.2x 18.2x 10.7x Proved Developed R / P 7.7 6.5 6.1 4.3 14.0 15.9 6.5 11.6 5.8 Credit Statistics Net Debt / $1,489 $1,078 $2,551 $1,058 $2,003 $1,531 $919 $1,105 2011E EBITDA 1.5x 1.4x 0.6x 1.9x 1.3x 2.4x 1.2x 1.4x 1.8x 2012E EBITDA 1.3 1.1 0.5 1.4 1.0 2.0 1.0 1.1 1.3

Proved Dev. Reserves ($ / Mcfe) $0.85 $0.79 $0.40 $2.15 $0.48 $0.79 $0.95 $0.53 $1.34

2011E Daily Production ($/ Mcfe/d) $2,112 $2,135 $664 $2,910 $1,888 $4,202 $2,135 $1,910 $2,208

2012E Daily Production ($/ Mcfe/d) 1,773 1,629 705 2,361 1,499 3,532 1,876 1,629 1,626

Valuation Metrics Price / 2011E CFPS 7.8x 8.5x 8.5x 7.4x 11.9x 9.2x 5.9x 9.8x 7.9x 2012E CFPS 7.0 6.7 6.7 5.3 9.3 7.7 4.9 7.3 5.6 Firm Value / 2011E EBITDA 8.7x 10.1x 8.9x 7.8x 11.9x 11.0x 6.7x 10.1x 10.1x 2012E EBITDA 7.8 7.2 7.2 6.1 9.7 9.1 5.7 7.7 7.2

Proved Reserves ($ / Mcfe) $2.02 $2.78 $3.03 $3.19 $2.23 $1.77 $2.78 $2.40 $4.02

2011 Production ($ / Mcfe/d) $12,578 $12,338 $9,219 $12,338 $17,646 $19,363 $11,748 $13,446 $12,055 2012 Production ($ / Mcfe/d) 10,556 10,327 9,786 10,009 14,016 16,273 10,327 11,471 8,878

(1)

Source: Company filings, investor presentations, Wall Street research. Market data as of 4/15/11. (1) Includes adjustments related to non-controlling interest and investments in affiliates. (2) Based on Q4 2010 production.

(3) Per Wall Street mean consensus estimates.

(2) (3) (3) (3) (3) (3) (3) (3) (3) (2) 22

Precedent Reserves Transactions Methodology: Overview

(1) Transaction Value / Adj. Transaction Value / Transaction Proved Reserves Reserves Daily Prod. Reserves Daily Prod. Date Acquiror Target / Seller Location Value ($ MM) (Bcfe) (MMcfe/d) % Gas % PD R / P ($ / Mcfe) ($ / Mcfe/d) ($ / Mcfe) ($ / Mcfe/d)

2010/03/18 Opon International Delta Petroleum Piceance $400 32 9.2 95% NA 9.5 $3.22 $11,124 $3.03 $10,486 2010/03/15 Fidelity E&P; MDU

Resources Undisclosed Green River Basin 113 63 14.5 92 81 11.9 1.49 6,464 1.40 6,091 2009/08/10 Williams Companies Orion Energy Piceance 258 150 24.0 100 NA 17.1 0.65 4,031 0.55 3,448 2009/03/03 Undisclosed Berry Petroleum Denver-Julesburg (D-J) 154 126 18.0 100 NA 19.2 1.11 7,778 1.00 7,035 2008/11/03 Devon Chevron Uinta 779 210 40.0 100 66 14.4 3.71 19,483 2.34 12,268 2008/05/05 Whiting Chicago Energy

Associates Uinta 365 115 19.0 98 22 16.6 3.17 19,211 1.34 8,136 2007/06/04 XTO Dom inion Uinta 2,500 1,060 200.0 95 64 14.5 1.69 8,937 0.96 5,075 2007/04/18 Plains E&P Laramie Energy Piceance 945 384 36.0 97 NA 29.2 2.13 22,692 1.22 12,961 2006/03/09 Black Hills Koch Exploration Piceance 51 40 1.9 100 22 57.0 1.27 26,500 0.69 14,415 2006/01/27 Berry Petroleum Undisclosed Piceance 159 26 1.0 100 NA 71.2 3.19 83,000 1.57 40,886 2005/02/23 Whiting Undisclosed Green River Basin 65 50 6.3 98 68 22.0 1.29 10,317 0.91 7,310 2004/12/06 Berry Petroleum J-W Operating Company Denver-Julesburg (D-J) 105 87 8.8 100 39 27.1 1.21 11,932 0.84 8,348 2004/09/01 Bill Barrett Calpine Piceance 137 50 NA 98 56 NA 2.74 NA 2.16 NA 2004/08/27 Pogo Producing Undisclosed San Juan Basin 106 56 8.4 100 NA 18.3 1.89 12,607 1.40 9,354 2004/08/27 Pogo Producing Calpine San Juan Basin 83 44 6.6 100 NA 18.3 1.89 12,591 1.40 9,342 2004/07/22 Western Gas Various San Juan Basin 82 60 NA 100 NA NA 1.37 NA 1.00 NA 2004/06/29 Energen SG Interests San Juan Basin 263 240 NA 80 50 NA 1.03 NA 1.10 NA 2003/06/06 XTO MarkWest San Juan Basin 61 50 9.5 100 NA 14.4 1.21 6,369 0.87 4,585 2003/04/09 XTO Williams Companies Raton/Hugoton/San

Juan 400 311 60.0 100 77 14.2 1.20 6,232 1.06 5,499 2003/03/11 Sacramento Municipal

Utility District El Paso San Juan Basin 138 163 16.0 100 NA 28.0 0.84 8,625 0.65 6,634 2002/11/25 XTO JM Huber San Juan Basin 160 154 29.0 100 79 14.5 1.04 5,517 1.16 6,156 2002/11/06 Westport Resources El Paso Uinta 502 600 80.0 100 47 20.5 0.84 6,275 0.98 7,369 2002/08/01 EnCana Williams Companies Jonah Field 350 395 106.7 96 68 10.1 0.79 2,911 1.12 4,151 2002/04/18 EnCana El Paso Piceance 293 300 38.0 85 NA 21.6 0.93 7,349 1.50 11,872 2002/04/11 MRO; XTO CMS Energy Powder River Basin 101 110 14.0 100 NA 21.6 0.67 5,253 0.88 6,909 2002/04/01 Bill Barrett Williams Companies Wind River 74 58 27.9 100 NA 5.7 1.23 2,573 1.57 3,280 2001/01/09 Texaco EnerVest San Juan Basin 121 204 21.5 100 NA 26.0 0.53 5,056 0.38 3,559 2000/10/25 Barrett Resources Kansas City Power & Light Raton Basin 53 75 5.2 100 20 39.5 0.65 9,309 0.65 9,437 Mean 98% 54% 22.5 $1.53 $12,886 $1.21 $8,984 Median 100 60 18.3 1.22 8,625 1.08 7,310

Total Net

Date Acquiror Target / Seller Location Value ($ MM) Acreage $ / Acre

2010/11/15 Newfield Exploration EOG Resources Marcellus $405.0 50,000 $8,100

2010/11/09 Chevron Atlas Energy Marcellus 3,703.0 342,000 7,084

2010/10/06 Chesapeake Energy Anschutz Exploration Marcellus 850.0 500,000 1,700

2010/09/22 Atinum Partners Gastar Exploration Marcellus 70.0 17,100 4,094

2010/08/31 Sumitomo Rex Energy Marcellus 140.0 15,555 9,000

2010/07/20 Trans Energy Republic Energy Marcellus 27.0 3,800 7,105

2010/08/05 Reliance Industries Carrizo Oil & Gas Marcellus 392.0 62,600 6,262 2010/05/28 Royal Dutch Shell East Resources / Kohlberg Kravis RobertsMarcellus 4,700.0 650,000 6,385

2010/05/28 Penn Virginia Undisclosed Marcellus 19.5 10,000 1,950

2010/05/10 BG Group EXCO Resources Marcellus 950.0 93,000 8,073

2010/04/21 Atlas, Reliance Undisclosed Marcellus 191.9 42,344 4,532

2010/04/09 Reliance Industries Atlas Energy Marcellus 1,700.0 120,000 14,167

2010/03/26 Statoil Hydro Chesapeake Energy Marcellus 253.0 59,000 4,288

2010/03/15 CONSOL Energy Dominion Resources Marcellus 3,475.0 491,393 4,797

2010/03/02 EQT Undisclosed Marcellus 280.0 58,000 4,828

2010/02/16 Mitsui Anadarko Marcellus 1,400.0 100,000 14,000

2010/01/19 Chesapeake Energy Epsilon Energy Marcellus 100.0 5,750 10,530

2009/12/21 Ultra Petroleum NCL Appalachian Partners Marcellus 400.0 80,000 5,000

2009/10/29 Magnum Hunter Resources Triad Energy Marcellus 81.0 47,000 1,000

2009/09/30 Chesapeake Energy Wyoming County Landowners Group Marcellus 212.8 37,000 5,751

2009/09/30 Fortuna Energy Friendsville Group Marcellus 192.0 35,000 5,486

2009/09/18 Undisclosed Epsilon Energy Marcellus 12.7 3,734 3,401

2009/08/19 Enerplus Resources Chief Oil & Gas Marcellus 406.0 116,000 3,500

2009/06/22 Williams Companies Rex Energy Marcellus 33.0 22,000 1,500

2009/06/09 Kohlberg Kravis Roberts East Resources Marcellus 350.0 650,000 538

2008/11/11 Statoil Hydro Chesapeake Energy Marcellus 3,375.0 585,000 5,769

2008/11/04 Carrizo Oil & Gas Avista Capital Partners Marcellus 71.5 77,500 923

2008/06/30 Antero Resources Dominion Resources Marcellus 347.0 114,259 3,037

2008/04/15 XTO Energy Linn Energy Marcellus 600.0 152,000 1,645

Mean JV $6,696

Median JV 6,016

Mean M&A $4,047

Median M&A 4,797

Precedent Acreage Transactions Methodology: Overview

Source: John S. Herold, Inc.

(1) Acreage represents Reliance JV AMI acreage only. Excludes Laurel Mountain and AHD value. $900mm of value allocated to proved reserves and hedges, 105,000 Utica / Collingwood acres values at $1,000 / acre, 144,000 non-Marcellus JV acres valued at $2,000 / acre.

(2) Value allocated assuming $8,000 / Mcfe/d of production and $250 / acre for non-Marcellus acreage (3) Value allocated to existing production at $10,000 / Mcfe/d

(4) Value allocated to existing production at $8,000 / Mcfe/d (5) Value allocated to existing production at $5,667 / Mcfe/d (6) Value allocated to existing production at $14,000 / Mcfe/d

(2) (3) (4) (5) (6) (1) 24

Drivers of Value

Good Rock



High Oil or Gas-in-place



Quality hydrocarbon



Ability of the hydrocarbon to

flow through rock

(permeability)



Some rock tougher to drill

Attractive Location



Relative supply and demand

for the commodity

–

Rockies vs. Appalachia



Proximity to Transportation

Infrastructure



Friendly operating

environment

Low Costs



Shallow reservoir = lower cost

drilling



Low operating costs

–

Low water cut

–

Infrastructure in place

(roads, electricity, etc)



Fiscal regime

Land and Leasing Issues



E&P companies rarely own the land on which they drill, but instead will lease mineral rights

–

Usually, the lessor (owner) receives an upfront cash payment (bonus payment) in addition to a

percentage of the oil and gas revenue generated by the lease (royalty)

–

Royalties in the Lower 48 typically range from 12.5% to 25%, but terms are negotiated, and vary

widely



A typical lease gives a company (lessee) a period of three to five years to generate commercial

production on the lease

–

Once commercial production is established, a lease is said to be held-by-production (HBP)

–

If no production is established, the expires

–

Future lease expirations often have a substantial impact on a company’s drilling plans as companies

will plan drilling programs to lock up acreage that expires in the near-term

–

Large, contiguous blocks of acreage are preferred as they provide operators with greater flexibility in

locking up acreage

Operating Drivers

Revenue = Price * Quantity

 Gross (Wellhead) Production

Less: royalties

Net Production

Note: Production generally shown in daily terms

 Benchmark (NYMEX) Prices Less: Basis

Less / Plus: Quality differences Less: Transportation Costs = Realized Prices

Expenses

 Production Taxes, which include:

Severance Taxes (Percent of Revenue) Ad Valorem Taxes (Percent of Revenue, but net of Severance)

 Lease Operating Costs (fixed and variable components, sometimes

simplified to a $ per Mcfe or Boe basis)

 SG&A (generally a fixed cost)

 Exploration Costs, depending on whether a company chooses full cost or

successful efforts accounting

– Added back to calculate EBITDAX for comparability purposes

 DD&A – calculation is complex Differential

Calculating Production

Current Production



Net wells = gross wells * average working interest (W.I.)

–

Gross: wells in which you own an interest

–

Working interest: percent that you own

–

Note: all company-level disclosure is generally on a net basis



Production = net wells * average net production per well



Net production per well = wellhead production less royalties

Future Production



Remaining drilling inventory (locations)= risked acreage / well spacing



Production = type curve * wells drilled



Risked acreage = total acreage * risk rate

Illustrative Horizontal Well Bore Schematic

Denson 2H-15

Denson 2H-15 200' FSL & 300' FWL Sec 10-1N-10E Coal Oklahoma 9 5/8", 36#, J-55 csg 688' GL, 710' KB Set @ 295' Cmt w/ 210 sxs. Cmt top @ 6150' KOP @ 7440' TD @13057' 5 1/2" P-110, 17# csg set @ 13057' 90.57 deg LP @ 8360' (81.68 deg - 8012' TVD) Cmt w/ 880 sxs 7838' TVD PBD @ 13000' Top of 8270' 8700' 9110' 9496' 10040' 10470' 10910' 11355' 11790' 12230' 12670' 4' perf guns 8370' 8800' 9190' 9540' 10130' 10565' 11010' 11450' 11890' 12330' 12810' 6 jspf 8470' 8900' 9280' 9590' 10230' 10675' 11110' 11550' 11990' 12430' 12950' 96 holes/stg 8570' 8990' 9380' 9640' 10330' 10770' 11200' 11650' 12090' 12530' 9690' 9740' 9790' 9885' December 1, 2009 29

Illustrative 80-Acre Horizontal Well Spacing

#1 #2 #3 #4 #5 #6 #7 #8 4 9 3 0 ’ L a te ra ls 4 9 3 0 ’ L a te ra ls 5 2 8 0 ’ 660’ 330’ 660’ 175’ 175’ 175’ 175’ 330’

Realizing Pricing Subject to Many Issues

Realized Pricing Benchmark Pricing WTI Brent Henry Hub Commodity Quality Location Differentials Transportation Quality Location 31

New Pipeline Capacity Has Reduced Woodford Basis

$0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00

Jan-08 Jul-08 Jan-09 Jul-09 Jan-10 Jul-10

$ / M M B tu

Centerpoint East Panhandle East Henry Hub

Accounting Discussion

Full Cost



Capitalize all costs associated with drilling,

including dry hole and G&G and G&A costs



Higher carrying value of PP&E



Generally, higher earnings than Successful Efforts

from lower expense associated with dry holes



In theory, identical cash from operations relative

to Successful Efforts



Preference of smaller companies with more

volatile earnings



More stringent ceiling test required to avoid build

up of unrecovered costs

–

Carrying value compared to after-tax, pre-G&A

PV-10 of cash flow

E&P companies may choose from two different accounting methods for exploration and dry well expenses: full cost or successful efforts.

Successful Efforts



Capitalize only costs of successful wells



Expense of dry hole and G&G and G&A costs as

incurred



Lower carrying value of PP&E



Generally, lower earnings than Full Cost from

higher expense associated with dry holes



In theory, identical cash from operations relative

to Full Cost



Preference of larger companies



Unusual to book asset impairments due to regular

expensing of unsuccessful efforts

–

Carrying value compared to pre-tax, pre-G&A,

undiscounted value of cash flow

Reserve Replacement Cost and Rate



Reserve Replacement Costs per boe (RRC) are computed by taking total costs incurred (proved and

unproved property acquisition costs, exploration costs and development costs) during the applicable

period as the numerator and dividing by the total oil equivalent reserve changes associated with

discoveries and extensions, revisions in estimates, improved recovery and purchase of proved reserves

in place as the denominator



Reserve Replacement Rates are computed by dividing production for the period into the total reserve

changes for the period used in the denominator for computing RRC reduced by volumes sold during the

period

Pioneer Nat Res Summary Worldwide 7 5 3

Capital Efficiencies Measures Worldwide United States

(1) All Sources 1 Year 3 Years 5 Years 1 Year 3 Years 5 Years

(a) Reserve Replacement Cost 2000 1998-00 1996-00 2000 1998-00 1996-00 Total Costs Incurred (US$ MM) $ 340 $ 1,004 $ 5,460 $ 204 $ 640 $ 3,908 Net Reserves Added (MMBOE)

Extensions and discoveries 38.0 59.2 66.6 15.9 17.0 23.1

Improved recovery - - -

-Revisions of previous estimates 27.5 70.7 191.3 29.9 74.8 195.9

Purchase of reserves in place 7.4 14.7 474.6 5.9 5.9 320.7

Total Net Reserves Added (MMBOE) 72.9 144.6 732.5 51.8 97.8 539.8

Reserve Replacement Cost (US$ / BOE) $ 4.66 $ 6.94 $ 7.45 $ 3.94 $ 6.55 $ 7.24

JS Herold $ 4.66 $ 6.94 $ 7.45 $ 3.94 $ 6.55 $ 7.24

Other Source NA NA NA NA NA NA

(b) Reserve Replacement Rate I

Total net reserves added (MMBOE) 72.9 144.6 732.5 51.8 97.8 539.8

Production (MMBOE) 43.6 157.5 216.8 30.9 117.0 175.4

Reserve Replacement Rate (%) 167% 92% 338% 168% 84% 308%

(c) Reserve Replacement Rate II Reserves Added Less Sales (MMBOE)

Total net reserves added (MMBOE) 72.9 144.6 732.5 51.8 97.8 539.8

Less: sales of reserves in place (6.6) (120.5) (184.3) (6.6) (104.1) (136.5)

Total Reserves Added Less Sales (MMBOE) 66.3 24.1 548.2 45.2 (6.3) 403.3

Production (MMBOE) 43.6 157.5 216.8 30.9 117.0 175.4

Reserve Replacement Rate (%) 152% 15% 253% 146% (5%) 230%

JS Herold NA NA NA 146% NA 230%

Other Source NA NA NA NA NA NA

Pioneer Natural Resources Company

F&D Cost and Rate



Finding and Development Costs per boe (FDC) are computed by taking as the numerator total costs

incurred less costs of proved property acquisitions and dividing by a denominator comprised of the total

oil equivalent reserve changes for the period associated with discoveries and extensions, revisions in

estimates and improved recoveries (costs associated with proved property purchases are excluded)



Finding and Development Replacement Rates are computed by dividing production for the period into

the total reserve changes associated with discoveries and extensions, revisions in estimates and

improved recoveries

Pioneer Nat Res Summary Worldwide

(2) Finding & Development Worldwide United States

(d) Finding & Development Costs 2000 1998-00 1996-00 2000 1998-00 1996-00

Costs Incurred (US$ MM)

Unproved property acquisition $ 31 $ 37 $ 581 $ 28 $ 65 $ 162

Exploration 131 323 458 65 170 290

Development 142 544 965 85 358 770

Costs Incurred (US$ MM) $ 304 $ 905 $ 2,003 $ 178 $ 594 $ 1,222

Reserves Added (MMBOE)

Extensions and discoveries 38.0 59.2 66.6 15.9 17.0 23.1

Improved recovery - - -

-Revisions of previous estimates 27.5 70.7 191.3 29.9 74.8 195.9

Reserves Added (MMBOE) 65.5 129.9 257.9 45.8 91.9 219.0

Finding & Development Cost (US$ / BOE) $ 4.64 $ 6.97 $ 7.77 $ 3.88 $ 6.46 $ 5.58

JS Herold $ 4.64 $ 6.97 $ 7.77 $ 3.88 $ 6.46 $ 5.58

Other Source NA NA NA NA NA NA

(e) Reserve Replacement Rate

Reserves Added (MMBOE) 65.5 129.9 257.9 45.8 91.9 219.0 Production (MMBOE) 43.6 157.5 216.8 30.9 117.0 175.4

Reserve Replacement Rate (%) 150% 82% 119% 149% 79% 125%

JS Herold 150% 82% 119% 149% 79% 125%

Other Source NA NA NA NA NA NA

(3) Finding & Development (No Revisions) Worldwide United States

(f) Finding & Development Costs 2000 1998-00 1996-00 2000 1998-00 1996-00

Costs Incurred (US$ MM) $ 304 $ 905 $ 2,003 $ 178 $ 594 $ 1,222

Reserves Added (MMBOE)

E&P Capital Efficiency Data

Pioneer Nat Res Summary Worldwide

(4) Exploration and Development Worldwide United States

(h) Finding & Development Costs 2000 1998-00 1996-00 2000 1998-00 1996-00

Costs Incurred (US$ MM)

Exploration 131 323 458 65 170 290

Development 142 544 965 85 358 770

Costs Incurred (US$ MM) $ 273 $ 868 $ 1,423 $ 150 $ 528 $ 1,060

Reserves Added (MMBOE) 38.0 59.2 66.6 15.9 17.0 23.1

Finding & Development Cost (US$ / BOE) $ 7.17 $ 14.66 $ 21.36 $ 9.42 $ 31.01 $ 45.87

(i) Reserve Replacement Rate

Reserves Added (MMBOE) 38.0 59.2 66.6 15.9 17.0 23.1

Production (MMBOE) 43.6 157.5 216.8 30.9 117.0 175.4

Reserve Replacement Rate (%) 87% 38% 31% 52% 15% 13%

(5) Proved Reserve Acquisitions Worldwide United States

(j) Proved Reserve Replacement Cost 2000 1998-00 1996-00 2000 1998-00 1996-00

Cost of proved property acquisition ($ MM) $ 36 $ 99 $ 3,457 $ 26 $ 47 $ 2,686

Reserves added through proved acq (MMBOE) 7.4 14.7 474.6 5.9 5.9 320.7

Proved Reserve Replacement Cost (US$ / BOE) $ 4.90 $ 6.73 $ 7.28 $ 4.41 $ 7.89 $ 8.38

(k) Reserve Replacement Rate

Reserves added through proved acq (MMBOE) 7.4 14.7 474.6 5.9 5.9 320.7

Production (MMBOE) 43.6 157.5 216.8 30.9 117.0 175.4

Reserve Replacement Rate (%) 17% 9% 219% 19% 5% 183%

Pioneer Natural Resources Company

Per Barrel Income and Cash Flow



Oil and gas differentials



Realized oil and gas revenue per BOE



Lease operating expense per BOE



Cash netback per BOE

Oil and Gas Disclosure: 1997 1998 1999 2000 Per Barrel Economics FYE Dec 31 FYE Dec 31 (US$ / BOE) 1997A 1998A 1999A 2000A

Blended Benchmark Commodity Price (1) 16.76 13.20 16.04 27.72 Oil and Gas Blended Differential (2.00) (1.84) (2.15) (2.51) Realized Oil and Gas Revenue 14.76 11.37 13.89 25.21 Lease Operating Expenses (3.56) (3.66) (3.23) (5.17) General and Administrative 0.00 0.00 0.00 0.00 Cash Netback (i.e., EBITDAX) 11.20 7.70 10.66 20.04 Oil and Gas DD&A (4.09) (3.88) (3.97) (5.13) Oil and Gas Operating Income (EBIT) 7.11 3.82 6.70 14.91 Oil and Gas Income Taxes (2.52) (1.37) (2.83) (5.78) Oil and Gas Net Income (NOPAT) 4.59 2.45 3.87 9.13 Oil and Gas Analyst Cash Flow 7.59 6.24 6.46 9.28

(1) Based on WTI oil and Henry Hub natural gas spot prices using co's actual production mix in given year

Oil and Gas Disclosure: Select Income, FYE Dec 31 FYE Dec 31 Cash Flow and Operating Data 1997A 1998A 1999A 2000A Total Production

Liquids (MMBBL) 14.5 17.8 21.1 47.0 Gas (BCF) 179.0 177.0 170.0 385.0

Oil Equivalent (MMBOE 6:1) 44.3 47.3 49.4 111.2

Average Realized Commodity Prices

Liquids (US$ / BBL) 16.76 11.05 15.76 25.29 Natural Gas (US$ / MCF) 2.30 1.92 2.08 4.13

Average Benchmark Commodity Prices

WTI oil spot (US$ / BBL) 20.58 14.38 19.30 30.37 Henry Hub gas spot (US$ / MCF) 2.48 2.08 2.27 4.30

Commodity Differentials

Liquids (US$ / BBL) (3.83) (3.33) (3.54) (5.07) Natural Gas (US$ / MCF) (0.18) (0.16) (0.19) (0.17)

Oil and Gas Revenues (US$ MM)

Liquids sales 242.6 197.8 333.0 1,213.0 Gas sales 411.7 339.8 353.6 1,590.1

Total Oil and Gas Revenues 654.29 537.6 686.6 2,803.0

Oil and Gas Costs and Expenses (US$ MM)

Production costs (incl. prod taxes) (157.8) (173.2) (159.5) (575.0) Other operating costs 0.0 0.0 0.0 0.0 General and administrative 0.0 0.0 0.0 0.0 Exploration expense 0.0 0.0 0.0 0.0 Impairment costs 0.0 0.0 0.0 0.0 Book DD&A (181.2) (183.6) (196.2) (570.0)

Total Oil and Gas Costs and Expenses (339.0) (356.8) (355.7) (1,145.0)

Oil and Gas Earnings B4 Int & Tax (EBIT) 315.3 180.8 331.0 1,658.0

Oil and Gas Income Taxes (US$ MM) (111.7) (64.8) (139.7) (643.0)

Oil and Gas Net Inc (NOPAT) (US$ MM) 203.6 116.0 191.3 1,015.0

Note: Oil and Gas EBITDAX (US$ MM) 496.4 364.4 527.2 2,228.0

Oil and Gas Disclosure: Select Income,

Cash Flow and Operating Data (cont'd) FYE Dec 31 FYE Dec 31 (US$ MM) 1997A 1998A 1999A 2000A Oil and Gas Analyst Cash Flow

Net Income 203.6 116.0 191.3 1,015.0

Anadarko Petroleum Corporation

Full-Cycle Economic Costs



Full-cycle costs are the total

capital and operating costs of

producing oil



Full cycle costs are sum of

–

Reserve replacement cost

–

+ Production cost



Full cycle costs generally

exclude G&A, interest and

transportation costs



A company’s full cycle costs

are very much tied to the

region(s) in which it operates

U .S . L a rg e -C a p E x p lo r a tio n a n d P r o d u c tio n S e c to r Y e a r 2 0 0 0 F u ll C yc le E c o n o m ic s ($ /B O E ) H is to ric a l F u ll C yc le E c o n o m ic s ($ /B O E ) 3 -Y r A ll S o u rc e s 2 0 0 0 L e a s e 2 0 0 0 F u ll-C yc le R e s e rv e R e p la c e - O p e ra tin g G & A E c o n o m ic 3 -Y r A v e r a g e (6 M C F / B b l) m e n t C o s ts E x p e n s e s C o s t C o s ts 2 0 0 0 1 9 9 9 1 9 9 8 (1 9 9 8 -0 0 ) B u rlin g to n 5 .8 0 7 .1 6 0 .0 0 1 2 .9 6 1 2 .9 6 1 1 .1 1 1 1 .4 2 1 1 .8 3 O c e a n E n e rg y 6 .0 8 5 .1 8 0 .0 0 1 1 .2 7 1 1 .2 7 1 1 .0 0 1 2 .4 3 1 1 .5 6 K e rr -M c G e e 5 .5 9 5 .8 4 0 .0 0 1 1 .4 3 1 1 .4 3 1 0 .9 8 1 3 .3 3 1 1 .9 1 P io n e e r N a t R e s 6 .9 4 5 .8 9 0 .0 0 1 2 .8 3 1 2 .8 3 1 2 .1 6 1 2 .8 4 1 2 .6 1 D e v o n E n e rg y 6 .5 7 4 .9 4 0 .0 0 1 1 .5 0 1 1 .5 0 9 .2 9 9 .6 3 1 0 .1 4 X T O E n e r g y 3 .8 1 5 .2 6 0 .0 0 9 .0 7 9 .0 7 8 .8 3 8 .7 8 8 .8 9 A n a d a r k o P e tro le u m 6 .3 0 5 .1 7 0 .0 0 1 1 .4 7 1 1 .4 7 7 .0 8 7 .0 2 8 .5 3 U n o c a l C o rp . 7 .1 0 3 .8 2 0 .0 0 1 0 .9 2 1 0 .9 2 1 0 .5 3 1 1 .4 3 1 0 .9 6 N o b le A ffilia te s 7 .6 5 4 .3 1 0 .0 0 1 1 .9 6 1 1 .9 6 9 .1 9 1 0 .9 4 1 0 .7 0 A p a c h e C o rp . 5 .6 1 3 .2 3 0 .0 0 8 .8 4 8 .8 4 8 .5 5 8 .9 2 8 .7 7 E O G R e s o u r c e s 5 .8 7 3 .2 5 0 .0 0 9 .1 1 9 .1 1 7 .5 5 5 .6 8 7 .4 5 M e a n $ 6 .1 2 $ 4 .9 1 $ - $ 1 1 .0 3 $ 1 1 .0 3 $ 9 .6 6 $ 1 0 .2 2 $ 1 0 .3 0 M e d ia n $ 6 .0 8 $ 5 .1 7 $ - $ 1 1 .4 3 $ 1 1 .4 3 $ 9 .2 9 $ 1 0 .9 4 $ 1 0 .7 0

The Full-Cycle Cost of Oil ($/Bbl) Regional Basis

Iraq 2.50 Other Latin America 5.52 Kazakhstan 7.00 Western Canada 9.25 Kuwait 3.80 Alaska 5.70 Mexico 7.20 North Sea 9.85 Saudi Arabia 4.00 Nigeria 5.75 US Lower 48 8.10 Indonesia 10.50 Venezuela 4.23 Oman 6.25 China-Onshore 8.90 China Offshore 11.80 Iran 4.50 Algeria 7.00 Angola 9.00 Brazil 12.50 Abu Dhabi 5.00 Western Siberia 7.00 US GOM 9.00 US Stripper Wells 15.17

Landscape of E&P Costs

Economics of the Large Cap E&P Sector

$18.50 Oil 15.1% 18.7% 0 2 4 6 8 10 12 14 16 18 20 $3 $5 $7 $9 $11 $13 9.0% Large Cap E&P Cost of Capital

$14.00 Oil

$16.00 Oil

$18.00 Oil

$19.72 Oil (10-yr Average WTI Price [1990-99]) (%) 1.1% 4.6% 8.1% 11.2% $22.00 Oil 9.0% $24.00 Oil

Returns and Full-Cycle Economics(1)(2)

Return on Capital Employed (%)

Notes

1. Returns calculated on replacement cost basis: ROCE equals NOPAT/replacement cost capital where (a) NOPAT equals EBITDAX less replacement cost of production less

Full-Cycle Economics ($/boe)

(Reserve Replacement Cost + Operating Cost [$/boe])



Full-Cycle Costs ($/bbl)

Reserve Replacement $6.50 Operating Cost3.57 Full-Cycle Cost$10.07



Cash Break-Even

WTI Price ($/bbl)

Full-Cycle Cost$10.07 Gen. & Admin. 1.00 Differential to WTI2.28 Break-Even WTI$13.35



At current costs and $18.50 oil

prices, the large cap companies

exactly earn their cost of capital



E&P companies have found it

devilishly hard to return their

cost of capital

– Capital-intensive business

– Historical lack of capital discipline

– Dependent on commodity

prices, which can fluctuate

Calculating ROCE’s in the E&P Sector

Pioneer Nat Res ROCE Calculations FYE Dec 31 FYE Dec 31 (US$ MM) 1997A 1998A 1999A 2000A (1) ROCE I

This is traditional ROCE: uses actual cash taxes and capital at historical cost from balance sheet (a) Reported NOPAT

Operating EBIT (B4 Expl Expense) 124 59 201 407 Less: Unlevered Cash Taxes (26) (66) (70) (61)

NOPAT (After-Tax EBIT) 98 (7) 131 345

(b) Capital Employed (Historical Cost)

Total Debt 1,950 2,175 1,746 1,579 Less: Cash (73) (59) (35) (26)

Minority Interest 0 0 0 0

Preferred Stock at Book Value 0 0 0 0 Common Equity at Book Value 1,549 789 775 905

Capital Employed 3,425 2,905 2,486 2,458

(c) ROCE I

Reported NOPAT 98 (7) 131 345 Capital Employed, beginning 3,425 3,425 2,905 2,486

ROCE 2.9% (0.2%) 4.5% 13.9%

(2) ROCE II

This ROCE is like (1) above except that it keeps running tally of invested capital using EVA framework (a) Reported NOPAT

Operating EBIT (B4 Expl Expense) 124 59 201 407 Less: Unlevered Cash Taxes (26) (66) (70) (61)

NOPAT (After-Tax EBIT) 98 (7) 131 345

(b) Capital Employed (EVA Method)

Invested Capital: Beginning --- 3,498 3,592 3,207 Addition: Net New Investment --- 94 (385) 24

Invested Capital: Ending 3,498 3,592 3,207 3,230

(c) ROCE II

Reported NOPAT 98 (7) 131 345 Capital Employed, beginning 3,498 3,498 3,592 3,207

ROCE 2.8% (0.2%) 3.6% 10.8%

Pioneer Nat Res Returns on

Capital Employed (ROCE) FYE Dec 31 FYE Dec 31 (US$ MM) 1997A 1998A 1999A 2000A (3) ROCE III

This ROCE is like (1) above except that NOPAT is adjusted to have uniform tax rate (across this and other companies) (a) Tax-Adjusted NOPAT

Operating EBIT (B4 Expl Expense) 124 59 201 407 Less: Assumed Taxes (35%) 35% (44) (21) (70) (142)

NOPAT (After-Tax EBIT) 81 38 131 264

(b) Capital Employed (Historical Cost)

Total Debt 1,950 2,175 1,746 1,579 Less: Cash (73) (59) (35) (26)

Minority Interest 0 0 0 0

Preferred Stock at Book Value 0 0 0 0 Common Equity at Book Value 1,549 789 775 905

Capital Employed 3,425 2,905 2,486 2,458

(c) ROCE III

Tax-Adjusted NOPAT 81 38 131 264 Capital Employed, beginning 3,425 3,425 2,905 2,486

ROCE 2.4% 1.1% 4.5% 10.6%

FYE Dec 31 FYE Dec 31 1997A 1998A 1999A 2000A (4) ROCE IV

This ROCE is like (3) above except that it keeps running tally of invested capital using EVA framework (a) Tax-Adjusted NOPAT

Operating EBIT (B4 Expl Expense) 124 59 201 407 Less: Assumed Taxes (35%) 35% (44) (21) (70) (142)

NOPAT (After-Tax EBIT) 81 38 131 264

(b) Capital Employed (EVA Method)

Invested Capital: Beginning --- 3,498 3,592 3,207 Addition: Net New Investment --- 94 (385) 24

Invested Capital: Ending 3,498 3,592 3,207 3,230

(c) ROCE IV

Tax-Adjusted NOPAT 81 38 131 264

Capital Employed, beginning 3,498 3,498 3,592 3,207

ROCE 2.3% 1.1% 3.6% 8.2%

Pioneer Nat Res Returns on

Capital Employed (ROCE) FYE Dec 31 FYE Dec 31 (US$ MM) 1997A 1998A 1999A 2000A (5) ROCE V

This is meant to be best economic ROCE measure for an E&P company; accounting-warped DD&A is replaced with economic cost of generating associated EBITDAX (i.e., production times reserve replace-ment cost); actual taxes are used; and accounting-capital is replaced w/ economic cost of replacing capital (a) Normalized NOPAT

EBITDAX 337 397 437 621

Less: Replacement Cost of Production (249) (544) (427) (302) Less: Unlevered Cash Taxes (26) (66) (70) (61)

Normalized NOPAT 61 (214) (60) 258

(b) Replacement Cost Capital

Proved Reserves Bgn Yr (MMBOE 6:1) 302 762 677 605 3-Yr Avg Reserve Repl Cost ($/BOE) 7.04 8.65 8.36 6.94 Replacement Cost of Reserves 2,127 6,590 5,659 4,203 Net Working Capital and Other Assets (91) (129) (17) (57)

Replacement Cost Capital 2,036 6,461 5,641 4,146

(c) ROCE V

Normalized NOPAT 61 (214) (60) 258

Replacement Cost Capital 2,036 6,461 5,641 4,146

ROCE 3.0% (3.3%) (1.1%) 6.2%

(d) Replacement Cost of Production

Production in Year (MMBOE 6:1) 35.4 62.9 51.1 43.6 3-Yr Avg Reserve Repl Cost ($/BOE) 7.04 8.65 8.36 6.94 Replacement Cost of Production 249 544 427 302

Pioneer Nat Res Returns on

Capital Employed (ROCE) FYE Dec 31 FYE Dec 31 (US$ MM) 1997A 1998A 1999A 2000A (6) ROCE VI

This ROCE is like (5) above except that NOPAT is adjusted to have uniform tax rate (across all companies) (a) Tax-Adjusted Normalized NOPAT

EBITDAX 337 397 437 621

Less: Replacement Cost of Production (249) (544) (427) (302) Less: Assumed Taxes (35%) 35% (31) 52 (4) (112)

Tax-Adjusted Normalized NOPAT 57 (96) 7 207

(b) Replacement Cost Capital

Proved Reserves Bgn Yr (MMBOE 6:1) 302 762 677 605 3-Yr Avg Reserve Repl Cost ($/BOE) 7.04 8.65 8.36 6.94 Replacement Cost of Reserves 2,127 6,590 5,659 4,203 Net Working Capital and Other Assets (91) (129) (17) (57)

Replacement Cost Capital 2,036 6,461 5,641 4,146

(c) ROCE VI

Tax-Adjusted Normalized NOPAT 57 (96) 7 207

FYEDec 31 FYE Dec 31 EVAAnalysis (US$ MM) 1997A 1998A 1999A 2000A Net Operating Profit After Tax (NOPAT)

Recurring EBIT (B4 Expl Expense) 124.3 59.2 201.2 406.5 Other Recurring Cash Income 23.2 55.6 88.8 39.8 Less: Cash Taxes (Unlevered) (26.4) (66.1) (70.5) (61.3)

NOPAT 121.1 48.7 219.5 385.0 Cash Taxes (Unlevered)

Cash Taxes (Levered) 35% 0.7 (8.6) (10.8) (4.6) Addback: Tax Savings fromInterest (35.0%) (27.1) (57.5) (59.6) (56.7)

Cash Taxes (Unlevered) (26.4) (66.1) (70.5) (61.3) Net Capital Expenditures

Total Gross Cap Expenditures (456.9) (538.9) (191.5) (299.7) Other Sources / Uses of Cash 0.0 0.0 0.0 2.4 Proceeds fromAsset Sales 115.7 21.9 390.5 102.7 Less: DD&A(proxy for Maintenance Capex) 212.4 337.3 236.0 214.9

Net Capital Expenditures (128.7) (179.7) 435.0 20.4 Net New Investment

Net Capital Expenditures (128.7) (179.7) 435.0 20.4 Investment in Net Working Capital (39.3) 86.0 (49.6) (44.0)

Net NewInvestment (168.0) (93.7) 385.5 (23.6) Unlevered Free Cash Flow

NOPAT 121.1 48.7 219.5 385.0 Less: Net NewInvestment (168.0) (93.7) 385.5 (23.6)

Unlevered Free Cash Flow (47.0) (45.0) 605.0 361.5 Check (Two Free Cash Flows equal [=0?]) Correct (0.0) 0.0 0.0 0.0 Invested Capital Howabout purchase accounting adjustments?

Invested Capital: Beginning --- 3,498.4 3,592.0 3,206.6 Addition: Net NewInvestment --- 93.7 (385.5) 23.6 Invested Capital: Ending 3,498.4 3,592.0 3,206.6 3,230.1

Economic Profit

Capital charge (WACC [8.0%] * IC) 8.0% 280 287 257 Economic profit (NOPAT - Cap charge) (231) (68) 128 ROIC(NOPAT / Beginning Invested Capital) 1.4% 6.1% 12.0% Economic Profit (ROIC - WACC) * IC (231) (68) 128

So Many Choices, So Little Time...

Glossary of Key Petroleum Terms

 Abandon – To discontinue attempts to produce oil or gas from a well or lease and to plug the reservoir in accordance with

regulatory requirements.

 AFE (Authority for Expenditure) – A form used during the planning process for a well about to be drilled. It includes an

estimate of costs to be incurred in the IDC category and in the tangible equipment category. The form represents a budget for the project against which actual expenditures are compared.

 Associated gas – Natural gas, occurring in the form of a gas cap, overlying an oil zone.

 Behind Pipe – Reserves expected to be recovered from zones in existing wells which will require additional completion

work or future recompletion prior to the start of production.

 Bonus – The consideration paid by the lessee to the lessor upon execution of an oil and gas lease.

 Carried interest – An agreement under which one party (carrying party) agrees to pay for a portion or for all of the

development and operating costs of another party (carried party) on a property in which both own a portion of the working interest. The carrying party is able to recover a specified amount of costs from the carried party’s share of the revenue from production, if any, from the property.

 Christmas tree – A term applied to the valves and fittings assembled at the top of a well to control the flow of oil.

 Completion – Refers to the work performed and the installation of permanent equipment for the production of oil or gas

from a recently drilled well.

 Condensate – A light hydrocarbon liquid which is in a gaseous state in the reservoir but which becomes liquid at the

surface.

 Conveyance – The assignment or transfer of mineral rights to another person.

 Cost center – The geological, geographical, or legal unit with which costs and revenues are identified and accumulated.

Examples are the lease, the field, and the country.

 Depletion – Amortization of capitalized costs of a mineral property. The deduction is based upon minerals produced. For

Federal income tax purposes depletion may be based on the amount of gross income from the property.

Glossary of Key Petroleum Terms (Cont’d)

 Development well – A well drilled to gain access to oil or gas classified as “proved reserves.”

 Dry hole – An exploratory or development well that does not produce oil or gas in commercial quantities.

 Estimated Ultimate Recovery (EUR) – The amount of oil and gas expected to be economically recovered from a reservoir

or field by the end of its producing life. Estimated ultimate recovery can be referenced to a well, a field, or a basin.

 Exploration well – All wells drilled to search for or produce oil or gas, except development wells and development-type

stratigraphic test wells drilled to gain access to proved reserves.

 Farm-out – Transfer of all or part of the operating rights from the working interest owner to an assignee, who assumes all

or some of the burden of development, for an interest in the property. The assignor usually retains an overriding royalty but may retain any type of interest.

 Field – An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual

geologic structural feature and/or stratigraphic feature.

 Fluid injection – Inducing gas or liquids into a reservoir to move oil toward the well bore.

 Fracturing / Fracing – A procedure to stimulate production by forcing under high pressure a mixture of oil ad sand into the

formation.

 Gravity – A standard API gravity scale which is related to specific gravity of a petroleum fluid based on a technical formula.

Glossary of Key Petroleum Terms (Cont’d)

 IDC (Intangible Drilling Cost)–Any cost which in itself has no salvage value and is necessary for and incident to the

drilling of wells and getting them ready for production. IDC can also occur when deepening or plugging back a previously drilled oil or gas well, or an abandoned well, to a different formation. IDCs are expensed for tax purposes, which result in companies that actively drill having a very low tax liability.

 IP (Initial Production)–The measurement of a well's production at the outset. Often measured either over 24 hours or

30-days.

 Lease–(1) A contract in which the owner of minerals gives an oil company the right to explore for, develop, and produce

minerals from the property. (2) Any transfer where the owner of a mineral interest assigns all or part of the operating rights to another party but retains a continuing non-operating interest in production from the property.

 Lifting costs–Costs of operating wells for the production of oil and gas (producing costs), loosely analogous to LOE, or

Lease operating costs

 Net profits interest (NPI)–An interest in production created from the working interest and measured by a certain

percentage of the net profits (as defined in the contract) from the operation of the property.

 Non-operating interest–An interest in minerals. The holder of this interest does not have the responsibility or bear the

cost of developing and producing the minerals.

 Net revenue interest (NRI)–A share of production after all burdens, such as royalty and overriding royalty, have been

deducted from the working interest. It is the percentage of production that each party actually receives.

 Offset well–Well drilled on one tract of land to prevent drainage of oil or gas to a nearby tract on which a well has been

drilled.

 Operator–Organization that obtains (buys or leases) the right to drill and produce oil and/or natural gas from the owner of

a specified location. The operator of an oil or gas well or field.