Citi_E&P Valuation Primer

Introduction to the Upstream Sector

Table of Contents

Additional Resources6.

Glossary5.

E&P Ratio Analysis4.

Understanding the Upstream P&L3.

E&P Valuation2.

Introduction1.

1. Introduction

What are Hydrocarbons?

Fossil Fuels

Crude Oil

Petroleum Coal

NGL

Natural Gas

SourWetDry/SweetOil SandsHeavy OilConventional

OilCondensate

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

Crude Oil = Primary Transportation Fuel Natural Gas = Electricity Generation

Distillates/Heavy Fuel Oil - 5

Oil and Natural Gas are not substitute products; there is no arbitrageopportunity from pricing anomalies

2

Spindletop, TX, 1901: The Birth of Modern Energy

http://www.priweb.org/ed/pgws/history/spindletop/spindletop.html3

Energy Value Chain

Exploration

Production

Production

Processing

Transportation Refining

Transportation Marketing

Marketing

Midstream DownstreamUpstream

CrudeOil

NaturalGas

4

Illustrative Well Production Profile

0

1,000

2,000

3,000

4,000

5,000

2 52 102 152 202 252 302

Months

Da

ilyP

rod

uctio

n(M

Mcfe

/d

) Initial Drilling & Completion (D&C) Cost: $5.00 millionInitial 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. Effectiveredeployment of that cash is the key to generating return for shareholders.

5

Oil and Gas Reserve Classification

Oil and GasReserves

Developed(PD)

Unproved Proved(1P)

Undeveloped(PUD)

ProbablePossible

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 certaintythat such reserves will be produced as well as costs involved todevelop them

Proved reserves is only class where one definition has developedgeneral acceptance among petroleum engineers

Proved Reserves = 1P

1P + Probable Reserves = 2P

2P + Possible Reserves = 3P

6

$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 Ratio

Commodity Prices Over Time

7

Oil

Pri

ce

($/B

bl)

Oil

/G

as

Ratio

Gas

Price

($/M

cfe

)

Historical relationships between oil and gas prices changed beginning in 2008 due to the emergence ofshale 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 oilequivalent 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 oilequivalent using a ratio other than a 6:1 ratio

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

6:1 reflects strict calorific equivalence

10:1 is actually standard reporting equivalence in Canada

8

Proved Reserves Disclosure

9

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 Value $9,471

Plus: Debt 2,563

Less: Cash (521)

Other Adjustments 109.4

Firm Value $11,623

Operating Metrics

Proved Reserves (MMBoe) 987

PV-10 $4,894

Valuation Metrics

($ / Boe) $11.77

Firm Value / PV-10 2.4x

10

SEC PV-10 Disclosure

11

Costs Incurred Disclosure

12

2. E&P Valuation

Valuation Overview

Firm Value

Future DevelopmentOpportunities Value

Proved Reserves Value

13

Wide Range of Valuation Methodologies

M&

AM

ark

et

Fo

cu

s

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 earningsvisibility

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

?

P / E

P / CFPS ?

14

Valuation Methodologies

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

Applicability limited to M&A transactions due toinclusion of acquisition premium

Does not factor in specific operating or riskcharacteristics of the asset

Comparables universe difficult to determine

Good proxy in M&A transactions; factorsacquisition premium

Proxy for value based on industry average

Precedent

Transactions

Not applicable in M&A transactions; does notfactor in acquisition premium

Does not factor in specific operating or riskcharacteristics of the asset

Comparables universe difficult to determine

Reflects asset value as an ongoingoperation

Proxy for value based on industry average

Trading

Comparables

Requires considerable data gathering, e.g. hostgovernment, geophysicists, petroleumengineers, tax advisors, etc

Estimation of expected production profile andrevenues involves a certain degree ofuncertainty and risk

Allows incorporation of operatingcharacteristics of the asset, based ongranular and detailed analysis

Factors any associated risks into the valueof the asset

Enables sensitivity analysis based onspecific parameters

NAV / DCF

Pros Cons

15

NAV Methodology: Assumptions

Citi evaluated the net asset value (NAV) of UltraPetroleums oil and gas assets in the Marcellus Shaleand the Pinedale and Jonah Fields in Wyoming

Well economics drilled in Jonah assumed to be thesame as Pinedale wells

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

NAV calculated based on a development plan builtup from a projected rig count, current acreage, andapplying an assumed type curve and well-levelassumptions

Current PDP based on historical drilling tomore accurately capture PDP decline curveversus 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 hedgeprogram, the decrease in value attributable toG&A needs of a going concern, non-drillingcapex, and income taxes

Base case price assumption based on 4/15/11 NYMEXstrip 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 InvestorPresentation andpeer declinerates

--HPDI--Type Curve

UPL 4Q10Transcript

Net Wells /Working Interest

UPL 3Q10Transcript

Company 10K

UPL 3Q10Transcript

11/4/10 UBSResearch

1/12/11 InvestorPresentation


UPL 3Q10Transcript

UPL 3Q10Transcript

Peer assumption


--


Source



5-10 acres; UPL4Q10 Transcript

Company 10K


UPL 2008Reserve Report



UPL 3Q10Transcript

UPL 3Q10Transcript

UPL 3Q10Transcript


UPL 2008Reserve Report

HPDI

Source

3,0002,964Net Remaining Well Locations

6,6675,335Gross Well Locations (5)

260,00044,000Undeveloped Net Acreage

80

10

86%

45.0%

$4.8(1)

Included inLOE and Capex

$0.24

5%

102%

--

4.2(1)

Marcellus

$0.29 (3)Gathering and TransportationCost ($ / Mcfe)

17Spud 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

16

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)

0

200

400

600

800

1,000

1,200

1,400

1,600

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

PDP Pinedale Marcellus

Net

Pro

du

cti

on

(MM

cfe

/d)

(1)Total = 6,007

(2)

(2)

Total (Bcfe)

Notes: (1) Pinedale wells based on company disclosed total gross wells as of 12/31/09 less expected wells brought online in 2010 (55% working interest). Marcellus gross well locations based on3,000 net locations and 45% working interest per 4Q10 transcript.(2) Excludes PDP of 1,744 Bcfe.

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

Net Wells Drilled

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

Net Production by Area (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)

Daily Production Profile by Play (MMcfe/d)

17

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

18

$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

PDP (PV-10) Rockies (PV-10) M arcellus (P V-10)

Total ResourceValue

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 ValueBase 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

Notes: (1) 5-year NYMEX strip prices as of 4/15/11.(2) Assumes 2010 G&A capitalized at 10x.(3) Cash taxes post G&A. Discounted at 10%. Assumes 40% income tax rate.(4) Assumes 75% location risking (no change to PDP value or production). Rockies and Marcellus risked PV-10 of $3,284mm and $2,685mm.

(4)

ImpliedSharePrice

$70.01Relative to

Current

45%

19

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

Months1 12 24 36 48 60

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

Company Working Interest 45.0%

Net Revenue Interest 86.0%

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

Net F&D Costs ($/mcfe) $1.33

Net LOE ($/mcfe) 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%

Co

mm

od

ity

Pri

ce

($/B

bl/$/M

MB

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

Co

mm

od

ity

Pri

ce

($/B

bl/$/M

MB

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%

Co

mm

od

ity

Pri

ce

($/B

bl/$/M

MB

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

Co

mm

od

ity

Pri

ce

($/B

bl/$/M

MB

tu)

Pro

duction

(Mcfe

/d)(2)

20

NAV Methodology: Consolidated Reserve Summary($m), unless otherwise noted

Gross Net Net Production Total Net Benchmark Commodity Prices Realized Commodity Prices

Wells Wells Oil Natural Gas Production Oil Natural Gas Oil Natural Gas NGLYear 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 Completion Cash Flow PV-10Year ($M) ($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

2024 291,309 3,430,411 3,721,720 355,990 236,668 117,372 3,011,690 947,063 2,064,627 569,816

2025 298,507 3,514,790 3,813,297 364,214 242,154 119,858 3,087,071 939,793 2,147,278 538,778

Rem. 7,077,449 97,209,313 104,286,761 8,812,407 5,939,498 2,444,000 87,090,857 14,083,233 73,007,624 5,714,525

Total $10,468,855 $135,726,108 $146,194,963 $12,879,033 $8,705,659 $3,843,361 $120,766,910 $28,230,229 $92,536,680 $13,908,868

21

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

2011EEBITDA 1.5x 1.4x 0.6x 1.9x 1.3x 2.4x 1.2x 1.4x 1.8x

2012EEBITDA 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

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

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

Valuation Metrics

Price /

2011ECFPS 7.8x 8.5x 8.5x 7.4x 11.9x 9.2x 5.9x 9.8x 7.9x

2012ECFPS 7.0 6.7 6.7 5.3 9.3 7.7 4.9 7.3 5.6

Firm Value /

2011EEBITDA 8.7x 10.1x 8.9x 7.8x 11.9x 11.0x 6.7x 10.1x 10.1x

2012EEBITDA 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

Source: John S. Herold, Inc.(1) Adjusted based on 12/7/10 strip of $89.90 / Bbl and $4.54 / MMBtu

(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

2010/03/15Fidelity E&P; MDU

ResourcesUndisclosed 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 WhitingChicago Energy

AssociatesUinta 365 115 19.0 98 22 16.6 3.17 19,211 1.34 8,136

2007/06/04 XTO Dominion 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 CompaniesRaton/Hugoton/San

Juan400 311 60.0 100 77 14.2 1.20 6,232 1.06 5,499

2003/03/11Sacramento Municipal

Utility DistrictEl 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 $8,984Median 100 60 18.3 1.22 8,625 1.08 7,310

23

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

2010/11/15 Newfield Exploration EOG Resources Marcellus $405.0 50,000 $8,1002010/11/09 Chevron Atlas Energy Marcellus 3,703.0 342,000 7,084

2010/10/06 Chesapeake Energy Anschutz Exploration Marcellus 850.0 500,000 1,7002010/09/22 Atinum Partners Gastar Exploration Marcellus 70.0 17,100 4,0942010/08/31 Sumitomo Rex Energy Marcellus 140.0 15,555 9,0002010/07/20 Trans Energy Republic Energy Marcellus 27.0 3,800 7,1052010/08/05 Reliance Industries Carrizo Oil & Gas Marcellus 392.0 62,600 6,2622010/05/28 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 1,9502010/05/10 BG Group EXCO Resources Marcellus 950.0 93,000 8,0732010/04/21 Atlas, Reliance Undisclosed Marcellus 191.9 42,344 4,5322010/04/09 Reliance Industries Atlas Energy Marcellus 1,700.0 120,000 14,1672010/03/26 Statoil Hydro Chesapeake Energy Marcellus 253.0 59,000 4,2882010/03/15 CONSOL Energy Dominion Resources Marcellus 3,475.0 491,393 4,7972010/03/02 EQT Undisclosed Marcellus 280.0 58,000 4,8282010/02/16 Mitsui Anadarko Marcellus 1,400.0 100,000 14,0002010/01/19 Chesapeake Energy Epsilon Energy Marcellus 100.0 5,750 10,5302009/12/21 Ultra Petroleum NCL Appalachian Partners Marcellus 400.0 80,000 5,0002009/10/29 Magnum Hunter Resources Triad Energy Marcellus 81.0 47,000 1,0002009/09/30 Chesapeake Energy Wyoming County Landowners Group Marcellus 212.8 37,000 5,7512009/09/30 Fortuna Energy Friendsville Group Marcellus 192.0 35,000 5,4862009/09/18 Undisclosed Epsilon Energy Marcellus 12.7 3,734 3,4012009/08/19 Enerplus Resources Chief Oil & Gas Marcellus 406.0 116,000 3,5002009/06/22 Williams Companies Rex Energy Marcellus 33.0 22,000 1,5002009/06/09 Kohlberg Kravis Roberts East Resources Marcellus 350.0 650,000 5382008/11/11 Statoil Hydro Chesapeake Energy Marcellus 3,375.0 585,000 5,7692008/11/04 Carrizo Oil & Gas Avista Capital Partners Marcellus 71.5 77,500 9232008/06/30 Antero Resources Dominion Resources Marcellus 347.0 114,259 3,0372008/04/15 XTO Energy Linn Energy Marcellus 600.0 152,000 1,645

Mean JV $6,696Median JV 6,016

Mean M&A $4,047Median 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 valuesat $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 toflow through rock(permeability)

Some rock tougher to drill

Attractive Location

Relative supply and demandfor the commodity

Rockies vs. Appalachia

Proximity to TransportationInfrastructure

Friendly operatingenvironment

Alaska vs. West Texas

Low Costs

Shallow reservoir = lower costdrilling

Low operating costs

Low water cut

Infrastructure in place(roads, electricity, etc)

Fiscal regime

Good Oil & Gas Property = Good Real Estate

25

3. Understanding the Upstream P&L

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 apercentage 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 varywidely

A typical lease gives a company (lessee) a period of three to five years to generate commercialproduction 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 companys drilling plans as companieswill 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 inlocking up acreage

Leasing terms from the federal government tend to be more favorable due to longer lease terms

More common in the Rockies

26

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 whethera company chooses full cost orsuccessful efforts accounting

Added back to calculate EBITDAX forcomparability purposes

DD&A calculation is complex

Differential

27

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

Wells drilled per year = rigs operating * (365 / spud-to-spud)

28

Illustrative Horizontal Well Bore SchematicDenson 2H-15

Denson 2H-15200' 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

49

30

La

tera

ls

49

30

La

tera

ls

5280

660330 660

175 175

175 175

660 x 7 + (330 + 330) = 5,280

330

1 section = 640 acres, or 1 square mile

30

Realizing Pricing Subject to Many Issues

RealizedPricing

BenchmarkPricing

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

MB

tu

Centerpoint East Panhandle East Henry Hub

A: REX West Pipeline goes into service.B: Texas Gulf Crossing Pipeline goes into service.

C: Midcontinental Express Pipeline goes into service.D: REX East Pipeline goes into service.

A B C DFall 08 Financial Crisis

32

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 Effortsfrom lower expense associated with dry holes

In theory, identical cash from operations relativeto Successful Efforts

Preference of smaller companies with morevolatile earnings

More stringent ceiling test required to avoid buildup of unrecovered costs

Carrying value compared to after-tax, pre-G&APV-10 of cash flow

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

Successful Efforts

Capitalize only costs of successful wells

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

Lower carrying value of PP&E

Generally, lower earnings than Full Cost fromhigher expense associated with dry holes

In theory, identical cash from operations relativeto Full Cost

Preference of larger companies

Unusual to book asset impairments due to regularexpensing of unsuccessful efforts

Carrying value compared to pre-tax, pre-G&A,undiscounted value of cash flow

33

4. E&P Ratio Analysis

Reserve Replacement Cost and Rate

Reserve Replacement Costs per boe (RRC) are computed by taking total costs incurred (proved andunproved property acquisition costs, exploration costs and development costs) during the applicableperiod as the numerator and dividing by the total oil equivalent reserve changes associated withdiscoveries and extensions, revisions in estimates, improved recovery and purchase of proved reservesin place as the denominator

Reserve Replacement Rates are computed by dividing production for the period into the total reservechanges for the period used in the denominator for computing RRC reduced by volumes sold during theperiod

Pioneer Nat Res Summary Worldwide 7 5 3Capital 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 30.9 117.0 175.4Reserve 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

34

F&D Cost and Rate

Finding and Development Costs per boe (FDC) are computed by taking as the numerator total costsincurred less costs of proved property acquisitions and dividing by a denominator comprised of the totaloil equivalent reserve changes for the period associated with discoveries and extensions, revisions inestimates and improved recoveries (costs associated with proved property purchases are excluded)

Finding and Development Replacement Rates are computed by dividing production for the period intothe total reserve changes associated with discoveries and extensions, revisions in estimates andimproved recoveries

Pioneer Nat Res Summary Worldwide(2) Finding & Development Worldwide United States

(d) Finding & Development Costs 2000 1998-00 1996-00 2000 1998-00 1996-00Costs Incurred (US$ MM)Unproved property acquisition 31$ 37$ 581$ 28$ 65$ 162$Exploration 131 323 458 65 170 290Development 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 23.1Improved 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 91.9 219.0Finding & 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 RateReserves Added (MMBOE) 65.5 129.9 257.9 45.8 91.9 219.0Production (MMBOE) 43.6 157.5 216.8 30.9 117.0 175.4Reserve 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 1996-00Costs 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 23.1Improved recovery - - - - - -

Reserves Added (MMBOE) 38.0 59.2 66.6 15.9 17.0 23.1Finding & Development Cost (US$ / BOE) 7.99$ 15.29$ 30.07$ 11.20$ 34.85$ 52.88$

(g) Reserve Replacement RateReserves Added (MMBOE) 38.0 59.2 66.6 15.9 17.0 23.1Production (MMBOE) 43.6 157.5 216.8 30.9 117.0 175.4Reserve Replacement Rate (%) 87% 38% 31% 52% 15% 13%


35

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 1996-00Costs Incurred (US$ MM)Exploration 131 323 458 65 170 290Development 142 544 965 85 358 770

Costs Incurred (US$ MM) 273$ 868$ 1,423$ 150$ 528$ 1,060$Reserves Added (MMBOE) 38.0 59.2 66.6 15.9 17.0 23.1Finding & Development Cost (US$ / BOE) 7.17$ 14.66$ 21.36$ 9.42$ 31.01$ 45.87$

(i) Reserve Replacement RateReserves Added (MMBOE) 38.0 59.2 66.6 15.9 17.0 23.1Production (MMBOE) 43.6 157.5 216.8 30.9 117.0 175.4Reserve 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 1996-00Cost of proved property acquisition ($ MM) 36$ 99$ 3,457$ 26$ 47$ 2,686$Reserves added through proved acq (MMBOE) 7.4 14.7 474.6 5.9 5.9 320.7Proved Reserve Replacement Cost (US$ / BOE) 4.90$ 6.73$ 7.28$ 4.41$ 7.89$ 8.38$

(k) Reserve Replacement RateReserves added through proved acq (MMBOE) 7.4 14.7 474.6 5.9 5.9 320.7Production (MMBOE) 43.6 157.5 216.8 30.9 117.0 175.4Reserve Replacement Rate (%) 17% 9% 219% 19% 5% 183%


36

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 BOEOil 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

DD&A 181.2 183.6 196.2 570.0

Exploration Expense + Impairment 0.0 0.0 0.0 0.0

Deferred Taxes (48.3) (4.5) (68.1) (553.7)

Oil and Gas Analyst Cash Flow 336.5 295.1 319.4 1,031.3

Oil and Gas Capital Expenditures

Acquisitions (55.6) (177.3) (92.9) (7,047.0)

Exploration (231.1) (305.2) (206.7) (415.0)

Development (363.7) (377.2) (353.5) (1,054.0)

Total Oil and Gas Capital Expenditures (650.4) (859.7) (653.1) (8,516.0)

Approximate Oil and Gas Free Cash Flow (314.0) (564.6) (333.7) (7,484.7)Source of data 12/97 10-K 12/98 10-K 12/99 10-K 12/00 10-K

Anadarko Petroleum Corporation

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Full-Cycle Economic Costs

Full-cycle costs are the totalcapital and operating costs ofproducing oil

Full cycle costs are sum of

Reserve replacement cost

+ Production cost

Full cycle costs generallyexclude G&A, interest andtransportation costs

A companys full cycle costsare very much tied to theregion(s) in which it operates

U .S . La rg e-C ap E xp lo ra tio n and P ro duction S ec to r

Y ear 2000 F u ll C yc le E co no m ics ($ /B O E ) H is to rical F u ll C ycle E co n o m ics ($ /B O E )

3-Y r All S o u rces 2000 L ease 2000 F u ll-C ycle

R eserve R ep lace - O p era tin g G & A E co n o m ic 3 -Y r Average

(6 M C F / B b l) m en t C osts E xpen ses C o st C o sts 2000 1999 1998 (1998-00 )

B urling ton 5 .80 7 .16 0 .00 12 .96 12 .96 11 .11 11 .42 11 .83

O cean E nergy 6 .08 5 .18 0 .00 11 .27 11 .27 11 .00 12 .43 11 .56

K err-M cG ee 5 .59 5 .84 0 .00 11 .43 11 .43 10 .98 13 .33 11 .91

P ioneer N a t R es 6 .94 5 .89 0 .00 12 .83 12 .83 12 .16 12 .84 12 .61

D evon E nergy 6 .57 4 .94 0 .00 11 .50 11 .50 9 .29 9 .63 10 .14

X T O E nergy 3 .81 5 .26 0 .00 9 .07 9 .07 8 .83 8 .78 8 .89

A nadarko P e tro leum 6.30 5 .17 0 .00 11 .47 11 .47 7 .08 7 .02 8 .53

U noca l C orp . 7 .10 3 .82 0 .00 10 .92 10 .92 10 .53 11 .43 10 .96

N ob le A ffilia tes 7 .65 4 .31 0 .00 11 .96 11 .96 9 .19 10 .94 10 .70

A pache C orp . 5 .61 3 .23 0 .00 8 .84 8 .84 8 .55 8 .92 8 .77

E O G R esources 5 .87 3 .25 0 .00 9 .11 9 .11 7 .55 5 .68 7 .45

M ean 6.12$ 4 .91$ -$ 11 .03$ 11 .03$ 9 .66$ 10 .22$ 10 .30$

M ed ian 6 .08$ 5 .17$ -$ 11 .43$ 11 .43$ 9 .29$ 10 .94$ 10 .70$

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

38

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 (%)

Notes1. Returns calculated on replacement cost basis: ROCE equals NOPAT/replacement cost capital where (a) NOPAT equals EBITDAX less replacement cost of production less

cash taxes, and (b) replacement cost capital equals beginning proved reserves times historical (then 3-year average) reserve replacement cost2. Large cap E&P sector full-cycle economics of $10.07/bbl as per JS Herold, which breaks down as $6.50/bbl for reserve replacement cost plus $3.57/bbl for operating cost.

Additionally, to calculate returns, $1.00/bbl for general and administrative costs are added to the full-cycle costs and $2.28/bbl for the average differential to WTI oil issubtracted from the WTI price

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-EvenWTI 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 oilprices, the large cap companiesexactly earn their cost of capital

E&P companies have found itdevilishly hard to return theircost of capital Capital-intensive business

Historical lack of capitaldiscipline

Dependent on commodityprices, which can fluctuatewildly

Best opportunity set available tomajors, not independent E&Ps

Full-Cycle Costs, ROCEs and Commodity Prices

39

Calculating ROCEs 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 IReported 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



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


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


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 IIITax-Adjusted NOPAT 81 38 131 264


ROCE 2.4% 1.1% 4.5% 10.6%

FYE Dec 31 FYE Dec 31

1997A 1998A 1999A 2000A

(4) ROCE IVThis ROCE is like (3) above except that it keeps running tally of invested capital using EVA framework

(a) Tax-Adjusted NOPAT


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


ROCE 2.3% 1.1% 3.6% 8.2%



(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)


Normalized NOPAT 61 (214) (60) 258

(b) Replacement Cost CapitalProved 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


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


Replacement Cost of Production 249 544 427 302



(US$ MM) 1997A 1998A 1999A 2000A

(6) ROCE VIThis 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


Replacement Cost of Reserves 2,127 6,590 5,659 4,203

Net Working Capital and Other Assets (91) (129) (17) (57)


(c) ROCE VI

Tax-Adjusted Normalized NOPAT 57 (96) 7 207

FYEDec 31 FYEDec 31

EVAAnalysis (US$MM) 1997A 1998A 1999A 2000A

Net Operating Profit After Tax(NOPAT)

RecurringEBIT(B4 Expl Expense) 124.3 59.2 201.2 406.5

Other RecurringCashIncome 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

CashTaxes (Unlevered)

Cash Taxes (Levered) 35% 0.7 (8.6) (10.8) (4.6)

Addback: TaxSavings fromInterest (35.0%) (27.1) (57.5) (59.6) (56.7)

CashTaxes (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 NewInvestment

Net Capital Expenditures (128.7) (179.7) 435.0 20.4

Investment in Net WorkingCapital (39.3) 86.0 (49.6) (44.0)

Net NewInvestment (168.0) (93.7) 385.5 (23.6)

UnleveredFree CashFlow

NOPAT 121.1 48.7 219.5 385.0

Less: Net NewInvestment (168.0) (93.7) 385.5 (23.6)

UnleveredFree CashFlow (47.0) (45.0) 605.0 361.5

Check (Two Free CashFlows equal [=0?]) Correct (0.0) 0.0 0.0 0.0

InvestedCapital Howabout purchaseaccounting 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 InvestedCapital) 1.4% 6.1% 12.0%

Economic Profit (ROIC- WACC) * IC (231) (68) 128

So Many Choices, So Little Time...

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5. Glossary

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 withregulatory requirements.

AFE (Authority for Expenditure) A form used during the planning process for a well about to be drilled. It includes anestimate of costs to be incurred in the IDC category and in the tangible equipment category. The form represents abudget 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 completionwork 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 thedevelopment and operating costs of another party (carried party) on a property in which both own a portion of the workinginterest. The carrying party is able to recover a specified amount of costs from the carried partys share of the revenuefrom 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 gasfrom a recently drilled well.

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

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

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Glossary of Key Petroleum Terms (Contd) 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 reservoiror 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-typestratigraphic 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 allor some of the burden of development, for an interest in the property. The assignor usually retains an overriding royalty butmay retain any type of interest.

Field An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individualgeologic 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 theformation.

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

Held-by-production (BHP) A provision in an oil, gas and mineral lease that perpetuates a companys right to operate aproperty or concession as long as the property or concession produces a minimum paying quantity of oil or gas. Alsoabbreviated as HBP.

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Glossary of Key Petroleum Terms (Contd)

IDC (Intangible Drilling Cost) Any cost which in itself has no salvage value and is necessary for and incident to thedrilling of wells and getting them ready for production. IDC can also occur when deepening or plugging back a previouslydrilled oil or gas well, or an abandoned well, to a different formation. IDCs are expensed for tax purposes, which result incompanies 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 or30-days.

Lease (1) A contract in which the owner of minerals gives an oil company the right to explore for, develop, and produceminerals from the property. (2) Any transfer where the owner of a mineral interest assigns all or part of the operatingrights 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, orLease operating costs

Net profits interest (NPI) An interest in production created from the working interest and measured by a certainpercentage 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 thecost of developing and producing the minerals.

Net revenue interest (NRI) A share of production after all burdens, such as royalty and overriding royalty, have beendeducted 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 beendrilled.

Operator Organization that obtains (buys or leases) the right to drill and produce oil and/or natural gas from the owner ofa specified location. The operator of an oil or gas well or field.

43


Overriding royalty (ORRI) A royalty interest that is created out of the operating interest. Its term is coextensive withthat of the operating interest from which it was created.

Percentage depletion A deduction for Federal income tax purposes based on the gross income from mineralproperties. Percentage depletion is in lieu of cost depletion. Also known as statutory depletion.

Permeability The measure of the ease with which oil can move through a reservoir.

Plug back To seal off a lower formation in a well bore in order to produce from a higher formation.

Porosity The relative volume of the pore space compared to the total bulk volume of the reservoir.

Production taxes Taxes levied by state governments on mineral production based on the value and/or quantity ofproduction. Also called severance taxes.

Proved developed reserves Reserves which can be expected to be recovered through existing wells with existingequipment and operating methods.

Proved reserves Quantities of reserves that, based on geologic and engineering data, appear with reasonable certaintyto be recoverable in the future from know oil and gas reserves under existing economic and operating conditions.

Proved undeveloped reserves Reserves which are expected to be recovered from new wells in undrilled provedacreage, or from existing wells where relatively major expenditures are required for completion.

Regulatory spacing The regulation of both the location and the number of wells which can be drilled into a commonreservoir (for conservation purposed). Regulations established by an agency of a state or government.

Reservoir A porous, permeable, subsurface rock formation containing trapped oil, natural gas, or water.

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Glossary of Key Petroleum Terms (Contd) Revenue interest The percentage of revenue received by a working interest after payment of royalties

Rig The derrick or mast, drawworks and attendant surface equipment of a drilling unit.

Royalty An interest in the oil and gas in place that entitles the holder to a specified fraction, in kind or in value, of thetotal production from the property, free of any expense of development and operation. The basic royalty interest isretained by the lessor of the oil/gas property in the original lease agreement.

Secondary recovery The use of such devices as water-flooding, gas-injection and other methods to recover oil beyondthat which can by natural flowing or by pumping.

Shut-in well A producing well (more often on gas properties than oil properties) that has been closed down temporarily.

Sidetrack A secondary wellbore drilled away from the original hole. It is possible to have multiple sidetracks, each ofwhich might be drilled for a different reason. A sidetracking operation may be done intentionally or may occur accidentally.

Spud To start the well drilling process by removing rock, dirt and other sedimentary material with the drill bit. To applyweight to a troublesome drilling section, usually by moving the drilling string up and down, in hopes that the section willdrill faster.

Stripper well A well nearing the end of its productive life; very little oil is being produced. For certain tax applications,wells with less than 10 B/D of production.

Take-or-pay contracts An agreement in which a gas purchaser agrees to take a minimum quantity of gas per year if heis not prevented form doing so by circumstances beyond his control and if the gas is available for delivery. If thepurchaser does not take the minimum quantity, he is required to pay for the minimum quantity at the contract price;normally, he may make up deficiency amounts in future years if he purchases in excess of minimum amounts.

Tangible assets The cost of assets that in themselves have a salvage value.

45


Tertiary recovery The use of sophisticated techniques such as flooding the reservoir with chemicals to increase theproduction of oil or gas.

Unitization An agreement under which two or more persons owning operating mineral properties agree to have theproperties operating on a unified basis and further agree to share in production from all the properties on a stipulatedpercentage or fractional basis regardless of from which property the oil or gas is produced. All owners of economicinterests in the properties should be involved in the agreement.

Viscosity The ability of a fluid to flow as a result of its physical characteristics.

Waterflooding A method of secondary recovery, in which water is injected into an oil reservoir for the purpose ofwashing the oil out of the reservoir rock and into the bore of a producing well.

Well spacing the space or acreage allocated to a well. The aerial extent that a well could drain (the volume) from areservoir. It is a conservation measure that identifies the location and number of wells that can be drilled to drain areservoir. Depending on the geologic structure, size of the reservoir and whether it is oil or gas, spacing could be as smallas 10 acres and as large as 640 acres.

Wellhead Flow control equipment located at the top of the casing string at the surface of the wellbore.

Wildcat An exploratory well drilled in an unknown or unproven area.

Workover Essentially, refurbishment of a well to improve its flow rate. Workover includes any of several operations on awell to restore or increase production when a reservoir stops producing at the rate it should. Many workover jobs involvetreating the reservoir rock, rather than the equipment in the well. Workover jobs typically take a few days to several weeksto complete.

Working interest (WI) The interest in the oil and gas in place which is burdened with the cost of development andoperation of the property. The mineral interest minus the royalty interest equals the working interest. Also called theoperating interest.

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6. Additional Resources

Additional ResourcesMacro Information:

http://www.naturalgas.org/index.asp

http://www.eia.gov/natural_gas/data_publications/natural_gas_monthly/ngm.html

http://www.woodmacresearch.com/cgi-bin/wmprod/portal/corp/corpPortal.jsp

http://www.ihs.com/

http://www.oilandgasinvestor.com/

http://www.UGcenter.com

http://www.info.drillinginfo.com

Public Filings:

http://www.sec.gov/edgar/searchedgar/companysearch.html

http://www.sedar.com/search/search_form_pc_en.htm

Rig Counts:

http://investor.shareholder.com/bhi/rig_counts/rc_index.cfm

http://www.smithprodserv.com/%24ca88deed-1360-463d-a271-5b959eb7fb87

Glossaries:

http://www.spe.org/industry/docs/GlossaryPetroleumReserves-ResourcesDefinitions_2005.pdf

http://www.spectraenergy.com/Natural-Gas-101/Glossary-of-Energy-Terms/

http://media.corporate-ir.net/media_files/irol/70/70888/pdf/Glossary_of_Drillings_Terms_041805.pdf

http://www.glossary.oilfield.slb.com/default.cfm

http://www.eia.gov/emeu/iea/glossary.html

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Citi_E&P Valuation Primer

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Transcript of Citi_E&P Valuation Primer