Petroleum Economic Modelling

8/12/2019 Petroleum Economic Modelling

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PPM Expert Visit - Indonesia,

December 6-9 2004

Petroleum economic modelling ingeneral

Dr. Alfred Kjemperud

The Bridge Group AS


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December 6-9 2004


December 6-9 2004

Why economic modeling

Economic models are mainly used

for the following four reasons:

Investment decisions Budgeting

Annual reports

Risk analysis to understand the risk

elements within the business and

within individual projects (sensitivities).


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December 6-9 2004

Petroleum investments are

capital intensive irreversible

high risk/uncertainty

Investment decisions today are onlyunfolded in the uncertain future for both

company and government

Investment Decisions


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December 6-9 2004

Modeling = Predicting

Petroleum project modelling is based on

knowledge of fundamental elements intechnology and economics

empiric data

and a bit of artistry


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December 6-9 2004

Warning

All modeling is imperfect. It is always a simplification of reality

Depends on quality of input

The challenge is to assess the weaknesses anddiscover flaws


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December 6-9 2004

Resource RentAllocation of revenues from Production

After Johnston (1995)

Bonuses

Royalties

Prod. Sharing

Taxes

Gov. Participation


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December 6-9 2004

Costs

Income

Time

Government

Activities and cash flow

Pre-license Exploration Development Production AbandonmentProduction

Rehab.

Contractaward

PDO

Lead Time


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December 6-9 2004

Input to cash flow models

Production curve

Oil/gas price Capex

Opex Fiscal regime

Discount rate

Gross revenue

Net revenue


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December 6-9 2004

Production curve

Time

Volume

Build-up

Plateau

Decline

Cutoff

ac ors e erm n ng


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December 6-9 2004

ac ors e erm n ngproduction

No of wells

Plateau factor (%) Production rate per well

Plateau production rate

Remaining oil/gas at start decline

Decline rate (%)

Cut off rate


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December 6-9 2004


December 6-9 2004

Oil Production

Oil Production

0.0

50.0

100.0

150.0

200.0

250.0

300.0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

Year

Thousandbbl/year

Oil [Thousand bbl/d]

Assoc. Gas [Thousand o.e./d]


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December 6-9 2004

Gas Production

Gas Production

0.0

500.0

1000.0

1500.0

2000.0

2500.0

3000.0

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

Year

Gas(Millions

cf/day)

Condensate(Thou

sandbbl/d)

Non Assoc. Gas [Million scf/d]

Condensate [Thousand bbl/d


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December 6-9 2004


December 6-9 2004

Statfjord Oil - NorwayOil Production - Statfjord, Norway560 million Sm3 (3520 Million bbl)

23 %

66 %

0

5

1

1

2

2

3

3

4

200220012000199919981997199619951994199319921991199019891988198719861985198419831982198119801979

Years

0 %

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

100 %

Oil Production

P/R percentage


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December 6-9 2004

Ula oil - Norway

Oil Production - Ula, Norway

80 million Sm3 (503 Million bbl)

53.7 %

35.1 %

0

1

2

3

4

5

6

7

8

20022001200019991998199719961995199419931992199119901989198819871986

Years

MillionSm3

0.0 %

10.0 %

20.0 %

30.0 %

40.0 %

50.0 %

60.0 %

70.0 %

80.0 %

90.0 %

Oil Production

P/R percentage


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December 6-9 2004

Oseberg Oil - Norway

Oil Production - Oseberg Field, Norway

350 million Sm3 (2200 million bbl)

39.2 %

70.5 %

0

5

10

15

20

25

30

35

2001200019991998199719961995199419931992199119901989198819871986

Years

MillionSm3

0.0 %

10.0 %

20.0 %

30.0 %

0.0 %

50.0 %

60.0 %

70.0 %

80.0 %

90.0 %

00.0 %

Oil Production

P/R percentage


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December 6-9 2004

Frigg Gas - Norway

Gas Production - Frigg Field, Norway

116 billion Sm3 (4.1 TCF)

63.9 %

29.8 %

0

2

4

6

8

10

12

20022001200019991998199719961995199419931992199119901989198819871986198519841983198219811980197919781977

Years

0

.2

.4

.6

.8

1

.2

Gasl Production

P/R percentage


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December 6-9 2004

Rules of thumb - 1

TECHNICAL ASPECTS Rule of Thumb

Peak production/total reserves 10-12%

Decline rate 10-12%


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Lead Time

02468

101214

161820

1968 1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990

22

Lille FriggStatfjord st

Sleipner Vest

Statfjord Nord

Hodst Frigg

Heimdal

CodTorEldfisk

EddaFrigg

Ekofisk

Statfjord

Murchison

Valhall

UlaTommelitenGamma

GullfaksOseberg

Snorre

Troll II

GydaVeslefrikk

Sleipner st

GugneTroll I

Loke HeidrunDraugen

Oseberg Vest

YmeFryTordis

EmblaGyda Sr

Gullfaks Vest

Albuskjell

Brage

VestEkofisk

Petr. res 961206

Year of discoveryYearsfrom

discovery

toproduction


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December 6-9 2004

Exercise - Production

Construct a production curve for an oil

field with 300 million barrels recoverablereserves which will be produced over 20years. Lead time is 5 years and cut off rate

is 10,000 bopd (Use Excel)


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December 6-9 2004


Production curve

Oil/gas price Capex

Opex Fiscal regime

Discount rate

Gross revenue

Net revenue


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December 6-9 2004

Oil prices through time

?


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December 6-9 2004


Production curve

Oil/gas price Capex

Opex Fiscal regime

Discount rate

Gross revenue

Net revenue


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December 6-9 2004

Expenditures = Cost

Capital expenditure

Wells Constructions - Facilities

Pipelines

Operating expenditures

The cost of running the operations

Fixed Opex

Variable Opex


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December 6-9 2004

Capex and OpexCapex and Opex

0

50

100

150

200

250

300

350

400

450

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

Years

M

illionUSD

0.0

50.0

100.0

150.0

200.0

250.0

300.0

350.0

TOTAL CAPEX [Million USD, inflated]

Varible Opex

TOTAL OPEX [Million USD, inflated]


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December 6-9 2004

Well cost - Asia

bbl Sm3

Expl.

Well cost Test

Appraisal

no. of

wells Well cost

Duration

(years)

Averages

, Capex

(USD/bbl)

Capex

(USD/Sm3)

First

oilYears

Field life

(years)

Averages,

Opex

(USD/bbl)

Opex

(USD/Sm3)

10 1.6 6.9 1.14 1 6.7 1.8 5.16 32.46 3.8 6.4 6.72 42.325 4.0 7.43 1.31 1.43 7.29 1.83 4.34 27.27 4.17 6.86 5.30 33.34

50 7.9 7.43 1.31 2.14 7.29 2.17 3.68 23.13 5.17 9.00 4.93 30.99

125 19.9 7.43 1.31 2.29 7.29 2.83 2.93 18.43 6.33 13.00 4.41 27.76

250 39.7 7.43 1.31 3.14 7.29 3.67 2.51 15.79 7.67 16.86 3.89 24.47

500 79.5 7.43 1.31 3.86 7.29 4.17 2.09 13.17 8.33 19.57 3.47 21.84

160.00 25.44 7.34 1.29 2.31 7.19 2.74 3.45 21.71 5.91 11.95 4.79 30.12

AveragesField size Exploration Appraisal Development/operation

O ( d/bbl)


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Opex (usd/bbl)(Norwegian fields 1998)

0.0

5.0

10.0

15.0

20.0

25.0

30.0

0 10 20 30 40 50 60 70 80

Fields

USD/BBL

Series1

Average 4.4

Facility Cost Estimates


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Facility Cost Estimates

Unit cost ($MM)

Exploration Well 3-4

Appraisal Well 2-4

Development 1-1.5CPP 300-500WP (4 legs) + Sealines 13 - 18

LQ 40-60 (100 - 200 POB)

FSO 1 MMbbl 100Booster Compressor 0.4-0.5

Pipeline 16 " 0.4 MM$ / km

Pipeline 24 " 0.6 MM$ / km

Ref. Anon Punnahitanon, PPM

Y l % f t t l


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Yearly opex as % of total capex(Norwegian fields 1998)

Yearly opex as % of total capex

0.00 %

1.00 %

2.00 %

3.00 %

4.00 %

5.00 %

6.00 %

7.00 %

0 10 20 30 40 50 60Fields

%


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December 6-9 2004

Model checks

Several checks of the results should beperformed

Royalty % per year

Profit share % per year

Production plot

Capex and Opex plot

Depreciation plot


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December 6-9 2004

Rules of thumb -2

BASIC ASSUMPTIONS Rule of Thumb

Capex/bbl 3-5 usd

Capex as % of Gross Revenue 10-20%

Opex/bbl 3-5 usd

Opex/peak year as % of total Capex 4-8%

I h fl d l


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December 6-9 2004


Production curve

Oil/gas price Capex

Opex Fiscal regime

Discount rate

Gross revenue

Net revenue


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Th G t Ch i


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December 6-9 2004

The Government Choice

Norway

United KingdomPakistan

Tunisia

New Zealand

Concessionary Systems

Limited usage

Pure Service Contracts

Argentina

Brazil

Venezuela

The Philippines

Risk Service Contracts

Service Contracts

Angola

Indonesia

India

Nigeria

Gabon

Production Sharing Contracts

Contractual Systems

Petroleum Fiscal Arrangements

El t i PSC


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Elements in a PSC

Work Commitment

Bonus Payment

Royalties

Cost Recovery (Cost Oil)

Profit Oil

Government participation

Domestic Market Obligation Ring fencing

n ones a- (4th Gen.)


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December 6-9 2004

Mother of all PSCs

(85/15 Split)

Royalty: 0%

FTP split 20%

Cost Oil : 100%

Profit Oil: 28.8462%

Tax Rate: 48%

Effects

The split does not change withthe level of cost

Effective Gov. take is 85%

Contractor GovernmenGross

Revenues100

5.8

First Tranche

Petroleum 14.2

20 %14.2 %

Net Revenues80

28.0 Cost Oil35 %

Profit oil52

15.0

Profit oil to

Contr. 37.028.8462 %

Taxable20.8

-10.0 Tax 10.048 %

38.8

After tax

entitlement 61.2

10.8

Net Cash

Flow 61.2

15 % Take 85 %

FTP


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FTP

Calculated from Gross Revenue

Works as a modified Royalty

Can cause premature abandonment

NPV form la (end ear)


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...where:

Fn - the net income in year ni - discount rate

n - total numbers of years (project duration)

F1

(1 + i)1

F2

(1 + i)2

Fn

(1 + i)n= + + ... +F0 +

Fn

(1 + i)n( )n = 0

n

NPV =

NPV formula (end year)

Time value of money


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Time value of money

-500

0

500

1000

1500

2000

2500

3000

3500

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Millio

nUSD

Cash flow

Cummulative cashflow

Inflation corrected

+ Value of time corrected

Current Values

Real Values

Discounted Values

Present Value


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Present Value

Year Cash Flow NPV 5% NPV 10% NPV 15% NPV 20%

2003 -200 -200.0 -200.0 -200.0 -200.0

2004 -50 -47.6 -45.5 -43.5 -41.7

2005 10 9.1 8.3 7.6 6.9

2006 100 86.4 75.1 65.8 57.9

2007 100 82.3 68.3 57.2 48.22008 200 156.7 124.2 99.4 80.4

SUM 160 86.8 30.4 -13.6 -48.3

Present Value IRR


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December 6-9 2004

Present Value - IRR

-100

-50

0

50

100

150

200

0 5 % 10 % 15 % 20 %

Discount Factor

NPV

IRR

Expected Monetary Value


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Expected Monetary Value

EMV=(R*SP)-(RC*(1-SP))

EMV=Expected Monetary Value

R = Reward = Net Present Value (NPV)

SP= Success Probability

RC= Risk Capital = Bonuses, Dry Hole Cost, G&Getc.


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EMV curve


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EMV curve

-40

-20

0

20

40

60

80

100

120

140

0 10 20 30 40 50 60 70 80 90 100

Probability of Success (%)

MillionUSD

EMV curve

Risk capital

Reward (NPV)

Break even POSCalculated

EMVCalculated POS

Synonyms


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Synonyms

Net present value (NPV)

Internal rate if return (IRR)

Expected monetary value

Present value

Discounted cash flow

Present value profit (PVP)

Present worth (PW)

Rate of return (ROR)

Profit investment ratio (P/I

ratio)Return on investments(ROI)

Expected valueRisked value

Basic assumptions


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December 6-9 2004

Basic assumptions

Start Year

Oil Price

Starting value Escalation

Model

Inflation Discount rate and year

Depreciation rules

GeoX Demonstration


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December 6-9 2004

GeoX Demonstration

The structure and functionality of GeoX

Prospect Analysis Discovery Analysis

Full Cycle Analysis

Petroleum Economic Modelling

Documents

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