Modelling in general - CCOP · PPM Expert Visit - Indonesia, December 6-9, 2004 16 Frigg Gas -...

PPM Expert Visit - Indonesia, December 6-9, 2004 1

Petroleum economic modelling in general

Dr. Alfred KjemperudThe Bridge Group AS

PPM Expert Visit - Indonesia, 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).



• Petroleum investments are– capital intensive – irreversible – high risk/uncertainty

• Investment decisions today are only unfolded in the uncertain future for both company and government

Investment Decisions



Modeling = Predicting

• Petroleum project modelling is based on – knowledge of fundamental elements in

technology and economics– empiric data– and a bit of artistry



Warning• All modeling is imperfect.

– It is always a simplification of reality– Depends on quality of input

• The challenge is to assess the weaknesses and discover flaws



Resource RentAllocation of revenues from Production

After Johnston (1995)

•Bonuses•Royalties•Prod. Sharing•Taxes•Gov. Participation



Costs

Income

Time

Government

Activities and cash flow

Pre-license Exploration Development Production AbandonmentProduction

Rehab.

Con

trac

t aw

ard

PDO

Lead Time



Input to cash flow models

• Production curve• Oil/gas price• Capex• Opex• Fiscal regime• Discount rate

Gross revenue

Net revenue



Production curve

Time

Volume

Build-up

Plateau

Decline

Cutoff



Factors determining production

• No of wells• Plateau factor (%)• Production rate per well• Plateau production rate• Remaining oil/gas at start decline• Decline rate (%)• Cut off rate



Oil ProductionOil 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

Thou

sand

bbl

/yea

r

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



Gas ProductionGas 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

(Mill

ion

scf/d

ay)

Con

dens

ate

(Tho

usan

d bb

l/d)

Non Assoc. Gas [Million scf/d]Condensate [Thousand bbl/d



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

23 %

66 %

0

5

10

15

20

25

30

35

40

200220012000199919981997199619951994199319921991199019891988198719861985198419831982198119801979

Years

Mill

ion

Sm3

0 %

10 %

20 %

30 %

40 %

50 %

60 %

70 %

80 %

90 %

100 %

Oil Production

P/R percentage



Ula oil - NorwayOil Production - Ula, Norway

80 million Sm3 (503 Million bbl)

53.7 %

35.1 %

0

1

2

3

4

5

6

7

8

20022001200019991998199719961995199419931992199119901989198819871986

Years

Mill

ion

Sm3

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



Oseberg Oil - NorwayOil Production - Oseberg Field, Norway

350 million Sm3 (2200 million bbl)

39.2 %

70.5 %

0

5

10

15

20

25

30

35

2001200019991998199719961995199419931992199119901989198819871986

Years

Mill

ion

Sm3

0.0 %

10.0 %

20.0 %

30.0 %

40.0 %

50.0 %

60.0 %

70.0 %

80.0 %

90.0 %

100.0 %

Oil Production

P/R percentage



Frigg Gas - NorwayGas Production - Frigg Field, Norway

116 billion Sm3 (4.1 TCF)

63.9 %

29.8 %

0

2

4

6

8

10

12

20022001200019991998199719961995199419931992199119901989198819871986198519841983198219811980197919781977

Years

Mill

ion

Sm3

0

0.2

0.4

0.6

0.8

1

1.2

Gasl Production

P/R percentage



Rules of thumb - 1TECHNICAL ASPECTS Rule of Thumb• Peak production/total reserves 10-12%• Decline rate 10-12%



Lead Time

02468

101214161820

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

22Lille Frigg

Statfjord Øst

Sleipner Vest

Statfjord Nord Hod

Øst Frigg Heimdal

CodTor Eldfisk

Edda Frigg

Ekofisk

Statfjord MurchisonValhall

Ula TommelitenGammaGullfaks

Oseberg

Snorre

Troll II

Gyda Veslefrikk

Sleipner Øst Gugne

Troll I

Loke HeidrunDraugen Oseberg Vest

Yme Frøy Tordis

Embla Gyda Sør

Gullfaks Vest

Albuskjell

Brage

Vest Ekofisk

Petr. res 9612067

Year of discoveryYea

rsfr

om d

isco

very

to p

rodu

ctio

n



Exercise - Production

• Construct a production curve for an oil field with 300 million barrels recoverable reserves which will be produced over 20 years. Lead time is 5 years and cut off rate is 10,000 bopd (Use Excel)





Gross revenue

Net revenue



Oil prices through time

?





Gross revenue

Net revenue



Expenditures = Cost• Capital expenditure

– Wells– Constructions - Facilities– Pipelines

• Operating expenditures– The cost of running the operations

• Fixed Opex• Variable Opex



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

Mill

ion

USD

0.0

50.0

100.0

150.0

200.0

250.0

300.0

350.0

TOTAL CAPEX [Million USD, inflated]Varible OpexTOTAL OPEX [Million USD, inflated]



Well cost - Asia

bbl Sm3Expl.

Well cost Test

Appraisal no. of wells Well cost

Duration (years)

Averages, Capex

(USD/bbl)Capex

(USD/Sm3)First

oilYearsField 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 33.3450 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 27.76250 39.7 7.43 1.31 3.14 7.29 3.67 2.51 15.79 7.67 16.86 3.89 24.47500 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



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

/BB

L

Series1

Average 4.4



Facility Cost Estimates

Unit cost ($MM)Exploration Well 3-4Appraisal Well 2-4Development 1-1.5CPP 300-500WP (4 legs) + Sealines 13 - 18LQ 40-60 (100 - 200 POB)FSO 1 MMbbl 100Booster Compressor 0.4-0.5

Pipeline 16 " 0.4 MM$ / kmPipeline 24 " 0.6 MM$ / km

Ref. Anon Punnahitanon, PPM



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 60

Fields

%



Model checks• Several checks of the results should be

performed– Royalty % per year– Profit share % per year– Production plot– Capex and Opex plot– Depreciation plot



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%





Gross revenue

Net revenue



Share, take and profit margin• Gross project revenue 100• -Royalty 0• Net project revenue 100• Total cost -40• Profit basis (Operating income) 60• Taxes 35• Net after tax income 25

– Contractor take 42% (25/60)– Contractor profit margin 25% (25/100)– Contractor share 65% (25+40/100)

– Government take 58% (35/60)



The Government Choice

NorwayUnited KingdomPakistanTunisiaNew Zealand

Concessionary Systems

Limited usage

Pure Service Contracts

ArgentinaBrazilVenezuelaThe Philippines

Risk Service Contracts

Service Contracts

AngolaIndonesiaIndiaNigeriaGabon

Production Sharing Contracts

Contractual Systems

Petroleum Fiscal Arrangements



Elements in a PSC• Work Commitment• Bonus Payment• Royalties• Cost Recovery (Cost Oil)• Profit Oil• Government participation• Domestic Market Obligation• Ring fencing



Indonesia- PSC (4th Gen.)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 with

the level of cost– Effective Gov. take is 85%

Contractor GovernmentGross

Revenues100

5.8First Tranche

Petroleum 14.220 %14.2 %

Net Revenues80

28.0 Cost Oil35 %

Profit oil52

15.0Profit oil to

Contr. 37.028.8462 %

Taxable20.8

-10.0 Tax 10.048 %

38.8After tax

entitlement 61.2

10.8Net Cash

Flow 61.2

15 % Take 85 %



FTP• Calculated from Gross Revenue• Works as a modified Royalty • Can cause premature abandonment



...where:Fn - the net income in year ni - discount rate n - total numbers of years (project duration)

F1

(1 + i)1F2

(1 + i)2Fn

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

Fn

(1 + i)n( )∑n = 0

n

NPV =

NPV formula (end year)



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

Mill

ion

USD

Cash flow

Cummulative cashflow

Inflation corrected

+ Value of time corrected

Current Values

Real Values

Discounted Values



Present Value

Year Cash Flow NPV 5% NPV 10% NPV 15% NPV 20%2003 -200 -200.0 -200.0 -200.0 -200.02004 -50 -47.6 -45.5 -43.5 -41.72005 10 9.1 8.3 7.6 6.92006 100 86.4 75.1 65.8 57.92007 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

-100

-50

0

50

100

150

200

0 5 % 10 % 15 % 20 %

Discount Factor

NPV

IRR



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&G

etc.



EMV - Example

• Assumptions• NPV = 120 million USD• RC = 15 million USD• SP = 22%

• EMV = (R*SP) - (RC*(1-SP))• EMV = (120*0.22) - (15*(1-0.22))• EMV = 14.7million USD

– Break even SP = 12.5% (EMV=0)



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 (%)

Mill

ion

USD

EMV curve

Risk capital

Reward (NPV)

Break even POS

Calculated EMV

Calculated POS



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 value•Risked value



Basic assumptions• Start Year• Oil Price

– Starting value– Escalation– Model

• Inflation• Discount rate and year• Depreciation rules



GeoX Demonstration

• The structure and functionality of GeoX– Prospect Analysis– Discovery Analysis– Full Cycle Analysis

Date post:	27-May-2020
Category:	Documents
Upload:	others
View:	1 times
Download:	0 times

Modelling in general - CCOP · PPM Expert Visit - Indonesia, December 6-9, 2004 16 Frigg Gas -...

Documents