Petroleum economic modelling in general

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1 Petroleum economic modelling in general Dr. Alfred Kjemperud The Bridge Group AS

2 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).

3 Investment Decisions Petroleum investments are capital intensive irreversible high risk/uncertainty Investment decisions today are only unfolded in the uncertain future for both company and government

4 Modeling = Predicting Petroleum project modelling is based on knowledge of fundamental elements in technology and economics empiric data and a bit of artistry

5 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

6 Resource Rent Allocation of revenues from Production Bonuses Royalties Prod. Sharing Taxes Gov. Participation After Johnston (1995)

7 Contract award PDO Activities and cash flow Income Government Time Costs Production Pre-license Exploration Development Production Rehab. Abandonment Lead Time

8 Input to cash flow models Production curve Oil/gas price Capex Opex Fiscal regime Discount rate Gross revenue Net revenue

9 Production curve Plateau Volume Build-up Decline Time Cutoff

10 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

11 Oil Production Oil Production Oil [Thousand bbl/d] Assoc. Gas [Thousand o.e./d] Thousand bbl/year Year

12 Gas Production Gas Production Non Assoc. Gas [Million scf/d] Condensate [Thousand bbl/d Gas (Million scf/day) Condensate (Thousand bbl/d) Year

13 Statfjord Oil - Norway Oil Production - Statfjord, Norway 560 million Sm3 (3520 Million bbl) 00 % % Oil Production P/R percentage % 70 % 60 % 66 % % % % 20 % 10 % 23 % % Years

14 Ula oil - Norway Oil Production - Ula, Norway 80 million Sm3 (503 Million bbl) 0.0 % % Oil Production P/R percentage % % 0.0 % 0.0 % 53.7 % 5 Million Sm % 35.1 % % % % Years

15 Oseberg Oil - Norway Oil Production - Oseberg Field, Norway 350 million Sm3 (2200 million bbl) 0.0 % 0.0 % 0.0 % Oil Production P/R percentage % 70.5 % % 0.0 % 0.0 % Million Sm % 0.0 % % % 0.0 % Years

16 Frigg Gas - Norway Gas Production - Frigg Field, Norway 116 billion Sm3 (4.1 TCF) 2 1 Gasl Production P/R percentage % % Years

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

18 Lead Time Years from discovery to production Sleipner Vest Lille Frigg Statfjord Øst Statfjord Nord Hod Troll II Øst Frigg Gugne Heimdal Snorre Brage Troll I Sleipner Øst Tommeliten Ula Gamma Gyda Loke Heidrun Cod Eldfisk Oseberg Veslefrikk Draugen Tor Albuskjell Gullfaks Vest Ekofisk Edda Murchison Oseberg Vest Frigg Statfjord Valhall Ekofisk Yme Frøy Tordis Embla Gyda Sør Gullfaks Vest Year of discovery Petr. res

19 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)

20 Input to cash flow models Production curve Oil/gas price Capex Opex Fiscal regime Discount rate Gross revenue Net revenue

21 Oil prices through time?

22 Input to cash flow models Production curve Oil/gas price Capex Opex Fiscal regime Discount rate Gross revenue Net revenue

23 Expenditures = Cost Capital expenditure Wells Constructions - Facilities Pipelines Operating expenditures The cost of running the operations Fixed Opex Variable Opex

24 Capex and Opex Capex and Opex TOTAL CAPEX [Million USD, inflated] Varible Opex TOTAL OPEX [Million USD, inflated] Years Million USD

25 Well cost - Asia Averages Field size Exploration Appraisal Development/operation bbl Appraisal no. of wells Averages, Capex (USD/bbl) Averages, Opex (USD/bbl) Sm3 Expl. Well cost Test Well cost Duration (years) Capex (USD/Sm3) First oilyears Field life (years) Opex (USD/Sm3)

26 Opex (usd/bbl) (Norwegian fields 1998) USD/BBL 15.0 Series Average Fields

27 Facility Cost Estimates Unit cost ($MM) Exploration Well 3-4 Appraisal Well 2-4 Development CPP WP (4 legs) + Sealines LQ ( POB) FSO 1 MMbbl 100 B ooster Compressor Pipeline 16 " Pipeline 24 " 0.4 MM$ / km 0.6 MM$ / km Ref. Anon Punnahitanon, PPM

28 Yearly opex as % of total capex (Norwegian fields 1998) Yearly opex as % of total capex 7.00 % 6.00 % 5.00 % 4.00 % % 3.00 % 2.00 % 1.00 % 0.00 % Fields

29 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

30 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%

31 Input to cash flow models Production curve Oil/gas price Capex Opex Fiscal regime Discount rate Gross revenue Net revenue

32 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)

33 The Government Choice Petroleum Fiscal Arrangements Concessionary Systems Contractual Systems Norway United Kingdom Pakistan Tunisia New Zealand Pure Service Contracts Limited usage Service Contracts Risk Service Contracts Argentina Brazil Venezuela The Philippines Production Sharing Contracts Angola Indonesia India Nigeria Gabon

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

35 Indonesia- PSC (4 th Gen.) Mother of all PSCs (85/15 Split) Royalty: 0% FTP split 20% Cost Oil : 100% Profit Oil: % Tax Rate: 48% Effects The split does not change with the level of cost Effective Gov. take is 85% Contractor 5.8 Gross Revenues 100 Government First Tranche Petroleum % 14.2 % Net Revenues Cost Oil 35 % 15.0 Profit oil 52 Profit oil to Contr % Taxable Tax % After tax entitlement 61.2 Net Cash Flow % Take 85 %

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

37 NPV formula (end year)...where: NPV = F 1 n = 0 ( F n ) (1 + i) n = F (1 + i) 1 (1 + i) 2 (1 + i) n F 2 F n F n - the net income in year n i - discount rate n - total numbers of years (project duration) n

38 Time value of money Cash flow Cummulative cashflow Inflation corrected Current Values Million USD Value of time corrected Real Values Discounted Values

39 Present Value Year Cash Flow NPV 5% NPV 10% NPV 15% NPV 20% SUM

40 Present Value - IRR IRR % 10 % 15 % 20 % NPV Discount Factor -100

41 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.

42 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)

43 EMV curve 140 Reward (NPV) 120 EMV curve Calculated EMV Million USD Break even POS Calculated POS Risk capital Probability of Success (%)

44 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

45 Basic assumptions Start Year Oil Price Starting value Escalation Model Inflation Discount rate and year Depreciation rules

46 GeoX Demonstration The structure and functionality of GeoX Prospect Analysis Discovery Analysis Full Cycle Analysis

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