1. MODULE 4 UPSTREAM PETROLEUM ECONOMICS 1

2. Introducing Upstream Petroleum Economic Module Seeing The Forest and The Trees Your Learning Partner Background… To include Key Terms/ Guiding Principles Include Pop Quizzes and Activities 2

3. Introducing Upstream Petroleum Economic Module Learning Objectives and Assessment Criteria At the end of the session, you will be able to … Describe overview of upstream project evaluation Describe the various analysis for economic indicators and results Develop a basic economic modeling Communicate economic modeling results 3

4. Relating To Commercial Value Chain Topics and The Commercial Value Chain PART 1: Overview of Upstream Project Evaluation Overview Upstream Project Evaluation Technical input/Economic assumptions Concepts of Cash Flow Tax & Capital Allowances Fiscal Arrangements PART 2: Analysing Economic Indicators and Results Economic Indicators Time Value of Money Risk & Sensitivity Analysis Decision Tree Analysis 4 Pre-Entry (Assessment) Acquire (Farm-in/M&A) Manage (E/D/P) Exit (Farm- out/Divest) STRATEGY EXECUTION

5. Relating To Commercial Value Chain Topics and The Commercial Value Chain PART 3: Basic Economic Modelling Applying in Excel PART 4: Communicating Economic Results Syndicate Preparation Syndicate Presentation 5 Pre-Entry (Assessment) Acquire (Farm-in/M&A) Manage (E/D/P) Exit (Farm- out/Divest) STRATEGY EXECUTION

6. Upstream Petroleum Economic Module Programme Schedule 6 DaySessionTimeAgenda One (1)Part 1 8.00 am-10.00 am Overview of Upstream Project Evaluation Technical Data/Economics Assumptions 10.15 am-12.30 pm Concepts of Cash Flow Tax & Capital Allowances 1.30 pm-3.00 pm Fiscal Arrangements Part 2 3.15 pm-5.00 pm Economic Indicators Time Value of Money Two (2) 8.00 am-10.00 am Risk & Sensitivity Analysis Decision Tree Analysis Part 3 10.15 pm-12.30 pm Basic Economic Modeling 1.30 pm-3.00 pm Basic Economic Modeling (cont’d) Part 4 3.15 pm-5.00 pm Case Study Preparation

7. Understand (able to describe) the meaning of project evaluation and steps involved in evaluating an E&P project Understand (describe) the various technical data necessary to perform an E&P project evaluation Familiarise with the oil & gas price forecasts, inflation, and escalation used in project evaluations Able to apply the concept of Cash Flow Know Petroleum Income Tax terms and calculations Tutorial Generate technical input data Calculate Cash Flow 7 Upstream Petroleum Economic Module Learning Objectives (Part 1)

8. Understand the various types of Fiscal Arrangements and its computational logic Able to appreciate the concept of Time Value of Money Understand the underlying concept of key economic indicators such as maximum cash sink, payout time, Net Present Value (NPV), Internal Rate of Return (IRR) Identify various risks involved in a petroleum project Calculate the economic effect of each risk factor Comprehend the meaning of a decision tree, and the step-by-step process involved in constructing a decision tree. Tutorial Develop Fiscal Arrangements computational logic Calculate key economic indicators Develop Spider plot, Construct Decision Tree Upstream Petroleum Economic Module Learning Objectives (Part 2) 8

9. Able to develop simple economics model, conduct rigorous analysis and rationalize the economic results. “Putting-All-Together” – Syndicate Exercise Interpret/extract/summarise various necessary technical data and assumptions to be made on oil & gas price forecasts, inflation, and escalation Perform key economic indicators such as maximum cash sink, payout time, Net Present Value (NPV), Internal Rate of Return (IRR) etc. Build simple Economic model Case Study preparation Upstream Petroleum Economic Module Learning Objectives (Part 3&4) 9

10. PART 1 Overview of Upstream Project Evaluation 10

11. Overview of Upstream Economic Evaluation 11

12. To facilitate decision making : where to focus efforts, where to allocate resources what is the optimal development option Why we need to do economic evaluation ? To determine “economic health” of the project for the purpose of : acquiring new petroleum acreages setting future exploration and development strategies tracking asset performance Recommendation of fiscal terms and/or negotiation parameters determining free cash flow for project financing analyzing impact of new or revised governmental regulations. Economic evaluation determines project value and generates profitability indicators … 12

13. Different types of projects are being evaluated throughout the life of an oil/gas field Site restoration Work over Campaign Infill program Prospect valuation Value of Information Valuing the Asset ExplorationDevelopmentProduction StrategyAcquireManageExit AbandonmentAcquisition Field Development Optimization Gas Sales Enhanced recovery 13

14. Understanding the evaluation process, requirements and results is important to facilitate effective communication among team members Technical Inputs Economic Model Economic Assumptions Economic Results Reserves Production Capex Opex Risk & Sensitivity Analysis Price Cost Escalation Inflation Exchange Rate Tax & Capital Allowance Fiscal Arrangement Economic Indicators eg. NPV, IRR 14

15. Understanding the evaluation process, requirements and results is important to facilitate effective communication among team members Technical Inputs Economic Model Economic Assumptions Economic Results Reserves Production Capex Opex Risk & Sensitivity Analysis Price Cost Escalation Inflation Exchange Rate Tax & Capital Allowance Fiscal Arrangement Economic Indicators eg. NPV, IRR 15

16. The evaluation requires a set of techno-commercial assumptions which relate to the development of the asset. CPP Fiscal & Commercial Terms Decision Tree Analysis Development Concept Drilling Requirement 16

17. Various parameters under the different phases of the field life are incorporated to simulate the expected life cycle value of the project Abandonment Cost Timing of abandonment Salvage value Reserves Development scenarios Capital expenditure (e.g. structure, process facilities, pipeline, development drilling cost) Number of development well Expenditure phasing First year of production Oil production profile Gas demand forecast and matching gas delivery rates from fields Typical operating cost Number of exploration and appraisal wells Well cost Timing of exploration and appraisal costs Resource volume Probability of exploration success Sunk cost Acquisition costs Exit AcquisitionExplorationDevelopmentProductionAbandonment Sunk cost Future value 17

18. Exit The results serve as one of the key consideration for decision making at different evaluation GATES for the project AcquisitionExplorationDevelopmentProductionAbandonment De- commissionin g Plan New business opportunities Project Commercial Evaluation To acquire or not Seismic Acquisition/ Processing/Interpretati on Exploration Economic Evaluation To drill an exploration well or not Feasibility Study Economic Evaluation To proceed with FDP or not If yes, FDP team Economic Evaluation Which development option Operations Planning, Production Performance & Monitoring Upgrade and Modification projects Economic Evaluation To proceed with project or not Economic Evaluation To continue operation or exit New business opportunities Project Commercial Evaluation What price to sell 18

19. Rigorous evaluation is necessary to support the petroleum investment decision which is normally made under condition of uncertainty. Significant degree of risk and uncertainty. below the ground risk : presence of hydrocarbon, producible amount above the ground risk : cost fluctuation, price volatility, stability Substantial cash flows spread over a long period of time. A very long lead time between expenditure and resulting revenue. First production normally realized after more than 5 years from initial investment. Capital intensive during the early stage. Resources depleting with time. 19

20. 202020 Tutorial 1 : Technical Data input for Economic Evaluation Field ‘Sparco’, located south east of the country, at 40 m water depth, with Gas Speculative Resource (SR) of 100 Bscf Well test indicate well deliverability of 10 MMscf/d per well for the reservoir around the area, with expected production decline after 75% reserves already produced Gas sales agreement signed for 5 years for 40 MMscf/d. Processed gas to be evacuated to sales point at Port Putra (25 km) Estimated well cost of $5 Million per well Require 1 Central Processing and 1 Wellhead Platforms to fully develop the resources at a cost of $ 90 million. Pipeline cost estimate = $1 MM/km Opex is expected to be 4% of cumulative Capex Estimate the production and cost parameters for the following conceptual development of Field ‘Sparco’ 20

21. Estimate the production and cost parameters for the following conceptual development of Field ‘Sparco’ Year 1Year 2Year 3Year 4Year 5Year 6Year 7Year 8Total No Wells Gas Sales(MMscf/d) Cum. Gas Sales/ Reserves (%) Facilities Cost(US$ MM) Pipeline Cost(US$ MM) Drilling Cost(US$ MM) Total Capex(US$ MM) Total Opex(US$ MM) Unit Development Cost (UDC)= US$ ____ /Kscf Unit Operating Cost (UOC) = US$ ____ /Kscf Unit Technical Cost (UTC)= US$ ____ /Kscf Tutorial 1 : Technical Data input for Economic Evaluation 21

22. ECONOMIC ANALYSIS WORK-FLOW Technical Inputs Economic Model Economic Assumptions Price Cost Escalation Inflation Exchange Rate Economic Results Reserves Production Capex Opex Risk & Sensitivity Analysis Net Cash Flow Tax & Capital Allowance Fiscal Arrangement Time Value of Money Economic Indicators eg. NPV, IRR 22

23. Oil Price Forecasts No forecast is a good forecast Long term price forecast is more important to E&P company in making project decisions. However, price escalation is subjective. Most companies have own in house “CORPORATE” long term oil forecast, approved by Senior Management. Source : International Energy Outlook 2004 23 Average annual increase ~ 14% (2004 – 2014) Demand Increases Oil Price Fluctuates CPI decreases

24. Gas Price Forecasts Demand driven Government Regulation for Power Sector Project Requirement – profits at certain economic threshold, e.g. IRR = 18% Fuel oil parity – pegged to other fuels, e.g. MFO or a basket of crude prices (OPEC basket, etc) Escalation per annum, e.g. percentage tied to CPI or Oil Field Machinery Index. 24 Source : 2015 BP Statistical Review

25. Price Assumptions PETRONAS Upstream economics assumptions are updated annually Price Oil price refers to BRENT BRENT price forecast : Per KPBI as issued by Center/PCSB SP For other crude types (Tapis, Miri Light, Labuan, Sudan, etc), price differentials (premium or discount depending on crude quality as compared to Brent e.g. Tapis priced at a premium to Brent where Tapis price = Brent + Tapis Price Differential Sudan = Brent – Sudan Price Differential Price assumed FLAT NOMINAL or MOD $ GAS : Per GSA or analog to existing GSA’s. If referenced to Fuel Oil or Crude, basis for these will be KPBI Escalation : Per KPBI Inflation : Per KPBI Exchange Rate : Per KPBI 25

26. Real Term and MOD Costs All costs are estimated based on current data and in TODAY’s dollars, often to referred to as “REAL TERM” dollars. Other terms include “Constant” dollars. Reference year must be specified such as RT 2002, RT 2003, etc During economic evaluation, to forecast future year cash, costs are escalated to FUTURE or MONEY of the DAY (MOD) dollars. Other terms include "Current”, "As Spent", "Escalated“, “Nominal” dollars. RT Dollars are converted to MOD dollars using ESCALATION Costs in MOD dollars are used in PETRONAS WP&B submission Real Term (RT) Cost Money of the Day (MOD) Cost ESCALATE Costs (MOD) =Costs (RT) x ( 1+e ) n e=escalation rate n = years ESCALATION Perception of market factors that will affect the cost of goods and services for the industry. Driven by supply and demand Example : Cost of basic essentials (eggs, chicken, etc) tend to go up during festive seasons 26

27. Real Term and MOD Price Oil and gas price forecasts can be quoted in RT or Nominal (=MOD) dollars. RT prices are converted to MOD dollars using INFLATION. In PETRONAS, price forecasts are usually in MOD dollars, hence no further inflation is applied. Real Term (RT) Cost Money of the Day (MOD) Price INFLATE Price (MOD) = Price (RT) x ( 1+i ) n I = inflation rate n = years INFLATION/DEFLATION Consumer Price Index (CPI) is the ratio of cost of purchasing a “basket” of consumer items in that year to the cost of purchasing the same “basket” in the Base Year. Inflation reduces our ‘Purchasing Power’ Example 5 years ago, RM 100 can buy a week’s grocery, today grocery for only 3 days. 27

28. Exchange Rates Changes to Exchange rate between two currencies over time are analogous to changes in the general inflation rate because the relative purchasing power between two currencies changes similar to relative purchasing power between actual money amounts and real money amounts. where f e – rate of change in the exchange rate i A – inflation rate in Country A i B – inflation rate in Country B Prior to 1997, the exchange rate has been fluctuating at RM 2.5 per US$. As the result of speculators/traders activities, the exchange rate has been pegged at RM 3.8 per US$ until August 2005. Source : exchangerate.com ( 1 + i Country A ) ( 1 + f e )=------------------------- ( 1 + i Country B ) Asian Financial Crisis Ringgit Floated within certain margin Ringgit to US$ pegging introduced 28

29. 29 Technical Inputs Economic Model Economic Assumptions Economic Results Reserves Production Capex Opex Price Cost Escalation Inflation Exchange Rate Risk & Sensitivity Analysis Net Cash Flow Tax & Capital Allowance Fiscal Arrangement Time Value of Money Economic Indicators eg. NPV, IRR 29 ECONOMIC ANALYSIS WORK-FLOW

30. We do economic evaluation to determine the economic merit of making an investment Cash Amount Received in the form of revenue e.g. Sales of Product Cash Amount Paid e.g. Operating Cost, Capital Expenditure, Royalty, Tax In simplest terms, a net cash flow forecast is a forecast of the CASH balance after deducting all monies spent from monies earned. The merit or the economic health of the project is measured using economic yardsticks, derived from the project Net Cash Flow (NCF). Net Cash Flow Equals to Cash InflowCash Outflow minus 30

31. Concepts Of Cash Flow NET CASHFLOW = CASH INFLOW - CASH OUTFLOW Capital expenditure (Capex): –eg. platforms, facilities, wells –asset life > 1 year Operating expenses (Opex): –eg. maintenance, chemicals, fuel, tariff paid –asset life <= 1 year Fiscal costs: –eg. royalty, taxes, duties, bonuses Other costs: –eg. premium payments Fiscal income: –eg. sale of oil and gas Operating income: –eg. tariff received Other income: –eg. premium received (+)(-) Examples of Cash InflowExamples of Cash Outflow 31

32. Concept of Net Cash Flow - Daily basis 34

33. Concept of Net Cash Flow - Daily basis 35

34. Concept of Net Cash Flow - Annual basis 36

35. Concept of Net Cash Flow - Annual basis 37

36. Concepts Of Cash Flow (-) Detailed Design (-) Construction/Fabrication (-) Hook-up/Commissioning (-) Development Drilling DEVELOPMENT PERIOD (+) PSC revenues (cost oil, profit oil) (-) Opex (-) Development Drilling (-) PSC costs PRODUCTION PERIOD (-) G&G studies (-) Seismic (-) Exploration Drilling EXPLORATION PERIOD Net Cash Surplus Net Cash Deficit Sample of A Field Life Cycle Project 38

37. A sample of A Field Life Cycle Project Unit Finding Cost (UFC) = Exploration Capex / Total Production= $ 10/50MMSTB = $0.20/BBL Unit Development Cost (UDC) = Development Capex / Total Production= $260/50MMSTB = $5.20/BBL Unit Operating Cost (UOC) = Total Opex / Total Production= $ 50/50MMSTB = $1.00/BBL Unit Technical Cost (UTC) = [Total Capex + Total Opex ] / Total Production = UFC + UDC + UOC= $0.20 +$5.20 + $1.00 = $6.40/BBL Exploration Period eg. Expl. Capex = US$ 10 MM Development Period eg. Dev. Capex = US$ 260 MM eg. Total Opex = US$ 50 MM Production Period eg. Total Production = 50 MMSTB 39

38. Cash Flow Model versus Financial (Accounting) Model TOTAL CAPEX $40,000 $10,000 Net Cash Flow Model simulates actual flow of cash for each year. 1/5 Cost $8,000 $10,000 1/5 Cost $8,000 1/5 Cost $8,000 1/5 Cost $8,000 1/5 Cost $8,000 Financial Model depreciates the asset over the assumed life of the asset. This result in a different profit picture. Concepts Of Cash Flow 33

39. Note: (1) Example from a Royalty-Tax fiscal regime Analytical Concepts Of Cash Flow  CASH INFLOW = Revenue = Price x Production  CASH OUTFLOW = Revenue - Royalty - Opex - Capex - Tax and, Royalty= RoyaltyRate x Revenue Tax= TaxRate x ( Revenue - Royalty - Opex - Capital Allowance ) Therefore,  NET CASHFLOW = ( Price x Production ) - RoyaltyRate x ( Price x Production ) - Opex - Capex TaxRate x (( Price x Production ) - Royalty - Opex - Capital Allowance ) = ( Price x Production ) x ( 1 - RoyRate ) x ( 1 - TaxRate ) minus Capex - TaxRate x Capital Allowance minus Opex x ( 1 TaxRate ) NET REVENUES (-) NET CAPEX (-) NET OPEX NET CASHFLOW = CASH INFLOW - CASH OUTFLOW 40

40. TUTORIAL 2 : Generate Technical Input Data Platform: US$ 80 Million spread over Year 1 and 2 Drilling : DM 120 Million spread over Year 2 and 3 Drilling costs will increase 10% p.a. in Real Term (RT) Facilities: Pesos 1 Billion in Year 1 Pesos 4 Billion in Year 2 Pesos 1 Billion in Year 3 Pipeline : US$ 5 Million in Year 1 US$ 30 Million in Year 2 Fixed Opex: 6% of Cumulative Capex to be paid in Pesos being indexed to local inflation rate Variable Opex : US$ 1.50/bbl Real Term (RT) being indexed to local inflation rate Oil Price: US$ 18/bbl, will increase by 2% p.a. in Real term (RT) Inflation rate : US$ 9% p.a.; DM 6% p.a. and Pesos 25% p.a. Exchange rate : 105 Pesos per 1 US$; 70 Pesos per 1 DM Suppose you have been assigned to conduct an economic analysis for a Country A with relatively high inflation rate. The following costs data have been collected if we were to develop it today. What would be our technical input data be ? 41

41. Suppose you have been assigned to conduct an economic analysis for a Country A with relatively high inflation rate. The following costs data have been collected if we were to develop it today. What would be our technical input data be ? Costs Data in RT Pesos Billion (1/1/Year 1)Year 1Year 2Year 3Year 4 Oil Production ForecastBbl/d40,00080,000 PlatformUS$ Mill FacilitiesPesos Bill. PipelineUS$ Mill. DrillingDM Mill. PlatformRT Pesos Bill. FacilitiesRT Pesos Bill. PipelineRT Pesos Bill. DrillingRT Pesos Bill. Total CapexRT Pesos Bill. Fixed Opex @ 6% Cum. CapexRT Pesos Bill. Variable Opex @ US$ 1.50/bblRT Pesos Bill. Pesos Escalation factor25% CapexMOD Pesos Bill. OpexMOD Pesos Bill. TUTORIAL 2 : Generate Technical Input Data 42

42. Note: (1) Example from a Royalty-Tax fiscal regime Cash In Royalty Opex Tax Capex Cash Out Net Cash Flow After Tax Approach : 1.Determine Capital Allowance schedule 2.Calculate Tax 3.Perform Net Cash Flow calculation 2 3 NET CASHFLOW = CASH INFLOW - CASH OUTFLOW 1 Tax Rate x ( Cash In – Royalty – Opex – Capital Allowance ) Concepts Of Cash Flow 32

43. Tax Payable =Tax Rate * Taxable Income Taxable Income =Income - Expenses – Capital Allowance Tax Paid (less) Taxable Income (equals) Income After Tax (equals) Tax & Capital Allowance Income Expenses (less) Income Before Tax (equals) Capital Allowance: –depreciation calculation begins from 1 st production OR 1 st year of investment incurred (whichever later) –rate varies with types of capital; investment in high risk areas or in Secondary/Tertiary recovery will entitle for higher depreciation rate (government incentive) –Intangible Capex, such as portion of development drilling (circa 80%), can be expensed off Capital Allowance (less) 44

44. Tax & Capital Allowance The most common types of Depreciation/ Depletion/ Amortisation to calculate Capital Allowance : 1. Straight Line method - Claimable in Equal amounts over number of years 2. Declining Balance method - Claimable based on yearly fixed percentage of the unrecovered capital at the end of the year 3. Depletion/Unit of Production method - Claimable based on the fraction of remaining reserves produced during the year 45

45. Example : Capex to be depreciated at 25% p.a., First Production in Year 2 Year 1Year 2Year 3Year 4Year 5Year 6Total Annual Production410 9740 Capex100 Depreciation Rate25% Capex to be Depreciated100 Capital Allowance25 100 Straight Line Method 46 Tax & Capital Allowance

46. Example : Capex to be depreciated based on 25% of the non-depreciated balance, First Production in Year 2 Year 1Year 2Year 3Year 4Year 5Year 6Total Annual Production410 9740 Capex100 Depreciation Rate25% Capex to be Depreciated10075564231 Capital Allowance2519141131100 Balance Non-depreciated755642310 Declining Balance Method Note : Since the production ends in Year 5, the remaining non-depreciated will be capitalised fully. 47 Tax & Capital Allowance

47. Example : Capex to be depreciated based on the ratio of the annual production to the reserves at the beginning of the year times the non-depreciated balance, First Production in Year 2 Year 1Year 2Year 3Year 4Year 5Year 6Total Annual Production410 9740 Reserves @ 1 st January403626167 Annual/Reserves10%28%38%56%100% Capex100 Capex to be Depreciated10090654018 Capital Allowance1025 2218100 Balance Undepreciated906540180 Depletion/Unit of Production Method 48 Tax & Capital Allowance

48. Straight Line method allow constant CCA claim compared to Declining Balance and Depletion/Unit of Production methods 49 Tax & Capital Allowance

49. Tax Losses Carry Forward Example: Year 1Year 2Year 3Total Net Income Before Tax60120 300 (less) Capital Allowance(110)(80) (270) (equal) Taxable Income(50)40 30 Tax Payable @ 40%(20)16 12 Tax Losses Carryforward(20)(4)-- (less ) Tax Paid--12 Net Income After Tax60120108288 50 Tax & Capital Allowance

50. Tax Deductible Revenue – Cash In100.0US$ MM (less) Royalty(30.0)US$ MM (less) Bonus(10.0)US$ MM Income Before Tax60.0US$ MM (less) Capital Allowance(10.0)US$ MM Taxable Income50.0US$ MM Tax Payable @ 38%(19.0)US$ MM (less) Tax Paid(19.0)US$ MM Income After Tax41.0US$ MM Revenue – Cash In100.0US$ MM (less) Royalty(30.0)US$ MM Income Before Tax70.0US$ MM (less) Capital Allowance(10.0)US$ MM Taxable Income60.0US$ MM Tax Payable @ 38%(22.8)US$ MM (less) Bonus(10.0)US$ MM (less) Tax Paid(12.8)US$ MM Income After Tax57.2US$ MM Tax Creditable 51 Tax & Capital Allowance

51. TUTORIAL 3 : Calculate Cash Flow Production Data: First Oil beginning of Year 3 Technical Costs: Oil Price forecast: US$ 20/bbl, expected to remain constant thereafter Terms and Conditions: Royalty 25% Tax rate 20%, Tax losses not allowed Capital Allowance – Straight line at 25% p.a., Only start after First Oil production Year 1Year 2Year 3Year 4Year 5Year 6Year 7Year 8Year 9 Annual Oil Production515 102.51.00.5 Year 1Year 2Year 3Year 4Year 5Year 6Year 7Year 8Year 9 Platform30 Facilities1530 Tangible Drilling1015104 Intangible Drilling2032155 Fixed Opex81415 Variable OpexUS$ 0.40/bbl produced The following offshore oil development project is being proposed. What would be your approach to address the opportunity ? 52

52. The following offshore oil development project is being proposed. What would be your approach to address the opportunity ? 1 2 Capital Allowance Calc.Year 1Year 2Year 3Year 4Year 5Year 6Year 7Year 8Year 9 Platform Facilities Tangible Drilling Total Capex CA Year 1 Capex @25% CA Year 2 Capex @25% CA Year 3 Capex @25% CA Year 4 Capex @25% Total CA Tax Calc.Year 1Year 2Year 3Year 4Year 5Year 6Year 7Year 8Year 9 Cash In Royalty Opex Income Before Tax Total CA Drilling costs Expensed Taxable Income Tax Paid @20% TUTORIAL 3 : Calculate Cash Flow 53

53. The following offshore oil development project is being proposed. What would be your approach to address the opportunity ? 3 Net Cash Flow Calc.Year 1Year 2Year 3Year 4Year 5Year 6Year 7Year 8Year 9 Cash In Royalty @25% Opex Capex Tax Cash Out Net Cash Flow TUTORIAL 3 : Calculate Cash Flow 54

54. PART 2 Analysing Economic Indicators and Results 55

55. Different types of petroleum arrangement are being adopted in different parts of the world. PETROLEUM AGREEMENTS CONCESSION SYSTEMS CONTRACTUAL SYSTEMS Service Contracts Production Sharing Contracts Pure ServiceRisk Service Concession Agreements 56

56. Contractual SystemConcessionary System Oil companies owns the production Contractors pay royalty and tax to the government Government has the sole ownership of petroleum resources. Oil companies are assigned as contractors Contractors furnish all risk capital. In return, contractors will be allowed to recover the cost upon production For Production Sharing Contract: remaining profit (after cost recovery) is shared between government & contractors For Service Contract: remaining profit belongs to government; contractors will be compensated through unused cost oil as their ‘remuneration’ Typical Characteristics of Fiscal Arrangements 57 Fiscal Arrangements

57. $40 $60 Costs = $40 Net Take = $60 Example: Revenue = $100 Cost = $ 40 Revenue Net Cash Flow Opex Capex Project Cash Flow (less) (equals) Project Fiscal Arrangements 58

58. Cost= $40 Government Take= $30 Contractor Take= $30 *Net Govt. Take = 50% $40 Costs = $40 $30 Contractor Take = $30 Government Take = $30 $10 Royalty @10% $20 Tax @40% Example: Revenue = $100 Cost = $ 40 Concession Agreement Fiscal Arrangements 59

59. Net Cash Flow State/Government Cash Flow (equals) Concession Agreement Revenue Opex Capex Project Cash Flow Net Cash Flow (equals) (less) Net Cash Flow (equals) Tax Royalty Contractor’s Cash Flow (less) Fiscal Arrangements 60

60. Concession Agreement Example: Morocco Production Concession Agreement Royalty: 10.0% Corporate Income Tax rate: 35% of taxable income Production Bonus (non-tax deductable): US$ 1.0 MM for first production US$ 2.0 MM for production exceeding 50 MSTB/D US$ 3.0 MM for production exceeding 100 MSTB/D US$ 5.0 MM for production exceeding 200 MSTB/D Fiscal Arrangements 61

61. Example: Pakistan Production Concession Agreement Royalty: 12.5% Corporate Income Tax rate: 55% of taxable income (Capital Allowances: Tangible Capex depreciated at the rate of 10%pa) Workers Participation Fund (WPF): = 5% of net income before tax less capital allowance Workers Welfare Fund (WWF): = 2% of net income before tax less capital allowance less WPF Production Bonus (non-tax deductable): - First Level = US$ 1.0 MM for first production - Second Level = US$ 3.0 MM for production exceeding 300 MMSCF/D - Third Level= US$ 5.0 MM for production exceeding 600 MMSCF/D Concession Agreement Fiscal Arrangements 62

62. Concession Agreement Provide the logic for Contractors’ Net Cash Flow calculations using the provided input variables Input Variable Gas Sales Gas Price Capex Opex Royalty Rate Depreciation Rate Tax Rate Computational Logic Revenue – Cash In Royalty Opex Income Before Tax Capital Allowance Taxable Income Tax Paid Income After Tax Capex Cash Out Net Cash Flow After Tax TUTORIAL 4 : Fiscal Terms Computational Logic 63

63. Cost Bank and Cost Recovery Concepts BANK Deposit Opex Capex Withdrawal Cost Recovery Cost Recovery Ceiling ACTUAL COST RECOVERED (2) Cost Bank = balance of cost to be recovered Cost Bank = Unrecovered Cost Cost Bank =Current Cost Bank Balance (+) Total Cost for the period (-) Cost Recovered Actual Cost Recovered = $50 Unrecovered Cost = $10 Actual Cost Recovered = $40 Unrecovered Cost = $0 Actual Cost Recovered = MIN [Cost Recovery Ceiling vs. Amount Cost Bank] Example 2: Ceiling $50 Cost Bank $60 Example 1: Ceiling $50 Cost Bank $40 Production Sharing Agreement (1) Fiscal Arrangements 64

64. Cost Bank and Cost Recovery Concepts BANK Deposit Opex Capex Withdrawal Cost Recovery Cost Bank = balance of cost to be recovered Cost Bank = Unrecovered Cost Cost Bank =Current Cost Bank Balance (+) Total Cost for the period (-) Cost Recovered Production Sharing Agreement Fiscal Arrangements Cost Oil Ullage Cost Oil Ceiling Costs below ceiling are recovered during the period Costs above ceiling are carried to next period 65

65. Fiscal Arrangements Gross Rate303525157 First 10 kstb/d7.0 4.9 Next 10 kstb/d6.0 3.00 Above 20 kstb/d5.07.52.500 Contractor Share ksbt/d18.020.515.510.04.9 Contractor Share %60%58.6%62.0%66.7%70.0% RateStateCont > 20 kstb/d50 2 nd 10 kstb/d4060 1 st 10 kstb/d3070 Sliding Scale Profit Split Concept Production Sharing Agreement 66

66. Cost= $40 Government Take= $51 Contractor Take= $ 9 *Net Govt. Take = 85% $10 Royalty @10% Govt. Profit Share @70% $6 $35 Tax @40% Government Take = $51 Cost Recovery Ceiling @50% = $40 $40 Contractor Take = $9 $9 Example: Revenue = $100 Cost = $ 40 Production Sharing Agreement Fiscal Arrangements 67

67. Production Sharing Agreement Royalty Net Cash Flow State/Govt. Profit Share (equals) (less) State/Government Cash Flow Revenue Opex Capex Net Cash Flow (equals) (less) Project Cash Flow Tax Net Cash Flow Cost Recovery Contr. Profit Share (less) (equals) (less) Profit Share (equals) (less) Contractor’s Cash Flow Fiscal Arrangements 68

68. Evolution of Malaysian PSC PETROLEUM DEVELOPMENT ACT (PDA) 1974: –PETRONAS have the exclusive rights to explore for and produce petroleum in the country –PETRONAS is responsible for the management of the petroleum operations while the Oil Company will be responsible to PETRONAS as a "Contractor" –Government or PETRONAS owns the production and shall pass to the Oil Company only on the production that accrue to them Fiscal Arrangements 69

69. Evolution of Malaysian PSC Fiscal Arrangements 70 Concession agreements between oil companies and State Government s. Primarily to convert the then existing concessio n agreement s into PSCs. Primarily to attract foreign investment to explore for oil and gas resources. Prod. tranche- based fiscal regime. Target for big players with experience in deepwater exploration, development & production. DW/UDW terms based on water depth production tranches. To attract new foreign exploration investments. To promote use of cost- effective new technology in the exploration for higher risk subtle plays. Profitability- based sliding scale fiscal regime hooked onto a profitability index with sliding scale sharing of unused cost. To attract developmen t of riskier potential in brown fields Provide base volume for Contractor to accelerate cost recovery Progressiv ely better profit sharing to contractor with developmen t of new resources Production Rate/Volume Based Profitability Based Concessio n Agreement Pre- 1976 1976 PSC 1976 1985 PSC 1985 DW/ Ultra DW PSC 1994 R/C PSC 1997 PROGRESSIVE VOLUME BASED 2012 To attract investments in operational challenging conditions of extreme high pressure and high temperature of deep reservoirs The terms offered are an improvement to the Standard R/C PSC to ensure deep shelf projects are commerciall y viable HP/HT PSC 2008 To attract niche players and promote innovation for cost optimizati on Increase local participat ion and develop local capability Some diversion in risk/rewar d sharing structure RISK SERVICE CONTRACT 2011

70. Production-Tranche and Profitability Based Comparison Production-Tranche BasedProfitability Based Gross Production is divided into 3 parts : - Royalty : Fixed - Cost Oil and Gas : Fixed - Profit Oil and Gas : Fixed Profit Split : Variable Gross Production is divided into 3 parts: - Royalty : Fixed - Total Cost Tranche : Variable - Total Profit Tranche : Variable Profit Split : Variable Available Unused Cost is treated as Profit and shared Accordingly. Better Profit Split in Unused Cost to Contractor than in Available Profit. Profit splits are volume based and triggered by production rates and fixed cumulative production volume cap Profit splits are triggered by R/C Index and the Threshold Volume, THV is variable (incremental) to encourage development to subsequent fields. Fiscal Arrangements 71

71. Example: Malaysian Production Sharing Contract (R/C Terms) Royalty: 10.0% Cost Recovery & Profit Sharing: where R/C = Revenue/Cost; TCT = Total Cost Tranche, TPT = Total Profit Tranche, P = PETRONAS/Govt., C =Contractor Petroleum Income Tax rate: 38% of taxable income Research Cess = 0.5% of Contractors’ Cost & Profit Oil Export Duty = 10% of Profit Oil Production Sharing Agreement Fiscal Arrangements 72

72. Example: Yemen Production Sharing Contract Royalty: 5% for production <= 50 MSTB/D 7% for production > 50 MSTB/D 10% for production > 100 MSTB/D Cost Oil Ceiling: 50% Profit Oil Sharing (Contractors’ Share) 37% for production <= 50 MSTB/D 30% for production > 50 MSTB/D 20% for production > 100 MSTB/D Petroleum Income Tax rate: 25% of taxable income Production Bonus (non-cost recoverable, non-tax deductable): US$ 1.0 MM for production > 25 MSTB/D US$ 2.0 MM for production > 50 MSTB/D US$ 3.0 MM for production > 100 MSTB/D Production Sharing Agreement Fiscal Arrangements 73

73. Production Sharing Agreement Provide the logic for Contractors’ Net Cash Flow calculations using the provided input variables Input Variable Oil Production Oil Price Capex Opex Royalty Rate Cost Ceiling Rate Contr. Profit Rate Depreciation Rate Tax Rate Computational Logic Revenue Royalty Cost Ceiling Cost Incurred Cost Bank Cost Recovered Unrecovered Cost Profit Contr. Profit Contr. Entitlment (Cash In) Opex Income Before Tax Capital Allowance Taxable Income Tax Paid Income After Tax Capex Cash Out Net Cash Flow After Tax TUTORIAL 5 : Fiscal Terms Computational Logic 74

74. Production Sharing Agreement Provide the logic for National Oil Company (NOC)’s Net Cash Flow calculations using the provided input variables Input Variable Oil Production Oil Price Capex Opex Royalty Rate Cost Ceiling Rate NOC Profit Rate Depreciation Rate Tax Rate Computational Logic Revenue Royalty Cost Ceiling Cost Incurred Cost Bank Cost Recovered Unrecovered Cost Profit NOC Profit NOC Entittlment (Cash In) Income Before Tax Taxable Income Tax Paid Income After Tax Cash Out Net Cash Flow After Tax TUTORIAL 6: Fiscal Terms Computational Logic 75

75. Production Sharing Agreement Calculate Contractors’ Net Cash Flow using the provided input Input Variable Oil Price (US$/bbl)20.0 Royalty Rate10% Cost Ceiling Rate50% Contr. Profit Rate30% Depreciation Rate20% Tax Rate38% Year 1Year 2Year 3 Annual Oil Production2.06.05.0 Capex30.020.0- Opex10.0 Revenue Royalty Cost Ceiling Cost Incurred Cost Bank Cost Recovered Unrecovered Cost Profit Contr. Profit Contr. Entitlment (Cash In) Opex Income Before Tax Capital Allowance Taxable Income Tax Paid Income After Tax Capex Cash Out Net Cash Flow After Tax TUTORIAL 7 : Calculate Net Cash Flow under Production Sharing 76

76. Production Sharing Agreement Calculate National Oil Company (NOC)’s Net Cash Flow using the provided input Input Variable Oil Price (US$/bbl)20.0 Royalty Rate10% Cost Ceiling Rate50% NOC Profit Rate70% Depreciation Rate20% Tax Rate38% Year 1Year 2Year 3 Annual Oil Production2.06.05.0 Capex30.020.0- Opex10.0 Revenue Royalty Cost Ceiling Cost Incurred Cost Bank Cost Recovered Unrecovered Cost Profit NOC Profit NOC Entitlment (Cash In) Income Before Tax Taxable Income Tax Paid Income After Tax Cash Out Net Cash Flow After Tax TUTORIAL 8 : Calculate Net Cash Flow under Production Sharing 77

77. Cost= $40 Government Take= $54 Contractor Take= $ 6 *Net Govt. Take = 90% Government Take = $54 Govt. Profit Share Tax @40% $50 $4 Cost Recovery Ceiling @50% = $40 $40 Contractor Take = $6 $6 Example: Revenue = $100 Cost = $ 40 Service Contract Agreement 78 Fiscal Arrangements

78. Service Contract Agreement Revenue Opex Capex Net Cash Flow (equals) (less) Project Cash Flow Net Cash Flow (equals) (less) Tax Cost Recovery Remuneration (less) Cost Ceiling (less) Contractor’s Cash Flow Net Cash Flow State/Govt. Profit Share (equals) State/Government Cash Flow 79 Fiscal Arrangements

79. Example: Iran Service Contract Cost Oil Ceiling: 60% Capital to be amortised over 6-year period for recovery Remuneration for contractors = remaining unused cost oil Petroleum Income Tax rate: 15% of taxable income Training bonus (non-cost recoverable, non-tax deductable): $1.5 MM per year (from 1st production) Service Contract Agreement 80 Fiscal Arrangements

80. 81 Government Take, % 2012 Proved Oil Reserves, Billion Barrels PETRONAS E&P Presence Screening Source: Proved Oil Reserves: BP Statistical Review of World Energy 2013 Government Take %: IHS PEPS, PEC internal assessment Fiscal Arrangements

81. 81 ECONOMIC ANALYSIS WORK-FLOW Technical Inputs Economic Model Economic Assumptions Economic Results Reserves Production Capex Opex Price Cost Escalation Inflation Exchange Rate Risk & Sensitivity Analysis Net Cash Flow Tax & Capital Allowance Fiscal Arrangement Time Value of Money Economic Indicators eg. NPV, IRR 82

82. Economic indicators are yardsticks used to quantify the relative attractiveness of an investment : 1. Establish the economic feasibility of an investment opportunity 2. Weight the RELATIVE merits on investment opportunities 3. Determine the value for buying or selling as asset 4. Assess the feasibility for project expansion or acceleration Other than strategic considerations, we need to apply APPROPRIATE profitability indicators to support management decisions Maximum Cash Sink Payback Period Breakeven Profit Investment Ratio Economic Life Ultimate Cash Surplus Examples of Profitability indicators 83 Economic Indicators

83. A Sample of Cash Flow Profile 1st Prod in 2006 Production Development Total Investment = US$ 950 Million Project starts 2003 Abandonment Project ends 2023 84 Economic Indicators

84. A Sample of Cash Flow Profile Definition: Maximum amount of cash outlay for a project Formula: MIN (Cumulative Net Cash Flow) Unit: Currency value Maximum Cash Sink = US$ 860 Million 85 Economic Indicators

85. A Sample of Cash Flow Profile Definition: The year when the sum of Cash Inflow equates to Cash Outflow, beyond which the project will fully fund itself Formula: Cumulative Net Cash Flow = 0 Unit: - Breakeven = in year 2010 86 Economic Indicators

86. A Sample of Cash Flow Profile Definition: No of years from First Development Investment to achieve breakeven Formula: COUNT (Breakeven - 1st Development) Unit: Years Payback Period Payback period = 7 years 1st Development in 2003 Breakeven in year 2010 87 Economic Indicators

87. A Sample of Cash Flow Profile Definition: The year where Maximum Cumulative Cash realised Formula: MAX (Cumulative Net Cash Flow) Unit: - Economic Limit Maximum Cumulative Cash = US$ 1,911 Million Economic Limit = in year 2021 88 Economic Indicators

88. A Sample of Cash Flow Profile Definition: No. of years from 1st Production to achieve Economic Limit Formula: COUNT (from 1st Prod to Economic Limit) Unit: Years Economic Life = 15 years Economic Limit in 2021 1st Prod in 2006 89 Economic Indicators

89. A Sample of Cash Flow Profile Ultimate Cash Surplus = US$ 1,801 Million Definition: Cumulative Net Cash Flow at the end of project life Formula: S( Net Cash Flow n ) =Undiscounted Net Present Value Unit: Currency Value Ultimate Cash Surplus 90 Economic Indicators

90. Definition: Amount earned for every dollar spent Formula: Undiscounted Net Present Value / Total Investment Unit: Ratio Undiscounted Profit Investment Ratio (PIR) Total Investment = US$ 950 Million PIR = US$ 1,801 Million = 1.9 US$ 950 Million Ultimate Cash Surplus = US$ 1,801 Million 91 Economic Indicators A Sample of Cash Flow Profile

91. Valuation of these cash flow streams which are realized at different points in time employs the time value money concept TIME VALUE OF MONEY oil and gas projects involve the investment of large sums of money, often over a span of several years before any revenue is obtained. projects can last for twenty years or more. a very long lead time between expenditure and resulting revenue time has a critical bearing on the value of money. 30 years ago, 50 sen was sufficient for a primary school kid to buy a good lunch at school today, the same good lunch costs about RM 2.00 cater for potential opportunity loss and risk opportunity cost - return foregone by investing in the project as opposed to alternative opportunities available present value analysis consistently values the money spent and received at different points in time 92

92. What is the equivalent today’s value of the money in the future? Because of the uncertainties, you discount the future value. NowFuture n th year $1 MM More Uncertain $1 MM Uncertain 6 th year $1 MM 1 st year If you have a chance to collect $1 Million, which year do you prefer? NowFuture n th year $0.5 MM More Uncertain $0.8 MM Uncertain 6 th year $1 MM 1 st year 93 Time Value of Money

93. Present Value = Future Value ( 1+ r ) n “Value of $1 today is more valuable than the value of $1 in the future”. - opportunity loss - risk In economic analysis, we should consistently value the money spent and received at different time The discounting technique: where; r = discount rate, n = number of years from today Future Value Present Value Present Value (RT) Future Value (MOD) n : numbers of period I : interest per period Calculate Profitability Indicators Discounting 94 Time Value of Money

94. Finding the Future Value - Compounding Future ValuePresent Value FV= PV x (1 + i) n FV= Future Value PV= Present Value i= compound rate n= time period (1+i) n = compounding factor Example : Cost of drilling a well in 2009 is $15 million. We expect cost to escalate at 5% p.a for the next 10 year period. If we plan to drill the well in 2013, what would be the expected cost ? Well cost in 2013= 15 x (1 + 5%) 4 = $18.2 million MOD (money of the day) 95

95. Year 2008200920102011201220132014Total Discount Factor @ 10%1.0001.1001.2101.3311.4641.6111.772 PV NCF t=0-250.0 PV NCF t=145.5 PV NCF t=282.6 PV NCF t=375.1 PV NCF t=447.8 PV NCF t=537.3 PV NCF t=628.2 Total NPV66.5 Through discounting, the money spent and received at different time are valued consistently The project is anticipated to generate total MOD NCF of $180 million. However, in 2008 term it worth $67 million to the company (NPV @ 10%) Discounted at 10% Net Cash Flow (NCF)-250.050.0100.0 70.060.050.0180.0 96

96. A company makes a retirement offer to its employees as follows :- a) receives RM 60K at the end of the 10 th year or b) receives additional annual salary of RM 5000 for the next 10 years Mr A is thinking of participating in an investment project which offers average annual return of 6%. Would he be better off if he accepts option (b) and put all the additional salary into the investment scheme? TUTORIAL 9 : Time Value Of Money Average Return6%RM ‘000 YearYear 1Year 2Year 3Year 4Year 5Year 6Year 7Year 8Year 9Year 10Total Deposit Year Begin Balance Year End Gain RM ‘000 Total amount deposited in the Investment scheme Total Profit Gain Total Amount collected at the end of 10th Year 97

97. The forecasted Consumer Price Index is around 3% per year. Your company’s Cost of Capital is at 10%. What is the Present Value of the following Net Cash Flow ? Year 1Year 2Year 3Year 4Year 5Year 6Year 7Total Net Cash Flow-60-921016317711720336 Discount Rate @ 3% Discounted NCF @3% Discount Rate @ 10% Discounted NCF @10% TUTORIAL 10 : Time Value Of Money 98

98. Definition: Sum of discounted Net Cash Flow over project life Formula: S ( Net Cash Flow n * discount factor n ) Unit: Currency Value Net Present Value (NPV) NPV@0% = US$ 1,801 Million NPV@10% = US$ 566Million NPV@15% = US$ 271 Million NPV@23% = US$ 0 Million NPV@40% = (US$ 197 Million) A Sample of Net Present Value Profile 99 Economic Indicators

99. Definition: Discount rate for which NPV=0 Formula: Discount rate where NPV=0 from NPV profile Unit: Percentage Internal Rate of Return (IRR) Internal Rate of Return = 23% NPV@23% = 0 100 Economic Indicators A Sample of Net Present Value Profile

100. NPV and IRR Both indicators apply time value money on the annual net cash flows forecast. Net Present Value describes the fair value of a project indicates whether the project creates value (positive NPV) or erodes value (negative NPV) a project which gives NPV@10% of $50 million tells us that by investing in the project, it will give us additional value of $50 million as compared to investing our money in some alternative scheme which provide a return of 10%. Internal Rate of Return not a measure of value a handy indicator for project screening against company hurdle rate; for example, if the hurdle rate is 15%, any project with IRR < 15% should be excluded from the portfolio. if the IRR of a particular project is greater than the rate of return which can be obtained in comparable alternative investments, then the project theoretically should be undertaken. 101

101. IRR and Hurdle Rate Hurdle Rate is … company specific usually is a function of the company’s weighted average cost of capital (WACC) plus the premium the company sets to cater for risks. IRR for project should be greater than the company hurdle rate for the project to considered economic. Project Return ‘Hurdle Rate’ Value Creation WACC Risk Premium ‘Hurdle Rate’ Weighted Average Cost of Capital (WACC) ‘Risk Premium’ Management’s prerogative to include risk premium from country and other perceived risks Cost of capital (funds) is a function of –cost of debt (interest on loan) –cost of equity (dividends paid to shareholders) f 102

102. Profit-to-Investment Ratio (PIR) o A measure of investment efficiency i.e. amount of present value profit per dollar of investment i.e. Capex o Normally, quoted on discounted basis at certain rates, to reflect time value of money and the pattern of Net Cash Flow 2008200920102011201220132014Total Net Cash Flow -100-150100 908070190.0 Discount Rate @ 10% 1.000.910.830.750.680.620.56 Discounted NCF @ 10% -100.0-136.583.075.061.249.639.271.5 2008200920102011201220132014Total Capex 100150 250.0 Discount Rate @ 10% 1.000.910.830.750.680.620.56 Discounted NCF @ 10% 100.0136.50.0 236.5 PIR @ 0%= 0.76 PIR @ 10%= 0.30 Investment opportunity may create value for the company if it generates PIR greater than company’s minimum acceptable PIR 103

103. Total Investment US$ 950 Million PIR = US$ 1,801 Million = 1.9 US$ 950 Million Cash Flow (US$MM) Maximum Cash Sink US$950 Million Breakeven in year 2010 Payback period 7 years 1 st Prod. 2006 Economic Life = 15 years Ultimate Cash Surplus US$ 1,801 Million Other indicators which could be derived from net cash flow 1 2 3 4 5 6 7 Economic Limit in year 2021 103 1 st Devt. Invest. 2003

104. A project requires US$ 260 Million of total Investment, which excludes exploration Sunk Cost of US$ 32 MM. First oil is expected to be in year 4. Below is the forecasted annual Net cash Flow for your assessment. Calculate the economic indicators for the project life at January Year 3. Year 1Year 2Year 3Year 4Year 5Year 6Year 7Year 8Total Net Cash Flow (32) - (260) 90 80 70 58 86 Cum. Net Cash Flow Discount Factor @ 10% 1.00 0.91 Discounted Net Cash Flow Discount Factor @ 15% 1.00 0.87 Discounted Net Cash Flow IRR NPV @0% NPV @10% NPV @15% Maximum Cash Sink Pay- back Undisc. PIR TUTORIAL 11 : Calculate Economic Indicators 105

105. Calculate the economic indicators for the previous project for look forward Year 3. Sunk cost of US$ 32 Million in year 1 is now excluded. Year 1Year 2Year 3Year 4Year 5Year 6Year 7Year 8Total Net Cash Flow- - (260) 90 80 70 58 118 Cum. Net Cash Flow-- Discount Factor @ 10% 1.00 0.91 Discounted Net Cash Flow - - Discount Factor @ 15% 1.00 0.87 Discounted Net Cash Flow- - IRR NPV @0% NPV @10% NPV @15% Maximum Cash Sink Pay- back Undisc. PIR TUTORIAL 12 : Economic Indicators 106

106. Your management is considering the option to invest in Project A OR in Project B. Which project would you recommend ? Note : Company’s WACC is 10% 107 Economic Indicators

107. Option B US$ 110 MM WACC of 10% Option A US$ 37 MM Option B 15% Option A 20% Observation ! IRR : Option A > Option B But NPV@10% : Option A < Option B Your management is considering the option to invest in Project A OR in Project B. Which project would you recommend ? Note : Company’s WACC is 10% 108 Economic Indicators

108. Your management is considering the option to invest in Project A OR in Project B. Which project would you recommend ? Note : Company’s WACC is 10% Conclusion ! Select Option B since the incremental costs of US$ 900 will result in IRR of 14.1% Option B US$ 110 MM WACC of 10% Option A US$ 37 MM Option B 15% Option A 20% 109 Economic Indicators

109. 109 Technical Inputs Economic Model Economic Assumptions Economic Results Reserves Production Capex Opex Economic Analysis Work-flow Price Cost Escalation Inflation Exchange Rate Risk & Sensitivity Analysis Net Cash Flow Tax & Capital Allowance Fiscal Arrangement Time Value of Money Economic Indicators eg. NPV, IRR 110

110. Source: (1) EPSS, ‘Risk White Paper’, August 2001 Country Risk uncertainty in location E.g. political risk, economic risk, regulatory risk Technical/Operational Risks uncertainty in operating cash flow e.g. production, cost, price Project Risks uncertainties in project execution e.g. reservoir, facilities, schedule, budget Production Development Appraisal Exploration Level of Uncertainty Risks and uncertainty in oil and gas investment Generally uncertainties tapers towards the production stage 111

111. Risk & Sensitivity Analysis Ad Hoc Methods –Discount Rate Adjustment –Capital at Risk –Time Risk and Capital Recovery Sensitivity Analysis –Analysis of One Variable –Analysis of More than One Variable –Range Approach Probabilities (Monte Carlo) Methods of Risk Analysis 112

112. Ad Hoc Methods To increase the discount rate for capital “at risk”, or to favour a short payback period in risky situations. Three (3) types of commonly used are : a.Discount Rate adjustment  To increase the test discount rate for capital projects which are considered to be risky. This suggest that capital invested in an uncertain project is required to yield a higher margin of profit than capital invested safely. b.Capital At Risk  The amount of capital at risk (or the sunk cost) is that proportion of the initial investment which would not be recovered in the event of the disposal of fixed assets. Once the capital has been proportioned as “safe” or “at risk” the project can be compared with company criteria. The decision can consequently be taken as to whether the rate of return justifies the risk. c.Time risk and Capital Recovery  Certain types of risk are based on time criteria alone, namely those which lead to the premature termination of a project i.e. political risk, the danger of nationalization or revolution. Payback might therefore be useful criterion to include in the overall assessment of investment projects. 113

113. Prod Price Capex Opex Risk & Sensitivity Analysis Sensitivity Analysis (Spider Plot) Investigates the relationships between change in key project variables and measure of value. Important variables are : a) Production b) Price c) Capex d) Opex Start with “Base Case” and change one variable at a time keeping all other assumption at the Base Case The steeper the slope is, the more sensitive the parameter would be. The shaded region reflects our confident range of variable uncertainty that will impact the project's IRR 114

114. Sensitivity Analysis (Tornado Chart) Investigates the relationships between change in key project variables and measure of value. Important variables are : a) Production b) Price c) Capex d) Opex Start with “Base Case” and change one variable at a time keeping all other assumption at the Base Case The longer the bar is, whether to the left or right from the Base case, the more sensitive the parameter would be. Risk & Sensitivity Analysis 115

115. Decision Tree Analysis A technique to structure decision-making process. It consists of two (2) type of “nodes” :- 1.Decision nodes – indicated by rectangles (or diamond) branch into a complete set of possible actions. 2.Chance nodes – indicated by circles (or rectangles) branch into all possible results or situations. There are four (4) steps involved in the analysis :- 1.Draw the tree – starts with the first decision to be taken, begin at the present, progresses in the future. 2.Assign values – normally NPV at certain discount rate, to all the “leaves” 3.Estimate the probabilities of the results. 4.Roll back the tree – evaluates at the “leaves” and works backward towards the “trunk” of the tree. The value of the chance is the statistical (weighted) average of all its results whereas the value of the decision is the optimum of the values of its action. 116

116. Create tree from left to right according to sequence of event/decision Solve from right to left OR Create tree from top to bottom according to sequence of event/decision Solve from Bottom to Up 117 Decision Tree Analysis

117. discovery dry EMV=2 EMV=(8) EMV=10 0.8 NPV @10% = (10) 0.2 NPV @10% = 50 An Example of Decision Tree Analysis Drill prospect EMV=0 Don’t drill Weighs risk capital and chance of losing it against potential rewards and the probability of achieving that rewards Expected Monetary Value (EMV) The rule is if EMV is positive, then the risk-weighted reward outweighs the risk- weighted cost of failure ( Probability of Success * Net Value Gain ) EMV=Less ( Probability of Failure * Net Value Loss ) 118 Decision Tree Analysis

118. EMV +ve Indicates the breakeven probability of success in order to achieve positive EMV Explains changes in probability assessment would results in a different recommendation Flip Point Analysis 119 Decision Tree Analysis

119. PART 3 & 4 Basic Economic Modeling Case Study Preparation 120

120. Economic Modeling – A Few Tips! “What else is missing ?” Cross check the flow diagram basis & assumptions project parameters Calibrate with manual calculation. Rationalize output. Prior running new cases or sensitivity, start with the reference case to ensure input and model are intact. Understand business model Summarize salient terms. Create revenue flow diagram List down basis & assumptions evaluation scenario project parameters Use headings for different calculation blocks. Keep formula simple, if necessary break down to a few rows/columns Insert comments for cells as required Avoid “cut and paste” within formula range. using > 2 decimal places (unless required) Before..While …After … 121

121. Getting Started : Information Required Exploration Costs G&G costs Number of wells, well cost, and timing of exploration and appraisal costs General Assumptions Oil price, gas price, Cost and price escalations, Currency exchange rate, Required hurdle rate Development Costs Development scenarios Development cost detailed by fixed structure, facilities, pipeline, etc. Development drilling cost Typical operating cost Phasing of each type of development capex Volumetrics SR for prospects and corresponding probability of exploration success Reserves for fields First year of production Oil production profile, gas demand forecast and matching gas delivery rates from fields Fiscal & Economic Modeling Fiscal Contract (PSC, Concession, Service Agreement) Tax law Joint Operating Agreement Farm-out offer PCSB equity share Funding arrangement Fiscal & Economic Model Project Parameters Assumptions Economic Analysis & Results 122

122. Three (3) - Fundamental Rules ! 1.“The input data must reflect the project parameters of the respective scenario” 2.“The calculation must reflect what stated in the contract” 3.“The input and the calculation must be correctly linked” 122

123. 123 CASE STUDY BENIN BLOCK 4 ECONOMICS MODELING

124. 124 Economics Basis and Results Snapshot 56 1 4 2 3

125. 125 Conversion of Real Terms (RT) to Money-of-Day (MOD) 1 Costs (MOD) =Costs (RT) x ( 1 + esc. ) n

126. 126 Profit Calculation 2

127. 127 Cost Recovery Calculation 3

128. 128 Costs Allocation for Carry provisions 4

129. 129 Contractor and Government NCF Calculation 5 NET CASHFLOW = CASH INFLOW - CASH OUTFLOW

130. 130 Profitability Indicators Calculation 6 Total Investment PIR Cash Flow (US$MM) Maximum Cash Sink Breakeven in year Payback period 1 st Production Economic Life Ultimate Cash Surplus 1 2 3 4 5 6 7 Economic Limit Internal Rate of Return = 23% NPV@23% = 0

131. Thank You for Your Attention 138