INTEGRATED GRADUATE DEVELOPMENT PROGRAM CLASS 2011 PETROLEUM ECONOMICS David Wood
IN-HOUSE COURSE prepared for
OMV EXPLORATION & PRODUCTION GMBH Vienna, Austria
HOT Engineering GmbH Parkstrasse 6 A-8700 Leoben, Austria Tel: +43 3842 430530 Fax: +43 3842 430531 E-Mail:
[email protected] www.hoteng.com
Copyright © 2012 by HOT Engineering GmbH Parkstrasse 6, A-8700 Leoben, Austria All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means: electronic, mechanical, photocopying, recording or otherwise, without written permission from HOT Engineering GmbH. Printed in Austria. Not for sale.
Overview of Course Objectives & Materials The Need for Petroleum Economics Project Cash Flow & Income Components Project Cash Flow & Income Components (Exercise #1) Petroleum Reserves Categories & Valuation Discounting & Time-Value Considerations (Exercise #2) Rates of Return Payout Time or Payback Periode Profit to Investment Ratios Risk and Opportunity Analysis Capital Budgeting Techniques & Yardsticks (Exercise #3) Which Oil & Gas Prices Should be Used to Value Assets? Valuing Incremental Investments Inflation, Buying Power, Money of the Day & Real Values Inflation Indices Estimating Values & Costs and Budget Cost Control (Exercise #4) Introduction to Upstream Fiscal Terms & Contract Types Production Sharing & Cost Recovery (Exercise #5) Funding Criteria: The Cost of Capital & Oil & Gas Finance Hurdle Rates and Selection of Discount Rates Probabilistic Methodology & Techniques for Economics & Risk Analysis Decision Analysis, Decision Trees & Flexibility Monte Carlo Simulation Demonstration (Exercise #6)
Petroleum Economics Overview of Course Objectives & Materials David A. Wood
Course Structure & Approach
The course is structured into a sequence of PowerPoint presentations and exercises. Your participation is welcome. My preference is for an informal approach to encourage an exchange of ideas and experience.
The course aims to be a stimulating & enjoyable experience for all!!
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Course Director: David A. Wood
Some 30 years of energy industry experience Widespread international operations & project exposure Governments, majors, independents, services & consultants
www.dwasolutions.com
[email protected] Twitter: @DWAEnergy Facebook: DWA Energy Limited LinkedIn: David A. Wood
Technical, commercial, training and senior corporate expertise Risk, economics, portfolio and fiscal modelling & research Advises governments and companies on approaches to fiscal design Broad focus: upstream, midstream and downstream Technical evaluation, numerical modelling and due diligence Mergers, acquisitions and divestments (management & negotiation) Project finance, hedging and trading Oil, gas (LNG, GTL and storage), power and renewables Strategy, geopolitics and contract negotiations PhD - Imperial College London (1977) – geology / deepwater drilling Diploma Company Direction – Loughborough / IOD (1996) Independent consultant since 1998; widely published; expert witness
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Petroleum Economics 2-day Module – Daily Themes Outline structure of course - each day has a distinct theme. The aim is to provide delegates with a comprehensive introduction and balanced view of petroleum economics.
Day 1 – Basic Analysis & Valuation Techniques
Day 2 – Constructing Economic Evaluation Models
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DAY 1 – Basic Analysis & Valuation Techniques Morning Session 4.1
Overview of Course Objectives & Materials The Need for Petroleum Economics Project Cash Flow & Income Components
Morning Break Morning Session 4.2
Distinguishing Cash Flow & Other Measures of Profitability (Exercise#1) Petroleum Reserves Categories & Valuation Discounting & Time-Value Considerations (Exercise#2)
Lunch Break © by David A. Wood
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DAY 1 – Basic Analysis & Valuation Techniques Afternoon Session 4.3
Rates of Return Payout Time Profit to Investment Ratios Risk and Opportunity Analysis
Afternoon Break Afternoon Session 4.4
Capital Budgeting Techniques & Yardsticks (Exercise#3) Which Oil & Gas Prices Should be Used to Value Assets?
End of Day 1 © by David A. Wood
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DAY 2 – Constructing Economic Evaluation Models Morning Session 4.5
Valuing Incremental Investments Inflation, Buying Power, Money of the Day & Real Values Inflation Indices Estimating Values & Costs and Budget Cost Control (Exercise #4) Introduction to Upstream Fiscal Terms & Contract Types
Morning Break Morning Session 4.6
Production Sharing & Cost Recovery (Exercise #5) Funding Criteria: The Cost of Capital & Oil & Gas Finance Hurdle Rates and Selection of Discount Rates Probabilistic Methodology & Techniques For Economics & Risk Analysis
Lunch Break © by David A. Wood
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DAY 2 – Constructing Economic Evaluation Models Afternoon Session 4.7
Decision Analysis, Decision Trees & Flexibility Monte Carlo Simulation Demonstration (Exercise #6) Assessment Test
Afternoon Break Afternoon Session 4.8
OMV Session on in-house “Easy Evaluation” Pre-tax Cash Flow Tool
End of Module
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Ask if You Need Clarification
There is a lot of material to get through, but time will be made for discussion.
Don’t be shy!
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Petroleum Economics The Need for Petroleum Economics David A. Wood
Key Metrics Show Distinctive & Dislocated Trends For E&P Assets
Key performance indicators (KPIs) give different impressions at different stages of an oil and / or gas assets life cycle. Economic and risk analysis provides a means of clarifying and quantifying the importance and relevance of these trends.
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E&P Investment Appraisal & Decisions Upstream projects are characterised by:
Large initial capital investment High rate of capital investment throughout asset life
Long payback period
High risk and uncertainty
Complexity
Multiple stages with deferrable decision points Incremental information flows and decision points Dependency upon volatile product prices and demand
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Cost – Time Cycle for Exploration Through to Field Production
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Constraints on Upstream Oil & Gas Companies Major upstream companies are characterised by:
Large portfolios of E&P projects available for investment at any one time.
Finite technical resources & skills to evaluate & manage each project.
Finite time in which to perform commitment work programmes
Finite financial resources and frequent budget constraints making them not indifferent to the level of risked capital required to optimise the portfolio.
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Which Development Option Makes Most Economic Sense? The type of field facilities, number of wells, timing of drilling, owning or leasing facilities are all decisions that require economic and risk analysis as well as engineering design.
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Oil Industry of Last 30 Years has been Characterised by Volatility Volatility caused by booms and recessions driven by the supply-demand balance and oil prices. For how long will such cycles be repeated?
Access to quality international upstream permits to explore and develop is a major challenge for IOCs, together with finding and retaining skilled staff.
Oil supply & demand main drivers for volatility in recent decades © by David A. Wood
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Boundary Scenarios Can Frame Economic Sensitivity Analysis Framing the future in terms of options helps to identify and quantify key issues and potential risks and pitfalls. Sensitivity and Simulation analysis are frequently essential to understanding the full picture.
It is important for economic analysts to consider more than one future. © by David A. Wood
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Costs of Delays in The Exploration & Appraisal Portion of Field Life Cycle Delays in exploration / appraisal always have a negative impact on project / company profitability over the long-term project or field cycle. Economic and risk analysis quantifies this impact.
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Extending Field Life by Reducing Operating Costs & Overheads Economic analysis can identify when it is necessary to introduce structural changes in order to extend the projects commercial life by reducing operating / production costs.
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Risk & Fiscal Analyses are Key Parts of the Investment Decision Process The economic structure of the oil and gas industry is intimately associated with risk versus reward tradeoffs and fiscal designs.
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Modern Portfolio Modelling Approach: Economic, Risk and Strategy Analysis In a portfolio approach projects are judged based on their contribution to long-term strategy, and how they interact with the other projects in the portfolio, as displayed by the feasible envelope, efficient frontier and probabilities of metrics being achieved. This is a dynamic process.
Portfolio modelling & management should firmly link investment decision-making at the asset, portfolio and merger / acquisition/ divestment levels to a quantified corporate strategy.
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There are Many Different Reasons Why Valuation & Risk Analysis are Required The results of such analysis are almost always ultimately linked to assisting and clarifying decisions. Some of the main reasons are:
Establishing that a project can achieve acceptable profitability Comparing the value of projects & investment opportunities Allocating values to different categories of reserves Indicating threshold commercial field sizes in specific environments Distinguishing the most appropriate field development plans Testing the impact of different economic scenarios (e.g. oil price) Assessing the impact of costs and overheads on project returns Identifying value at different points along the supply chain Consider available options for optimising returns from reserves Evaluating merger, acquisition and divestment opportunities Justifying budgets, forecasts, business plans and strategic options Negotiating and comparing fiscal and contract terms Securing project finance and other forms of debt Reporting historical performance & forecasting to stakeholders Quantifying the impact of risk and opportunity on projects Valuing portfolios of oil and gas projects & assessing performance
We will address these reasons and several others during this course. © by David A. Wood
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Petroleum Economic & Risk Analysis Aids Decisions to Balance Risk & Reward Balancing is never easy!!!
Economic & risk analysis is a fundamental process in strategic and operational management of the oil and gas industry. © by David A. Wood
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Petroleum Economics Project Cash Flow & Income Components David A. Wood
Simplified Flow Chart For The Financial Process in a Typical Upstream Oil Company The role of financial management is to optimise the value and use of the basic reservoir of cash and its associated funds flow. Financial management involves funding decisions in the raising of cash in the form of equity and debt. It also involves the efficient allocation of funds between assets, credit investments, etc. Reserves do not appear in this model but can influence depreciation.
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Focus of Economic Analysis For an oil and gas company to prosper it has to find and/or acquire new reserves and make a financial profit.
E&P companies do not stay in business long without returning a financial profit. Production cannot be sustained without new reserves to produce. Economic analysis must therefore be focused on increasing profits and optimising profitability from their reserves. A key question is how do we define and measure profit?
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Upstream Cash flow Components: Influence Diagram – Role of Reserves Costs are an important component controlling the overall value of projects and reserves. Costs are distinguished as CAPEX & OPEX. CAPEX Decisions, such as project design or field development often pivot on cost, timing, efficiency and capital constraints, e.g. well design. In the production stage OPEX is often the focus in determining efficiency, profitability and viability. Reserves and reservoir characteristics have huge influence on cash flow components.
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Basic E&P Economic Analysis Techniques Are Straight-forward None of the economic calculation techniques commonly applied are complex but their analysis can become so. Most economic evaluations readily establish: levels of capital investment required future cash flows national or local tax liabilities earned and paying interests The complications arise in: ranking projects against each other allowing for existing commitments allocating & monitoring sources of funds identifying risks and opportunities correctly adjusting cash flow for uncertainty Estimating chances of success. market conditions and product price forecasting.
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Petroleum Projects Require High Capital Outlay to Achieve Long-term Returns There is an unparalleled relationship of expenditure, risk, timing and revenue in the oil and gas industry that distinguishes it from other industries.
E&P economic analysis focuses on the value of available reserves and the timing of their production that maximizes cash flow and profits (earned income) for those holding interests in those reserves.
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Cash Flow Projections Cumulative net cash flow is the basis for most economic analysis. It is calculated on a “before and after tax” basis and has these major components:
Cash Items: monies actually paid and received. Non-Cash Items: such as depreciation, depletion (North America), book values used mainly for tax and accounting calculations. Royalties: property of the state either paid in money or product is not technically a cash or non-cash item as it is never owned by the E&P company.
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Cash Flow Components - Cash Items Monies actually paid and received can be subdivided into a number of specific categories:
Working interest E&P revenues Income from property sales (and their capital gains tax) Working interest local taxes Operating costs Overheads (corporate / operational, G&A, loan interest) Capital investments Land, lease and licence fees and bonuses Corporation taxes (investment tax credits) Special petroleum taxes (e.g. PRT in older UK licences) Debt capital and interest repayments
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Cash Flow Combines Cash Inflows with Cash Outflows Inflows usually equate to production revenues but also may include asset sales. Outflows include expenditures and taxes.
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Taxable Income is Not Cash Flow but Profit Adjusted by Accounting & Taxation Rules
Calculations of taxable income depend upon accounting and tax rules which vary from country to country and sometimes between E&P contracts in the same country. It is often referred to as Net Income or Earnings (in US)
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Calculation of Key Project & Corporate Accounting Measures Applicable to Oil & Gas Projects
The term Mineral-Interest Reserves is used to distinguish projects from those projects subject to the terms of Production Sharing Agreements (PSAs). Some companies focus more on cash flow performance (~EBITDA) others more on earnings.
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The Tax Burden in E&P Contracts Has Many (Often Complex) Components
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Taxable Income Is Usually Not Cash Flow Calculations of taxable incomes depend upon accounting and tax rules, particularly involving the depreciation of capital costs.
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Generic Corporate Tax Model Calculations of taxable incomes, particularly in tax-royalty fiscal regimes, are usually complex and require specialist tax advice.
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Depreciation of Capital Costs This is applied to costs for items that will benefit the company for more than a single year. It is a system that spreads the costs of such items over each year of its useful life or production unit.
Depreciation can be calculated in a variety of ways some of which load more depreciation on to the early years where the equipment is most useful and its maintenance costs should be lowest. Methods allowed depend upon prevailing legislation. Book value of capitalised assets is their original cost less the accumulated depreciation. It should not be confused with market value or replacement value. A gain or loss on the sale of an asset is computed by comparing the sale price with the book value. These are included as extra line items on income statements. Small items even though they may last several years are often treated as an expense in the year in which they are purchased provided it does not yield material errors.
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Typical Asset Lives For DD&A Purposes Asset lives will depend upon prevailing legislation, but example ranges are:
Production plant including in-field flow lines and tangible well costs - 5 to 10 years. Intangible costs (sometimes a portion of these have to be capitalised rather than expensed) – 5 years.
Drilling equipment & vehicles – 5 years.
Transmission / Trunk pipelines – 10 to 40 years.
Refinery Plant & equipment – 10 to 20 years.
Buildings – 20 to 30 years.
Computer hardware and software – 3 to 5 years.
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Depreciation & Calculation of Book Value Depreciation records are concerned with costs not value. Hence purchase price less accumulated depreciation equals remaining cost but is termed the book value. This is not a value but a remainder.
Consider a machine that cost $60,000 and management estimates its useful life to be 10 years and its salvage value after 10 years to be $10,000. On a straight-line depreciation basis the annual depreciation rate will be ($60,000 - $10,000) /10 which equals $5,000 per year. At the end of the second year an accumulated depreciation schedule for the machine could be: – Original purchase costs:
$60,000
– 1st year depreciation allowance:
$5,000
– 2nd year depreciation allowance:
$5,000
– Total accumulated depreciation:
$10,000
– Book Value:
$50,000
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Depreciation is a Key Non-cash Component in Calculating Net Income Amortisation of capital investments so as to spread costs over a period of time for tax or accounting purposes. Methods are designed to recover capital costs over the life of an asset. Some depreciation methods accelerate the amortisation process (e.g. double declining balance; SYD; MACRS). Depreciation methods used in E&P industry are: –
Units of Production (costs recovery linked to production and reserves) - widely used for accounting purposes.
–
Straight Line - costs recovered in equal fractions per year.
–
Declining balance - various rates are applied - single(100%), 150% & double (200%) rates used.
–
Sum of the Years’ Digits (rarely used outside North America).
–
MACRS -(modified accelerated cost recovery system) used for U.S. federal income tax (FIT) capital cost depreciation
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Depreciation & Capital Cost Recovery Depreciation rate is important to project valuation in that it controls how quickly capital investments are recovered from cash flow.
From the investor’s point of view it wishes to recover all costs as soon as possible. The best solution would be expensing all capital costs together with operating cost (equivalent to a 100% annual depreciation rate applied from the year of expenditure). If capital costs are depreciated over 5, 10, or 20-year periods discounted cash flow values for a venture decrease as the annual depreciation rate reduces. Governments like to have low annual depreciation rates as it increases their tax revenues as companies show higher taxable incomes in the early years of a project. This is a means of governments receiving a share of revenues from oil and gas projects from early in the production life of a field development.
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Different Rates of Depreciation It is not unusual for different depreciation rates to be applied to different categories of capital expenditure.
Exploration costs (drilling & G&G costs) are often depreciated at 100%(i.e. expensed) to provide investors with an incentive to make new and risky investments. Development costs are often divided into categories such as tangible (plant with a long life) and intangible (materials or services consumed in an operation, e.g. drilling mud, wire-line services). The intangibles are often expensed or subject to a more rapid depreciation rate. Allocation between categories can be arbitrary and subject to change. It is the cause of many disputes with the tax authorities. UK authorities have in recent years reduced the depreciation rates applied to intangibles on development wells in response partly to side-track technology developments.
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Depreciation, Depletion & Amortization - DD&A This originally North American concept is now also widely used in international oil and gas accounting.
Depreciation is a means of accounting for the recovery and allocation of costs associated with fixed (tangible) assets over the deemed useful life of an asset. Annual depreciation charge is deducted from revenue in the net income calculation. Depletion is the same concept as depreciation but applied to purchase prices (i.e. acquisition values) of mineral resources (e.g. oil & gas) enabling them to be deducted for tax purposes over time. Amortization is the same concept as depreciation but applied to intangible assets. Commonly these terms are used interchangeably and /or collectively as DD&A. Depreciable life of specific assets is governed by rules specified in the prevailing accounting and tax legislation.
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Example DD&A Methodology Stated by US Oil Company in a 10-K Return to SEC The following extract comes from Apache Corp’s form 10-K submission of Feb, 2011 to SEC for year ending Dec 31st 2010:
Source: Apache Corp 10K 2010 © by David A. Wood
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DD&A is an Operating Expense on the Income Statement The following extract comes from Apache Corp’s condensed statement of operations in its 10-K submission of Feb, 2011 to SEC for year ending Dec 31st 2010:
Source: Apache Corp 10K 2010
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Depletion (DD&A) Calculated by Unit of Production Method DD&A is the only impact reserves have on the profit & loss (income) statement. The unit of production annual depletion calculation can be expressed generically by the equation: (C – AD – S) * P / R Where: –
C
= Capital cost of plant and equipment
–
AD
= Accumulated depreciation to date
–
S
= Salvage or residual value
–
P
= Annual production (boe)
–
R
= 1P Reserves Remaining at beginning of year (or 2P reserves in Canada and many other countries)
The unit values that are deducted for tax purposes can be substantial (e.g. $2/boe up to >$10/boe. The higher values may indicate higher cost / lower reserves than originally expected. Good performers maintain DD&A charges below $5 / boe particularly when calculated on a 2P basis. Merger and acquisition costs are usually included in the depletion cost pool. © by David A. Wood
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Petroleum Economics Project Cash Flow and Income Components (Exercise #1) David A. Wood
Calculation of “Profit”, “Cash flow” & “Income” Measures Applicable to Oil & Gas Projects
When a figure is referred to as “profit”, “cash flow” or “income” without qualification or explanation it is important to distinguish what it is actually measuring. There are several different possibilities! © by David A. Wood
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Input Information for Calculating Measures of “Profit”
When a figure is referred to as “profit”, “cash flow” or “income” without qualification or explanation it is important to distinguish what it is actually measuring. There are several different possibilities! © by David A. Wood
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Petroleum Economics Petroleum Reserves Categories & Valuation David A. Wood
How Do We Know There are Reserves Out There? “Shell said the oil exists – if only they can find it. Trouble is, they can’t convince the SEC”. Same applied in 2004 to El Paso, Forest, Nexen, Husky, etc…. Many reserve write-downs occurred. These headlines in the general media and cartoons emphasize the popular view of how oil reserves are measured and how they exist in the sub-surface. Reality is more complex and uncertain, but Shell are damaged by both popular image and the technical reality.
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Relevance of Resources Versus Reserves to Petroleum Portfolios
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Conventional versus Non-conventional Petroleum Resources SPE Oil & Gas Resource Committee (2007) place Ultra-heavy crude, tight gas sands and shale gas in their conventional categories. They draw the horizontal line lower.
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Classification of Upstream Oil & Gas Assets & their Reserves
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Reserves Terminology Commonly Applied in Valuation
1P Reserves – Proven Developed (PD) – Producing (PDP) – Non –producing (PDNP) – Proven undeveloped (PUD)
2P Reserves – Proven plus Probable
3P Reserves – Proven plus probable plus possible
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Petroleum Reserves Classification SPE versus SEC Until 2010 SPE and SEC have had different requirements for reserves reporting that has caused many issues for petroleum companies registered on US stock exchanges.
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Petroleum Reserves Classification SPE / WPC / AAPG / SPEE This approach is in line with SPE /WPC / AAPG /SPEE guidelines and the Petroleum Resource Management System (PRMS) approved in 2007 updated November 2011.
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Resource Classification Commences with In-place Classifications Culmination of two-year review approved in March 2007 (updated Nov 2011).
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Bookable Oil & Gas Reserves Valued in Production Asset Sales
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Aligning Reserves Definitions with Petroleum Project Cycle This approach is in line with SPE /WPC / AAPG /SPEE guidelines and the Petroleum Resource Management System (PRMS) approved in 2007.
SPEE = Society of Petroleum Evaluation Engineers AAPG = American Association of Petroleum Geologists
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Project-based Approach Works best for Petroleum Reserves Valuation Petroleum Resource Management System (PRMS, 2007) recognises the need for much more than establishing resource volumes.
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Categorizing Reserves by Levels of Uncertainty – Key to Valuation Petroleum Resource Management System (PRMS, 2007, 2011) acknowledges deterministic and probabilistic methodologies. In practice integrating both approaches is useful.
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Forecasts and Valuation Scenarios
Valuations and decisions are based on the evaluators view of “Forecast Conditions” – i.e. those assumed to exist during a project’s implementation. Alternate valuation scenarios are typically considered in the decision process and, in some cases, to supplement reporting requirements. One sensitivity case commonly reviewed assumes “current conditions” will remain constant throughout the life of the project (“constant case”).
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Pivotal Role for Probable Reserves in Acquisition Valuations In some areas, probable reserves assume a key role in acquisition values. Significant value is ascribed to probable reserves in: Offshore, particularly in hostile or deep water environments. where significant investment decisions for facilities and infrastructure have to be made early in development. Assets are immature and lots of undeveloped potential remains. Internationally probabilistic reserves categories are applied. 2P reserves (probabilistic proved plus probable) is the reserve estimate commonly where probable reserves are to form a significant part of the assets to be acquired. Method is suited to valuing whole fields rather than small parcels of land. However, internationally it is also not unusual to discount or risk probable reserves more heavily than proved reserves when calculating acquisition values.
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Why Do Companies Acquire Assets, Merge or Divest? Because the benefits out-weigh the downsides and growth or focus on material assets can be achieved. The most common reasons given by oil companies are to: achieve greater efficiency; consolidate and grow to meet increased competition; increase shareholder value; benefit from operational synergies; diversify asset portfolio; balance asset portfolio.
Mergers and acquisitions do allow economies of scale and step-decreases in G&A costs. Downsides are potential job or location cuts. Restructuring and relocation often mean many voluntary and involuntary redundancies.
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How Does an Acquisition or Divestment Add Value to an Asset Portfolio?
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Petroleum Economics Discounting & Time-Value Considerations (Exercise #2) David A. Wood
Time-Value Considerations Oil and gas projects are characterised by high capital investment in early years, without revenue, followed by high revenue after production startup which gradually declines in line with production towards field abandonment.
Rate at which costs are recovered impacts contractor’s value. © by David A. Wood
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Present Value (PV) Concepts Money to be received at some time in the future is said to have a present value which is less than the amount received by the interest that could be earned on it in the interim.
The PV is the amount that could be invested at an interest rate such that the amount plus the total interest earned equals the future value (FV).
Future value (FV) = PV + (i * PV )
(where i is the interest rate for one
interest period and FV is the value at the end of that one interest period).
Re-arranged to: FV = PV (1 + i)
An example: FV = ($2,000) (1+0.15) = $2,300 so that $300 is the simple interest at 15% on an investment of $2,000 (the principal).
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Present & Future Values and the Time Value of Money PV and FV are related to each other through interest rates and discount factors.
For example, if an interest rate (i) of 10% applies for one investment period then a PV of US$10 million has a FV of US$11 million at the end of the investment period: FV = PV * (1 + i)
In this example the FV of US$11million can be discounted to a PV of US$10 million at the start of the investment period by applying a discount factor (1 + d) of 10%: PV = FV / (1 + d)
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Simple Versus Compound Interest If the interest is withdrawn at the end of the period only simple interest (on the principal investment) is earned the next period.
If the interest is re-invested in subsequent periods it will earn interest itself in addition to that earned by the principal, i.e. compound interest. Compound FV for a second period: –
= ($2,300)(1.15) = ($2,000)(1.15)(1.15) = $2,645
Thus FV of a PV invested at an interest rate of i per year has the general form: –
FV = PV (1 + i)n
–
(1 + i)n
where n = number of years
is called the compound factor.
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The Discount Factor This is the reciprocal of the compound factor and represents one of the most important concepts of cash flow analysis. Applying the discount factor to the FV calculates its PV such that: –
PV = FV [ 1 / (1 + i)n ] = FV (1 + i) –n
–
Hence the PV of an FV of $6,125 to be received at the end of three years based on an annual interest rate of 7% is $5,000.
–
$5,000 = $6,125 (1 + 0.07) –3
–
In this case the 7% is called the discount rate.
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Risking Cash Flow Profiles by Increasing Discount Rate is Not Appropriate Higher discount rates preferentially penalise later years in a cash flow profile.
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Net Present Value (NPV) is the Sum of Discounted Cash Flows for Each Period A general solution for the NPV calculation is:
where CFj is the annual net cash flow in year j, i is the discount rate, n is the total number of time periods. Cash flow in the initial period CF0 remains undiscounted. This can be more neatly expressed as:
Most spreadsheets have NPV functions. It is important to take care that the initial investment and type of discounting applied to it are appropriate.
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Net Present Value Profile Trends Calculating the NPV’s of cash flows of projects to be compared at different discount rates and viewing them graphically can discriminate.
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Present Value Profile Trends Projects that look the most attractive at one discount value may not do so at another.
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Discrete Investment Functions Interest earned on money in a deposit account is normally paid at set regular (discrete) intervals. The example below shows an investment of $10,000 accumulating with interest earned at 6% per annum. It grows discretely at the end of each annual investment period.
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Discrete Versus Continuous Functions Production from an oil or gas well accumulates continuously by the minute and over a long period its cumulative production represents a continuous function (usually with breaks for well service). The example here shows a well producing at an initial rate of 10,000 bopd and declining exponentially at a rate of 20% per annum for 10 years.
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Nominal Versus Continuous Compounding Nominal interest is the annual interest rate if money is compounded annually. If compounding is set at periods other than one year then the FV equation needs re-stating: – FV = PV [ 1 + (i / P)] n where P equals interest conversions per year and n equals the number of interest conversions for the total investment period and i equals nominal interest rate per year. – $2,000 compounded quarterly at 6% per year becomes $2,000 [1 +(0.06/4)]12 after three years = $2,391. Annual compounding equals $2,382. – For continuous compounding: FV = PV (e in) where n is the number of i interest periods. $2,000 after three years at 6% is: $ 2,000 (e 0.18) = $2,394.
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Various Compounding Outcomes Common compounding methods are summarised in this table for an investment period of one year, but with formulae that work for multiple years. In the formulae shown “n” equals the number of years in the total investment period (n=1 in the examples shown for just one year) and “i “equals nominal interest rate per year:
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Net Present Value (NPV): A Yardstick Useful for Ranking Projects (Exercise #2) You have the option to select one project for investment from projects X, Y and Z and the discount rate for all three projects is 10% per annum.
X costs $2million now and returns $3 million in 4 years.
Y costs $2million now and returns $4million in 6 years.
Z costs $3million now and returns $4.8 million in 5 years.
Calculate the NPV for each project, using the discount factor table provided. Then use the NPVs to rank the projects in order (best to worst) and select the best for investment.
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Discount Factor Table In practice a spreadsheet, calculator or economic software package would calculate this for you.
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Petroleum Economics Rates of Return David A. Wood
Rates of Return An earned interest on the money invested.
There are two quite distinct rates of return commonly used and referred to: – The accounting or book rate of return including return on net assets and return on capital employed (ROCE) or return on average capital employed (ROACE). – The internal or investor’s rate of return (IRR) and its modifications.
It is important not to confuse the two. Accountants, investors and financial analysts often refer to the former. It is the later that interests petroleum economists and investors when looking at project economics.
© by David A. Wood
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Book Rate of Return This is a single-year performance measure usually extracted from financial accounts.
Book ROR =
Profit/Year Investment
The average value for the total life of a multi-year project can however be approximated as: Book ROR = Profit Investment Ratio Number of Years
Such ratios are used for annual financial reporting purposes and corporate performance analysis and are not suitable for economic decisions concerning specific projects.
© by David A. Wood
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Investor’s Rate of Return (IRR) The rate which will discount the cumulative cash flow to zero, before or after taxes. Put another way it is the rate of return at which the PV of future returns equals the initial outlay.
“d” equals the IRR when: Rn (1+d) -n = 0 where n is the number of years and R is the net cash flow in each year. For such a series of cash flows, a trial-and-error or iterative solution is required to obtain the IRR; there is no direct solution with more than two cash transactions. “d” is sometimes compared with a hurdle rate or minimum acceptable rate of return (MARR). If it exceeds that value the project is viable.
© by David A. Wood
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Investor’s Rate of Return: Appropriate Uses Although widely used as an investment yardstick it has significant problems.
Advantages: Valid as a qualifying parameter. Widely used within industry. Does not depend on project magnitude. Disadvantages: Assumes all monies can be & are reinvested at IRR.(but can be modified for a specific re-investment rate – MIRR) Not valid as a ranking parameter. May not yield a unique solution. Gives no indication of project magnitude.
© by David A. Wood
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IRR and NPV Reflect Time-Value Influences Consider cash flows X and Y. The only difference is in the timing of the investment, but note the impact on both NPV and IRR.
© by David A. Wood
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IRR and Discount Rate Relationship NPV’s for a range of discount rates either side of the IRR.
© by David A. Wood
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Discounted Versus Undiscounted Cash Flows The undiscounted cash flow for each period is discounted back to its equivalent value at the start of period 1 by the discount rate and formula.
© by David A. Wood
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Investor’s Rate of Return Example For an interest hurdle rate of 6% project A requires an investment of $18,000 for a $20,000 return one year later while project B involves an initial outlay of $2,000 for a return of $2,500 one year later. Which project should be selected for investment?
IRRA = (20,000/18,000) - 1 = 0.11 = 11%. IRRB = (2,500/2,000) - 1 = 0.25 = 25%.
NPVA = -18,000 +(20,000/1.06) = $868. NPVB = -2,000 +(2,500/1.06) = $359.
IRR suggests B is better than A; NPV suggests A is better than B. More information than IRR in isolation is needed for a good decision. If there were 8 other projects like B then they would represent the best investment of $18,000.
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© by David A. Wood
Investor’s Rate of Return is an Indicative not a Definitive Yardstick IRR is not a good yardstick for discriminating between projects or justifying projects as this example shows.
IRR does not always give a unique solution. NPV is more realistic as it is calculated at a discount rate that is meaningful to the company concerned (e.g. its investment hurdle rate or cost of capital).
© by David A. Wood
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Investor’s Rate of Return Excel versus Interpolation Spreadsheets offer good IRR functions but it can be calculated by interpolation or graphically. Table below uses mid-year discounting.
Example of Investor's Rate of Return Calculation
Year 0 1 2 3 Totals
Present Present Present Net Cash Value Value Value Flow (PV10) (PV15) (PV20) -500 -500 -500 -500 400 381 373 365 100 87 81 76 100 79 71 63 100 47 25 5 21.29% IRR (Excel) 21.28% quick hand calculation
Present Value (PV25) -500 358 72 57 -13
[5 / (5+13)] * (25 -20) +20 = 21.28% Interpolation must not be over more than 10 percentage points.
© by David A. Wood
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IRR Does Not Always Provide a Single Solution There are two IRR points for this project. Both are mathematically correct – one ~ 5% the other ~29%. The shape of the graph shows that for discount rates between these two values the project is profitable.
© by David A. Wood
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IRR & MIRR (ERR): The Reinvestment Issue A calculated IRR is not actually earned unless positive cash flows from each period are reinvested at the IRR rate. Consider the following investment: Actual "i" Earned May Not Be the IRR Year 0 1 2 3 Totals
Net Cash Flow ($1,000) $680 $680 $680 $1,039
PV@: 38% ($1,000) $465 $318 $217 $0
MIRR – modified IRR function incorporates a re‐investment rate so overcomes this shortcoming of IRR.
then FV= $2040 = $1000 * e 3i then Ln (2.040) / 3 = i = 23.8%
MIRR Excel function returns the modified internal rate of return for a series of periodic cash flows. It considers both the cost of the investment and the interest received on reinvestment of cash.
If $680 is taken out each year and re-invested at rates less than 38% then 24%< i <38%
MIRR sometimes called external rate of return ERR.
PV = FV * e
-in
0% IRR
If $680 is taken out each year and not re-invested: then FV= 3* $680 = PV * e
3i
David Wood & Associates
© by David A. Wood
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MIRR / ERR Provides a More Realistic Rate of Return The formula is, however, quite difficult to visualise. MARR = minimum acceptable rate of return (hurdle rate).
© by David A. Wood
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Petroleum Economics Payout Time or Payback Period David A. Wood
Delays Erode Value It is not only the magnitude of the cash flow components that influence value, it is also the timing of the cash flow elements:
David Wood & Associates
© by David A. Wood
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Time Related Yardsticks Such measures have a calendar significance:
Project life. This is the length of a project, usually in years. It is related to the time horizon of a corporation’s strategy and its long and short-term goals. Pay-back or pay-out period. This is the time, usually in years, for a project to return the after-tax investment. It is the point at which the cumulative net cash flow becomes positive. Discounted pay-out time. Payout calculated using discounted revenues and investments Time to first revenue. This is the time from first investment to first income. Useful for those companies requiring operating cash flow.
© by David A. Wood
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Pay Back Period or Payout Payout is the time at which the cumulative cash flow, discounted or undiscounted (depending on selected definition), becomes positive. Most analysts quote undiscounted payback times. Advantages: – Is a measure of liquidity. – Is a measure of risk exposure. Disadvantages: – No indication of what occurs after payout. – Multiple payouts with staged investments. – Reflects no magnitudes. – Is affected only by total cash flow to that point and not by timing of that cash flow.
© by David A. Wood
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Payout / Payback Calculations Payout time indicates liquidity (risk) rather than profitability:
© by David A. Wood
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Simple Payout Calculation Ignores Time-Value Considerations
Where: Rk = revenue year k Ek = expenditure year k I = initial investment
Discounted Payout formula:
© by David A. Wood
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Petroleum Economics Profit to Investment Ratios David A. Wood
Cost to Benefit Ratios These ratios divide returns by costs but have several options for calculation which can lead to confusion.
Defined using different values for the investment, which may be the same for any one project: Net cash flow/maximum negative position Net cash flow /risk capital (also referred to as risk capacity and number of times investment returned (NTIR). Net cash flow /development capital Net cash flow/total investment
These may be before-tax or after-tax values and both or either numerator and denominator may be calculated on a discounted or undiscounted basis depending on the preferred definition.
© by David A. Wood
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Cost to Benefit Ratios: Pros & Cons These are widely used investment efficiency indicators. Advantages: – Measure magnitude of cash flow (profit) per dollar invested – Discounted values give a measure of the efficiency of the use of capital; can be used as a ranking parameter – Independent of project magnitude Disadvantages: – Give no indication of time flow of money – May not reflect total investment – Do not reflect project magnitude
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© by David A. Wood
Undiscounted Benefit to Cost Ratios These are widely used because they are easy to calculate.
Return on Investment:
ROI =
Cumulative Net Cash Flow Maximum Negative Position
Profit to Investment Ratio:
PIR =
© by David A. Wood
Cumulative Net Cash Flow Total Investment
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Discounted Benefit to Cost Ratios Discounted ratios are more useful ranking yardsticks, particularly when capital is rationed. What costs are included in the denominator needs to be clear. Discounted Return on Investment:
DROI =
NPV of Cash Flow Maximum Negative Cumulative PV
Discounted Profit to Investment Ratio:
DPIR =
NPV of Cash Flow PV of Total Investment
Profitability Index:
PI =
NPV of Cash Flow PV of Capex only
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© by David A. Wood
Benefit to Cost Ratios Compared Ranking of projects can vary depending upon which ratio is used. Examples of Cost Benefit Ratios To Describe Cash Flows Year 0 1 2 3 4 5 6 7 8 9 10 Net Cash Flow
Project I ($500) $100 $100 $100 $100 $100 $100 $100 $100 $100 $100 $500
Project II ($500) $200 $200 $200 $200 $200 $0 $0 $0 $0 $0 $500
Project III ($100) $100 $100 $100 ($400) $200 $100 $100 $100 $100 $100 $500
Project IV ($500) $100 $200 ($500) $500 $400 $300 $0 $0 $0 $0 $500
1.0
not reached
5.0 2.500 1.000 2.000 0.650
4.5 0.714 0.500 0.273 0.191
Cost to Benefit Ratios First Investment Payback (years) Next Investment Payback (years) ROI PIR DROI10 DPIR10
© by David A. Wood
5.0 not reached 1.000 1.000 0.309 0.309
2.5 not reached 1.000 1.000 0.590 0.590
When capital is constrained discounted cost to benefit ratios are the best measures to use to discriminate between projects. Note: it is important to discount investment ROI requires calculation of cumulative cash flow to establish maximum negative cash flow exposure.
David Wood & Associates
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Misleading Benefit to Cost Ratios It is important to check how they are calculated. Promoters can make the ratios appear more favorable than they are: Well Costs Completion Costs
175,000 95,000
Total Investment
$270,000
Gross Revenue Operating Costs
$922,000 20,000
Net Revenue Cash Flow
$902,000 $632,000
Two benefit /cost ratios could be presented: Promoter’s “PIR” = 902 / 270 = 3.34 Actual PIR = 632 / 270 = 2.34
© by David A. Wood
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Petroleum Economics Risk and Opportunity Analysis David A. Wood
Uncertainty: Risk and Opportunity Because of the common misuse of the term risk it is appropriate to distinguish clearly what we mean by the terms risk and uncertainty. The term “opportunity” can help to clarify our understanding.
To many people “risk” means a “potential for loss” Positive outcomes from risk can equate to opportunity Uncertainty implies outcome is unknown (usually within limits) Uncertainty suggests potential for loss (risk) or gain (opportunity) The chances for loss are sometimes discrete and easy to distinguish In most cases outcomes cover a wide grey (continuous) spectrum Interactions between many continuous uncertainties are complex Risk is highly non-linear in its outcomes Combining the impact of risk events is not a simple additive process Some uncertainties are dependent upon or impact others
© by David A. Wood
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Discrete & Continuous Components to Risk Not all uncertainty is captured by continuous probability distributions.
Example shows an exploration prospect with a 10% chance of success and a range of possible reserves outcomes if successful.
There is uncertainty associated with both discrete and continuous aspects of risks © by David A. Wood
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Probabilistic Approaches Help But Rarely Capture All of the Uncertainty Much that uncertainty in nature follows normal distributions. Situations that compound many individual uncertainties tend to follow lognormal distributions, but it is difficult to capture all potential contractual, human, social and political impacts and uncertainties in such distributions.
© by David A. Wood
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Upstream Risk & Opportunity is Multi-faceted
It is useful to consider the collective impact of these uncertainties in an holistic risk assessment.
Updated from: David Wood et al. World Oil, September 2007 © by David A. Wood
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Exercise: Extreme Risks Extreme risks need to be addressed, particularly in the upstream oil and gas sector?
Try to identify some of the possible extreme /catastrophic events that should be considered?
What contingency steps / actions might be taken to respond if such events should actually occur?
© by David A. Wood
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Risk Diagram Showing the Shareholder and Judicial Scrutiny Regions Shareholders and many operations managers often focus more on events with greater likelihood of occurrence. When extreme events (“black swans” / catastrophes) occur inquiries are more likely to be focused on high impact - low likelihood events. Risk management systems need to address the full spectrum of events.
© by David A. Wood
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Potential Events, Actual Incidents and Risk Management The relationship between potential events and actual incidents requires clarification. It is always better to focus on preventing (or exploiting) potential events rather than managing incidents from a control viewpoint.
© by David A. Wood
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Risks Usually Outweigh Opportunities Once a project is underway the downside risks are usually greater than the upside opportunities. But it is important not to lose sight of the fact that opportunities exist.
© by David A. Wood
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Three Broad Types of Risk Assessment Prevail in Industry Some organisations resist moving to a quantitative approach.
Qualitative
Semi-quantitative
Quantitative
Moving to more quantitative techniques does not have to mean involving more complexity, time and cost. © by David A. Wood
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Pure & Speculative Risks Compared For pure risks, hazards or threats are objects, substances, activities, behaviours or situations capable of causing harm. Managing pure risks can result, at best, in no harm outcomes from a specific hazard or threat. Speculative risk events involve a greater spectrum of choice and uncertainty of outcomes. For speculative risk management success often means optimizing financial, political or other outcomes from speculative investments of various kinds and avoiding loss or disadvantage.
Because pure and speculative risks often overlap and interact, creating artificial boundaries between them may be inappropriate.
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© by David A. Wood
Risk Profiling – Traffic Light Analogy Risk profiling (or mapping) is a good starting place for risk identification.
Risks should be plotted on a gross basis – i.e. before mitigation actions are taken - in order to ensure resources are deployed to manage them. On a net basis - i.e. after mitigation actions are taken -all risks should plot in manageable squares
The impact needs to be assessed in terms of key objectives. © by David A. Wood
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Bowtie & Butterfly Diagrams Link Risks to Causes & Impacts Useful for identifying multiple outcomes and multiple causes for events. Focuses mitigation strategies on the ultimate causes of identified risks.
David Wood et al. World Oil, September 2007
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© by David A. Wood
Addition Rule of Probabilities If the outcomes of two events are mutually exclusive the addition rule determines their combined probability of occurrence.
This rule states that the probability that one or another of two or more mutually exclusive outcomes will occur is the sum of their separate probabilities. Consider the probability of rolling a 1 with a single die. It is one of six alternatives so the probability is: P(1) = 1/6 or 16.67%.
The probability of rolling a 1 or a 5 with one roll of the die. The events are mutually exclusive so the addition rule applies: P(1 or 5) = 1/6 + 1/6 =1/3 or 33.33%
© by David A. Wood
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Multiplication Rule of Probabilities If the outcomes of two events are independent of each other the multiplication rule determines their combined probability of occurrence.
This rule states that the probability of two or more independent events having specific outcomes is the product of their separate probabilities. Consider the probability of rolling a double 1 with a single roll of two dice. It is one of six alternatives on one die together with one of six independent alternatives on the other die. The probability on each die remains: P(1) = 1/6 or 16.67%. P(1 and 1) = 1/6 * 1/6 =1/36 or 2.8%
There are 35 other combinations for two die.
© by David A. Wood
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Possible Outcomes With Two Dice
Probability of throwing a 7 with two dice = 6/36 = 16.7% Probability of throwing a 7 or a 3 = (6/36) + (2/36) = 22.2% Probability of two straight sevens = (6/36)*(6/36) = 2.8%
© by David A. Wood
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Chance of Finding Some Hydrocarbons Multiplication Rule For Geological Risk Estimating the chance of success, is most consistent when several discrete probability estimates of independent geological attributes are combined to yield a chance factor by a semi-quantitative justification.
Since the chance of success is much less than the chance of failure most of the time one or more of the geologic controls will be lacking.
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© by David A. Wood
Probability of Wildcat Success
A geological chance of success (Pdiscovery) of 25% may only equate to a commercial chance of success (Pcommercial success ) of 15% because of reserve size and also: technological, economic infrastructure, fiscal terms and political risks
© by David A. Wood
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Development Threshold Field Size The difference between technical and commercial success is the development threshold field size. The higher this threshold size the greater the difference between the chances of commercial and technical success. Threshold field size will vary according to: 1. Cost related factors: •Reservoir depth •Number of wells •Reservoir quality •Water depth •Proximity to infrastructure 2. Product related factors: •Oil and gas prices •Product quality 3. Fiscal terms
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© by David A. Wood
Two-step Approach to E&P Chance of Success Step 1: Sub-surface Chance Factor (GCF) Step 2: Above-ground Chance Factor (ECF) Sub-surface Chance Factor: Greater than ECF as it is easier to find small fields Usually expressed as a percentage chance of success Above-ground Chance Factor: Probability of accumulation being of economic size log-normal field size distributions help to estimate it Political, fiscal, market, technological issues etc., etc.
© by David A. Wood
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Key Economic Success Factors Chance of Geologic Success will vary from basin to basin and prospect to prospect. It is unlikely to be higher than 25 to 30% in wildcat prospects. Chance of Economic Success will also depend upon: – Fiscal Terms – Depth to Pay – Reservoir performance & well flow rates – Location of field relative to infra-structure – Complexity of development engineering – Quality of hydrocarbon and its market – Proximity to market (for gas) – Prevailing oil, gas or product prices – Political and business environment
© by David A. Wood
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Aspects of Economic Risk Factors The economic risk factors can be as difficult to estimate as the geologic risk factors.
Technological Risk: risk of drilling problems or of achieving the well path and flow rate performance expected.
Oil & Gas Price Risk: large effect on NPV’s.
Project Over-Run Risk: cost and time variances.
Political risk: risk of civil unrest in a country delaying or preventing development of a discovery (e.g. Iraq, Libya, Nigeria, Sudan, Syria, Yemen etc.). But there are also many political and regulatory risks in OECD countries. Fiscal risk: risk of government introducing new tax or changing the cost recovery mechanism that will make economics of a discovery less favorable or even uneconomic.
© by David A. Wood
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Petroleum Economics Capital Budgeting Techniques & Yardsticks (Exercise#3) David A. Wood
Most Investment Opportunities Require Analysis Few opportunities are good investments just by inspection. Analysis is required for: –
Very large investments.
–
Complex investments inter-related with and incremental to existing projects with several choices or possible outcomes.
–
Marginal investments.
–
Incremental investments
–
High-risk investments.
–
New venture investments (new geology, new industries, new markets).
–
Capital budgeting: selecting the best projects to pursue when funds are limited and it is possible to fund all profitable projects
© by David A. Wood
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Investment Yardsticks (Economic Key Performance Indicators) Investment yardsticks are the various criteria used to help in measuring, comparing and describing investment opportunities. Comparative investment evaluation implies: – The expectation of future profits, usually involving both uncertainty and risk associated with two or more mutually exclusive investments. – Income generated over a period of time from each potential investment. – A freedom of choice among investments, i.e., the discretion to select the best from various opportunities.
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© by David A. Wood
The Ideal Investment Yardstick A single ideal yardstick which properly ranks each investment opportunity would have the following characteristics: –
It would illustrate the effect on corporate profits of making a specific investment and incorporate an assessment of risk.
–
It would isolate only those investment opportunities which are acceptable within the confines of a defined corporate strategy.
–
It would always make the correct choice from a group of mutually exclusive opportunities.
Unfortunately, no ideal yardstick exists. Several yardsticks are necessary for comparative investment evaluation. Wise decisions are more likely when measuring an opportunity from several viewpoints.
© by David A. Wood
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Cash Flow Yardsticks Not Involving Discount Factors Cash flow components themselves provide potential yardsticks:
The investment—both before and after tax (if investment tax credits are available). A unit basis (i.e., pence/therm or $ / barrel.) is sometimes used for pre-tax investments. Maximum negative cash flow. This is largest sum of money, out-of-pocket at any one time. Ultimate net positive or negative cash flow. This is the cumulative net cash flow (or actual value profit) from a project. It is the sum of inflows minus outflows. Ultimate net cash flow to investment ratio. This is the cumulative net cash flow divided by the cumulative maximum negative cash flow. Profit (Income) -to-investment ratio. This is the total actual value profit divided by investment. Complicated by profit and investment not always being defined in the same way, but usually with accounting rules included.
© by David A. Wood
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Time Related Yardsticks These have a calendar significance.
Project life. This is the length of a project, usually in years. It is related to the time horizon of a corporation’s strategy and its long and short-term goals. Pay-back or pay-out period. This is the time, usually in years, for a project to return the after-tax investment. It is the point at which the cumulative net cash flow becomes positive. Time to first revenue. This is the time from first investment to first income. Useful for those companies requiring operating cash flow.
© by David A. Wood
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Time-Value Related Yardsticks that Incorporate Discounting These yardsticks reflect the time value of money:
Present value profit (loss) or Net Present Value (NPV). This is the total of a discounted net cash flow stream. Present value profiles. These are curves resulting from plotting present value profits versus a range of discount rates. Investor’s rate of Return (IRR). This is the discount per cent which reduces a cash flow stream to zero. Also MIRR Discounted profit-to-investment ratio (P/I). This yardstick measures investment efficiency. The investment should also be discounted if the investment stream goes beyond year zero.
© by David A. Wood
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Yardsticks Extracted from Financial Statements / Accounts These are rarely good economic discriminators for single projects. They are company specific and are clouded by accounting principles.
Booked investment. These are the items that accounting principles allow to be capitalized in the financial accounts or “corporate books”. Annual, cumulative and average booked net income (earnings). The net profit (or loss) reported to shareholders on the profit and loss statement is the booked net income. Earnings Before Interest & Tax (EBIT) and EBITDA (also excluding depreciation) now commonly used in conjunction with project cash flows to assess a project’s economic potential. Annual or average booked rate of return. The booked net income divided by the average net booked investment is the booked rate of return. Traditionally return on net assets has been used for one or several years. Return on Capital Employed (ROCE or ROACE) includes long-term debt with assets as capital employed and is widely used as a yardstick for company wide investment performance.
© by David A. Wood
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Investment Yardsticks Commonly Used It is important to use a range of investment yardsticks. The yardsticks [KPIs] that the E&P investment analyst generally consider are:
– Magnitude of investment & maximum financial exposure – Time scale of project (length of cash flow stream) – Time to pay back – Cash flow (annual, total and cumulative trends) – Discounted indicators to establish the time-value (PV, NPV, IRR) – Investment efficiency - profit/investment ratios – Risk capacity – total cash flow divided by risk capital – Risk adjusted indices – expected monetary value (EMV)
© by David A. Wood
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Interpretation of Investment Yardsticks For Project Ranking & Investment Thresholds A value of an investment yardstick may be considered to be good or acceptable in some circumstances but unacceptable in others. Consider the values of the yardsticks in the context of: –
Risk - technical and / or political risks often overwhelm all other aspects of an investment opportunity.
–
Availability of capital to undertake projects.
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Corporate strategy - short and long-term goals and corporate attitude to risk.
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Number of available opportunities and competition for them.
© by David A. Wood
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Exercise to Rank Projects Using Investment Yardsticks As an E&P manager, you must decide which of 8 projects labelled A to H are profitable and compatible with your company's strategic goals and objectives. Your technical team and economic analyst have evaluated and submitted the projects shown below for your consideration and approval under the current exploration budget.
© by David A. Wood
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Exercise: Investment Yardsticks The following investment yardsticks have been calculated from the project cash flow profiles for 8 projects (A to H):
© by David A. Wood
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Ranking Projects: Use Yardsticks to build a Matrix Construct a ranking matrix in tabular form of the projects based on a selection of the nine most useful investment yardsticks. Rank 1 = best; Rank 8 = worst. Rank the projects using letter codes (A to H):
© by David A. Wood
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Which Projects (A to H) Should be Selected? Use the matrix you have constructed to help you to list the projects that would be selected under the following conditions assuming and there are no other investment opportunities available: I.
Capital limited to a total $180 million investment budget and your company’s cost of capital is 9%. Projects? Total Investment? @9% discount rate NPV? II. Capital limited to a total of $105 million, your cost of capital is 15%. Projects? Total Investment? @15% discount rate NPV? III. Same as II but Project E is in a country where a civil war has started? Projects? Total Investment? @15% discount rate NPV? © by David A. Wood
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Which Projects (A to H) Should be Selected? Use the matrix you have constructed to help you to list the projects that would be selected under the following conditions assuming and there are no other investment opportunities available: IV. No limit on capital resources and your cost of capital is 9%. Projects? Total Investment? @9% discount rate NPV? V. Capital is limited to US$60 million and the board has issued an initiative to improve investment efficiency and shorten payout time. Cost of capital remains at 9%. Projects? Total Investment? @12% discount rate NPV? VI.
Same as 5 but corporate directives say that projects maximizing P/I discounted @9% should be prioritized and a longer term view adopted. Projects? Total Investment? @12% discount rate NPV?
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© by David A. Wood
Which Projects (A to H) Should be Selected? Use the matrix you have constructed to help you to list the projects that would be selected under the following conditions assuming and there are no other investment opportunities available:
VII. You have only projects E & B left from which to make a selection. You are capital limited with other reinvestment opportunities having a Profit / Investment ratio discounted at 9% equal to: (a) 0.6
(b) 0.50
(c) 0.4
VIII. You decide to rank the projects in order of their liquidity (i.e. those that provide maximum positive cash flow in the shortest period of time) and take the four most attractive.
© by David A. Wood
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OMV’s Prefered Yardsticks For Economic Analysis
© by David A. Wood
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Petroleum Economics Which Oil & Gas Prices Should be Used to Value Assets? David A. Wood
Short-term Oil & Gas Price Drivers
Global supply and demand (commodities & products)
Refinery surplus capacity
OPEC surplus capacity
Market perception
Weather
Unexpected supply disruptions
Stock-building in consuming markets (particularly OECD)
© by David A. Wood
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Long-term Oil & Gas Price Drivers
Non-OPEC new sources. e.g. deepwater Gulf of Mexico, Caspian
Demand growth in developing economies: China, India
Global and regional economic cycles
New technologies e.g. fuel cells, gas-to-liquids (GTL), substitutes
Expanding demand for natural gas, LNG, GTL, Gas-to Power
Unconventional oil and gas exploitation (high-cost supply)
Renewables, alternatives, biofuels take market share
Politics, geopolitics and politics (with a small “p”)
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© by David A. Wood
Crude Differential Trends Enable Arbitrage Opportunities in Markets
2006
2007
2008
2009
2010
2011
Oil Market Report, IEA 2005 to 2011 © by David A. Wood
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U.S. Long-term Price Forecasts by EIA for 2011 to 2035 In real terms EIA sees natural gas prices rising modestly in real terms ($2009) to 2035 reaching about US$7.0/mmbtu. Over-optimistic? 3Q-2011 Henry Hub spot natural gas price was about $4.0/mmbtu. Crude oil forecast to rise to $(2009) 125 by 2035 in the EIA’s reference case. Note the large uncertainty for oil forecast.
© by David A. Wood
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U.S. Light Sweet Crude Forward Curve 28 October 2011 CME quotes nine years forward (six years monthly and final 3 years for June and December). WTI moderate contango.
© by David A. Wood
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U.S. Light Sweet Crude Forward Curve 9 September 2011 CME quotes nine years forward (six years monthly and final 3 years for June and December). WTI moderate contango.
© by David A. Wood
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Brent Crude Oil Forward Price Curve September 2011 Steep backwardation.
© by David A. Wood
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Spot & Forward Curves Evolve
© by David A. Wood
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Real & Nominal Crude Oil Prices Show Volatility Since the 1970’s
© by David A. Wood
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Short-term versus Long Run Crude Oil Prices (Nominal & Real)
© by David A. Wood
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OPEC Reference Basket (ORB) The “new” OPEC Reference Basket (ORB), introduced on 16 June 2005, is currently made up of the following: Saharan Blend (Algeria), Girassol (Angola), Oriente (Ecuador), Iran Heavy (Islamic Republic of Iran), Basra Light (Iraq), Kuwait Export (Kuwait), Es Sider (Libya), Bonny Light (Nigeria), Qatar Marine (Qatar), Arab Light (Saudi Arabia), Murban (UAE) and Merey (Venezuela). Notes: As of January 2006: The Weekly, Monthly, Quarterly & Yearly averages are based on daily quotations. As of January 2007: The basket price includes the Angolan crude "Girassol". As of 19 October 2007: The basket price includes the Ecuadorean crude "Oriente". As of January 2009: The basket price excludes the Indonesian crude "Minas". As of January 2009: The Venezuelan crude "BCF-17" was replaced by the crude "Merey". © by David A. Wood
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OPEC Reference Basket Price Historical 1998 to 2011 Historical annual average ORB prices and comparisons to Brent. 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
$12.28/bbl $17.48/bbl $27.6/bbl $23.12/bbl $24.36/bbl $28.1/bbl $36.05 /bbl $50.64 /bbl $63.18 /bbl $69.08/bbl $94.45 /bbl $61.06/bbl $75.59/bbl
US$ / barrel
Dated Brent $54.52 (2005Avg) Dated Brent $65.14 (2006 Avg) Dated Brent $72.39 (2007 Avg) Dated Brent $97.26 (2008 Avg) Dated Brent $61.67 (2009 Avg) Dated Brent $79.50 (2010 Avg)
www.opec.org
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© by David A. Wood
2011 OPEC Reference Basket Price The new OPEC Reference Basket (ORB) introduced in June 2005 is made up of twelve crudes: Saharan Blend (Algeria), Girassol (Angola), Oriente (Ecuador), Iran Heavy (Islamic Republic of Iran), Basra Light (Iraq), Kuwait Export (Kuwait), Es Sider (Libya), Bonny Light (Nigeria), Qatar Marine (Qatar), Arab Light (Saudi Arabia), Murban (UAE) and Merey (Venezuela).
Indonesia withdrew to observer status from OPEC in 2008.
US$ / barrel
Prices based on daily quotes since Aug 2009. Note that OPEC crudes are not traded on any exchange so do not represent internationally traded benchmarks. www.opec.org © by David A. Wood
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OPEC Reference Basket (ORB) Price Relative to Benchmarks The OPEC basket price follows Brent.
2011
2010
OPEC Market Report April,2011 © by David A. Wood
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US Natural Gas Forward Curve 28 Oct 2011
© by David A. Wood
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UK & US Forward Gas Curves 2006 and 2008
© by David A. Wood
17
Hedging & Margin Erosion Fully (over?) valued acquisitions executed in a high commodity price environment can present future profitability risks for buyers.
Near-term commodity price risk can be partially mitigated in an acquisition through an aggressive hedging program. Longer-term issues do arise if prices continue to rise (e.g. in hindsight companies that hedged in 2003 / 2004 sacrificed much upside in 2005/2006). Hedging provides top line protection (reduces leverage) should prices ease. It enables leveraged buyers to repay debt finance. Hedges cannot, however, protect a company from rising costs or "bottom-up" margin erosion. Equity of companies that hedge aggressively can often trade at significant discounts to that of their unhedged peers. Puts pressure on management to fund the next acquisition(s) in a more leveraged manner?
© by David A. Wood
18
Petroleum Economics Valuing Incremental Investments David A. Wood
Analysis of Incremental Investments Often there are more than two investment alternatives on offer. An unrealistically positive NPV or other yardstick may result if the options are considered in isolation rather than on an incremental basis. Examples of incremental investments are: –
Drill a prospect versus farmout the prospect
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Complete versus abandon well
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Develop versus sell field discovery
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Install enhanced recovery systems versus deplete field
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Offshore pipeline versus shuttle tanker to produce field
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Upgrade /simplify plant versus keep existing facilities
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Install Electric Submersible Pumps (ESPs) versus keep beam pumps, screw pumps, jet pumps or gas lift.
–
Etc……
© by David A. Wood
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Analysis of Field Development: Case A – No Secondary Recovery Analysis can provide additional insight for decisions by focusing on incremental benefits or sacrifices associated with different project options.
© by David A. Wood
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Analysis of Field Development: Case B – With Secondary Recovery Analysis can provide additional insight for decisions by focusing on incremental benefits or sacrifices associated with different project options.
© by David A. Wood
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Incremental Analysis of Field Development: Case B versus Case A Analysis can provide additional insight for decisions by focusing on incremental benefits or sacrifices associated with different project options.
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© by David A. Wood
Cash Flow Analysis of Drilling Opportunity This considers a straightforward upfront equity investment to drill the well.
Cashflow Analysis of Drilling Opportunity Year 0 1 2 3 4 5 Totals (yrs1 to 5) Net Totals (yrs 0 to 5)
Production Barrels 0 1000 550 300 175 100 2125
Revenue Expenses (Values in 000's) $0 $0 $20,160 ($1,000) $11,090 ($1,080) $6,100 ($1,160) $3,350 ($1,260) $1,840 ($1,360) $42,540 ($5,860) ROI:
Note: IRR function calculates back to year 0 Discount factor applied mid-year from year 1
© by David A. Wood
NCF Pre-tax ($10,000) $19,160 $10,010 $4,940 $2,090 $480 $36,680 $26,680 2.67 IRR: DROI:
PV15 NCF Pre-tax ($10,000) $17,867 $8,117 $3,483 $1,281 $256 $31,004 $21,004 143% 2.10
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Drill versus Farmout Options Analysed Incrementally It is often not necessary to calculate the incremental case as decisions can be based on relative NPVs of two or more alternatives. However the incremental value between two options can often provide useful additional insight. Farmout Option Where Farminee Pays All Well Costs -Farmor has 25% Back-in Option at Payout Values in 000's Year 0 1 2 3 4 5 Totals (yrs1 to 5) Net Totals (yrs 0 to 5)
Drill Case Investment $10,000 Drill NCF A ($10,000) $19,160 $10,010 $4,940 $2,090 $480 $36,680 $26,680
Note: IRR function calculates back to year 0 Discount factor applied mid-year from year 1
© by David A. Wood
PV15 NCF ($10,000) $17,867 $8,117 $3,483 $1,281 $256 $31,004 $21,004
Farmout Case Investment $0 Farmor NCF B $0 $2,290 $2,503 $1,235 $523 $120 $6,670 $6,670
PV15 NCF
$2,135 $2,029 $871 $320 $64 $5,420 $5,420 ROI:
Incremental Case Investment $10,000 Incr. NCF A-B ($10,000) $16,870 $7,508 $3,705 $1,568 $360 $30,010 $20,010 2.00 IRR: DROI:
PV15 NCF ($10,000) $15,731 $6,088 $2,612 $961 $192 $25,584 $15,584 114% 1.56
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Petroleum Economics Inflation, Buying Power, Money of the Day & Real Values David A. Wood
Cost Inflation: Significant Impacts on Oil & Gas Industry
UCCI: Equipment that cost $100 in 2000 costs $230 at end 3Q 2008 ($218 at end 1Q 2011) DCCI: Equipment that cost $100 in 2000 costs $176 at end 1Q 2008 ($192 at end 1Q 2011)
Oil industry cost inflation since 2005 has impacted upstream and downstream industry acting as drags on development leading to project cancellations and delays. Costs escalated through 2008 despite economic slowdown. World steel demand down 15% in 2009. Activity and inflation increased again 2010 to 2011.
© by David A. Wood
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Inflation and Cash Flow Calculations If a 15% rate of return is desired and 10% /year inflation is forecast: Cashflow Analysis of Investment Opportunity With 10% Inflation of Revenue and Expenses Cash flow adjusted for 10% inflation No inflation considered in calculating net cash flow Values in 000's PV25 NCF Revenue Expenses NCF PV15 NCF NCF PV15 NCF Year Pre-tax Pre-tax Pre-tax Pre-tax Pre-tax 0 ($10,000) $0 $0 ($10,000) ($10,000) ($10,000) ($10,000) 1 $4,651 $6,000 ($800) $5,200 $4,849 $5,454 $5,086 2 $2,361 $4,000 ($700) $3,300 $2,676 $3,807 $3,087 3 $1,374 $3,000 ($600) $2,400 $1,692 $3,046 $2,148 4 $779 $2,000 ($300) $1,700 $1,042 $2,373 $1,455 5 $293 $1,000 ($200) $800 $427 $1,228 $655 Totals (yrs1 to 5) $9,458 $16,000 -$2,600 $13,400 $10,686 $15,908 $12,430 Net Totals (yrs 0 to 5) ($542) $3,400 $686 $5,908 $2,430 ROI: 0.34 0.59 Note: IRR function calculates back to year 0 IRR: 14.8% 23.4% Discount & inflation mid-year from year 1 DROI: 0.07 0.24
Implication of this calculation is that factoring in inflation increases value! Adjustments to the discount rate are required.
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© by David A. Wood
Allowing for Inflation in Cash Flows It is not correct to simply add the inflation rate to the discount rate to compensate for inflation (but when inflation rates are very low it makes very little difference to the analysis). A composite discount rate accounting for inflation is provided by: –
(1 +r) = (1+ i)(1 + f) where i is the desired rate of return, f is the rate of inflation and r is the composite discount rate. If i = 15% and f = 10% then: r =26.5% (not 25%).
However there are complications: –
Costs and product prices often inflate at different rates. This is particularly so in the petroleum industry.
–
In after tax calculations some components (e.g. depreciation) are not adjusted by inflation in many fiscal regimes.
© by David A. Wood
4
Money of the Day (MOD or Nominal) Cash Flow Values It is usually more effective and realistic for economic analysis to inflate cash flow components separately and then to deflate the resulting combined cash flow before applying discount factors. Costs are adjusted for inflation using the formula: – FVm =FVt * (1+fc)n – where: FVm is money of the day value, FVt is today’s value, fc is the annual rate of inflation for costs and n is the number of years. (n-0.5 can be used for mid-year inflation factors) – fp is substituted for fc to give an equation for prices. Future inflated cash flows calculated by combining the inflated components are said to be expressed in money of the day or nominal terms.
© by David A. Wood
5
Real Cash Flow Values Money of the day cash flows can be deflated before applying discount factors to provide cash flows in real rather than nominal terms. Money of the day or nominal cash flows are deflated back to today’s values (or values of any specified period) by adjusting for inflation using the formula: – FVr =FVm * (1+d)-n – where FVm is money of the day value, FVr is the real value, d is the annual rate of deflation and n is the number of years. (n-0.5 can be used for mid-year factors). – unlike the inflation factors which are cost and price specific for the industry the deflator should be related to broader economic inflation indicators to reflect forecasts for the effective buying power of money.
© by David A. Wood
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Oil & Gas Prices are Often Expressed in Both MOD (Nominal) and Real Terms Two forecasts for natural gas prices in Canada at Alberta Hub. Real terms is in the money of year 1. MOD terms is in the money of each year including inflation.
The effects of inflation can be removed by deflating the cash flows to real $ year 0.
© by David A. Wood
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Buying Power Concept – Supplier Example Buying power is synonymous to the expression of future cash flows PV’s or of future cash flows in terms of current monetary values. A supplier buys 1000 valves in year 1 at $30 each and fits them into a simple surface meter that is sold for $100. His other materials and overhead costs are $30,000. For year 1: Suppliers First Year Cash Flow Sales: 1000 metres $100,000 1000 Valve Costs ($30,000) Other Costs & Expenses ($30,000) Profit taken ($10,000) Net cashflow for reinvestment $30,000
The supplier reorders the valves to find they are now $50 each (a 66.7% increase). His $30,000 will now only buy 600 valves. His money is now only worth 600 * $30 = $18,000 in year 1 terms
© by David A. Wood
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Equation to Calculate Buying Power The equation also has to consider the potential earning power of year 1 money. The situation for the supplier is worse than it appears because he has also foregone interest that could have been earned on the original $30,000 investment. If that interest (i) is say 10%: –
PV10 ($30k) = ($30k)(0.9091) = $27,273
–
This has to be combined with the effective value of the ($30,000) to the supplier (i.e. the inflation rate, f) to calculate the buying power.
–
BPVi = CFn*[(1+i)(1+f)] -n is the general buying power equation, where n is number of years.
–
BPV10 = $30K*[(1 + 0.1)(1 + 0.667)] -1 =$16,331
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© by David A. Wood
Real Rate of Return There is another relationship between the desired discount rate and inflation rate that is used to calculate the rate of return in real terms. Equation to calculate real rate of return is: – S = (i - f)*(1 + f) -1 where i is the nominal rate of return, f is the inflation rate of investment costs and S is the real rate of return. If a cash flow with f=10% has a nominal rate of return of 23.4%. The real rate of return was: – (0.234 - 0.1)*(1+ 0.1) -1 = 12.2% The same equation can be re-arranged to give the nominal rate of return needed for a desired real rate: – i =S + f(1 + S) e.g. 0.15 + 0.1(1+ 0.15) = 26.5% © by David A. Wood
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Petroleum Economics Inflation Indices David A. Wood
Constant or Real Price Terms By expressing values in terms of prices of a particular year it removes price inflation or fluctuation and gives volume information but expressed in monetary terms, i.e. output in real or constant prices.
Current prices, nominal prices and nominal terms or values include the effects of inflation. Volumes, constant prices, real prices and real terms or values exclude any inflationary influences. Price indicators used to convert between current and constant prices (to deflate) are sometimes called price deflators. Any series of numbers can be converted into index numbers with a base of 100 by: 1) selecting a reference base year value; 2) dividing that number by 100; 3) dividing all the numbers in the series by the result of step 2.
© by David A. Wood
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Constant Versus Current Dollar Energy Costs
© by David A. Wood
3
Calculating Price Indices Any series of numbers can be converted into index numbers with a base of 100 by:
1.
Selecting a reference base year value
2.
Dividing that number by 100
3.
Dividing all the numbers in series by result of step 2.
Index numbers have no units. This avoids distracting units and changes are easier to assess.
© by David A. Wood
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Current & Constant Price Indices & Price Deflators Index numbers have no units. This avoids distracting units and changes are easier to assess.
© by David A. Wood
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Indices: Points To Be Aware of Basis for weighting indices and assessing the effect of the base year selected.
Frequently two or more indices are combined to form one composite index (e.g. Purchase Price Index PPI or Consumer Price Index CPI). The different components are weighted according to their contribution to the index in the base year. Composite indices can become distorted if one component becomes much more or much less significant in terms of its contribution compared with that in the base year. Always check when an index was last re-based and whether there were significant changes in its components. Two or more indices will always meet at the base period because they both equal 100. This can be misleading. Always check where the base is located. This is known as illusory convergence.
© by David A. Wood
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Index Numbers – Do Not Be Fooled By Illusory Convergence The base year selected will arbitrarily control when current and constant price indices converge.
© by David A. Wood
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Contract Prices & Tariffs are Often Escalated Periodically Using Composite Indices Long-term product sales and pipeline tariff contracts sometimes include indices to adjust prices each year (or quarter). This protects buyer and seller from inflation and other changes in market conditions.
Composite indices such as PPI are often used in long term sales and transport contracts to take account of inflation and changes in market conditions. For example a price formula in a UK long-term gas contract was: P = IP[0.4(X/X0)+0.2(E/E0)+0.25(G/G0)+ 0.15(H/H0)]
Where P is the inflated price, IP is the base price, X is Producer Price Index, E is the industrial electricity index, G is the gas oil index and H is the heavy fuel oil index. X,E, G & H are all quoted in UK Government statistical publications. The base year index (denominator)values have a 0 suffix. All components to such indices should ideally be appropriate to the market and be based to relevant years.
© by David A. Wood
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Volume and Price Usually Determine Value When interpreting economic figures it is important to distinguish between the effects of inflation and the real level of economic activity. Economic indicators measure one of three things: –
Volume - e.g. barrels of oil.
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Price - e.g. market price of 1 barrel of oil.
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Value - e.g. market value of oil produced in 1 year.
The relationship between them is simple: –
Volume * Price = Value.
–
Inflation indices enable us to express price and value at different periods of time.
© by David A. Wood
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Petroleum Economics Estimating Values & Costs and Budget Cost Control (Exercise #4) David A. Wood
Oil Price Forecast – Energy Specialists 1998
Actual Price
We are worse (as individuals or groups) than we think we are at forecasting! © by David A. Wood
2
Costs in an Upstream Oil & Gas Perspective Costs are not usually the most important influence on overall project value. Oil price, reserves & production rate and even exchange rates often have largest impact on NPV. Tornado charts are useful to display sensitivities. In the case of a single asset, project level and corporate level cost drivers often have less impact on long term profitability than revenue drivers. For LNG, deep water and marginal field developments costs are more important but usually remain subordinate to the revenue and production drivers. Can use absolute numbers and / or percentages © by David A. Wood
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Tornado Charts Display Relative Importance of Costs Capital expenditure is a key project driver for deepwater Nigerian prospects. Absolute numbers and percentages are usefully displayed.
© by David A. Wood
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Spider Charts Widely Used for Sensitivity Analysis
© by David A. Wood
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Spider Charts Interpretation: Steep Trends Indicate High Sensitivity
© by David A. Wood
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Opportunities to Simplify Old Facilities & Reduce Operating Costs As production / revenues decline in mature fields management must seek changes to the operation that reduce OPEX and extend field life.
Fixed costs can often be reduced by facilities rationalisations in stages as a field matures. Variable costs often fluctuate over the life of a project and may increase as break-even is approached as economies of scale are lost.
© by David A. Wood
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Eliminating Bias from the Estimation Process Systematic bias — the tendency for us to consistently overestimate reserves or underestimate costs — permeate the upstream oil & gas industry!
Two biases that commonly bedevil our geotechnical forecasts are:
–
over-confidence — setting predictive ranges too narrow, resulting in frequent surprising outcomes.
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over-optimism — motivational bias, caused by excessive zeal in “selling” the prospect prompted by perceived competition from the prospects of others.
© by David A. Wood
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Common Estimating Trend of Increasing Costs Through Project Life
The challenge is to predict realistic cost early in the project. The cost curve here shows a common estimating trend, a pattern of increasing costs from one phase of the project to the next.
© by David A. Wood
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Reasons for Poor Early Cost Estimates Most common ailments or root causes are optimistic estimates and schedules, lack of experienced personnel, lack of time, lack of money, manipulative access to funding and / or poor execution.
Optimistic early estimates may secure project sanctioning, but once exposed after commitments are secured may reveal that the sanctioned project is uneconomic. Poor early estimates once quoted are difficult to replace in contracts with better defined and possibly more expensive. A poor early estimate can result in a loss of credibility between the client and estimator.
© by David A. Wood
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Cost Estimating Phases & Accuracies Early estimates should not be over-defined to a degree that is excessive for that estimating phase.
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© by David A. Wood
Contingency Versus Accuracy Contingency is the amount added to the base estimate to achieve a P50 cost. The P50 cost has a 50% probability of either under-running or overrunning the final actual cost. Contingency is an allowance for costs expected to occur but currently undefined and unknown. Contingency does not allow for costs associated with scope growth or premises changes. The amount of contingency applied should be an ownerdefined cost and responsibility based on an empirical method, one which documents the process and provides some explanationjustification to support the allowance.
© by David A. Wood
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Cost Risk Analysis Example Example of a pre-FEED cost risk analysis performed on a GOM deepwater subsea tieback project (excludes costs of drilling and completion).
Yale & Knudson, Deepwater Technology, Jan 2006 © by David A. Wood
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Probabilistic Approaches to Cost Estimate Uncertainties It is useful to clearly indentify what is involved in cost estimate contingencies and uncertainties. Probabilistic distributions offer a useful technique to do this that can be sampled in simulation analysis.
© by David A. Wood
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The Time to Influence Expenditure is During the Planning Stage
15
© by David A. Wood
Authority for Expenditure (AFE) Essential for Cost Control & Approvals AFE system is widely used in the oil and gas sector because of joint ventures.
All joint venture parties are expected to sign off an AFE produced by the project sponsor or operator. By doing this all parties formally approve project costs which are documented and explained in the AFE.
© by David A. Wood
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AFE Process, Cash Calls & Cost Control Report
The AFE is a document describing the scope of work and associated costs required for a project. It usually includes: – Cost estimate breakdowns of the items of expenditure needed to complete work – Timing and duration of activities involved – A total of the base case project cost with contingencies and any escalation factors associated with inflation to provide “a cost estimate for approval”
Details including a project description and economic justification to support the cost estimate are usually included in a brief 3 to 4 page document. Participants in the joint venture are expected to give their formal signature/ approval to the AFE within a specified period, commonly 30 days. They are then cash called by the operator to provide their shares of the required funds. If expenditures during the project seem likely to exceed 10% of the approved cost then a supplemental AFE is issued. A cost control report is prepared at the end of the project.
© by David A. Wood
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80:20 and 95:60 Rules of Thumb Provide Useful Guides for Cost Control Concentrate efforts on the 20% of key items / services that drive the project and minimize time and overhead spent on the 40% of items that represent only 5% of the costs.
© by David A. Wood
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Petroleum Economics Introduction to Upstream Fiscal Terms & Contract Types David A. Wood
Parties & Agreements Commonly Involved in Petroleum Field Projects
Note: 1. Lenders can be banks and or multi-lateral agencies (e.g. IFC) 2. Offtake here includes transportation, throughput & processing. © by David A. Wood
2
Strategic Objectives of Fiscal Design & Types of Fiscal Agreement
3
© by David A. Wood
Key Government and Contractor Aspirations HOST GOVERNMENT
Maximise/optimise its share of the economic rent Ensure good governance (safety, environment & corporate)
CONTRACTOR / IOC
Avoid undue speculation and corruption
Create competitive investment climate
Sustain growth and development
Create employment, training and commercial opportunities for its nationals
© by David A. Wood
Build equity and maximise value for the shareholders Maximise return on investment and its share of reserves and production Provide fiscal stability and flexibility Reward risk taking Minimise bureaucracy, fiscal complexity (ambiguity) & corruption Offer progressive taxation
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Overall Government Takes from Petroleum Production Varies Substantially Governments need to retain the ability to adjust fiscal designs to meet changing conditions. Most governments open new areas for licensing, re-licensing, or for contract by IOCs in stages over time. Often such activity is linked to bidding rounds. It is useful for the governments to retain rights to adjust fiscal terms associated with new licensing.
© by David A. Wood
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Components of Government Take in Terms of Economic Rent Government’s and IOCs shares of economic rent.
© by David A. Wood
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Progressive and Regressive Fiscal Elements & Government Risk
© by David A. Wood
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Progressive Fiscal Structures Respond to Changing Conditions Progressive fiscal structures take more for the state when prices are high or costs are low.
© by David A. Wood
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Regressive Fiscal Structures Less Flexible in Changing Conditions Regressive fiscal structures will damage commerciality in harsh economic conditions.
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© by David A. Wood
Royalty Can Become a Significant Burden The regressive nature of royalties is easy to demonstrate:
© by David A. Wood
With a gas price of $10 / mmbtu, a 20% royalty accounts for 50% of the gross profit of a field costing $6/mmbtu to produce. With a crude oil price of $15/mmbtu, the royalty share of profit decreases to 33.3% With a crude oil price of $20/mmbtu the royalty share of profit decreases to 28.6%. This graph illustrates the regressive impact of royalties on profits.
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Time-Value-Cost Analysis of Oil & Gas Projects & Fiscal Terms
Cross plotting, on a per barrel basis, discounted contractor cash flow (NPV) and full project costs reveals much more about the economic performance of specific projects and contract terms. Such plots are useful negotiating aids for both contractor and government. Such plots can be enhanced by incorporating assessments of risk.(i.e. using EMV instead of NPV).
© by David A. Wood
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Licence Agreement Terms Influencing Financial & Economic Performance
Contract area / prevailing law Duration of phases / contract management / voting rights Relinquishment Schedule / accounting procedures & currencies Land rentals ($/km2) / employment obligations Exploration obligations and work commitments Bonuses (signature, training, production, reserves thresholds) Royalty (% of gross production- perhaps sliding scale) Cost Recovery Allocation (% of gross revenue) Uplift Allowances of Capital Costs (% of eligible costs) Overhead and debt interest cost allowances Custom’s duties and other local levies and employment taxes. Cost Amortization (%/yr depreciation rates for cost categories) Profit Oil or Gas Split (% usually a sliding scale) Domestic Market Obligation – subsidy to world market price Ring fencing (of costs and/or revenues); oil / gas price caps Income Tax (% of contractor profits) Tax Credits for additional capital expenditure (e.g. exploration) Withholding / Remittance Tax (% of profits remitted overseas) State Participation / back-in option (% of joint venture group) Rights of Assignment / dispute resolution / arbitration
© by David A. Wood
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Long-term Fiscal and Contractual Stability Often Proves to be Elusive Key issues: Alignment Empathy Understanding Trust Long-term Perspectives Flexibility Sustainability
13
© by David A. Wood
E&P Licence Areas and Unitisation Offshore UK quadrants of 1 degree latitude by 1 degree longitude are subdivided into 30 blocks of about 250 sq. km.
Original Unitisation of Nelson Field 22 / 06a: 43.29% 22 / 07: 0.75% 22 / 11: 53.33% 22 / 12a: 2.63%
Nelson Field
© by David A. Wood
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Joint Development Zones Nigeria / Sao Tome JDZ
© by David A. Wood
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Unitisation- Definition of Process
“A process to facilitate the equitable distribution of volumes to the stakeholders of a petroleum accumulation, and to share in the benefits of production, revenues and the costs of obligations inherent in the development and production within the oilfield.”
© by David A. Wood
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Petroleum Economics Production Sharing & Cost Recovery (Exercise #5) David A. Wood
Division of Proceeds from Oil & Gas Production Sharing Contracts This scheme considers how the profit and cost components from oil (or gas) fields are divided on a full project basis.
Contractor Take: Government Take The division is simplistic as it ignores the time value of money and risk versus reward concepts
© by David A. Wood
2
Time-Value Considerations For Cost Recovery Mechanisms Oil and gas projects are characterised by high capital investment in early years, without cash flow, followed by high cash flow after production startup which gradually declines in line with production towards field abandonment. Rate of cost recovery impacts contractor’s value.
© by David A. Wood
3
Production Sharing Contracts: Basic Fiscal Components Over time PSCs have changed substantially and today many have complex features to refine the production sharing process. In its most basic form a PSC has four main fiscal properties. 1.
Contractor often pays a royalty on gross production.
2.
Contractor is entitled to a pre-specified share (e.g. 40 percent) of production for cost recovery (termed cost oil).
3.
The remainder of the production, so called profit oil, is then shared between government and contractor at a stipulated share (e.g. 70% government: 30% contractor) or on a sliding scale.
4.
In some contracts income tax is paid from the government’s share. In others the contractor has to pay income tax on its share of profit oil. In some contracts (e.g. Nigeria) a pre-specified share of production is designated for the payment of tax and termed tax oil.
© by David A. Wood
4
PSA Take & Cash Flow Breakdown Average Over Field Life
Taxation, cost recovery (allocation and depreciation) and state participation all have significant impact on the economic performance of upstream oil and gas contracts. Some taxes may be paid from the Government’s share to attempt tax stability.
5
© by David A. Wood
PSC Take & Cash Flow Breakdown (1a) Average Over Field Life – Good Cost Oil Signature and other bonuses should also be included in the State Take. This average barrel over the life of the field ignores the effects of depreciation.
David Wood & Associates
© by David A. Wood
In this example cost recovery is sufficient to recover the cost of the average barrel, but it may not be enough to recover the all the costs in the early years of production.
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PSC Take & Cash Flow Breakdown (1b) Average Over Field Life – Good Cost Oil In this example cost recovery (E) is sufficient to recover the cost of the average barrel, but it may not be enough to recover the all the costs in the early years of production. Gross revenue is split approximately: •62% to State •7% to Contractor •31% to Costs
7
© by David A. Wood
PSC Take & Cash Flow Breakdown (2a) Average Over Field Life – Poor Cost Oil Cost recovery allocation is reduced here to 25%. It is now not sufficient for all the costs to be recovered. Unrecovered costs remain in a cost pool. Contractor has spent $6 but only recovered $4.25. Contractor’s take and cash flow are significantly reduced.
David Wood & Associates
© by David A. Wood
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PSC Take & Cash Flow Breakdown (2b) Average Over Field Life – Poor Cost Oil In this example cost recovery (E) is insufficient to recover the cost of even the average barrel in a single period. The State’s Take and cash flow are the same. The contractor’s are not, because contractor is funding upfront capital costs. Gross revenue is split approximately: •69.5% to State •-0.7% to Contractor •31.2% to Costs •But nearly one-third of those costs (10% of gross revenue) are not recovered in a single period. © by David A. Wood
9
Yearly Price Fluctuations Influence Reserves Booked Under PSCs Higher the product price the lower the number of barrels to satisfy the cost oil allocation. Remaining barrels go into profit split.
© by David A. Wood
10
Contractor: Government Takes & Interests “Bookable” in Financial Statements
The tax component is also accepted as a bookable component in some PSCs
Bookable In Financial Statements
© by David A. Wood
11
Exercise to Calculate Revenue Split For Example Production Sharing Terms – Fill in the Gaps! David Wood Exercise #5
Petroleum Economics Funding Criteria: The Cost of Capital & Oil & Gas Finance David A. Wood
Cost of Investment Capital is Usually Complicated by Taxation Issues Tax allowances for debt and equity sources of capital are usually different.
The simplest case is: all money is provided by a single lending agency at a single rate. The cost of capital is the before-tax or after-tax interest charge, e.g: A bank loan at 10% – Cost of Capital =
10% before tax.
– Cost of Capital =
(10)(1 - 0.29) = 7.1% after tax.
Note that in most countries the government effectively subsidises borrowing by allowing corporate tax relief on loan interest.
© by David A. Wood
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Cost of Investment Capital: Weighted Average Cost of Capital The weighted-average cost of investment capital (WACC), from all sources, is usefully expressed as a percentage interest cost, not as an absolute currency amount.
A second simple case of investment money derived from three separate lending agencies: Bank A: 100 M$ at 10% Bank B: 200 M$ at 12% Bank C: 300 M$ at 15%
Cost of Capital = [(100)(10) + (200)(12) + (300)(15)]/600 = 13.17% before tax. Cost of Capital = (13.17)(1 - 0.29) = 9.35% after tax.
© by David A. Wood
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Cost of Debt Plus Equity Investment Capital (1) Most companies fund ventures with both debt and equity making the cost of capital calculation more complex. All sources of capital funds have associated costs that must be consider in calculating WACC.
A third, real world case, is a public corporation with debt (loans, bonds, etc.) and equity (stock/traded shares) capital. In this case, the cost of capital can be estimated as:
[(% Equity) * (Growth Rate + Dividend Rate)] + [(% Debt) * (Interest Rate)]
Consider such a corporation trying to maintain a 10% stock value growth rate and paying a 4% dividend. Debt consists of 75% in 7% bonds and 25% in 15% short-term notes. The debt : equity split is 40 : 60 and the percent equity is 60, for a debt/equity ratio of 0.67.
© by David A. Wood
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Cost of Debt + Equity Investment Capital (2) Most large companies fund ventures with both debt and equity.
Cost of Capital = (0.6)(10 + 4) + (0.4)[(0.75)(7) + (0.25)(15)] = [8.4/(1 - 0.29)] + 3.6 = 15.43% before tax Cost of Capital = 8.4 + (3.6)(1 -0.29) = 10.96% after tax Growth and dividend payments are accomplished with after-tax funds so before tax calculation requires tax adjustment (which will increase the equity cost pre-tax). After taxes, debt capital is cheaper than equity capital, even at relatively high interest rates for borrowing.
© by David A. Wood
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Link Discount Rate To Cost of Capital Most companies fund ventures with both debt and equity.
Prudent practice dictates that investments not be made in projects returning less than the cost of capital. Therefore, the minimum investor’s rate of return for qualifying projects, as well as the appropriate minimum discount rate for present value calculations, is the cost of capital. IRR, PV and NPV should all be determined on an after-tax basis and with risk and inflation prefigured into the net cash flow stream and not incorporated into the required rate of return or discount rate.
© by David A. Wood
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Simplified Flow Chart For The Financial Process in a Typical Upstream Oil Company The role of financial management is to optimise the value and use of the basic reservoir of cash and its associated funds flow.
Financial management involves funding decisions in the raising of cash in the form of equity and debt. It also involves the efficient allocation of funds between assets, credit investments, etc.
© by David A. Wood
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Providers of Project Finance to Major Energy Projects Energy investors and commercial banks make the major funding contributions.
© by David A. Wood
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OECD Export Credit Agencies Export credit agency contributions as debt or guaranties help to reduce project risk.
www.exim.gov (U.S.A) www.ecgd.gov.uk (U.K.) http://www.oekb.at (Austria)
© by David A. Wood
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LIBOR and EURIBOR Benchmark lending rates.
The Libor is the average interest rate that leading banks in London charge when lending to other banks. It is an acronym for London Interbank Offered Rate. Banks borrow money for various time periods(up to one year) and they pay interest to their lenders based on certain rates. The Libor figure is an average of these rates. The Libor rate is announced daily at 11 a.m. And is used by financial institutions to fix their own interest rates (when lending to others), which are typically higher than the Libor rate. LIBOR is therefore a benchmark for finance all around the world. Euribor is short for Euro Interbank Offered Rate. The Euribor rates are based on the average interest rates at which a panel of more than 50 European banks borrow funds from one another. There are different maturities, ranging from one week to one year.
© by David A. Wood
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Petroleum Economics Hurdle Rates and Selection of Discount Rates David A. Wood
How Do Organisations Select an Appropriate Discount Rate? Commonly applied discount rates are.
Rate of interest paid on borrowed capital (i.e. the cost of debt capital).
Full cost of capital, cost of debt plus equity.
Effective rate of return offered from available competing investments or from an existing portfolio. Minimum threshold effective interest rate desired for available investment capital. Oil & gas equity investors generally want a greater return than they can earn from less risky investments. (Equity therefore usually costs an oil and gas company more than debt) The discount rate should not be less than the cost of the capital being invested in the project.
© by David A. Wood
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What Discount Rate Should be Used? Discounted cash flow calculations form the cornerstone of modern economic analysis. However, there is often uncertainty as to what discount rate should be used to calculate present values.
Different companies can have different criteria for selecting discount rates. Commonly used rates are: – Cost of capital – Prevailing interest rates available for bank deposits or money market – Arbitrarily selected values above cost of capital to represent expectations of equity investors (e.g. 15% or 20%) – These are often used and referred to as Hurdle rates or minimum acceptable rate of return (MARR) © by David A. Wood
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Invalid Discount Rates Many companies mislead themselves by applying invalid rates to calculate the discount factors used in their economic evaluations: Inappropriate rates often applied are: – Inflation rate – An interest rate plus inflation – An interest rate increased to account for risk – An interest rate plus a desired return Considerations such as risk, inflation and interest paid need to be included in the cash flow calculation but not in the form of the discount factor which can distort calculated present values. © by David A. Wood
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Taking the Project Inventory to the Portfolio Level
© by David A. Wood
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Risking Cash Flow Profiles by Increasing Discount Rate is Not Appropriate Higher discount rates preferentially penalise later years in a cash flow profile.
© by David A. Wood
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Discount Rate Versus Success Rate Consider a cash flow profile discounted at several rates. The “cash flow” column is undiscounted (i.e. zero rate) For this cash flow profile the relationship between the net present values (NPVs - total discounted values) is: NPV@16% is 35% of the undiscounted cashflow, 59% of the NPV@8% and 76% of the NPV@12%. Increasing the discount rate to compensate for perceived higher risk will reduce the value by a fixed amount which will usually not correspond to the level of risk associated with each of a number of projects.
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© by David A. Wood
Risk-Weighted Prospect Cash-flows Risk should be applied to cash-flows using risk factors (chance of success or failure) not by raising discount rate. Risked NPV@8% for a chance of success of 40% is $11.5 million which drops to $5.7 for a chance of success of 20%. Doubling the discount rate from 8% to 16% only reduces the NPV to $8.8 million.
© by David A. Wood
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Petroleum Economics Probabilistic Methodology & Techniques For Economics & Risk Analysis David A. Wood
Investment Yardsticks Incorporating Evaluations of Risk It is important to take risk into account in economic analysis:
Expected monetary value (EMV). This is the combination of the net present value of success weighted with the chance of success and the present value (discounted cost) of a failure weighted with the chance of failure. Risk-weighted profit (EMV) to investment ratio. This is the EMV divided by the discounted total investment weighted for success plus the discounted risk investment lost on failure and weighted for failure. Risk Capacity. This is the NPV divided by the PV of the risk capital. Statistics from calculated probability distributions. The interrelation of numerous uncertainties is evaluated by the Monte Carlo simulation mathematical technique.
© by David A. Wood
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Quantifying Risk: the Probability Scale Quantifying risk on a numerical scale of probability offers a more systematic and consistent approach to expressing risk than adjectives.
Replaces verbal expressions of outcome like “good” or “almost certain”. © by David A. Wood
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Expected Monetary Value (EMV) EMV is the average value obtained when all outcomes are weighted on the basis of their respective probability of occurrence.
In an EMV calculation the sum of the probabilities must be 1.0 or 100%. © by David A. Wood
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EMV is Not Usually the Value Realised from a Single Trial It is the average outcome (value) expected from a large number of ventures of the same type.
Consider tossing a coin: heads you win $100; tails you lose $100. The expected outcome (EMV) from one toss is (+$100 * 0.5) + (-$100 * 0.5) = $0. But from one toss that can never be the outcome. That EMV will be the average result from repeated trials a large number of tosses. No two oil and gas ventures are exactly the same, in terms of probabilities and outcomes. Therefore, even this average outcome cannot really be expected. If each individual decision is made on the basis of optimising EMV, the overall ultimate outcome can be expected to be the average of all the individual EMVs. In an EMV calculation, the sum of the probabilities obviously must be 1.0 or 100 percent.
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© by David A. Wood
The Zero to One Sum Game Exploration projects commonly have potentially multiple success and failure outcomes. For example:
Consider another exploration venture. A dry hole costs $1,000,000, and there is a 60% probability that one dry hole will condemn the prospect, with a complimentary probability of 40% that two dry holes will be required. If a discovery is made, four outcomes are considered to be possible:
20% probability of losing $500,000 (discounted values). 40% probability of making $500,000. 30% probability of making $10,000,000. 10% probability of making $20,000,000.
There is a 70% probability (Pf) of finding no production and therefore Ps = 30% as: Pf + Ps =1.0 = 100%
© by David A. Wood
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Example of a Two-stage EMV Calculation Reduce the dry hole alternatives to one EMV for failure and the discovery alternatives to one EMV for success then combine the two:
Decision rule using EMV: if EMV is positive it is a worthwhile venture if EMV is negative it is not a worthwhile venture.
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© by David A. Wood
Calculating Probability of a Specific EMV This also gives the maximum probability of failure.
Pf + Ps =1.0
EMV = (Ps * NPV success)+ (Pf * NPV failure).
Ps to achieve an EMV of +$1,000,000 is calculated:
so
Pf = 1 – Ps
In millions: $ 1.0 = (Ps)(+$5.1)+(1 - Ps )(-$1.4) this simplifies to: 6.5(Ps ) = 2.4 Ps = 36.9% and Pf = 63.1% This means that for the EMV to equal +$1,000,000 then the Ps value in stage 2 of the calculation must equal 0.369.
© by David A. Wood
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Risk / Opportunity Models Often Need to Combine Discrete & Continuous Probabilities Combining discrete event likelihood estimates with continuous cost / value consequence distributions is a key part of the expected value calculation process of simulation models. Simulation models also need to incorporate timing estimates and discounting calculations to generate valuations of projects extending over many years. Logic of when events occur is a key part of the modelling process. It is important for the analyst to understand the implications of any assumption made in this regard.
© by David A. Wood
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Risk Capacity, Risk –Reward Ratio & EMV All Yield Valuable Information If EMV & Risk-Reward Ratio > 0 then a project is commercially viable on a risked basis. Values of zero indicate the minimum reserves threshold for a commercially viable risked project.
© by David A. Wood
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NPV and Reserves Risk Need to be Combined to Reveal Risked Values It is instructive to review the full probability distributions to understand the range of possible outcomes.
© by David A. Wood
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Risk Capacity Can Quickly Define the Minimum Reserve Threshold Cross plotting risk capacity and reserves risk against field size is a quick method of identifying the minimum reserves threshold, i.e. where the curves intersect is equivalent to the reserves size at EMV =0.
© by David A. Wood
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EMV:Risk-Reward Ratio Relationship: Both = 0 at Minimum Reserve Threshold
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© by David A. Wood
Risk-Reward Relationships are Influenced By Fiscal Terms Expected Value theory weights the value of a successful project with the chance of success and cost of failure with the chance of failure.
The discounted cash flow (Net Present Value – NPV) is the value of success. The risk capital expenditure on exploration measures the potential cost of failure – i.e. the dry hole cost.
© by David A. Wood
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Petroleum Economics Decision Analysis, Decision Trees & Flexibility David A. Wood
Decision Tree Nomenclature Decision trees are a means of diagramming a series of decisions, events, and outcomes to incorporate probabilities and EMVs.
They make analysis of a tortuous sequence of decision alternatives possible and presentable. They provide a permanent record of the analysis contributing to a decision as it existed, or was thought to exist, at the time of an original decision. Two node symbol convention is commonly used: –
Decision node, with actions taken (usually symbolised by a circle)
–
Event or chance node, with outcomes that occur (usually symbolised by a square)
© by David A. Wood
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Decision Tree Preparation: A Two-step Process Decision trees should be constructed systematically.
Step 1: Diagram and label the sequence of decisions, events, and outcomes with the associated probabilities of each event and outcome. Probabilities associated with one chance node should sum to 1.0 (i.e. the sum of all branches having the same origin equals 1). Step 2: Calculate expected monetary values and post them on the tree by working from right to left. It is necessary to calculate and post the EMV of each event node and leg.
© by David A. Wood
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Decision Trees: Step 1 A pictorial representation of a sequence of events and possible outcomes can help make complex decisions. The “event” node is sometimes referred to as the “chance” node.
© by David A. Wood
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Decision Trees: Step 2 EMV = (-2 * 0.7) + (2 * 0.15) + (15 * 0.1) + (75 * 0.05) = $4.2 mm
The EMV is placed by the event node and represents the risked value of everything to the right of it, i.e. the value of what would follow from the decision to drill. To maximise EMV decision here would be to drill. © by David A. Wood
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Petroleum Economics Monte Carlo Simulation Demonstration (Exercise#6) David A. Wood
Quantitative Approaches Require Probabilistic Models to Handle Uncertainty Models are required to process economic and risk data provided as probabilistic input distributions.
Spreadsheets combined with simulation add-ins (e.g. Crystal Ball , @Risk ) or driven by self-built simulation and statistical analysis VBA macros, offer a powerful tool to aid this analysis.
Having defined the range of the expected cost / value distributions of each event the simulation software transforms this into a distribution of selected type and then samples that distribution in a statistically valid way for a large number of model iterations or trials.
In the oil & gas industry Monte Carlo simulation is widely used to model uncertainty & value for field / prospect reserves, economics, risks and portfolios as well as for cost, time, resource analysis in project planning.
Simulation is also widely used in the financial sector to value financial instruments.
© by David A. Wood
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Simulation Example: Purchase of a Laptop & Software as Two Separate Items Market research of 30 sources suggests that the price of the laptop required can vary over a range of $700 to $1,700. A single average number does not adequately describe this range or the shape of the distribution, but it does provide the best estimate of price at $1,200
© by David A. Wood
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Simulation Example: The Two Separate Items May Have Quite Different Price Distributions Market research of 30 separate sources suggests that the price of the software required can vary over a range of $500 to $1,500. The distribution is asymmetrical with a positive skew resulting in mode (most frequent), median (P50) and mean having different values. Cumulative Probability is calculated for each value to provide a probability of the price being equal to or less than a certain value.
© by David A. Wood
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Analogy of Simulation Process With Selection of Lottery Balls Consider each of the 30 price samples for each item as the numbered balls inside two separate lottery barrels.
The laptop lottery barrel would contain 1 $700 ball but 6 $1,200 balls, etc. The software lottery barrel would contain 1 $500 ball but 8 $700 balls.
It is therefore 6 times more likely that a $1,200 ball will be drawn from the laptop lottery barrel than a $700 ball.
A well constructed simulation model samples the distributions in a similar way, i.e. proportional to the frequency of occurrence. It uses cumulative probabilities to do this.
For each trial it then adds the value on the two samples drawn from the “lottery barrels” or distributions to give the combined cost.
The process then replaces all the balls and repeats the process for the number of iterations (trials) specified.
© by David A. Wood
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Considerations Based Upon the Two Cost Distributions Prior to running a simulation analysis the following points can be deduced:
Randomly buying the two articles in any store the chance of paying the lowest combined price of $1,200 or the highest combined price of $3,200 is much less than the chance of paying the combined average prices of the two distributions.
Cumulative probabilities are expressed on a scale of 0 (price is always greater than that) to 1 (price is always less than that). If a total number of 30 is used to calculate the cumulative probability the highest price will have a probability of 1
Spreadsheet random number generators provide numbers randomly between 0 and 1 (but never actually those two numbers exactly). If the highest price has a probability of 1 it will never be sampled by a random number in such a sequence.
To overcome this a total of 31 is used to calculate the cumulative probabilities shown in the previous graphs.
© by David A. Wood
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Random Numbers are Selected to Represent Cumulative Probabilities This simple model uses VLOOKUP tables in Excel to extract values from the two price data sets based on two series of random numbers.
Other trials omitted….. space constraints ……
A random number is linked to a cumulative probability and the price associated with the next lowest cumulative probability in the tables adjacent to previous graphs is selected. The model then adds the two prices derived in each trial to provide a combined price.
© by David A. Wood
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Output Distribution From Monte Carlo Simulation Model The output or forecast distribution is uneven (and in this case bimodal) with gaps because limited number of trials make it statistically inadequate with results strongly influenced by chance. Most sets of 50 trials show a single mode, but some are more uneven than others. Many more trials are required to generate a statistically smooth output distribution. Expressing this as a cumulative probability distribution provides information on the chance of not paying more than a specific combined price. What if the two price distributions are correlated?
© by David A. Wood
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Advantages of Monte Carlo Simulation The main purposes of a simulation study are to generate a statistically valid probability distribution(s) for the objective function(s) and to provide greater understanding of the relationship between the input metrics and the objective functions. Advantages of Simulation are: Mathematics is relatively straightforward and widely used, forming the heart of diverse aspects of financial analysis (e.g. pricing options, corporate portfolio models etc.).
Spreadsheet functions & VBA code are mostly sufficient.
Distributions encapsulate both optimistic and pessimistic estimates and limit potential for forecasts being unduly biased in either direction. Bias is a problem with single point estimates.
More trials can be run in seconds to improve statistics.
People accept the technique and believe the results (sometimes too readily!!).
Models can usually be updated easily. Correlations and complex dependencies can be incorporated. The effort of using a model once established is low.
© by David A. Wood
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Monte Carlo Simulation Technique – Step by Step For Cash flow Analysis (1) A number of different input distributions are combined to calculate reserves and prospect expected monetary values (EMVs) for a number of trials.
© by David A. Wood
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Monte Carlo Simulation Technique – Step by Step For Cash flow Analysis (2) A number of different distributions are combined to calculate prospect NPV’s & EMV’s by the Monte-Carlo technique.
David Wood has published details of simulation applications in the Oil & Gas Journal (e.g. OGJ 1 Nov, 1999; 23 Oct 2000 plus executive reports).
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© by David A. Wood
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Caution Required For Monte Carlo Simulation Model Structure & Interpretation Frequency distributions generated by computer can be very believable despite being based in some cases on meaningless input distributions.
The computed frequency distributions for in-place hydrocarbons commonly produced by simulation are only as good as the quality of the frequency distributions assigned to the input variables.
It is important to identify those variables which are dependent upon (or correlated with) other variables and treat them as functions of those independent variables.
A geological example of dependent variables are porosity and water saturation that are inversely correlated in many cases. Capital costs and operating costs are positively correlated in some oil and gas projects (i.e. as one increases so does the other).
If porosity and water saturation are treated as independent then random numbers will associate an unrealistic water saturation with a porosity in individual iterations of the simulation.
© by David A. Wood
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Mechanics of Monte Carlo Simulation Cumulative frequency distributions, random numbers and a large number of iterations means many numbers to crunch and analyse.
A Monte Carlo simulation requires that the uncertain variables be defined as either discrete or continuous frequency (probability) functions.
Numerous passes through the entire calculation are made. For each calculation the value assigned to each variable is determined by a random number sampling the variable distribution.
A different random number is applied to each variable for each pass or iteration of the model.
In this way, each value utilized for each variable occurs according to its prescribed frequency function for the distribution type selected.
The result is a frequency distribution of the calculated metric.
© by David A. Wood
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Random Sampling of Independent Variables For independent variables it is important that the random numbers selected to sample each variable are random and distributed in accordance with the selected distribution to approximate each variable. Random sampling of two uniform distributions crossplotted should appear similar to the adjacent diagram. Increasing the number of sample trials should result in filling the gaps and not increasing the clusters. Different mathematical routines are available to smooth sample point spread, but these are beyond the accuracy of the method for most oil and gas problems.
© by David A. Wood
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Statistical Stability & Significance of Simulations Sufficient simulation passes should be made so that the standard deviation of the calculated distribution is no longer changing significantly. Another rule to follow is to run a simulation until the standard error of the mean (i.e. standard deviation / √ number of trials in the simulation) is less than 1% of the mean.
© by David A. Wood
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Decision Trees and Simulation A Monte Carlo simulation derives a distribution which represents a large number of possible outcomes rather than a few discrete outcomes of a simple decision tree.
© by David A. Wood
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Exercise #6: Monte Carlo “Simulation”: Two Variable / 10 Trial Problem To illustrate the technique a simplistic calculation is required in this exercise using just two variables defined as discrete distributions.
© by David A. Wood
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Example of Monte Carlo “Simulation” Perform the 10 Trials (Exercise #6) Net cash flow is calculated for each of ten iterations (trials) by multiplying the $/barrel selected value by the reserves selected value. But firstly fill in the blanks for the two variable columns.
© by David A. Wood
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Simulation Exercise #6 Sequence of analysis: 1.
Select values for each trial
2.
Use rules established in first table
3.
Calculate net cash flow for each trial
4.
Work out the mean of the net cash flow distribution
5.
Arrange the results into a cumulative frequency distribution
© by David A. Wood
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