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SIS Education
The Fundamentals of Petroleum Economics
COPYRIGHT Copyright © 2005 Schlumberger. All rights reserved.
No part of this document may be reproduced or transmitted in any form, or by any means, electronic or mechanical, including photocopying and recording, for any purpose without the express written permission of Schlumberger. Merak™ is a trademark of Schlumberger. Merak Peep® is a registered trademark of Schlumberger. All other names and trademarks are the property of their respective owners. Released in Canada, March, 2006.
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Contents
Chapter 1: Introduction
1
Course Objectives......................................................................................................................................2 Why Perform Economics on Oil & Gas Projects? ......................................................................................2 Basic Steps for Economic Analysis............................................................................................................2 Basic Cash Flow .................................................................................................................................................... 2 Production Volumes............................................................................................................................................... 3 Prices ..................................................................................................................................................................... 3 Royalties ................................................................................................................................................................ 3 Operating Expenses .............................................................................................................................................. 3 Capital Investments ............................................................................................................................................... 3 Income or Federal Taxes ....................................................................................................................................... 4
Chapter One Conclusion............................................................................................................................4
Chapter 2: Detailed Analysis
5
Components of Economic Analysis ...........................................................................................................6 Production Volumes...................................................................................................................................6 Definitions of Petroleum Fluids and Reserves....................................................................................................... 6 Reserve Classifications.......................................................................................................................................... 7 Proved Reserves ................................................................................................................................................... 7 Unproved Reserves ............................................................................................................................................... 8 Reserve Status Categories .................................................................................................................................... 8
Methods of Estimating Reserves & Production Volumes...........................................................................9 Performance Methods............................................................................................................................................ 9 Volumetric Methods ............................................................................................................................................. 10 Analogy and Statistical Methods.......................................................................................................................... 10 Combination of Methods ...................................................................................................................................... 11 Production Schedules .......................................................................................................................................... 12 Subordinate Products .......................................................................................................................................... 16 Curtailed Wells or Leases .................................................................................................................................... 16
Chapter Exercise 1 ..................................................................................................................................17 Pricing ......................................................................................................................................................19 Benchmarks ......................................................................................................................................................... 19 Base Oil Prices and Adjustments ........................................................................................................................ 21 Base Gas Prices and Adjustments ...................................................................................................................... 22
Interests ...................................................................................................................................................23 Ownership Interests ............................................................................................................................................. 23 Fiscal Regimes .................................................................................................................................................... 23 Canadian Royalties.............................................................................................................................................. 25 Working Interests ................................................................................................................................................. 27 Specifying Reverting Interests ............................................................................................................................. 27 Entering Over-Riding Royalties ........................................................................................................................... 28 Entering Net Profit Interests................................................................................................................................. 28
iii
Contents Interest Definitions ............................................................................................................................................... 28 Basic Interest Equation: ....................................................................................................................................... 30 Calculating Net Revenue Interest (NRI) .............................................................................................................. 31
Chapter Exercise 2 ..................................................................................................................................33 Operating Expenses ................................................................................................................................35 Overhead expenses............................................................................................................................................. 35 Industry Operating Cost Norms ........................................................................................................................... 35
Capital Investments and Depreciation .....................................................................................................36 Intangible Investments ......................................................................................................................................... 36 Tangible Investments and Depreciation .............................................................................................................. 36 Abandonment & Salvage ..................................................................................................................................... 39 Entering Sunk Costs ............................................................................................................................................ 39
Chapter Exercise 3 ..................................................................................................................................41 Taxes .......................................................................................................................................................43 Taxable Income ................................................................................................................................................... 43 Tax Rates............................................................................................................................................................. 44 Negative Taxes .................................................................................................................................................... 45 Book Tax.............................................................................................................................................................. 46
Chapter Exercise 4 ..................................................................................................................................49 Economic Limit.........................................................................................................................................51 Daily Economic Limit............................................................................................................................................ 51
Escalation and Inflation............................................................................................................................52 Inflation: Theory in a nutshell............................................................................................................................... 53 Price Impact on Project Economics ..................................................................................................................... 53 Percentage Escalation ......................................................................................................................................... 54 Monthly Escalation/Inflation ................................................................................................................................. 55 Percent De-escalation.......................................................................................................................................... 56 Inflation ................................................................................................................................................................ 56
Chapter Exercise 5 ..................................................................................................................................57
Chapter 3: Discounted Cash Flow Analysis
59
Introducing Discounting Topics................................................................................................................60 Time Value of Money...............................................................................................................................60 Compounding....................................................................................................................................................... 60 Discounting .......................................................................................................................................................... 61 Net Present Value................................................................................................................................................ 62 Selecting a Discount Rate.................................................................................................................................... 63 Discount Methods and Timing ............................................................................................................................. 64
Chapter Exercise 1 ..................................................................................................................................67 Economic Indicators.................................................................................................................................69 Rate of Return (ROR) .......................................................................................................................................... 69 Discounted Profitability Index (DPI) ..................................................................................................................... 70 Profit to Investment Ratio (PIR) ........................................................................................................................... 70
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Contents Discounted Return on Investment (DROI) ........................................................................................................... 70 Payout Period ...................................................................................................................................................... 71
Chapter Exercise 2 ..................................................................................................................................73 Chapter Exercise 3 ..................................................................................................................................75
References
77
Glossary of Oil & Gas Terminology
79
Petroleum Economics: The Fundamentals
v
Chapter 1: Introduction In this Chapter This chapter includes information for the following topics:
1
Course Objectives
Why Perform Economics on Oil & Gas Projects?
Basic Steps for Economic Analysis
Chapter One Conclusion
Chapter 1: Introduction
Course Objectives This class is designed to give you an understanding of petroleum economics, which can be applied to the use of Peep. We will estimate reserves or production rate forecasts, sensitize on pricing schedules, determine estimated future costs and expenses, select proper tax treatments, and calculate cash flows. From there, we can calculate net present values and profit indicators, then apply risk methods and advanced property analysis.
Why Perform Economics on Oil & Gas Projects? Economic evaluations are prepared to justify exploration projects and development wells, value a property for sale or exchange, make acquisitions, or obtain loans. Management also uses economic evaluations for corporate budgeting, government reporting, valuations of estates, lease bidding, work over justification, equipment purchases, and investor reporting.
Basic Steps for Economic Analysis For this class, we will create a simple cash flow using Excel as the calculation engine. Several screen captures in this document are windows from the Merak Peep application. Peep will not be used in this course but will be introduced in a separate course offering.
Basic Cash Flow A basic cash flow takes a production estimate and applies price to calculate a revenue stream. From this revenue stream, we subtract royalties and operating expenses to achieve an Operating Income. Capital is then removed to create a Before Tax Cash Flow (BTCF). Income taxes are then calculated, and the After Tax Cash Flow (ATCP) is created. Revenue
2
=
Volume ∗ Price
Operating Income =
Revenue – (Royalty + Opcosts)
BTCF
=
Operating Income – Capital
Taxable Income
=
Operating Income – Depreciation
ATCF
=
BTCF – Taxes Payable
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Chapter 1: Introduction
Production Volumes The first step to an economic analysis is the forecasting of production volumes. These values are estimates, created from an extrapolation of past performance, or using a simulator or equation to predict new reservoir performance. Mathematical methods of prediction are usually based on exponential or hyperbolic equations, although sophisticated simulations are sometimes required on new or large reservoirs.
Prices Price is the monetary value received for each unit of oil or gas produced and sold. Secondary byproducts may also be sold from some reservoirs. Prices may be kept at a constant value or change over time. These changes are predictions of how the price will vary based on market conditions. The quality of the hydrocarbon being sold can also impact the price received. In addition, some purchasers impose a surcharge or transportation fee as a means for the producer to share in the cost of marketing the petroleum products.
Royalties Royalty is value deducted from the revenue stream, which usually has no obligation toward covering expenses. It is considered to come “off the top,” after product quality adjustments, but before operating costs or investments are deducted. Many different formulas are used for the calculation of royalties, particularly in Canada.
Operating Expenses Operating expenses are the day-to-day costs of operating a property and maintaining production. Typical charges would be well tender fees, lease electricity, chemicals, water disposal, and overhead. They are normally deductible for income tax purposes.
Capital Investments Capital consists of investments for drilling, exploration, equipment and facilities. Usually broken down into Tangible and Intangible categories. Capital expenditure is used in the calculation of before tax cash flow. Capital depreciation is used in the calculation of taxes payable. Tangible investments are equipment purchases, such as pumping units, pipelines, compressors, and buildings. They often have salvage value. Intangible investments are drilling fees, mud and chemicals, logging, and other non-equipment charges. They typically have no salvage value. Costs to abandon an area or location are sometimes grouped with capital investments. Spent at the end of the life of a project, they may be offset by any recoverable equipment sold as salvage or transferred within the organization.
Petroleum Economics: The Fundamentals
3
Chapter 1: Introduction
Income or Federal Taxes The calculation of taxes is typically performed as a separate calculation from cash flow. This calculation utilizes depreciation rather than capital expenditure to determine taxable income. A tax rate is applied to Taxable Income, taxes are subtracted, and the After Tax Cash Flow is created.
Chapter One Conclusion This chapter was designed to provide a basic understanding of cash flow analysis. No discounting was performed, and the time value of money was not considered. As we build on our understanding of the basic components, we will begin to incorporate escalation, inflation and discounting into the equations.
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Chapter 2: Detailed Analysis In this Chapter This chapter includes information for the following topics:
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Components of Economic Analysis
Production Volumes
Methods of Estimating Reserves
Pricing
Interests
Operating Expenses
Capital Investments and Depreciation
Taxes
Economic Limit
Escalation and Inflation
Chapter 2: Detailed Analysis
Components of Economic Analysis This portion of the class is designed to cover, in detail, the components of economic analysis. Production volumes, pricing considerations, royalties, interests, operating expenses, capital and taxes will be explained and applied. The first step in the analysis is the forecasting of production volumes. For simplicity in basic equations, we will focus on oil production. Gas will be considered as a secondary product to examine ratio forecasting.
Production Volumes Definitions of Petroleum Fluids and Reserves Reserves The term "reserves" means the volumes of crude oil, natural gas, and associated products that can be recovered profitably in the future from subsurface reservoirs.
Petroleum Petroleum is a general term that applies to all naturally occurring mixtures that consist predominantly of hydrocarbons. Petroleum includes natural gas, crude oil, and natural bitumen.
Crude Oil Crude oil is the portion of petroleum that exists in the liquid phase in natural underground reservoirs and remains liquid at atmospheric conditions of temperature and pressure. Crude oil may contain small amounts of nonhydrocarbons produced with the liquids. Crude oil may be subclassified as follows:
extra heavy: less than 10° API
heavy: 10 to 22.3° API
medium: 22.3 to 31.1° API
light: greater than 31.1° API
Natural Gas Natural gas is the portion of petroleum that exists either in the gaseous phase, or in solution in crude oil, in natural underground reservoirs, and is gaseous at atmospheric pressure and temperature. Natural gas may include amounts of nonhydrocarbons. Natural gas may be subclassified as associated or nonassociated gas. Associated natural gas is found in contact with, or dissolved in, crude oil in a natural underground reservoir. Nonassociated natural gas is found in a natural underground reservoir that does not contain crude oil.
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Chapter 2: Detailed Analysis
Solution Gas Natural gas that is dissolved in reservoir oil under reservoir conditions of pressure and temperature and is liberated from solution by reduction in pressure and temperature as the oil is produced through surface gas-oil separation equipment.
Condensate Condensate is a hydrocarbon liquid—consisting mostly of pentanes and heavier substances—that is in the gas (vapor) phase under reservoir conditions and condenses to the liquid phase when the gas is produced through surface separation equipment on a lease operating under ambient conditions.
Reserve Classifications Reserves are estimated volumes of crude oil, condensate, natural gas, natural gas liquids, and associated substances anticipated to be commercially recoverable from known accumulations from a given date forward, under existing economic conditions, by established operating practices, and under current government regulations. Reserve estimates are based on interpretation of geologic and/or engineering data available at the time of the estimate. Reserve estimates generally are revised as reservoirs are produced, as additional geologic and/or engineering data become available, or as economic conditions change. All reserve estimates involve some degree of uncertainty, the relative degree of uncertainty may be conveyed by placing reserves in one of two classifications: proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be sub-classified as probable or possible to denote progressively increasing uncertainty.
Proved Reserves Proved reserves can be estimated with reasonable certainty to be recoverable under current economic conditions. Current economic conditions include prices and costs prevailing at the time of the estimate. Proved reserves may be developed or undeveloped. In general, reserves are considered proved if commercial producibility of the reservoir is supported by actual production or formation tests. In certain instances, proved reserves may be assigned on the basis of electrical and other type logs and/or core analysis Proved reserves must have facilities to process and transport those reserves to market that are operational at the time of the estimate, or there is a commitment or reasonable expectation to install such facilities in the future.
Petroleum Economics: The Fundamentals
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Chapter 2: Detailed Analysis
Unproved Reserves Unproved reserves are based on geologic and/or engineering data similar to that used in estimates of proved reserves, but technical, contractual, economic, or regulatory uncertainties preclude such reserves being classified as proved. They may be estimated assuming future economic conditions different from those prevailing at the time of the estimate. Unproved reserves may be divided into two sub-classifications: probable and possible.
Probable Reserves Probable reserves are less certain than proved reserves and can be estimated with a degree of certainty sufficient to indicate they are more likely to be recovered than not.
Possible Reserves Possible reserves are less certain than probable reserves and can be estimated with a low degree of certainty, insufficient to indicate whether they are more likely to be recovered than not.
Reserve Status Categories Reserve status categories define the development and producing status of wells and/or reservoirs.
Developed Developed reserves are expected to be recovered from existing wells. Improved recovery reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Developed reserves may be sub-categorized as producing or non-producing. Producing Producing reserves are expected to be recovered from completion intervals open and producing at the time of the estimate Non-producing Non-producing reserves include shut-in and behind-pipe reserves.
Undeveloped Undeveloped reserves are expected to be recovered from new wells on undrilled acreage, by deepening existing wells to a different reservoir, or where a relatively large expenditure is required to recomplete an existing well or install production or transportation facilities for primary or improved recovery projects. The basic volumetric method is based on ownership and development maps, geologic maps based on structure and thickness, electric logs and formation tests, reservoir and core data, production performance. Volumetric estimation is most appropriate when no actual performance data exists; you have a depletion drive reservoir, or a gravity drive reservoir.
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Chapter 2: Detailed Analysis
Methods of Estimating Reserves & Production Volumes Methods to estimate reserves are categorized here as:
performance
volumetric
analogy/statistical
Performance Methods Performance methods may be used after a field, reservoir, or well has been on sustained production long enough to develop a trend of pressure and/or production data that can be analyzed mathematically. These procedures are based on the assumption that those factors that control the trends will continue in the future.
Decline Curve Analysis The term "decline curve analysis" refers to the analysis of declining trends of the production of oil or gas — the principal products of oil wells or gas wells, respectively — versus time or versus cumulative production to estimate reserves. After a field, reservoir, or well has been on sustained production long enough for the producing characteristics to develop clearly defined trends, it may be possible to extrapolate these trends to the economic limit to estimate reserves. Performance Trends Frequently, one or more of the "performance indicators" of a well or reservoir exhibits a trend before the production rate of the principal product begins to decline. Depending on reservoir type and drive mechanism, these performance indicators include:
water/oil ratio (WOR)
water/gas ratio (WGR)
gas/oil ratio (GOR)
condensate/gas ratio (CGR)
bottomhole pressure (BHP)
flowing tubing pressure (FTP)
shut-in tubing pressure (SITP).
Production Decline Types Three types of decline curves are commonly used: hyperbolic, harmonic, and exponential.
Material Balance Method The Material Balance method involves estimating the remaining volume in the reservoir based on changes in the reservoir pressure as volumes are produced from the reservoir.
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Chapter 2: Detailed Analysis
Material balance methods may be used to estimate reserves when there is sufficient reservoir pressure and production data to perform reliable calculations of hydrocarbons initially in place and to determine the probable reservoir drive mechanism. For reliable material balance calculations, the reservoir should have reached semisteady state conditions, i.e., pressure transients should have affected the entire initial hydrocarbon accumulation. Reliable application of this method requires accurate historical production data for all fluids (oil, gas, and water), accurate historical bottomhole pressure data, and pressure-volume-temperature (PVT) data representative of initial reservoir conditions.
Volumetric Methods Volumetric methods are used when subsurface geologic data are sufficient for structural and isopachous mapping of the objective field or reservoir. One of the objectives of this mapping is to estimate oil and gas initially in place. The fraction of oil and gas initially in place that is commercially recoverable may be estimated using a combination of analogy and analytical methods.
Volumetric Estimate of Initial Oil in Place N
=
( 7758 ∗ A ∗ H n ∗ Φc ∗ ( ( 1– S w ) ÷ B oi ) ) ∗ E r
where: 7758 =
Barrels per acre foot
N
=
STB of recoverable hydrocarbon
A
=
Area of reservoir in acres
Hn
=
Net reservoir sand thickness in feet
Φc
=
Average effective porosity of sand (decimal fraction)
Sw
=
Percent water saturation
B oi
=
Initial Oil formation volume factor rb/stb (reservoir bbl/stock tank bbl)
Er
=
Recovery efficiency factor (decimal fraction)
Analogy and Statistical Methods Analogy and statistical methods are typically used for undrilled prospects, and to supplement volumetric methods in a field or reservoir’s early stages of development and production. In addition, the method may be used to estimate reserves for undrilled tracts in a partially developed field or reservoir. The methodology is based on the assumption that the analogous field, reservoir, or well is comparable to the subject field, reservoir, or well, regarding those aspects that control ultimate recovery of oil or gas. The weakness of the method is that this assumption’s validity cannot be determined until the subject field or reservoir has been on sustained production.
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Chapter 2: Detailed Analysis
Analogy Methods Analogy methods involve using recovery factors (barrels per acre-foot or cubic feet per acre-foot) or recovery efficiencies (percent recovery) observed in analogous reservoirs to estimate oil and gas recovery from reservoirs being evaluated. Often, per-well recoveries from analogous reservoirs may be used to estimate recoveries from wells or reservoirs under study. For complete validity, analogous and subject reservoirs should be similar regarding:
reservoir structure, especially average dip
depositional environment of reservoir rock
nature and degree of principal heterogeneity
ratio of net to gross pay
petrophysics of the rock-fluid system
reservoir fluid properties and drive mechanism
initial pressure and temperature
spatial relationship between free gas, oil, and aquifer at initial conditions
well spacing
well location
well completion and production method
Seldom, if ever, are all these requirements met, and adjustments usually must be made to compensate for the differences.
Statistical Methods Depending on the amount of data available from the area of interest, statistical methods may be used to supplement analogy methods to estimate reserves. Log-Normal Distribution of Reserves Experts in this field of study have noted that, in a given geologic setting, a lognormal distribution is a reasonably good approximation to the distribution of field sizes, i.e., to the initial reserves of oil or gas in those fields.
Combination of Methods Usually, more than one method is used to estimate reserves. Typically, in the early stages of development and production of a field or reservoir, reserves are estimated using a combination of analogy and volumetric methods. In some areas, it may be feasible to use seismic data to help determine reservoir or field size before there are sufficient well data to prepare reliable geologic maps. As development continues, and the early wells begin to develop pressure and production trends, reserves for those wells may be estimated using performance or decline curve analysis. Reserves for undrilled tracts in a developing area may be estimated by analogy with older wells in the same, or similar, reservoirs in the field.
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Chapter 2: Detailed Analysis
Example An oil company is considering drilling a new prospect. The staff has evaluated available information such as logs, cores, and geological data from nearby wells and estimated the following reservoir parameters: A
=
200 acres
Hn
=
20 feet
Φ
=
12%
Sw
=
35%
B oi
=
1.3 rb / stb
Calculate the original oil in place:
N
=
7758 ∗ A ∗ Hn ∗ Fe ∗ ( (1 – S w) / B oi )
=
7758 ∗ 200 ∗ 20 ∗ .12 ∗ ( (1 – .35) / 1.3 )
=
1,861,920 bbls
If the Recovery Efficiency Factor is 15%, what is the Recoverable Oil? =
1,861,920 ∗ .15
=
279,288 bbls
Production Schedules In order to perform an economic analysis on reserves, how the volume will be produced over time must be known. Common techniques for scheduling production are:
Manual
Exponential
Hyperbolic
Harmonic
Manual Production Manual is a specified amount per year or month or other time period. Year 1 – 25, 000 bbls Year 2 – 23,750 bbls Year 3 – 21,723 bbls
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Chapter 2: Detailed Analysis
Exponential Decline Exponential is a constant percent (loss ratio) per year. This is the most common decline method. It displays as a straight line on semi-log rate vs. time paper. The exponential equation for each day’s production is: Q
=
Q i (1 - D)
t
Where: Q
=
flow rate
Qi
=
Initial flow rate
T
=
Time
D
=
Effective decline rate (decimal % per year)
N
=
Cumulative production
To calculate the cumulative production N at any time use: N
=
(Q - Q i) / l n (1 - D)
Note: If Q and Q i are in bbls/day then multiply equation by 365 days/year to get volume produced: Where: ln
=
natural log of number
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Chapter 2: Detailed Analysis
For example, if the initial rate on a well is 100 bbls per day, and the effective decline rate is 20% per year, the cumulative production during the first year would be: Q
N
=
Q i (1 - D) t
=
100 (1 – 0.20)
=
80 bbls/day
=
(Q - Q i) / ln(1 – D)
=
( ( 80 – 100 ) / ( ln( 1 – .2 ) ) ∗ 365 days/year
=
32,714 bbls
1
The cumulative volume through the second year would be: Q
N
2
=
100 ∗ ( 1 – .2 )
=
64 bbls/day
=
( (64 – 100) / ln(1 – .2) ) ∗ 365 days/year
=
58,886 bbls
Monthly Methodology in Peep Peep actually defaults to a monthly calculation base, rather than annual. You will still have an annual effective decline rate, but you must modify the equation to calculate any cumulative monthly value. Note: This methodology assumes equal number of days is selected. 1/12
Qmonthly
=
Q i (1 – D)
Nmonthly
=
(Q – Q i) / ln(1 – D)
These values are then summed to annual numbers for reporting. For example, if the initial rate on a well is 100 bbls per day, and the effective decline rate is 20% per year, the cumulative production for the first month would be: Q
N
1/12
=
Q i (1 – D)
=
100 – (1 – 0.20)
=
100 (0.9816)
=
98.16 bbls/day
=
(Q – Q i) / ln(1 – D)
=
(98.16 – 100) / ln(0.8) ∗ 365.25
=
-1.842 / -0.223 ∗ 365.25
=
3015.62 bbls
1/12
Effective Versus Nominal Decline The effective decline rate, De , is frequently used in many computer model calculations. The effective decline rate may be in better agreement with actual production records. The nominal decline rate is used in some equations and is normally used in nomographs.
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Chapter 2: Detailed Analysis
The effective decline rate may be expressed: De
=
(Q i – Q) / Q i
Where: Q is measured after one year.
For example, if the production at the beginning of the year was 100 BOPD, and at the end of the year was 80 BOPD, then the effective decline rate is: De
=
(Q i – Q) / Q i
=
(100 – 80) / 100
=
.20 or 20%
The effective decline rate, D e , is related to the nominal decline rate, D n , by the following equations: De
–dn
=
1–e
=
- ln ∗ (1- D e)
And Dn
Effective Rate
Nominal Rate
.095
.10
.181
.2
.259
.3
Hyperbolic and Harmonic Decline With a hyperbolic decline, the value for “D” changes. “D” is the decline rate when the production rate is “Q.” “Di” and “Qi” are the nominal decline rate and production rate when T = 0. However, the concept of annual decline rate is less meaningful when the instantaneous decline rate is continuously changing. For this reason, most software packages use the relationship: Dnominal
= – ln (1 – Deffective)
To calculate the flow rate at any point in time: Q
=
Qi ( 1 + n ∗ Di T )
-1/ n
Where n
=
hyperbolic exponent (typically between 0 and 1.0)
Di
=
initial nominal decline rate
To calculate the cumulative production at any time: N
n
=( Q i / D i ∗ (1 - n) ) ∗ (Q i
1– n
– Q
1– n
) ∗ 365 days/year
Where D i is the nominal decline rate.
Petroleum Economics: The Fundamentals
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Chapter 2: Detailed Analysis
The harmonic decline equation is the same, except that n is always equal to 1.
Subordinate Products Once the primary product values have been calculated, you can then estimate the secondary product production. Condensate, casinghead or associated gas, water, and other liquids are examples of products usually scheduled as ratio values. These values are usually predicted from well tests or production history relationships, and are stated as GOR or Yield. GOR is gas/oil or scf/bbl. Yield is oil/gas or bbl/mmscf. Notice the difference in volume units between GOR and Yield. Ratios may be constant over time, or changing as the characteristics of the reservoir change. The easiest method of predicting a secondary stream using a ratio is to simply multiply the primary product by the value of the ratio in each production period. For example, if the oil volume in Year One is 1000 bbls, and the ratio is 1200 scf/bbl, then what is the gas volume? Gas Volume
=
Oil ∗ Ratio Value
=
1000 ∗ 1200
=
1,200 MSCF
Curtailed Wells or Leases Production of oil or gas from leases or wells may be curtailed for several reasons, including pipeline limitations, limited market, or inability to handle all produced water. Thus, before attempting to analyze production trends, the engineer should determine whether the lease or well in question has been curtailed.
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Chapter 2: Detailed Analysis
Chapter Exercise 1 Production Scheduling Exercise Oil Production: Initial Rate = 1000 bbls/day (instantaneous) Exponential annual decline = 10% effective
Gas Production: Constant Ratio of 1200 scf/bbl
Find, for both oil and gas: 1.
Rate at end of first year
2.
Rate at end of second year
3.
Production for Year One and Year Two
(See next page for solution)
Petroleum Economics: The Fundamentals
17
Chapter 2: Detailed Analysis
Solution to Production Scheduling Exercise 1.
First Year Oil
Q
Q
First Year Gas
2.
Second Year Oil
Q
Q
Second Year Gas
3.
Year One Production
Noil
Ngas
Noil
qi (1 - d)
=
1000 (1 – 0.1)
=
900 bbls/day
=
Q oil ∗ ratio
=
900 ∗ 1200
=
1080 mscf/day
=
1000 (1 – 0.1)
=
810 bbls/day
=
810 ∗ 1200
=
972 mscf/day
=
( (q – q i) / l n (1 – d) ) ∗ 365
=
( (900 – 1000) / l n (1 – 0.1) ) ∗ 365
=
346,430 bbls
=
346,430 ∗ 1200
=
415,716 mscf
=
( (810 – 900) / l n (1 – 0.1) ) ∗ 365
=
311,787 bbls
=
311,787 ∗ 1200
=
374,144 mscf
Year Two Production Ngas
18
t
=
1
2
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Chapter 2: Detailed Analysis
Pricing Every economic evaluation needs price forecasts for each product. This value is used to calculate the revenue in each time period. Most companies create price forecasts for the various locations where products are sold, and then distribute the forecasts for use in all evaluations. These are usually called base prices and the imperial units are $/bbl for oil and $/MMBTU or $/MSCF for natural gas. Byproducts may also be sold in $/bbl or $/gallon. Prices are impacted by many factors. Quality of hydrocarbon, politics, supply available, transportation surcharges, and proximity to market issues are usually handled with price adjustments. Adjustments may be reductions (downward) or premiums (upward). A study by WTRG Economics on the history of oil prices is listed as a reference. One of the main points brought out in this analysis is the fact that oil prices have maintained an average price of $19.00US plantgate when adjusted for inflation (in 1996 dollars). History indicates that prices do spike due to specific events in our world but then return to a consistent price, adjusted for inflation, over time.
Benchmarks West Texas Intermediate West Texas Intermediate (WTI) crude oil is of very high quality and is excellent for refining a larger portion of gasoline. Its API gravity is 39.6 degrees (making it a “light” crude oil), and it contains only about 0.24 percent of sulfur (making a “sweet” crude oil). This combination of characteristics, combined with its location, makes it an ideal crude oil to be refined in the United States, the largest gasoline consuming country in the world. Most WTI crude oil gets refined in the Midwest region of the country, with some more refined within the Gulf Coast region. Although the production of WTI crude oil is on the decline, it still is the major benchmark of crude oil in the Americas. WTI is generally priced at about a $2-per-barrel premium to the OPEC Basket price and about $1-per-barrel premium to Brent, although on a daily basis the pricing relationships between these can vary greatly. WTI is priced at Cushing Oklahoma.
Brent Blend Brent Blend is actually a combination of crude oil from 15 different oil fields in the Brent and Ninian systems located in the North Sea. Its API gravity is 38.3 degrees (making it a “light” crude oil, but not quite as “light” as WTI), while it contains about 0.37 percent of sulfur (making it a “sweet” crude oil, but again slightly less “sweet” than WTI). Brent blend is ideal for making gasoline and middle distillates, both of which are consumed in large quantities in Northwest Europe, where Brent blend crude oil is typically refined. However, if the arbitrage between Brent and other crude oils, including WTI, is favorable for export, Brent has been known to be refined in the Petroleum Economics: The Fundamentals
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United States (typically the East Coast or the Gulf Coast) or the Mediterranean region. Brent blend, like WTI, production is also on the decline, but it remains the major benchmark for other crude oils in Europe or Africa. For example, prices for other crude oils in these two continents are often priced as a differential to Brent, i.e., Brent minus $0.50. Brent blend is generally priced at about a $1-per-barrel premium to the OPEC Basket price or about a $1-per-barrel discount to WTI, although on a daily basis the pricing relationships can vary greatly.
NYMEX Futures The New York Mercantile Exchange (NYMEX) futures price for crude oil, which is reported in almost every major newspaper in the United States, represents (on a perbarrel basis) the market-determined value of a futures contract to either buy or sell 1,000 barrels of WTI or some other light, sweet crude oil at a specified time. Relatively few NYMEX crude oil contracts are actually executed for physical delivery. The NYMEX market, however, provides important price information to buyers and sellers of crude oil in the United States (and around the world), making WTI the benchmark for many different crude oils, especially in the Americas. Typically, the NYMEX futures prices tracks within pennies of the WTI spot price described above, although since the NYMEX futures contract for a given month expires 3 days before WTI spot trading for the same month ceases, there may be a few days in which the difference between the NYMEX futures price and the WTI spot price widens noticeably.
OPEC Basket Price For a discussion of crude oil pricing in general, and of the OPEC Basket price in particular. OPEC collects pricing data on a "basket" of seven crude oils, including: Algeria's Saharan Blend, Indonesia's Minas, Nigeria's Bonny Light, Saudi Arabia's Arab Light, Dubai's Fateh, Venezuela's Tia Juana Light, and Mexico's Isthmus (a non-OPEC crude oil). OPEC uses the price of this basket to monitor world oil market conditions. As mentioned above, because WTI crude oil is a very light, sweet (low sulfur content) crude, it is generally more expensive than the OPEC basket, which is an average of light sweet crude oils such as Algeria's Saharan Blend and heavier sour crude oils (with high sulfur content) such as Dubai's Fateh. Brent is also lighter, sweeter, and more expensive than the OPEC basket, although less so than WTI. Since OPEC has (at least informally) tied its production management activity to the goal of maintaining the OPEC Basket price between $22 and $28 per barrel, market watchers now pay close attention to this oil price indicator.
Henry Hub Natural Gas The Henry Hub is the largest centralized point for natural gas spot and futures trading in the United States. The New York Mercantile Exchange (NYMEX) uses the Henry Hub as the point of delivery for its natural gas futures contract. The NYMEX gas futures contract began trading on April 3, 1990 and is currently traded 72 months into the future. NYMEX deliveries at the Henry Hub are treated in the same way as cashmarket transactions.
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Many natural gas marketers also use the Henry Hub as their physical contract delivery point or their price benchmark for spot trades of natural gas. The Henry Hub is owned and operated by Sabine Pipe Line, LLC, which is a wholly owned subsidiary of ChevronTexaco. The Sabine Pipe Line starts in eastern Texas near Port Arthur, runs through south Louisiana, not far from the Gulf of Mexico, and ends in Vermillion Parish, Louisiana, at the Henry Hub near the town of Erath. The Henry Hub is physically situated at Sabine’s Henry Gas Processing Plant. The Henry Hub interconnects nine interstate and four intrastate pipelines, including: Acadian, Columbia Gulf, Dow, Equitable (Jefferson Island), Koch Gateway, LRC, Natural Gas Pipe Line, Sea Robin, Southern Natural, Texas Gas, Transco, Trunkline, and Sabine’s mainline. Collectively, these pipelines provide access to markets in the Midwest, Northeast, Southeast, and Gulf Coast regions of the United States.Sabine currently has the ability to transport 1.8 billion cubic feet per day across the Henry Hub. Relative to the total U.S. lower 48 average daily gas consumption of 60.6 billion cubic feet per day in 2000,the Henry Hub can handle up to 3.0 percent of average daily gas consumption. Approximately 49 percent of U.S. wellhead production either occurs near the Henry Hub or passes close to the Henry Hub as it moves to downstream consumption markets. This is based on 2000 production levels reported for the Gulf of Mexico and the onshore Louisiana and Texas regions encircling the Gulf of Mexico. Other price points include: AECO, Sumas and Chicago.
Base Oil Prices and Adjustments Oil prices are normally quoted in imperial as $/bbl, or in metric as $/m3, some countries may use a mass measurement such as $/ton. Purchasers will post prices based on location and quality, relating back to industry-accepted benchmarks as described above.
This Peep example shows a constant base price of $18.65 per barrel with a downward adjustment of $1.3987, for a net price of $17.2512 per barrel.
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Base Gas Prices and Adjustments Gas prices can be stated in imperial as $/mscf or $/MMBTU. Most purchasers list gas prices as $/MMBTU. BTU, or British Thermal Unit, is the amount of energy required to raise the temperature of one cubic foot of water one degree Fahrenheit. The metric heat energy equivalent is refered to as $/GJ or gigajoule. A heating standard measurement unit of 1000 is used to convert the $/MMBTU price to $/mcf. If the gas is richer, contains liquids such as propane or butane, then the BTU value will be greater than 1000. The inverse holds true for gas that contains other components, such as helium or nitrogen, in the stream. This factor is used to adjust the gas price received, and is in addition to adjustments for transportation surcharges or pipeline fees. To adjust a gas price for a BTU value other than 1000, divide the factor by 1000. The resulting number is then multiplied by the $/MMBTU price to result in a $/mscf. Gas Price $/mcf =
22
$/MMBTU ∗ (BTU / 1000)
=
2.00 ∗ (1120 / 1000)
=
2.00 ∗ 1.120
=
$2.24/mscf
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Interests Ownership Interests The ownership of petroleum resources plays a critical role in the calculation of petroleum economics. Whoever owns the mineral rights can, and usually does, extract a royalty from the resource Producer. Royalties are usually calculated based on the revenue, with no regard for profitability. There are two basic types of Resource Ownership:
Private Ownership
State Ownership
Private Ownership When a person or corporation holds the mineral rights, they charge the producer a leasehold or freehold royalty. The terms of this royalty are usually negotiated between the leaseholder and the producer. The royalty is usually expressed as a fixed percentage of production or revenue. Private ownership of mineral rights is most common in the United States. However, there are also examples of this found elsewhere (e.g. railway lands in Canada).
State Ownership Most of the world’s petroleum resources are owned by the country in which they exist. The government of that country then takes the responsibility for managing the resource.
Fiscal Regimes One tool that governments use to manage their natural resources is the fiscal regime. The fiscal regime dictates who owns the resource once it is produced (i.e. brought to the surface) and how the revenue generated by the production of the resource is allocated. There are two main types of fiscal regimes:
production sharing contracts
concessionary regimes
Concessionary regimes (also know as royalty/tax regimes) are more typical in western or developed nations, while production sharing contracts (PSC) are more commonly seen in developing nations.
Production Sharing Contracts Production sharing contracts are characterized by the following:
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under production sharing contract (PSC) systems, the government retains ownership of the hydrocarbons.
companies can reclaim costs incurred from production revenues, subject to constraints.
oil companies negotiate a right to a share of the production revenues (profit split).
companies may also pay corporate tax on profit share.
Production Sharing Contracts are often negotiated and calculated on a field or block of wells
Production Sharing Regime Flowchart
Concessionary Concessionary contracts are characterized by the following:
individuals or companies buy the right to extract and sell mineral resources (a concession)
the state owns resources but transfers title to the licensee at the wellhead
licensee receives all sales revenues in the first instance
licensee company is then liable for royalties and taxes (examples of concessionary systems include the UK, the United States and Canada)
royalties are payable on value of oil/gas produced – irrespective of project viability or profitability
usually have specific petroleum taxes — e.g. UK Petroleum Revenue Tax (PRT)
taxes usually based on profit-sensitive basis
Concessionary Regime Flowchart
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Canadian Royalties Canada and all of its petroleum producing provinces use concessionary fiscal regimes. There are many different royalty regimes in Canada. The Federal Government has a Frontier regime, and each of the provinces have their own unique regimes. In most provinces there are separate regimes for oil and gas, different regimes in various geographical and/or geological areas, different regimes for varying types of oil (heavy, light) and gas (solution, non-solution) as well as incentives for exploration and low productivity wells. The dozens of royalty regimes applied in Canada will be broken down into two general types for the example purposes.
Western Canadian Regimes Most of the regimes of the major petroleum producing provinces (Alberta, B.C. and Saskatchewan) use a combination of price, production and vintage to calculate the royalty rate, and hence royalties. Vintage refers to the date on which the well was drilled. From time to time, governments change the royalty regime. Any wells drilled on or after the regulated date are considered to be of a different vintage. Price sensitivity is built into most royalty regimes in Western Canada. If the price of oil or gas goes above a certain level, a higher royalty percentage is levied. In order to facilitate this calculation, governments publish Reference and Select Prices on a monthly basis. Reference Prices reflect what is considered a fair market value for the product and Select Prices are threshold above which additional royalty is payable (i.e. if the Reference Price is less than the Select Price, the minimum rate is charged). Select Prices are adjusted yearly for inflation. Production sensitivity is also common in these types of regimes. The lower the production rate is for a well in a given month, the lower the calculated royalty percentage. Even in regimes where the basic royalty rate is not sensitive to production rates, there is often a Low Productivity Allowance. This is to encourage producers to continue production instead of shutting a well in after production has declined significantly.
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Valuing the Crown’s Share The royalty rate (or percentage) indicates the portion of the production that is owned by the Crown. Typically, the Crown will take payment in cash in lieu of the actual production. For this reason the Crown’s share needs to be given a value. This value is determined by the Reference Price, which is not necessarily the same as the Selling Price received by the Producer.
When calculating royalties, it is important to use reasonable Reference and Select Prices. Also, because the Crown receives cash in lieu of production for royalties, it provides the producer with allowances to cover certain costs involved in the gathering and processing its share of the production. Example – Alberta Gas Royalties This is a simplified example meant to illustrate the equations involved in calculating Gas royalties in Alberta. To accurately determine the Gas royalty percentage, the Gas stream would have to be broken down into its individual Instream Components (i.e. Methane, Ethane, Propane, Butane, Pentanes) each of which have a separate royalty equation.
Gas Crown Royalties in Alberta are dependent upon:
Gas Reference Price
Gas Select Price (for New and Old gas)
Gas Vintage (New or Old)
Royalty % = 15(Select Price) + 40(Reference Price – Select Price) ________________________________________________________________________________________________
Reference Price
The minimum Crown royalty rate for New or Old Gas is 15%. The maximum Crown royalty rate for New Gas is 30% and Old Gas is 35%.
Frontier Royalties Regions of Canada that calculate royalties based (sometimes loosely) on the Federal “Frontier” regime include: Frontier Lands in the Territories, Offshore production on the East Coast and Oil Sands production in Alberta. These regimes consist of various “Tiers” of royalties that change over time. Early in the production cycle a low royalty rate is applied which then increases over time. One of the significant events that influences the royalty rate is Payout. Example – Alberta Oil Sands
Pre-Payout Royalty The pre-payout royalty is 1% of gross revenues until project payout.
Post-Payout Royalty At project payout the royalty payable is the greater of 25% of net revenue and 1% of annual gross revenue. Post-payout royalties are limited to zero.
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Payout occurs when the Adjusted Cumulative Cost Base (ACCB) equals the Cumulative Adjusted Gross Revenue (CAGR)
Return Allowance Return Allowance is added to the Adjusted Cumulative Cost Base to extend project payout. The Long Term Government Bond Rate is applied to the following equation to determine the Return Allowance value: (Adjusted Cumulative Cost Base - Return Allowance from Previous Period) (Cumulative Adjusted Gross Revenue)
Working Interests The operating interest, also known as the working interest (WI), is the portion of lease expenses that are paid by the working partner. It can be broken down by product or capital type. The product revenues, operating costs, and overhead are multiplied by the Operating Interest to determine your working interest share of each. Some lease agreements specify a change in the interest positions when certain hurdles or triggers are met. These changes in operating interests and royalties are referred to in Peep as interest reversions. All the interest positions in Peep can be set to change or revert. The default is that no reversion is specified. Up to three reversion interests can be specified for each interest field in a case. A reversion point or trigger can be specified four different ways:
capital amount to be recovered
oil volume to be produced
gas volume to be produced
date to be reached
Specifying Reverting Interests All the interest positions in Peep can be set to change or revert. The default is that no reversion is specified. Up to three reversion interests can be specified for each interest field in a case. A reversion point or trigger can be specified in different ways:
a capital amount to be recovered (percentage or dollar amount)
a given volume of a specific product
a date to be reached
Each of the reversion trigger types is described in the table below: Enter this …
To revert interests …
Payout - % of All Capital
Before-tax cash flow reaches a given percent of all the capital in the case
Reversion Capital Volume
Before-tax cash flow reaches a specified amount When production total for a specific product reaches a specified amount
Date
When a given date is reached
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Notes about reverting interests:
Peep displays the calculated reversion points on all summary reports.
If you do not enter any reversion triggers, Peep does not revert.
You can enter a reversion with more than one trigger. Peep reverts at the first occurrence. For example, you can enter a reversion to occur at 200% of all the capital in the case or in January, 1998. Peep reverts at whichever trigger occurs first.
Entering Over-Riding Royalties An over-riding royalty (ORR) is a burden that amounts to a given percentage of the total lease production. When you are receiving an ORR, you often do not have a working interest in production. All burdens are multiplied by the ORR/Burden interest % defined under the Lease tab (Interests side tab). To evaluate a burden interest, input a receivable burden in the Peep case. Then set the operating interest to 0 (zero), and set the ORR/burden interest to the appropriate value. The program will calculate the value of the burden.
Sliding Scale ORR A sliding scale royalty is a fraction of the monthly production that follows a sliding scale of the crown’s percentage, with a maximum and a minimum limit set. Typically, the fraction is set to 1/150 (5 to 15 percent). Peep defaults to a 5% minimum and a 15% maximum, using 150 as the divisor. Essentially, the ORR is a percentage equal to 1/150 of monthly production per well but is no more than 15% and no less than 5%.
Entering Net Profit Interests A net profit interest (NPI) is similar to an over-riding royalty except that an NPI is paid when the operating income is positive. (The operating income is the total revenue after royalties and operating costs are deducted.) Enter positive values if you are paying the NPI; enter negative values if you are receiving the NPI. An NPI can also be paid only when the before tax cash flow is positive (that is, after royalties, operating costs, and capital costs are paid). If the NPI is based on cash flow, you will need to create a new burden variable in your Peep model.
Interest Definitions Working Interest: Working Interest is the portion of lease expenses that are paid by the working partner. If a company has a 50% working interest they would normally be obligated to pay 50% of all operating expenses and capital expenditures. They would normally also receive 50% of the net revenue. Capital Interest: The portion of the capital investment a company is obligated to pay. Typically capital interest and working interest will be the same, but not always.
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Net Revenue Interest: This is a company’s portion of revenue less all royalty interest paid. Royalty Interest: A retained interest (usually by the land owner or mineral rights holder) deducted from a working interest and having no obligation toward paying operating expenses or capital expenditures. Overriding Royalty: This is an additional royalty created out of the working interest and having the same term as this interest. This form of royalty may also become part of a farm-out agreement. Overrides are normally less than 10% of the lease interest. Net Profits Interest: An additional interest that could be paid or received. A net profits interest is normally taken out of the net income stream. Occasionally it is deducted from cash flow. Commonly the NPI will be in the 5 to 10% range.
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Basic Interest Equation: Net Revenue Interest = Working Interest ∗ (1 - Total Royalty) + Overrides Received
Example: The Interest Pie Chart Assume: Working Interest = 100% Leasehold Royalty = 12.5% Overriding Royalty = 5%
Interest Pie ORR 5.00%
Leasehold Royalt y 12.50%
NRI 82.50%
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Calculating Net Revenue Interest (NRI) Assume four equal partners (i.e. WI = 25% each) Leasehold Royalty = 12.5% Overriding Royalty = 7.5% Therefore, the working interest pie looks like:
Working Interest Pie
25%
25%
25%
25%
And the NRI pie looks like:
NRI Pie
NRI 20.00%
ORR 7.50% LH Roy 12.50%
NRI 20.00%
NRI 20.00% NRI 20.00%
Where:
NRI = 0.25 ∗ (1 – (0.125 + 0.075)) + 0 = 0.20
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Chapter Exercise 2 Working Interest Exercise What is the revenue share of a 75% working interest if you must pay a 12.5% Net ORRI, and Crown Royalties totalling 25%? Calculate the working interest revenue stream below, then subtract the royalty shares. The result is the Net Revenue Interest (NRI).
Year
Price
Prod.
1
$2.00
500
2
$2.00
450
3
$2.10
400
4
$2.205
370
.5
$3.00
300
6
$3.30
260
WI Revenue
ORRI
Crown
Net Revenue
Total
(See next page for solution)
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Solution to Working Interest Exercise Year 1 2 3 4 5 6 Total
34
Price 2.000 2.000 2.100 2.200 3.000 3.300
Prod. WI Revenue 500 750.00 450 675.00 400 630.00 370 610.50 300 675.00 260 643.50 2280 3984.00
ORRI 93.75 84.38 78.75 76.31 84.38 80.44 498.00
Crown Net Rev. 187.50 468.75 168.75 421.88 157.50 393.75 152.63 381.56 168.75 421.88 160.88 402.19 996.00 2490.00
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Operating Expenses Ongoing costs related to the day-to-day operations of a well, lease, or field, is usually called Operating Expenses. They are identified with a specific property and might include lease maintenance, treating fluids, general repairs, fuel and electricity, and secondary or enhanced recovery operations. Common methods of scheduling operating costs are:
Variable ($/bbl or $/mcf)
Well Count ($/well/month or $/well/year)
Fixed (M$/month or M$/year)
Overhead expenses Overhead type charges such as salaries and office costs are usually grouped with operating expenses in a basic cash flow analysis. In Peep they can be charged as a percentage of operating or capital costs. The industry varies on their practice of burdening projects with overhead costs. Some corporations have a standard rate, which is applied to all projects while others ignore it completely.
Industry Operating Cost Norms It is difficult to provide an average operating cost for a producer. Operating costs vary dramatically dependent on many factors such as:
type of product: oil or gas
artificial lift requires power to generate
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sour or sweet: sour gas is expensive to sweeten
distance to processing facility factor into gathering costs
onshore or offshore production has a major impact on opcosts
remote location with no road access requires helicopter costs to access
remote location may require an oil well’s production to be trucked rather than shipped through a pipeline
completion zone: the deeper the well, the more costly maintenance is on the well
well maturity: a mature oil well may be producing significant quantities of water requiring disposal
Capital Investments and Depreciation Capital is the amount of money invested in new exploration or on-going development projects for drilling, equipment and facilities. Usually broken down into tangible and intangible categories. capital expenditure is used in the calculation of before-tax cash flow. Capital depreciation is used in the calculation of taxes payable. Sometimes referenced as depreciation, depletion and amortization (DD&A), capital recovery can be different based on corporation size, and is dependent on the laws of each country.
Intangible Investments Intangible investments are drilling fees, mud and chemicals, logging, and other nonequipment charges. They are normally considered expensed or written off in the year spent and have no recoverable salvage value. Some types of intangible investments can be included in cost recovery in certain fiscal tax regimes.
Tangible Investments and Depreciation Tangible investments are equipment purchases, such as pumping units, pipelines, compressors, and buildings. Capital of this type is depreciated over time. Depreciation may be defined as the lessening in value of a physical asset with the passage of time. With the possible exception of land, the consideration is characteristic of all physical assets. Depreciation reduces taxable income by charging a part of the cost against each year’s income. There are three main methods for grouping DD&A:
36
Straight Line
Declining Balance
Unit of Production Depletion
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Straight Line This depreciation method deducts an equal increment each year over the life of the property. For example, a tank battery has an initial cost of $100,000, and will have a useful life of 10 years. The basic straight line equation is Annual Depr. Amt.
=
Initial Cost / Useful Life
=
$100,000 / 10
=
$10,000 / year for 10 years
Accelerated Recovery Accelerated methods for computing depreciation apportion larger amounts of the depreciable investment to earlier years in the life of the equipment. You get a faster tax write-off or and earlier availability of money. The two most common methods for accelerated recovery are Declining Balance and Unit of Production Depletion. How and when these two methods are used is dependent on governmental regulations and standards for book tax or financial reporting.
Declining Balance Method In the declining balance method, a depreciation rate is applied to the undepreciated balance of the investment each year. Yearly Depr. = Depr. Balance ∗ Yearly Rate
For example, assume the same 100 M$ investment as the 10 year life of the straightline method. The recovery schedule would be: Year One
100∗0.20
$ 20.00
Year Two
(100-20) ∗ 0.20
80∗0.20
$ 16.00
Year Three
(80-16) ∗0.20
64∗0.20
$ 13.00
Year Four
(64-13.00) ∗ 0.20
51.00∗0.20
$ 10.20
Year Five
(51-10.20) ∗0.20
40.80∗0.20
$ 8.16
Year Six
(40.8-8.16) ∗0.20
32.64∗0.20
$ 6.53
Year Seven
(32.64-6.53) ∗0.20
26.11∗0.20
$ 5.22
Year Eight
(26.11-5.22) ∗0.20
20.89∗0.20
$ 4.18
Year Nine
(20.89-4.18) ∗0.20
16.71∗0.20
$ 3.34
Year Ten
(16.71-3.34) ∗0.20
13.37∗0.20
$ 2.67
The remaining unrecovered balance is either handled as salvage or written off in the next year. Peep takes the balance in the next year. If the economic life of the property is less than the years of recovery, then all unrecovered balances are written off in the last year of the property.
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Unit of Production Depletion Method The Unit of Production method is used to depreciate lease and well equipment that has a life largely controlled by the physical depletion of reserves. It is a similar calculation to that of cost depletion. The amount to be deducted each year may be expressed as: (Cost or Balance – Depreciation) ∗ (Yearly Production / Remaining Reserves)
For example, there is an initial investment of 1000 M$ to recover 200 MBBLS. Using a simple exponential decline, the depreciation in the first few years would be: Year
Yearly Prod
Remaining Reserves
Yr.Prod. / Rem. Resv
Yearly Depreciation
Depreciation Balance
1
50
200
0.250
250
750
2
40
150
0.267
200
550
3
30
110
0.273
150
400
4
20
80
0.250
100
300
5
10
60
0.167
50
250
This depletion method is most often used when recovering lease purchases or when calculating the book or financial tax value of a property.
Other Methods In some jurisdictions, other methods are used for depreciation. Most commonly, a defined schedule assigning factors to each year following the investment. Note that none of these depreciation values have financial meaning, as the investment is actually paid as a lump sum and that is where it affects cash flows. DD&A is purely an economic way of accounting for the investments for company reports and tax calculations.
Canadian Sample Depreciation Types Capital Type
Examples
Method
Capital Cost Allowance (CCA) Class 41
Tangible investments
25% Declining Balance with ½ year rule
Canadian Exploration Expense (CCE)
Intangible exploratory costs (drilling, geophysical, etc.)
Expense
Canadian Development Expense (CDE)
Intangible development costs (drilling, etc.)
30% Declining Balance
Canadian Oil and Gas Property Expense (COGPE)
Purchase of oil and gas properties
10% Declining Balance
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Abandonment & Salvage Capital categorized as abandonment receives no capital depreciation. The abandonment entry in a Peep case gives you the ability to schedule costs that are tagged to the economic limit of the case. Capital categorized as salvage results in no change to the undepreciated capital pools. The salvage entry in a Peep case gives you the ability to schedule revenue that is tagged to the economic limit of the case.
Entering Sunk Costs Sunk costs are costs that have typically occurred prior to the project evaluation. The costs are considered spent and therefore are not included in the economics of a go forward decision. These sunk costs though are typically included for purposes of reducing taxes payable specific to the project. If capital has already been spent for a case, you may enter the amount prior to the evaluation date for the case. Capital entered in this manner will be treated as a tax pool. Depreciation will be calculated, but the expenditure will not enter the beforetax cash flow.
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Chapter Exercise 3 Capital Depreciation Exercise Complete the following Depreciation schedule. Investment: $1,000 Straight Line: 10 years Declining Balance: 25% Year
Production
1
100.00
2
90.00
3
81.00
4
72.90
.5
65.61
6
59.05
7
53.14
8
47.83
9
43.05
10
38.74
Total
651.32
StraightLine
Declining Balance Balance
Declining Balance Depreciation
Portion of Total Production
UOP Depreciation
(See next page for solution)
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Solution to Capital Depreciation Exercise Year 1 2 3 4 5 6 7 8 9 10 Total
42
Production Straight Line 100.00 100 90.00 100 81.00 100 72.90 100 65.61 100 59.05 100 53.14 100 47.83 100 43.05 100 38.74 100 651.32 1000
Declining Declining Balance Balance Balance Depreciation 1000.00 250.00 750.00 187.50 562.50 140.63 421.88 105.47 316.41 79.10 237.30 59.33 177.98 44.49 133.48 33.37 100.11 25.03 75.08 18.77 943.69
Remaining Reserves 651.3200 551.3200 461.3200 380.3200 307.4200 241.8100 182.7600 129.6200 81.7900 38.7400
Prod/ UOP Depr UOP Reserves Balance Depreciation 0.1535 1000.00 153.53 0.1632 846.47 138.18 0.1756 708.28 124.36 0.1917 583.92 111.93 0.2134 472.00 100.73 0.2442 371.26 90.66 0.2908 280.60 81.59 0.3690 199.01 73.44 0.5263 125.58 66.10 1.0000 59.48 59.48 1000.00
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Chapter 2: Detailed Analysis
Taxes Any activity that generates revenue, almost universally, pays tax to a government. Taxes may be paid to municipal, state, provincial or federal governments. Taxes are usually payable at a corporate level and are based on the profitability of that corporation. Taxes payable are calculated based on taxable income and an applicable tax rate.
Taxable Income Taxable Income is not the same as Before-tax Cash Flow or Operating Income. Taxable Income is defined as: Taxable Income = Taxable Revenues – Eligible Deductions Typically this means: Taxable Income = Revenues – OpCosts – Burdens – Depreciation
Depending on the tax regime, expenses such as interest may be deducted from the Taxable revenue. Note: The major difference between BTCF and Taxable Income is that while Capital Expenditures are used to calculate BTCF, Capital Depreciation is used for calculating Taxable Income.
Taxable Income in the Canadian Resource Sector In Canada, a Resource Allowance is calculated and deducted from the Federal Taxable Income, however Crown Royalties are not deductible. How Resource Allowance and Crown Royalties are deductible from Provincial Taxable Income varies from province to province. The Resource Allowance is calculated as follows: Resource Allowance = 0.25 ∗ (Resource Income – Resource Operating Costs (field and well expenses) – Tangible Capital and Gathering Capital Depreciation (CCA) – Indian Royalties – Freehold Production Royalties)
Petroleum Economics: The Fundamentals
43
Chapter 2: Detailed Analysis
It has been proposed in the 2003 Federal Budget that Resource Allowance and Crown Royalties be deductible according to the following schedule: Year
Deductible % of Resource Allowance
2003 2004 2005 2006 2007
90 75 65 35 0
Deductible % of Crown Royalties 10 25 35 65 100
Tax Rates The Tax Rate represents the amount of the Taxable Income that is owed as tax. This Tax Rate may be expressed as a simple percentage or may involve more complicated calculations. The Tax Rate may change with time, income, price or production levels.
Tax Rates in the Canadian Resource Sector The 2003 Federal Budget has the following schedule of Federal Tax Rates. As of 2004, the Provincial Tax Rate in Alberta is 11.5. Year 2003 2004 2005 2006 2007
44
Federal Resource Tax Rate 28.12 27.12 26.12 24.12 22.12
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Chapter 2: Detailed Analysis
Example Tax Calculation CASH FLOW STATEMENT 1
2
3
4
100 240 10
100 --10
100 --10
100 --10
Before Tax Cash Flow Tax Payments
-150 9
90 9
90 9
90 9
After Tax Cash Flow
-159
81
81
81
Year Revenue Capital Expenditure Operating Cost
TAXABLE PROFIT / LOSS
Tax Rate: 30%
1
2
3
4
Total
100 60 10
100 60 10
100 60 10
100 60 10
240
Taxable Profit
30
30
30
30
Tax Payments
9
9
9
9
Year Revenue Capital Depreciation Operating Cost
Negative Taxes Sometimes the amount of Tax calculated turns out to be negative. However, you would not actually get money from the government in this situation. How should this be handled?
Stand-Alone Tax If taxes were being calculated while modeling an entire taxable entity (i.e. the entire Corporation), any negative tax would have to be carried forward. In each time period with negative tax, the tax would be set to zero and the negative amount would be carried forward as a ‘pool’ to be used to reduce any future positive taxes.
Petroleum Economics: The Fundamentals
45
Chapter 2: Detailed Analysis
Example: Year
Tax calculated
Carry forward
Tax payable
1
-100
100
0
2
-50
150
0
3
100
50
0
4
500
0
450
Flow-through Tax If taxes are being calculated on a project-by-project basis, any negative tax could be used to offset positive taxes payable by other projects in the company. Therefore, including the negative tax in the cash flow calculations of a project more accurately represents the project’s impact on the economics of the entire company.
Book Tax Book tax accounting methods are not designed to report the cash generation potential of a property. Rather, book tax valuations are designed to report the current accounting value of the asset. Generally this is the original cost less any depreciation, depletion and amortization charged to date. Book profit is the net income available after cash costs (opcosts, taxes) and non-cash costs (DD&A). Original costs of projects typically use the Unit of Production Depletion method for recovery. That is, you cannot take more depreciation value in a year than that fraction which is equal to the current production / total reserves.
Unit of Production Depletion Method The Unit of Production method is used to depreciate lease and well equipment that has a life largely controlled by the physical depletion of reserves. It is a similar calculation to that of cost depletion. The amount to be deducted each year may be expressed as: (Cost or Balance – Depreciation) ∗ (Yearly Production / Remaining Reserves)
For example, there is an initial investment of 1000 M$ to recover 200 MBBLS. Using a simple exponential decline, the depreciation in the first few years would be:
46
Year
Yearly Prod
Remaining Reserves
Yr.Prod. / Rem. Resv
Yearly Depreciation
Depreciation Balance
1
50
200
0.250
250
750
2
40
150
0.267
200
550
3
30
110
0.273
150
400
4
20
80
0.250
100
300
5
10
60
0.167
50
250
6
10
50
0.20
50
200
7
10
40
0.25
50
150
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Chapter 2: Detailed Analysis
As the reserve base declines, the fraction that can be recovered changes proportionately. If new reserves are credited to the property, then the deductible fraction will change. Normally, only Proven Reserves can contribute to the book tax reserve base. In other words, production that can be economically and realistically recovered will contribute to the book value. This type of reporting tends to show maximum shareholder value that is gained with each new property that is completed, since the recovery of development costs is generally spread out over a longer period of time. For example, compare a five-year Straight Line recovery to UOP Depletion. Use the same 1000 M$ original investment and 200 MBBLS. Assume a $20 oil price.
Year
Yearly Prod
Revenue
5 Yr SL Depr.
1
50
1000
200
2
40
800
3
30
4
Yearly Depl
Book Profit for Depl
800
250
750
200
600
200
600
600
200
400
150
450
20
400
200
200
100
300
5
10
200
200
0
50
150
6
10
200
0
200
50
150
7
10
200
0
200
50
150
Petroleum Economics: The Fundamentals
Book Profit for SL
47
Chapter 2: Detailed Analysis
48
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Chapter 2: Detailed Analysis
Chapter Exercise 4 Tax Exercise Complete the following chart. Capital is depreciated using 5 year straight-line Tax Rate is 20% Year
Revenue
OpCost s
Capital
1
100
20
5000
2
200
20
3
5000
20
4
3000
20
5
2000
20
Deprec.
BTCF
FlowThrough Tax
StandAlone Tax
FlowThrough ATCF
StandAlone ATCF
(See next page for solution)
Petroleum Economics: The Fundamentals
49
Chapter 2: Detailed Analysis
Solution to Tax Exercise
50
Year
Revenue
OpCosts
Capital
Depr.
BTCF
FlowThrough Tax
StandAlone Tax
1
100
20
5000
1000
2
200
20
3
5000
4 5
FlowThrough ATCF
StandAlone ATCF
-4920
-184
0
-4736
-4920
1000
180
-164
0
344
180
20
1000
4980
796
448
4184
4532
3000
20
1000
2980
396
396
2584
2584
2000
20
1000
1980
196
196
1784
1784
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Chapter 2: Detailed Analysis
Economic Limit Once you have a revenue stream associated with operating and capital expenses, you can determine an economic limit for the project. Economic limit usually refers to the point in time that continued operations of the property are no longer commercially viable. Peep defines the economic limit of a case to be when the highest cumulative before tax cash flow is attained. The economic limit is derived on a before tax basis rather than an after tax basis. The rational behind this method is as follows:
taxes are typically calculated at a corporate level
the decision to discontinue producing petroleum product does not typically affect corporate taxes
Given these factors, the economic limit is best determined on a before tax cash flow basis. Note: It is rare that the economic limit date varies between ‘before-tax cash flow’ and ‘after-tax cash flow.’
Daily Economic Limit Peep does not calculate an economic limit based on this methodology but it is illustrated here as another method for determining economic viability. The basic equation for a daily economic limit is: Economic Limit = Cost per Day / Revenue per unit
= (Opex / days in month) / Revenue per unit For example: what is the economic limit in bbls/day if operating costs are $1500/month (January) and the oil price is $15.00/bbl? No other adjustments will be made in this example. Economic Limit
= (1500 / 31) / 15.00 = 3.23 bbls/day
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Chapter 2: Detailed Analysis
Economic Limit – Cumulative Before Tax Cash Flow
M$
Cumulative Cash Flow 5000 4000 3000 2000 1000 0 -1000 -2000 -3000 -4000
Economic Limit
Cum BTCF Cum ATCF 1
2
3
4
5
6
7
8
9 10 11 12 13 14 15
Time
The diagram above illustrates an economic case that has a production life of 15 years but due to decreasing revenue coupled with fixed costs the economic limit occurs in year 12. A workover occurred in year 6 resulting in a decrease in before tax cumulative cash flow. The impact was not as great on the after tax cash flow because the additional capital expenditure qualified for 100 writeoff reducing taxes payable in that year.
Escalation and Inflation Escalation and inflation rates are used to estimate how product prices will change and what capital or operating expenses will cost in the future. For example, you may know the cost to install a compressor today, but what will it cost when you plan to install one in 5 years? Or you want to predict that oil prices will increase by $2.50 over the next 18 months, and gas will be 20% higher. Many companies use the terms escalation and inflation synonymously, but they can actually be separate calculations, both changing the value received. Inflation is usually associated with a currency, accounting for real changes in the value of the currency due to politics or policy. Escalation is used to predict the future value of a price or cost above the forecast inflation rate. This may occur because of exceptional supply/demand issues in a specific region or for specific goods or services. In combination, they act to calculate the future (or nominal) value of a cost or revenue from the current (real) value. The difference comes in reporting, which should allow both real (including escalation but without inflation) and nominal (includes both escalation and inflation) values. It is important to understand the source for the capital or operating cost expenditure. Although you may be analyzing the project in a certain country, the materials and labor may be sourced from another country in that country’s currency. Further,
52
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Chapter 2: Detailed Analysis
product prices may be calculated in another currency. Understanding the dynamics of currency and inflation will enable the analyst to determine the risks apparent in operating in a certain country.
Inflation: Theory in a nutshell Inflation is frequently the consequence of society’s spending beyond its capacity to produce. Other things being equal, increases in a country’s total money supply tend to increase total spending. Once high employment levels are reached and total output becomes virtually fixed, this added spending only serves to make prices spiral upward.
Price Impact on Project Economics Because price volatility can have such widespread impact on project economics, many companies try to estimate how prices will change over time. These price projections are then applied to the project analysis. Price escalation formulas are the most common means of estimating these changes. Changing prices can have a critical impact on petroleum project economics. Consider the following table, which summarizes the economics from an acquisition study. Profit Indicators Assuming $1,500,000 Acquisition Price Oil Price Case $15.00
$18.00
$21.00
$24.00
Rate of Return (%) after tax
0
27.75
51.69
75.73
Payout (Years) after tax
–
2.74
2.01
1.58
Net Income/Investment after tax
.97
1.68
2.51
3.44
Reserves (MBBLS)
419
608
646
716
Cumulative Cash Flow (M$)
-41
1014
2265
3654
-261
520
1399
2334
Present Worth at 10% Disc Rate (M$)
∗ Note: a 16.67% change in oil price (between $18/bbl and $21/bbl) makes a 120% change in cumulative cash flow (1014 M$ versus 2265 M$).
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Chapter 2: Detailed Analysis
Percentage Escalation In calculating a future value using percentage escalation, multiply an initial value by a set of fractions. Percent escalation is the most common method of escalation, and the basic formula for an annual escalation is: P
=
P i (1 + E)
t
Where P
=
Price per production unit
Pi
=
Initial price
E
=
Escalation percent (annual)
t
=
Time in years
Example 1: calculate the price of a barrel of oil in the fifth year if the initial average annual price is $15.00 per barrel with a 5% escalation. P
4
=
15 (1 + .05)
=
$18.23/bbl
Example 2: In January, 1998 the oil price is 20.00 $/Bbl. The monthly revenue escalation rate in January, 1998 is 1.0%. The oil price calculated for February, 1998 is: P
=
P i (1 + E)
t
Where Pi
=
20.00 $/Bbl
E
=
1%
t
=
1
P
=
20.00 (1 + 0.01)
=
20.20 $/Bbl
1
Assuming the monthly revenue escalation rate in February, 1998 is 0.5%, the oil price calculated for March, 1998 is: P
1
=
20.20 (1 + 0.01)
=
20.20 (1 + 0.005)
=
20.301 $/Bbl
1
You can enter a negative escalation rate. The resulting calculation differs from percent deescalation.
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Chapter 2: Detailed Analysis
Monthly Escalation/Inflation To modify the annual escalation equation for Peep’s default of monthly, use the equation: P
=
Pi ( 1 + E
1/12 t
)
Notice that the escalation rate is not simply divided by 12, but raised to the power of one divided by 12. This takes into consideration the fact that escalation will compound monthly. Example: An annual nominal escalation rate of 12% compounded monthly will result in an annual effective interest rate of 12.6825%. Peep compounds inflation and escalation monthly and will always display an effective annual interest rate. The example below left shows an annual effective inflation rate of 6%. The example below right shows the monthly inflation rate applied to achieve an effective annual rate of 6%.
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Chapter 2: Detailed Analysis
Percent De-escalation De-escalation is the opposite of escalating. In escalation, an initial value is multiplied by a set of fractions to generate escalated future values. De-escalation divides future values by the escalation rates to return to constant dollar (unescalated) values. The de-escalation process starts at the last entry in the column and works up to the first entry. The equation is: P
=
P n / (1 + E)
t
Inflation Inflation changes input values using the same calculation as escalation, but the difference is seen from a timing perspective. If you select the real radio button on a case input form, Peep will automatically inflate the values to nominal prior to case calculation. Peep will not inflate if you indicate that your input is already adjusted for inflation (nominal). You would still need to choose the Escalate at run-time feature or manually escalate any variable for additional escalation to apply. Note: This section is intended to introduce Peep’s handling of inflation, currency and escalation. A detailed analysis of the subject is covered in Peep course offerings.
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Chapter 2: Detailed Analysis
Chapter Exercise 5 Inflation Exercise Inflation Exercise You are anticipating buying some equipment from the US next year. The price of the equipment would be US $1MM today. The US inflation rate is expected to be 2%.. The forecast exchange rate is at $0.72 US to Cdn dollars. Canada’s inflation rate is expected to be 3%. What is the REAL Price of this purchase in Canadian Dollars?
(See next page for solutions)
Petroleum Economics: The Fundamentals
57
Chapter 2: Detailed Analysis
Solution to Inflation Exercise Steps Real US Dollars for Purchase US Inflation Rate Nominal US Dollars for Purchase US to Cdn conversion rate Nominal Cdn Dollars for Purchase Cdn Inflation Rate Real Cdn Dollars for Purchase
58
M$ 1000.00 2.00% 1020.00 0.72 1416.67 3.00% 1375.405
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Chapter 3: Discounted Cash Flow Analysis In this Chapter This chapter includes information for the following topics:
59
Introducing Discounting Topics
Time Value of Money
Economic Indicators
Chapter 3: Discounted Cash Flow Analysis
Introducing Discounting Topics Once cash flows have been calculated, and the economic limit determined, you can then apply financial indicators to determine the profitability of the project. Peep provides a number of these indicators, and we will begin our discussion with the Time Value of Money, and conclude with Profitability Indicators and Special Calculations.
Time Value of Money Money is worth less, the longer you have to wait to receive it. In the same regard, money received yesterday is worth more than money received today. Consider that you can take yesterday’s earnings and invest it, earning additional value. If you have to wait to receive money, you must delay the investment, therefore potentially losing money. Also consider that inflation will erode the value of money. For example, if the inflation rate is 5%, a dollar today is worth $1.05 next year, or $1.00 ∗ (1 + .05). In general, goods purchased in one year’s time will cost 5% more. This time value of money concept is applied through Compounding and Discounting.
Compounding Compounding refers to moving a present value forward in time to a future value. A savings account would be one example of a compounding investment. If the savings account compounded yearly then each year a new balance would be calculated on the account based on the cash in the account and the interest rate. Compounding FV
=
Where
60
PV ∗ (1 + i)
n
FV
= Future Value
PV
= Present Value
i
= Interest Rate
N
= Number of time periods
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Chapter 3: Discounted Cash Flow Analysis
Time Value of Money 30000 25000 20000 15000 10000 5000 0
2000
2002
2004
2006
2008
2010
year
In the above diagram an initial investment of $10,000 is being compounded annually with a 10% interest rate yielding a value of $25,000 after 10 years. If this same investment was not compounded annually but rather calculated once at the end of the 10th year then the final value would only be $20,000.
Discounting Discounting, is the opposite of compounding, and is used to move future cash flows back in time to a present value. The basic formulas are: Discounting PV
=
Where
n
FV ∗ (1 / ( 1 + I ) )
FV
= Future Value
PV
= Present Value
n
= Number of Time periods
i
= Interest or Discount Rate
For example, would you rather receive $100 now or $150 in five years? Assume that PV=$100, FV=$150, n=5, i=10%. A)
By Comparing Future Values (Compounding) FV
n
= PV ∗ (1 + i)
5
= 100 ∗ (1 + .10) = $161 > $150 B)
By Comparing Present Values (Discounting) PV
n
= FV ∗ (1 / (1 + i) ) 5
= 150 ∗ (1 / (1 + .10) ) = $93 < $100
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61
Chapter 3: Discounted Cash Flow Analysis Therefore, if you can earn 10% on your money, you would rather have the $100 today. Now work the same problem, but assume i=8%. FV
PV
5
=
100 ∗ (1 + .08)
=
$147 < $150
=
150 ∗ (1 / (1 + .08) )
=
$102 > $100
5
If you can earn only 8% on your money, you would rather have $150 in five years.
This basic discounting formula can be used for any period, and the periods summed to create what is commonly called Present Worth. The next table illustrates a periodby-period discounted cash flow, using a 15% factor. Period
Cash Flow
Formula
Discounted Value
1
1
804,780
1/(1+0.15) =1/1.15
2
753,142
1/(1+0.15) =1/1.3225
3
753,142
1/(1+0.15) =1/1.52
4
753,142
1/(1+0.15) =1/1.75
5
753,142
1/(1+0.15) =1/2.01
6
753,142
1/(1+0.15) =1/2.31
Total
699,808
2
588,113
3
567,576
4
497,406
5
392,374
6
320,524
4,820,185
3,065,807
Net Present Value With the concepts of discounting and compounding covered we can now look at a project’s cash flow over time and determine the net present value (NPV) for the project. Net Present Value Example Year 0 1 2 3 4 5 6 7 8 9 10
62
Investment 20 30 40 40 0 0 0 0 0 0 0
Revenue 0 0 0 0 40 45 50 55 60 65 70
Cash Flow
Discount Factor -20 -30 -40 -40 40 45 50 55 60 65 70 255
1.000 0.9091 0.8264 0.7513 0.6830 0.6209 0.5645 0.5132 0.4665 0.4241 0.3855 NPV at 10%:
Discounted Cash Flow 10% -20 -27 -33 -30 27 28 28 28 28 28 27 84 Æ
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Chapter 3: Discounted Cash Flow Analysis
The example above is a project with an 11-year life (including time zero). In the first four years the project is development and does not generate any revenue resulting in negative cash flow. In the remaining 7 years the project produces revenue and generates positive cash flow. Armed with the understanding that cash flow today is worth more than cash flow in the future we can apply a discount rate to the cash flows. As the time period increases the discount factor is reduced. When we review the results we see that the total undiscounted cash flows for this project equal 255 while the discounted cash flows equal 84. This 84 is described as the Net Present Value at a discount rate of 10%. What does this mean? If as investors we expected a rate of return equal to 10% then we would consider any investment that yielded a NPV at a 10% discount rate equal to or greater than zero. This project is therefore considered economically viable from an NPV standpoint. This next table illustrates Peep’s ability to calculate and report the cash flow using several different discount rates. The previous example did not consider 4 separate cash flow streams. Peep provides a NPV for Operating Income, Before Tax Capital invested, Before Tax Cash Flow and After Tax Cash Flow. Using consistent discount rates and methods allows projects with different cash flow periods to be compared on an equal basis.
Selecting a Discount Rate Corporations normally calculate a weighted average cost of capital (WACC). This is derived from two components:
debt, in the form of bank loans or bonds
equity, in the form of common and/or preferred stocks
Providers of debt financing require a return on investment based on several factors. Some of those factors could relate to the bond rating of the company, the type of industry the business is in and the company’s current financial condition. Providers of equity financing (shareholders) expect to receive a rate of return based on the assumed risk of the enterprise. Shareholders realize their return on investment through stock dividends and/or appreciation of the stock price.
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Chapter 3: Discounted Cash Flow Analysis
Debt financing is typically a fixed rate and is considered of lower risk. Interest must be paid prior to any returns being paid out to shareholders. Because of these factors the rate of return on debt is assumed to be lower. Typically a WACC in North America is around 10%. Analysis of Canadian oil and gas producer stocks indicates returns in the area of 6% though. Corporations may use different discount rates for different types of analysis. For acquisitions they may discount at a higher rate and for dispositions a lower rate.
Discount Methods and Timing The examples and formulas in the time value of money section were calculated assuming an annual time period with discounting occurring at the end of the period. There are several options available in Peep for discounting purposes. Corporations vary in what method is used. It is important to understand the discount method being utilized and it’s impact on data entry and results in Peep.
End-Year Discounting End-Year Discount Factor = 1 / (1 + i)
n
Where i = annual discount rate
Mid-Year Discounting To calculate mid-year discounting, you need to assume that capital is moved to the middle of the year, and that each year’s cash flow is also received as a lump sum payment at that same time. Modify the general formula by subtracting half a year from the exponent year. Mid-Year Discount Factor = 1 / (1 + i)
(n-0.5)
So for Year 1, the exponent would be 0.5, Year 2 = 1.5, Year 3 = 2.5, and so on, making the 10% rate for: Year 2 Discount Factor
1.5
= 1 / (1 + 0.10) = 1 / 1.1537 = .8668
This factor is then multiplied by the year’s value to report the discounted value, or net present value.
Beginning-Year Discounting Beginning-Year Discount Factor = 1 / (1 + i)
(n-1)
Where i = annual discount rate
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Chapter 3: Discounted Cash Flow Analysis
Monthly Discounting To calculate monthly discounting, you should still assume an annual effective discount rate, but modify the formula to be: Monthly Discount Factor = 1 / [(1 + i)
1/12 n
]
Where i = annual discount rate
So if the discount rate were 10%, then for month 2 the formula would read: Monthly Discount Factor
= 1 / [(1 + 0.10)
1/12 2
= 1 / [1 + (1.008))
]
2
= 0.9921
The discounted monthly values are then summed to calculate the annual discounted value, or net present value.
Petroleum Economics: The Fundamentals
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Chapter 3: Discounted Cash Flow Analysis
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Chapter 3: Discounted Cash Flow Analysis
Chapter Exercise 1
Discounting Exercise
Fill in the table below, using the formulas described in the preceding pages.
You can use the Excel template provided but do not use Excel functions.
Use a discount rate of 10%
Year
Cash Flow
1
100
2
100
3
100
4
100
5
100
6
100
Total
600
Mid-Year Discount Factor
Mid-Year Present Value
Year End Discount Factor
Year End Present Value
(See next page for solutions)
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67
Chapter 3: Discounted Cash Flow Analysis
Solution to Discounting Exercise
Year 1 2 3 4 5 6 Total
68
Cash Flow 100 100 100 100 100 100 600
Mid-Year Mid-Year Year End Year End Discount Present Discount Present Factor Value Factor Value 0.9535 95.35 0.9091 90.91 0.8668 86.68 0.8264 82.64 0.7880 78.80 0.7513 75.13 0.7164 71.64 0.6830 68.30 0.6512 65.12 0.6209 62.09 0.5920 59.20 0.5645 56.45 456.78 435.53
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Chapter 3: Discounted Cash Flow Analysis
Economic Indicators The economic analysis of a project would not be complete without the addition of economic indicators. NPV is an economic indicator that has already been discussed in the previous section. This section will cover several common economic indicators as follows: Rate of Return (ROR), Discounted Profitability Index (DPI), Profit to Investment Ratio (PIR or ROI), and Payout. Companies may use different names but the equations are fairly standard within the petroleum industry.
Rate of Return (ROR) The rate of return (ROR) or internal rate of return (IRR) is the single discount rate that produces a NPV of zero. It is also described as the discount rate that equates the present worth of cash flows to be equal to the present worth of the investments
The two charts illustrate how Peep calculates the ROR for Before and After Tax Cash Flows. You can estimate the ROR from the NPV table based on the values displayed. The Economic Indicators section shows the actual values of the ROR. Drawbacks to ROR as a profitability indicator are that it favors high initial earnings projects over long life cash generation projects. If this indicator is used independent of other indicators it can lead to incorrect investment decisions. In the example above the ATCF ROR is 36.7%. If this project had a cost of capital of 10% it is unlikely
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69
Chapter 3: Discounted Cash Flow Analysis
that funds generated from this project could be reinvested at 36.7%. Selecting projects solely on a higher ROR may lead to incorrect decisions. In some cases due to the nature of the cash flow stream the project may actually have multiple RORs. This may happen in acceleration type projects or projects with investments that occur in later time periods. It is recommended that ROR not be used in these situations.
Discounted Profitability Index (DPI) This indicator is a measure of investment efficiency, and is used to evaluate multiple rates of return projects relative to the investment requirements. Consistent use of the same discount rate is necessary when comparing projects by using DPI. This indicator is sometimes called PI. In Peep PI and DPI is the same calculation. DPI =( Net Present Value + Capital) / Capital If NPV is $5,000,000 and capital is $1,500,000, then the DPI is: DPI = (NPV + Capex) / Capex = (5,000,000 + 1,500,000) / 1,500,000 = 4.333
Profit to Investment Ratio (PIR) Also know as the Return on Investment (ROI), this indicator is similar to DPI. It simply divides total NPV by total capital. Known as the “bang for the buck” indicator, it is very useful for ranking projects when capital is limited. PIR = Net Present Value / Capital If NPV is $5,000,000 and capital is $1,500,000, then the PIR is: PIR = Net Present Value / Capital = 5,000,000 / 1,500,000 = 3.333
Discounted Return on Investment (DROI) Similar to both DPI and PIR, this indicator includes the cost of managing a company’s funds, often called capital overhead. It is also used for ranking projects with similar capital outlays. DROI = Net Present Value / (Capital + Overhead on Capital) If NPV is $5,000,000, capital is $1,500,000, and overhead is $15,000, then the DROI is: DROI
= Net Present Value / (Capital + Overhead on Capital) = 5,000,000 / (1,500,000 + 15,000) = 3.3003
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Chapter 3: Discounted Cash Flow Analysis
Payout Period The Payout period is the time to return an investment. It is calculated from the net cash flow stream. The point at which the cumulative net cash flow stream becomes positive is the Payout. There are advantages and disadvantages to using this method as an indicator of income potential. Some of the advantages are:
simple and easy to calculate
measure of rate at which revenue is generated early in a project
measure of time risk. The quicker the payout, the less the risk
estimates the time at which a liability to the treasury is removed
The simple graph above indicates a payout in the third year of a project. But this simple graph fails to consider the disadvantages of this indicator. It fails to:
consider the time value of money
consider the magnitude and timing of cash flows after the pay back period
measure total cumulative cash flow
consider that a project may have multiple payout periods
For example, the chart below displays a total $1000 investment.
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Chapter 3: Discounted Cash Flow Analysis
Each of the three cash flows indicates a three-year payout, but the overall profitability of each is very different. Period
Proposal B
Proposal C
-1000
-1000
-700
1
500
200
-300
2
300
300
500
3
200
500
500
4
200
1000
100
5
200
2000
0
6
200
4000
0
Cash Flow Total
600
7000
100
Initial Inv.
Proposal A
Peep calculates two payout indicators, Standard and Project. Standard payout is the point in time when the undiscounted cumulative cash flow becomes positive, measured from the case start date. Once the standard payout date is reached any capital expenditure past this date is not included in the calculation. Project payout is the point at which the undiscounted cumulative operating income (before capital) exceeds the total capital in the case. Peep moves all the capital (including abandonment and salvage) to the first month in the case and then determines the point at which the cash flow becomes positive, measured from the case start date.
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Chapter 3: Discounted Cash Flow Analysis
Chapter Exercise 2
Profitability Exercise Using the values in the tables below, calculate the DPI, PIR and DROI for this project for Before and After Tax values. Assume capital overhead of 50 M$, and use the 0%, 10% and 15% Discount Rates. Disc Rate %
Operating Income
Capital
Before Tax Cash Flow
After Tax Cash Flow
0
7633.3
1500.0
6133.3
3417.9
8
4751.5
1487.3
3264.1
1679.7
10
4327.2
1484.4
2842.8
1421.0
12
3971.7
1481.5
2490.3
1203.5
15
3537.4
1477.2
2060.2
936.5
20
2999.2
1470.5
1528.7
603.5
Before Tax
After Tax
DPI @ 0% DPI @ 10% DPI @ 15% PIR @ 0 % PIR @ 10% PIR @ 15% DROI @ 0 % DROI @ 10% DROI @ 15%
(See next page for solution)
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Chapter 3: Discounted Cash Flow Analysis
Solution to Profitability Exercise DPI @ 0% DPI @ 10% DPI @ 15% PIR @ 0% PIR @ 10% PIR @ 15% DROI @ 0% DROI @ 10% DROI @ 15%
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Before Tax 5.09 2.92 2.39 4.09 1.92 1.39 3.96 1.85 1.35
After Tax 3.28 1.96 1.63 2.28 0.96 0.63 2.21 0.93 0.61
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Chapter 3: Discounted Cash Flow Analysis
Chapter Exercise 3 Cash Flow Exercise This exercise encapsulates the majority of the components discussed in this manual. It is intended as an introduction to petroleum economic evaluations. Actual economic evaluations are typically much more complex. Using the provided Excel spreadsheet, build an economic evaluation. The template has been preset for an exponential production equation.
Enter the following values at the top of the spreadsheet: Working Interest
= 100%
Initial Rate
= 200,000 barrels in Year One
Decline %
= 20
Royalties
= 25% of revenue
Federal Tax Rate
= 30% of Taxable Income
Enter the following values in the appropriate columns: Oil Price
= $16.50 per barrel, inflated by 1.5% per year after year one
Opcosts = $5.25 per barrel and $20,000 per year, inflated by 1.5% per year after year one Capital
= $5,000,000 in year one
Calculate the following: In the Capital Depreciation column depreciate the capital utilizing a declining balance of 20% Using the formulas from this document calculate the Net Present Value of this project on a before and after tax basis utilizing a discount rate of 10%. Use an End of Year discount method. Through Excel’s NPV Function estimate what the ROR will be for this project OR Utilizing Excel’s IRR Function calculate a BTROR and ATROR.
Based on a 10% cost of capital is the project economic?
(See next page for solutions)
Petroleum Economics: The Fundamentals
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Chapter 3: Discounted Cash Flow Analysis
Solution to Cash Flow Exercise BTNPV10% BTROR
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$545.90 15%
ATNPV10% ATROR
$17.59 10%
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References For further reading, please refer to the following reference materials:
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The Institute of Petroleum - http://www.petroleum.co.uk/
American Petroleum Institute - http://api-ec.api.org/frontpage.cfm
Society of Petroleum Engineers - http://www.spe.org/
Petroleum Society: Canadian Institute of Mining, Metallurgy & Petroleum http://www.petsoc.org/
Petroleum Communication Foundation - www.centreforenergy.com
WTRG Economics - http://www.wtrg.com/
BP Statistical Review of World Energy June 2005 http://www.bp.com/genericsection.do?categoryId=92&contentId=7005893
Oil and Gas Fiscal Regimes of the Western Canadian Provinces and Territories http://www.energy.gov.ab.ca/docs/tenure/pdfs/FISREG.pdf
Government of British Columbia Oil and Gas Royalty Handbook http://www.em.gov.bc.ca/subwebs/resourcerev/royataxs/handbook/default.htm
Saskatchewan Crown Royalty and Freehold Production Tax Programs and Payments http://www.ir.gov.sk.ca/Default.aspx?DN=3661,3430,3384,2936,Documents
Alberta Energy- http://www.energy.gov.ab.ca/default.asp
Glossary of Oil & Gas Terminology API AT Abandonment
Associated Gas BOE BT
After Tax Converting a drilled well to a condition that can be left indefinitely without further attention and will not damage fresh water supplies or potential petroleum reservoirs as defined by governing bodies Natural gas that is produced along with crude oil Barrels of Oil Equivalent Before Tax
B.T.U.
British Thermal Unit – the heat required to raise the temperature of 1 lb. Of water through 1 F
Barrel
A unit of measurement of volume for petroleum products. One barrel is the equivalent of approximately 35 Imperial gallons.
Battery Complete a well Condensate
Concessionary Regime Cubic Foot
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American Petroleum Institute
Equipment to process or store crude oil from one or more wells Finish the work on a well and bring it to a productive state A mixture of pentanes and heavier hydrocarbons, recoverable from an underground reservoir and gaseous in its virgin reservoir state, but liquid at the conditions under which its volume is measured or estimated The operator of the oil or gas well has ownership of the resources but is obligated to pay a royalty to the governing body The volume of gas that fills a cube that is one foot by one foot by one foot under set temperature and pressure conditions. The standard pressure is 14.73 psia and the standard temperature is 60 degrees Fahrenheit.
Glossary
Curtailment
Development well
Discovery well Dry hole
Degrees API Density
Downstream business Ethane
Exploratory well Farm-in Farm-out
Field Formation
Fuel gas
Gas
Gas Heat Content
Gas Heat Energy
Gas-Oil Ratio (GOR)
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Limiting the production capability of a well due to the constraints of the processing facility or gathering system. It may also be used to describe facility down time (also referred to as turnaround time). A well drilled in proven territory in a field for the purpose of completing the desired pattern of production. Sometimes called an exploitation well. An exploratory well which discovers a new oil or gas field An exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities (i.e. uneconomic) to justify completion Equals: (141.5 / specific gravity @ 60 F) – 131.5 The gravity of crude oil, indicating the proportion of large, carbon-rich molecules, generally measured in lbs per cubic foot or degrees on the API gravity scale That portion of the oil and gas industry focused on marketing, refining and petrochemicals In addition to its normal scientific meaning (C2H6), a mixture mainly of ethane which ordinarily may contain some methane or propane A well which is drilled to test for the presence of oil or gas in a previously undeveloped area. Also called a wildcat well. The secondary party in a farm-out agreement The name applied to a specific form of assignment wherein the Leassee grants a conditional interest to another party in consideration for the drilling of a well within a specified length of time on given acreage. It is usually undertaken where the Lessee has leases on a relatively large block of acreage and does not wish to undertake the sole cost of developing it. The surface area above one or more underground petroleum pools sharing the same or related infrastructure A sedimentary rock deposit having common physical characteristics (often called a bed or zone). A lithologic unit. In oil areas each formation is given a name, frequently as a result of the study of the formation outcrop at the surface. Other names are based on the fossils found in the formation. Gas used to fuel a generator for the purpose of providing power to surface facilities. A significant factor in some countries in the calculation of royalties. Any fluid, either combustible or noncombustible, which is produced in a natural state from the earth and which maintains a gaseous state at ordinary temperature and pressure conditions Used to convert gas volume to gas heat energy. Expressed in BTU/cubic foot or its metric equivalent. Content is determined after gas shrinkage. It is the total energy contained in the produced gas stream. It can be a calculated value by multiplying the gas volume by the heat content. . The ratio of gas to oil as produced from a well. Usually stated as the number of cubic feet produced with a barrel of oil.
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Glossary
Gas Processing Plant
Gas Shrinkage Heavy Crude Oil Hydrogen Sulphide (H2S)
Joule
Light Crude Oil Lithology
A facility designed (1) to achieve the recovery of natural gas liquids from the stream of natural gas which may or may not have been processed through lease separators and field facilities and (2) to control the equality of the natural gas to be marketed. Accounts for the amount of raw gas production that is reduced due to the elimination of natural gas liquids, acid gases and/or fuel gas Oil with a gravity below 28 degrees API This compound is the cause of sourness in natural gas. It is one of the most dangerous of industrial gases. It must be removed prior to transport in a pipeline. Pipeline gas contains less than 0.0016 percent H2S The basic SI unit of energy used to measure energy content. On joule is the equivalent of energy required to heat one gram of water by approximately one quarter of one degree Celsius. Since the joule is such a small unit of energy, the natural gas industry normally works in large multiples – e.g. Gigajoule (GJ) = 1 billion joules. Light petroleum with a gravity above 28 degrees API The character of a rock formation
Methane
The principal constituent of natural gas; the simplest hydrocarbon molecule, containing one carbon atom and four hydrogen atoms
Midstream Business
Typically refers to a gas plant that strips NGLs from the sales gas stream. Also referred to as a straddle plant
Multiple Zone Well completion
The method used to complete a single well in such a way that production is segregated and is obtained from more than one formation
NI NPI
NPV Natural Gas or Raw Gas
Net Income Net Profit Interest is similar to an ORR except that an NPI is paid on the operating income (revenue less royalties less operating costs) Net Present Value A highly compressible, highly expandable mixture of hydrocarbons having a definite specific gravity and occurring naturally in a gaseous form
Natural Gas Liquids (NGL)
Liquids obtained during natural gas production, including ethane, propane, butanes and condensate
Non-associated gas
Natural gas which is in reservoirs that do not contain significant quantities of crude oil
OPEC ORR Operating interest
Pool
Organization of Petroleum Exporting Countries Overriding Royalty is a burden that amounts to a given percentage of a specified lease production The operating interest is that portion of the working interest charged with the operational responsibility of the lease. This operating interest handles all accounting, charging or remitting to each working interest its prorata share of expenses and profits. A natural underground reservoir containing, or appearing to contain, an accumulation of petroleum
Petroleum Economics: The Fundamentals
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Glossary
PSC
Propane
A liquefiable hydrocarbon with a chemical formula (C3H8). Market grade contains trace elements of methane, ethane and butane.
Quality Adjustment
An adjustment to the price of oil typically due to degrees API and/or chemical composition
Rich gas
Gas containing a lot of compounds heavier than ethane, about 0.7 US gallons of C3 + per mcf of raw gas
Ring Fence
STB
Many fiscal regimes require the calculation of burdens or taxes on independent areas where deductions from one area can be used in another area Stock Tank Barrel. See barrel.
Standard Conditions
Standard conditions for the measurement of gas are 101.325 kPaa and 15C in metric and 14.65 psia and 60F in imperial
Step-out well
A well drilled adjacent to or near a proven well to ascertain the limits of the reservoir
Sweet oil & gas Sales Gas
Specific Gravity
Upstream Business WACC Working Interest
Workover
Zone
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Production Sharing Contract. The government maintains ownership of the resource and pays the operator for the resource according to the contract.
Petroleum containing little or no hydrogen sulphide Gas which after processing, has the quality to be used as a domestic or industrial fuel. It meets the specifications set by a pipeline transmission company and/or distributing company. The ratio of weight of volume of a body to the weight of an equal volume of some standard substance. In the cases of liquids and solids the standard is water (equal to 1); and in the case of gases, the standard is air. The specific gravity is numerically equal to the density. Particularly in the case of oils, the specific gravity is determined through the use of a hydrometer. That portion of the oil and gas industry focused on producing and processing oil and gas resources Weighted Average Cost of Capital The portion of lease expenses that are paid by the working partner They would also normally receive an equal portion of the revenue. It is formed by the granting of a lease by the owner of the mineral rights. To perform one or more of a variety of remedial operations on a producing oil well with the hope of restoring or increasing production The term “zone” as applied to reservoirs, is used to describe an interval which has one or more distinguished characteristics, such as lithology and/or porosity.
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