Separate cash Flow Evaluations - Applications to Investment Decisions and Tax Design* By Magne Emhjellen** and Petter Osmundsen*** ** Petoro AS *** University of Stavanger
Abstract Oil project assessment using separate cashflow valuation (Jacoby and Laughton, 1992, Laughton and Jacoby, 1993 and Emhjellen, 1999), presume that the present value of the cost cashflow of oil projects can be calculated using a risk free rate. This paper examines whether this practice, at least to a first approximation, is reasonable. More specifically, the paper examines whether labour wage hours costs and steel prices, as cost factors in the investment cost stream, are systematic risk factors (i.e. have a beta different from zero). The paper also investigates whether oil price as a factor in the revenue stream is a systematic revenue factor. Separate cash flow evaluation has been discussed in relation to petroleum taxation. A petroleum tax commission in Norway stated that tax reductions due to depreciation should separately be discounted by a risk free rate. We discuss the role of partial cash flow discounting in tax design.
** Magne Emhjellen, Petoro AS, Postboks 300 Sentrum 4002 Stavanger , Norway, Email:
[email protected] **** Petter Osmundsen, University of Stavanger, Department for Industrial Economics and Risk Management, 4036 Stavanger. Email:
[email protected], Home page: http://www5.uis.no/kompetansekatalog/visCV.aspx?ID=08643&sprak=BOKMAL
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1.1
Introduction
In research related to oil project valuation one often makes the assumption that the present value of the cost cashflow may be calculated using the risk free rate (Laughton and Jacoby, 1993, Laughton, 1998 and Emhjellen, 1999). From a Capital Asset Pricing Model (CAPM) (Sharpe, 1964, Lintner, 1965) point of view this is only permissible when the uncertain changes in the cost cashflow is not correlated with the rate of change in the market portfolio. To examine this, in Secion 2 we test whether two important cost factors for oil projects, labour costs and steel prices, are systematic risk factors (i.e. correlated with the value of the market portfolio). In addition, we examine in Section 3 whether oil prices represent a systematic revenue factor, and thus whether the CAPM beta obtained for oil prices support using a higher required rate of return when discounting revenues than when discounting costs. After identifying the main cost variables for the example project, historical data on the cost variables, as well as historical data on a proxy for the market portfolio (The Total Index, Oslo Stock Exchange) are presented. The betas of these cost variables are then calculated. The data of our analyses is documented in eight tables,
3
and can be found in our downloadable working paper 2009/16 at the University of Stavanger.1 The results for the period examined show that the oil price beta is higher than the cost betas and that risk free discounting of the cost cashflow may be a reasonable approximation until other cost factors are identified and examined. The results of the paper therefore support the idea that revenues should be discounted at a higher rate than costs when calculating the present value of oil exploration projects. However, uncertainty related to the correct size of the individual cashflow betas indicate that further research should be undertaken on the required rate of return of individual cashflow streams. The issues of distinct required rates of return for discounting individual cashflow streams of oil projects have been raised by the Tax Commission in Norway. In a tax evaluation study they implicitely propose that the oil companies should change their valuation method from discounting the aggregate net cashflow stream to a method where one specific partial cashflow is valued separately, namely the tax reduction cash flow from tax depreciation (Government Report NOU 2000:18).2 The companies actual investment valuation methods is essential to evaluate the implications of the suggested tax changes. The Commission 1
http://ideas.repec.org/p/hhs/stavef/2009_016.html This deviates from previous tax theory and policy recommendations, see e.g. Osmundsen, (1999a). 2
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recommended a slower pace of tax depreciation. Tax depreciation time should expand from the current 6 years (linear depreciation) to a time frame more accurately reflecting the economic life of extraction and transportation installations.3 The companies argued that, with their global practise of using average discount rates, this would cause considerable tax increases and lead to a non-neutral tax system that would generate underinvestment. At any rate, they said, tax reduction cash flows are by experience not certain, as verified for example by the Commission s own report that proposed tax increases. The Tax Commission, on the other hand, argued that the revised tax system would be neutral if the companies correctly discounted tax reductions by a risk free rate. This debate raises important questions. Present tax theory usually presumes average discount rates. In the event of the adoption of separate cashflow discounting, how should the tax reductions of depreciations be discounted. Separate cashflow betas are discussed and estimated in section 2 and 3. Uncertainty related to tax recovery and government tax changes are discussed in Section 4 and in section 5 an example project valuation is shown using the standard net cashflow 3 The short depreciation time, together with an added depreciation of 30 per cent (uplift), were designed so that the special resource rent tax of 50 per cent should actually only be levied on excess returns, and so that the tax system would not distort investment decisions of the oil companies (neutrality), see White Paper Ot.prp. 1991-92.
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discounting method and a separate cashflow discounting method. Our data sources are presented in an Appendix.
2. CAPM and separate cashflow betas Finance theory (Sharpe 1964, Lewellen 1977) related to valuation in the mean-variance framework argues that in order to calculate the present value of an uncertain individual cashflow stream one needs an estimate of the expected value of the cashflow stream and the cashflow streams covariance with the return of the market portfolio. The issue of estimating the expected value is raised in section 3. We now turn to the issue of the required rate of return. The Capital Asset Pricing Model (CAPM) (Sharpe 1964) relationships states that:
E Ri
Rf
i
E Rm
Rf ,
where E(Ri) is the expected required rate of return on equity of an asset i and Rf if the risk free rate, E(Rm) is the expected return on the market portfolio and
i
is the covariance of the return of asset i
with the return of the market portfolio divided by the variance of the return of the market portfolio (
i
Kov (ri , rm ) ). Var (rm )
From the value additivity principle (Shall, 1972), the net present value of an asset is the sum of the present values of the component cashflows of the asset:
(2.1)
6
Mi
Vi
X ij ,
(2.2)
j 1
where Xij is the present value of the jth component of the cashflow of asset i discounted using the expected required rate of return of the jth component of asset i, E(Rij), and Mi is the number of cashflow components of asset i. The expected rate of return on equity of an asset is equal to the sum of the value weighted expected rates of return of the individual component cashflows
Mi
E Ri
w ij E R ij .
(2.3)
j 1
X ij
In equation 2.3, w ij
Vi
Mi
and
w ij
1 . From the CAPM relation-
j 1
ship, the expected required rate of return of the jth component of the cashflow of asset i may be written:
E Rij
Rf
ij
E ( Rm ) R f .
Substituting equation 2.4 into equation 2.3,
(2.4)
i
may be written as
Mi
w ij
i j 1
ij
.
(2.5)
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An example is where there are only two distinct cashflows generated by an asset (Lewellen, 1977 and Emhjellen and Alaouze, 2002): the expected after tax revenue cashflow and the expected after tax cost cashflow, where each of the expected after tax cashflow streams has a different beta. Thus, j=1,2, and to specify notation, let
i1
iD
be
the expected after tax revenue cashflow beta for asset i and i2
be the expected after tax cost cashflow beta for asset i.
iC
The value of a project given by 2.3 may be written as
Vi
Vi
D
C
Vi .
(2.6)
In equation 2.6, ViD denotes the PV of the expected after tax revenue cashflow of asset i, and ViC
0 denotes the PV of the expected
after tax cost cashflow of asset i. The beta for asset i may be written as i
where w iD
w iD
D
w iC
C
,
ViD and w iC D C Vi Vi
(2.7)
ViC ViD
ViC
,
This shows that if an individual cashflow valuation method is to be used, an integral part in order for the value of the project to be determined, must be to determine the cost cashflow beta and it s relative weight. In other words the systematic risk associated with the project cost must be determined in order to estimate the required rate
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of return and thereby calculate the present value of this cost cashflow. An interesting point noted by Lewellen, 1977 is that a higher beta for the capital expenditure cost cashflow implies a higher project value. The reason for this is that cost cashflow is a cash outflow where higher discounting (higher beta implies higher required rate of return) implies a lower present value of cost. This is contrary to what is true for revenue, where higher systematic risk implies less value.
2.1 Calculating the ex post betas of cost input variables Before estimating the ex post betas of cost input variables it is important to have in mind that this approach is very different from estimating the ex post beta of a company. Firstly, the expost beta for the companies will have debt included amplifying the business risk of the company (companies are normally partly debt financed). The levered company beta is therefore higher than the company unlevered beta. For a discussion on this see Copeland and Weston (1992). With a separate cashflow valuation method the individual cost or revenue betas will have no debt associated with them since a debt cashflow will be valued separately. It is important to note that an investor will face, in addition to the business and financial risk related to the betas, also the change in the level of the risk free rate as well as the changes in the market risk
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premium (exemplified recently with the financial crisis). Unepected changes in these parameters will affect individual companies differently because of different debt levels and levels of business risk (ie. size of unlevered beta). A final point regarding estimation of individual cashflow betas is that they will be dependant on the parameters chosen, the total period and the return period chosen and the market portfolio proxy (index). In addition, one runs the risk that the returns on the parameters chosen are correlated and or that there are parameters not selected that have various degrees of correlation with the chosen parameters or the proxy for the market portfolio. However, the company beta is given by equation 2.5 where a debt level different from zero would be associated with a beta of debt. With no debt the company or project beta can be described by equation 2.7. The results below are therefore only one first attempt at identifying weather the chosen parameters has betas different from zero.
The rate of change of the cost data and the rate of change of the Total Index were calculated using the real quarterly data on wage hour cost, steel prices and the Total Index. The rate of change data are shown in Table 5.
The ex post betas of the wage hour costs and steel prices were calculated using Equation (1) and the data in Table 5.
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(1)
i
Cov( Ri, Rm) . 2 ( Rm)
A total of three ex post cost betas were calculated:
^
(2)
^
C ov( R1 , Rm ) 1
2
( Rm )
0,73 140,2
0,0052 ,
^
where
is the estimated offshore wage cost beta, R1 is the rate of
1
change of the offshore wage cost, and Rm is the rate of change of the Total Index. Similarly, the beta of the onshore wage cost is ^
represented by
^ 2 , and the steel price beta by
3.
^
(3)
^
C ov( R2 , Rm ) 2
2
( Rm )
10,47 140,2
0,0747 ,
22,56 140,2
0,1609 .
^
(4)
^
C ov( R3 , Rm ) 3
2
( Rm )
These results indicate that of labour cost and steel prices, steel prices have the highest beta, which indicates that at least the
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materials input part in the investment cashflow of oil projects has a positive beta.4 Hence, this part of the costs cashflow should be discounted at a rate higher than the risk free rate. For labour cost, although the results show positive betas, the betas (at least for offshore workhour cost) are only marginally greater than zero.
Using a market risk premium [E(Rm)-Rf] of approximately 6% (Johnsen, 1991), this indicates a required rate of return for the labour cost portion (with a beta of 0,0747) of approximately 0,44% above the risk free rate [0,0747(6%)]. Similarly using the steel price beta the required rate of return would be approximately 1% above the risk free rate. A weighted average of labour cost and material cost using these two betas would therefore indicate a required rate of return less than 1% (0,7%) above the risk free rate.
3 Calculating the ex post oil price beta The oil price beta was calculated using the price data on WTI (West Texas Intermediate) as given in Standard & Poors Platt's Prices and Data for the period 1986 to 1994. The nominal WTI price data in US dollars per barrel were converted to real Norwegian currency using the CPI (Norway) and the NOK/USD exchange rate. The real rate of change for each period was then calculated quarterly. 4 In deriving the weighted average of the ex post cost betas, we have used their relative PV weights. Assuming that the PV of the labour cost is 60% of the after tax cost cashflow, and that the PV of steel represents the remaining 40% of the after tax cost cashflow (from the cost structure of project N), the cost cashflow beta is a weighted average of the two cost betas.
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The data are presented in Table 6. The nominal oil prices in US dollars are shown in column one, the exchange rates in column two, the CPI in column three, real oil prices in Norwegian currency in column four, the percentage changes in real oil prices in column five and the percentage changes in the Total Index in column six.
The oil price beta was calculated in the same manner as the cost betas using the data in Table 1. The oil price beta was calculated to 0,293 using Equation (1). This is higher than the cost cashflow betas obtained. It is, however, important to note that the estimated oil price beta, as the cost betas, could be different with data from different time periods and different length of time periods. Thus, the ex ante oil price beta, just like the cost cashflow beta, may be very different from the calculated ex post beta based on historic data. For the time period chosen here, however, the oil price beta is substantially higher than that of the cost cashflow beta, implying that a higher risk adjustment is called for when discounting the expected after tax revenue stream than when discounting the expected after tax cost stream. Using this oil price beta as estimate for the required rate of return on revenues gives a rate 1,8% above the risk free rate (given a market risk premium of 6%).5 5 It should be noted that the period examined contains the period of the Iraqi invasion of Kuwait where the stock indexes around the world (including the Total Index) depreciated in value while the oil price increased. This has the effect of reducing the size of the oil price beta for the period calculated.
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4. Tax payments and risk adjustment We will raise two issues regarding valuing the tax reduction cashflow from tax depreciation when valuing cashflows separately. First, there is the possible direct tax concern for the timing and likelyhood of cost recovery. Second, there is the issue of possible government changes in the tax level. Is it reasonable to discount these tax reductions by a risk free rate? This is not a trivial issue, since such tax reductions normally are a non-linear function of both costs and income, where the latter is crucial for determining whether the oil company is in a tax paying position. The non-linearity, which may challenge the assumption of additivity, makes taxes hard to separate from other cash flow components. Discounting with a risk free rate may not be the relevant approach, due to the option nature of tax payments, see Lund (1992). The Norwegian Petroleum Tax Commission makes several recommendations that would affect the valuation of tax reductions. In June 2001 the Norwegian Parliament approved an amendment to the Petroleum Tax Law, allowing the oil companies to carry forward deficit with interest (risk free rate), and allowing the companies to
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transfer losses to other companies.6 Thus, the likelihood of effective tax deductions are increased, the tax system has become more linear, and the option nature of tax cash flows are less evident than in most other petroleum tax regimes, e.g., ring fence systems. Another suggestion from the Petroleum tax Commission, not endorsed by Parliament, was to increase the tax depreciation time. Such a change would have increased the political risk for the companies, as there would be a higher risk risk of a change in tax conditions after irreversible investments are literally sunk on the seabed. After investments have been made in facilities that may extract petroleum for some thirty years, new governments will come into power, and there is limited possibilities to establish credible guarantees for a stable tax policy, as one Parliament
according to the Constitution
cannot commit the tax policies of future Parliaments.
4.1 Tax effects resulting from revenues and costs The norwegian tax base is given by: Tax base = Revenues (oil price x sale of oil) operating cost tax depreciation interest cost. The oil companies will pay a percentage tax of this tax base, making the tax payments a function of oil price, production and costs. For revenues, given the assumption that the sale of oil from 6 Transfer of losses at full tax value, however, presumes an efficient market for tax deferrals. In periods of low petroleum prices, there may be a buyer s market.
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an oil project is independent of changes in the value of the market portfolio, would have a beta equal to the oil price. This follows, since the after tax revenue is only a scaled down level of the revenues before tax (timing og tax reduction from depreciation amounts discussed separately). Consequently, the percentage changes in the after tax cashflow will be equal to the percentage changes in the before tax cashflow and their correlation with the changes in the value of the market portfolio will be equal, resulting in the same beta. The operating cost cashflow reduces the tax base the same year while the investment cashflow reduces the tax base through tax depreciation. Given that the cost betas before tax are only marginally positive, the cost betas after tax will primarily be linked to the systematic risk of the oil price. This because the reduction in tax (after tax cost cashflow) resulting from the cost cashflow will only be positive when the tax base is positive. In other words, the negative tax base resulting from low oil prices will have to be carried forward until the project generates a positive tax base. Consequently, even though the results of this paper indicate low systematic risk for the cost cashflow (labour cost and steel prices), the after tax cost cashflow has a timing risk and risk of loss (lost after 10 years) that is a result of the systematic risk of the oil price. This possible delay or loss of the cost recovery - if it is not fully covered by transfer of losses - is a risk that will reduce the full value of the tax reduction resulting from incurring cost. The calculation of
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this tax loss must be a function of the oil price since given production and costs the oil price level determines the likelyhood of not beeing in a tax position. 4.2 Government changes of tax level One major uncertainty related to future tax payments is government changes of the tax system which may cause changes in the tax base and/or the tax rate. It is likely, given past observations related to tax changes, that governments are inclined to increase the tax level when oil prices are stable and high for some time (1-2 years), and to lower the tax level when the oil prices are very low. One could argue that these tax changes causes the risk to be lower since over the long run this would reduce the upper levels and increase the lower levels of the after tax cashflow of the project to the oil companies while providing the same expected after tax cashflow. However, from past observations, these changes in tax are sometimes only implemented for new projects when prices are low (to stimulate new activity), while they are implemented across the board when prices are high (i.e., a ratchet effect). Given this type of asymmetric tax policy over the business cycle, the risk has increased, or rather, the expected value of the cashflow is reduced by limiting the upside return to the companies and not limiting the downside.
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Consequently, the oil companies will have to take these possible tax changes into account when calculating project value and deciding on new oil projects.
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4.3 Calculating the value of the tax cashflow Separate cashflow valuation methods require use of correct required rates of return when discounting the individual after tax cashflow streams. Given the arguments above the present value of tax on revenues (and consequently the after tax revenue cashflow) should be calculated using a required rate of return based on the before tax beta of revenues. The present value of the expected after tax cost cashflow should, like for revenues, be calculated using the correct required rate of return on the before tax cost cashflow. However, there remains the question of how to adjust for the possible time or actual loss of cost recovery. One possible method would be to assess the probability of this reduction in cost recovery and adjust the cost recovery accordingly. Another approach would be to use a higher required rate of return when calculating the present value of the cost recovery. Both methods would be difficult in the sense that with the first method the probability would be difficult to assess and with the second method the difficulty of finding a correct higher required rate of return. An investigation into oil companies project valuation practise found that the standard discounted cashflow method was the method most in use (Siew, 2001). Even though this study does not distinquish (when asking the energy companies) whether the discounted cashflow method (DCF) is based on discounting net after
19
tax cashflow or indvidual cashflows, it is likely that it has been interpreted by the energy companies as standard net cashflow valuation. The Value Additivity Principle (Shall, 1972) however, makes a separate cashflow discounting method possible since the sum of the individual cashflow values should be equal to the project value. This however, does not necessarily make this valuation approach a practical method. There remains the issue of whether one can obtain reasonable estimates for the required rate of return of the individual cashflow streams. The fact that most energy companies prefer the DCF based on calculating the present value of the net after tax cashflow is probably motivated by the difficulies in finding correct required rates of return for the individual cashflows and/or the above mentioned cost recovery and tax incentive issues. There are, however, also obvious difficulties in finding a correct required rate of return for an individual projects net cashflow (Emhjellen, 1999) , which makes further research into separate cashflow valuation interesting.
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5 Oil project valuation example A valuation of an oil project will be illustrated using real oil project data obtained from Statoil (Project N in Emhjellen, 1999). The project data are given in Table 7. 5.1 Assumptions used in calculating project NPV The expected after tax cashflows used in calculating present values are based on the Norwegian tax regime. The assumptions are as follows:
1)
A 50% special tax is applied to the offshore oil industry. The actual amount of special tax is determined by the tax base, which is calculated as follows: Tax base = Revenue (d) - Operating cost (OC) - Depreciation tax shield (DTS) - Interest payments (IP) - Additional depreciation allowance (ADA). The special tax is equal to the tax base multiplied by 0.5.
2)
An ordinary corporate tax rate of 28% is applied to tax base special tax less ADA (uplift).
3)
Total tax = special tax +ordinary tax With the separate cashflow discounting method of NPV calculation, revenue cashflow tax and cost cashflow tax are equal to:
4)
Revenue cashflow tax = d
(0.5+0.28).
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5)
Cost cashflow tax = total tax - revenue cashflow tax.
6)
The depreciation amount is 6 year linear depreciation applied to investment. This tax benefit can be claimed against other offshore oil revenue of the company (no ring fence on the NCS). When calculating the expected after tax cost and revenue cashflows, the tax effect of the depreciation amount is treated as a reduction in costs.
7)
The additional depreciation allowance (ADA) (applicable to offshore oil development) is 30% of investment treated as 6 year linear depreciation. When calculating the expected after tax cost and revenue cashflows the tax effect of this depreciation amount is treated as a reduction in costs.
8)
All calculations are in US dollars
9)
Expected nominal cashflows (expected cost and expected revenue) were calculated assuming a constant expected inflation rate of 2.0%.
10)
The nominal risk free rate of return is assumed equal to 6.5%.
11)
The expected oil price is assumed constant at a real $20US per barrel.
12)
The market risk premium (E(Rm)-Rf) is assumed equal to 6%
13)
The levered beta for the company is equal to 1 based on Statoil beta level. Given a debt level of 30% and a marginal tax rate of 78% the unlevered company beta is equal to 0.914 (assuming Copeland and Weston, 1992. Pp. 459). This unlevered beta is used as the project beta to reflect business risk.
14)
The required rate of return for the oil projects is calculated to be nominal 11.98% =12% based on assumption 10, 12 and 13.
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Results A cashflow model was created using the Excel spreadsheet (version 5.0). Discounting based on one year periods was chosen for the model because the data are annual. The cashflow results and NPV calculated using the standard net cashflow discounting method (396,4 million USD) are shown in Table 8. With separate cashflow valuation the tax on revenue is the marginal tax rate of 78%. The tax on the cost cashflow however, may not be calculated independantly of revenues since the revenues of the project determines when the costs can be recovered. The tax on cost is then calculated based on the difference between tax on revenues and tax on the whole project. Using a discount rate of 8,3% (1,8% above the risk free rate) when discounting the expeted after tax revenues gives a present value for expected after tax revenues of 1214,4 million USD, while using a discount rate of 7,2% (0,7% above the risk free rate) when discounting the expected after tax cost gives a present value for the expected after tax cost casflow of 532 million USD. This gives a project net present value of 682,4 million, which is 286 million USD higher than the NPV obtained using the standard net cashflow discounting method. This example illustrate the large difference in valuation that might occur when using a separate cashflow valuation method. In this case it is the lower discounting of the revenues that
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gives a high net present value of revenues which is only slightly offset (compared to the standard net cashflow discounting method) by the lower discounting of costs. It is not reasonable to conclude that the separate cashflow method of NPV is more correct than the NPV obtained using the standard net cashflow discounting method. For the standard net cashflow discounting method it is a question of how the required rate of return for the individual project was obtained. For the separate cashflow discounting method the question is if the ex post beta estimates obtained for revenues and costs are reasonable approximations for the ex ante betas. Is the cost risk in wage rates and steel prices (price risk), for instance, representative for overall cost risk in the companies? How should we effectively and objectively account for volume risk and productivity risk, which were the main reasons for cost overruns in the last decade on the NCS? In addition, the rate used in calculating the present value of the expected after tax cost cashflow does not reflect the uncertainty related to cost recovery (depending on revenues) and, while the project required rate of return might reflect a risk adjustment for government tax changes (based on observed market beta for an oil company), it is not likely that the rates used in discounting the separate cashflows include such a risk adjustment. And how should discount factors be adjusted to account for the recent tax changes? These are all reasons why the implementation of a separate cashflow valuation method will be
24
difficult without more reaserch on market data related to the required rates of return of individual cashflow streams. 6 Summary and further work The results indicate that the present value of the expected after tax cost cashflow stream of oil projects in the North Sea should be calculated using a lower rate than that applied to the expected after tax revenue stream. The size of the derived cost betas supports the theoretical recommendations (Laughton and Jacoby, 1993), at least to a first approximation, of using the risk free rate when calculating the present value of the cost cashflow. However, there are reasons, as exemplified by the large difference in net present value of the example project valuation, that further work should be undertaken to examine systematic risk of oil revenues as well as possible other systematic risk factors in the cost cashflow of oil projects. One such factor could be to examine the cost overruns and their correlation with the value of the proxy for the market portfolio. To derive cost betas we have used market prices of wage rates and steel prices. In analyses of the recent cost overruns on development projects, major factors explaining overruns were not input prices but rather volume and productivity risk.7 In addition, for both the standard discounted net cashflow valuation method and the separate cashflow valuation method, there is the challenging issue of how to estimate the risk adjusted value of
7
See Emhjellen et al. (2002).
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the tax effect of the cost cashflow when accounting the possible delay or loss of the tax reduction.
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References Confederation of Norwegian Business and Industry, 1986-1995. Wages and attendance statistics, quarterly. Copeland, T.E. and Weston, J.F. 1992. Financial Theory and Corporate Policy: Third Edition, Addison - Wesley. Pp. 457-459. Emhjellen, M. and Alaouze, C. M. 2002 Project Valuation when There are Two Cashflow Streams , Energy Economics, Vol. 24, September, pp. 455-467. Emhjellen, K., Emhjellen, M., Osmundsen, P. 2002. "Investment Cost Estimates and Investment Decisions", Energy Policy, vol. 30, pp. 91-96. Jacoby, H. and Laughton, D. 1992. "Project Evaluation: a Practical Modern Asset Pricing Method", The Energy Journal, Vol. 13, pp. 19-47. Johnsen, T. 1991. "Criteria for Profitable Investments in Oil Explorations: A Report to the Department of Oil and Energy", Norwegian School of Business, November Lintner, J. 1965. "Security Prices, Risk and Maximal Gains from Diversification", Journal of Finance, Vol. 20, pp. 587-615. Laughton, D. and Jacoby, H. 1993. "Reversion, Timing Options, and Long-Term Decision Making", Financial Management, Vol. 22, pp. 225-240. Laughton, D. 1998 (1). "The Management of Flexibility in the Upstream Petroleum Industry", The Energy Journal, Vol. 19, pp. 83114. Laughton, D. 1998 (2). "The Potential for Use of Modern Asset Pricing Methods for Upstream Petroleum Project Evaluation: Concluding Remarks", The Energy Journal, Vol. 19, pp. 149-153.
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Lewellen, W.G. 1977. "Some Observations on Risk-Adjusted Discount Rates", Journal of Finance, Vol. 32, pp. 1331-1337. Lund, D. 1992. "Petroleum taxation under uncertainty - contingent claims analysis with an application to Norway", Energy Economics, 14, 23-31. Metal Bulletin, 1986-1995. Prices and Data: Iron and Steel, Steel Reinforcing Bars, Brussels Bourse, Metal Bulletin Books Ltd. NOU 2000: 18, Skattlegging av petroleumsvirksomhet (Taxation of the Petroleum Industry), Report by the Petroleum Tax Commission, delivered to the Ministry of Finance, 20 June 2000. Osmundsen, P. 1999. "Risk Sharing and Incentives in Norwegian Petroleum Extraction", Energy Policy 27, 549-555. Osmundsen, P. 1999a. Effektivitet, Insentiver og Proveny (Efficiency, Incentives and Revenue), Report for the Norwegian Ministry of Oil and Energy, scientific attachement to the annual government report on the Norwegian oil industry, Oljemeldingen, St.meld. nr. 39 (1999-2000), 9. June 2000.
Schall, L.D. 1972. "Asset Valuation, Firm Investment, and Firm Diversification", Journal of Business, Vol. 45, pp. 11-28. Sharpe, W. 1964. "Capital Asset Prices: A Theory of Capital Market Equilibrium under Conditions of Risk", Journal of Finance, Vol. 19, pp. 425-442. Siew, Wei-Hun. 2001."The investment appraisal techniques used to assess risk in the oil industry" Conference Proceedings, 24th IAEE International Conference. April 25-27, 2001. Standard & Poors. Platt's Prices and Data, 1986-1984, McGrawHill. Statistics Norway. Monthly Bulletin of Statistics, 1986-1995.
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Appendix Cost data for example project
The cost data for the example project (project N in Emhjellen, 1999) were provided by Statoil and contains a division of the total investment cost into separate groups, see Table 1.
From the investment data presented in Table 1, two principal cost classes can be identified. One class relates to the actual planning, building, and drilling, which is the "work hour" cost of the project. The other class relates to the cost of materials required. For the example project, 60% of the cost is related to the "work hour" group, while 40% is specified as material costs.
We assume that Norwegian data on "work hour wages" related to the oil industry reflect the changes in the "work hour" cost of the development over time. The second cost group, materials, is to a large extent the cost of steel necessary to complete the project. Consequently, the assumption is made that the cost of steel comprises the cost of materials.
Even though these assumptions are simplifications in that work hours and steel do not constitute 100% of the cost of the
29
investment, they may reveal whether the rate of change of these two, at least substantial cost factors, are correlated with the rate of return of the proxy for the market portfolio over the period. The period chosen is from 1986 through 19948.
Offshore industry work hour cost The Norwegian quarterly "work hour cost" is obtained from The Confederation of Norwegian Business and Industry "Wages and Attendance Statistics", 1986-1994. Data were collected for two separate cost groups related to the Norwegian offshore industry.
The first group is data on the work hour wages of oil industry workers performing specific tasks onshore, while the second group is the work hour wages of oil industry workers offshore. The use of these data as a measure of the cost to the oil companies for each work hour is a simplification in that the overall cost of each work hour to the oil companies is not identical to the work hour cost. Overhead costs and employment taxes have to be added to the wage hour cost to get the total hour cost. Because we are only interested in the changes in work hour costs over time, however, it is likely that the changes in wage hour costs would reflect the changes in the total hour cost.
8
Consistent steel price data were not available before 1986.
30
The data on the wage hour cost are shown in Table 2. The wage hour costs are denominated in Norwegian kroner (NOK, 1 krone=100 øre). The first column shows nominal offshore wage hour costs, the second column shows nominal onshore wage hour costs, and the third column shows the Consumer Price Index (CPI)(Monthly Bulletin of statistics, Statistics Norway, 1986-1995). The fourth and fifth columns show the real offshore and onshore wage hour costs, respectively, where the real values have been calculated by deflating the nominal values with the consumer price index.
Data on steel prices The steel price data were obtained from the Metal Bulletin (Metal Bulletin, 1986-1995). The most consistent steel price data found are the data on monthly export steel prices for reinforcing bars at Brussels Bourse. These data were therefore used to estimate the cost of steel to the oil industry. Because 1986 was the first year when consistent steel price data were available in the Metal Bulletin, quarterly averages were calculated from monthly data from that year.
The steel price data are presented in Table 3. The first column shows the nominal price data in US dollars. The second column shows quarterly averages of US/NOK exchange rate, while the third column shows the CPI. The fourth column shows real steel prices
31
quoted in Norwegian kroner using the monthly average NOK/USD and the CPI, both data series obtained from Monthly Bulletin of Statistics. (Statistics Norway, 1986-1995, with quarterly averages calculated from monthly data).
Data on the Total Index of the Oslo Stock Exchange The Total Index is a value index of the stocks listed on "Børs 1" of the Oslo Stock Exchange, with the value on 1 January 1983 given as 100. The monthly data on the Total Index of the Oslo Stock Exchange were obtained from the Monthly Bulletin of Statistics, Statistics Norway. The monthly averages were used to calculate quarterly averages for the period 1986 through 1994. The quarterly Total Index averages were deflated using the consumer price index (all goods and services) with quarterly averages calculated from monthly data (Monthly Bulletin of statistics, 1986-1994). The quarterly Total Index data are shown in Table 4.
Tables Table 1. Investment Cost Data for The Example Project (Millions of 1994 USD)
32
Investment Cost for project N $US Project development cost Administration,management Project planning Fabrication Production ship-deck production ship-body+hookup Under water installations
%of total
74 84
111 101 36
(Investment figures converted to USD) Source: Statoil, Exploration & Production, Finance and Control, Financial Analysis.
33
Table 2. Norwegian wage hour cost in the oil industry
Quarterly 1986
1987
1988
1989
1990
1991
1992
1993
1994
Nominal Nominal Offshore Onshore Workhour Workhour Cost Cost 13236 9966 13617 10331 13230 10217 13953 10289 14823 11367 15125 12342 15373 12130 15508 11683 16340 12062 16708 12206 15987 11762 16203 11644 16320 12101 17043 12184 16525 12353 16576 12074 16966 12277 17421 12756 17099 12863 18125 12457 17840 12655 18144 13048 18600 13404 18437 13437 18744 13276 18852 13651 18576 13327 18736 13500 19276 13642 19665 14041 19406 13962 19591 14014 19691 13850 19916 14090 19801 13968 19845 13714
CPI 177.0333 180.3667 185.7667 189.1333 194.7000 197.8333 200.4333 203.2333 208.3333 211.9667 213.6667 215.5667 218.2667 221.9000 223.3667 224.7000 227.7667 230.3667 231.8000 234.8333 236.5000 238.9333 239.9000 241.0667 242.2333 244.7667 245.7000 246.4333 248.4000 250.8000 250.6667 251.1667 251.5000 253.2333 254.6000 255.7000
Real (quarterly 1986 öre) Offshore Onshore Workhour Workhour Cost Cost 13236.00 9966.00 13365.35 10140.07 12608.03 9736.67 13060.34 9630.75 13477.99 10335.58 13534.77 11044.37 13578.25 10713.86 13508.77 10176.88 13885.08 10249.81 13954.42 10194.38 13246.02 9745.40 13306.65 9562.59 13236.95 9814.97 13597.02 9720.48 13097.19 9790.60 13059.66 9512.69 13186.95 9542.39 13387.78 9802.79 13059.07 9823.90 13663.86 9390.93 13354.23 9472.97 13443.47 9667.68 13725.80 9891.43 13539.67 9867.80 13698.83 9702.61 13635.16 9873.41 13384.50 9602.46 13459.61 9698.16 13737.90 9722.58 13881.02 9911.18 13705.49 9860.66 13808.60 9877.68 13860.69 9749.15 13923.11 9850.20 13768.41 9712.50 13739.64 9494.86
34
Source: Confederation of Norwegian Business and Industry. "Wages and Attendance Statistics" quarterly, 1986-1995. The cost is given in Norwegian øre (1NOK=100øre), and work hour overtime cost is included. The nominal work hour costs are deflated using the consumer price index (all goods and services). The quarterly averages shown in the Table were calculated from monthly data. (Monthly Bulletin of Statistics, Statistics Norway, 1986-1995).
Table 3. Steel Prices (NOK per tonne)
35
Quarterly 1986
1987
1988
1989
1990
1991
1992
1993
1994
Nominal Steel Prices reinforcing bars (US$) NOK/US$ 231.273 7.32333 242.917 7.51667 234.420 7.38667 237.397 7.47000 245.870 7.03667 251.388 6.71000 256.402 6.72667 261.250 6.47667 270.525 6.36333 283.645 6.25667 289.628 6.83667 320.553 6.61000 335.208 6.72333 283.519 7.01000 289.792 7.03667 291.111 6.84667 288.148 6.53333 277.917 6.48667 283.333 6.15000 295.000 5.86333 295.000 5.97333 283.542 6.75333 273.518 6.81333 270.000 6.39333 270.000 6.35333 267.381 6.30667 251.852 5.79000 247.222 6.39667 254.101 6.95333 275.000 6.84667 278.518 7.25333 274.583 7.32333 270.556 7.45000 277.708 7.21000 280.000 6.84333 282.500 6.73667
CPI 177.0333 180.3667 185.7667 189.1333 194.7000 197.8333 200.4333 203.2333 208.3333 211.9667 213.6667 215.5667 218.2667 221.9000 223.3667 224.7000 227.7667 230.3667 231.8000 234.8333 236.5000 238.9333 239.9000 241.0667 242.2333 244.7667 245.7000 246.4333 248.4000 250.8000 250.6667 251.1667 251.5000 253.2333 254.6000 255.7000
1986 NOK per tonne Steel Prices reinforcing bars (NOK) 1693.69 1792.18 1650.18 1659.90 1573.12 1509.47 1523.37 1473.90 1462.81 1482.20 1640.60 1740.10 1827.96 1585.61 1616.18 1570.33 1463.24 1385.39 1330.80 1303.95 1319.05 1418.77 1375.22 1267.68 1253.68 1219.64 1050.69 1136.05 1259.22 1329.04 1426.76 1417.35 1418.83 1399.78 1332.36 1317.61
Source: Metal Bulletin, Prices & Data, Iron & Steel, Steel Reinforcing Bars, Export Price, Brussels Bourse, 1986 -1995. The nominal prices were deflated using
36
the consumer price index (all goods and services), with the quarterly averages shown in the Table calculated from monthly data. (Monthly Bulletin of statistics, Statistics Norway, 1986-1994).
Table 4. Total Index
37
Quarterly Nominal values Total Index (Oslo S. E.) 1986
1987
1988
1989
1990
1991
1992
1993
1994
292.000 274.667 282.000 290.667 293.667 324.000 384.333 302.000 269.667 288.667 286.667 304.000 407.333 485.000 516.000 500.333 599.667 620.667 611.333 483.000 457.333 500.000 506.333 436.667 428.000 432.333 344.000 361.000 409.333 479.333 549.000 601.333 670.333 625.000 629.667 628.667
CPI 177.0333 180.3667 185.7667 189.1333 194.7000 197.8333 200.4333 203.2333 208.3333 211.9667 213.6667 215.5667 218.2667 221.9000 223.3667 224.7000 227.7667 230.3667 231.8000 234.8333 236.5000 238.9333 239.9000 241.0667 242.2333 244.7667 245.7000 246.4333 248.4000 250.8000 250.6667 251.1667 251.5000 253.2333 254.6000 255.7000
Quarterly Real values (1986) Total Index (Oslo S. E.) 292.00 269.59 268.74 272.07 267.02 289.93 339.46 263.07 229.15 241.09 237.52 249.66 330.38 386.94 408.97 394.20 466.10 476.97 466.90 364.12 342.34 370.47 373.65 320.68 312.80 312.70 247.86 259.34 291.73 338.35 387.73 423.85 471.85 436.93 437.83 435.26
38
Source: Statistics Norway. "Monthly Bulletin of Statistics", Statistics Norway 1986-1995). Quarterly averages which are shown in the Table were calculated from monthly data. The nominal values were deflated using the Consumer Price Index (all goods and services).
39
Table 5. Rate of change: Wage Hour Cost, Steel Prices, and the Total Index
1986
1987
1988
1989
1990
1991
1992
1993
1994
Quarterly real rate of change (%) Total Index Offshore Onshore Steel Prices Oslo Stock work hour work hour reinforcing Exchange cost cost bars -7.67 0.98 1.75 5.81 -0.31 -5.67 -3.98 -7.92 1.24 3.59 -1.09 0.59 -1.86 3.20 7.32 -5.23 8.58 0.42 6.86 -4.05 17.08 0.32 -2.99 0.92 -22.50 -0.51 -5.01 -3.25 -12.89 2.79 0.72 -0.75 5.21 0.50 -0.54 1.33 -1.48 -5.08 -4.40 10.69 5.11 0.46 -1.88 6.06 32.33 -0.52 2.64 5.05 17.12 2.72 -0.96 -13.26 5.69 -3.68 0.72 1.93 -3.61 -0.29 -2.84 -2.84 18.24 0.97 0.31 -6.82 2.33 1.52 2.73 -5.32 -2.11 -2.46 0.22 -3.94 -22.01 4.63 -4.41 -2.02 -5.98 -2.27 0.87 1.16 8.22 0.67 2.06 7.56 0.86 2.10 2.31 -3.07 -14.18 -1.36 -0.24 -7.82 -2.46 1.18 -1.67 -1.10 -0.03 -0.46 1.76 -2.71 -20.73 -1.84 -2.74 -13.85 4.63 0.56 1.00 8.12 12.49 2.07 0.25 10.84 15.98 1.04 1.94 5.54 14.59 -1.26 -0.51 7.35 9.31 0.75 0.17 -0.66 11.33 0.38 -1.30 0.10 -7.40 0.45 1.04 -1.34 0.21 -1.11 -1.40 -4.82 -0.59 -0.21 -2.24 -1.11
40
Numbers are real percentage rate of change (average for quarter) from one quarter to next quarter, with the numbers in first quarter of 1986 representing the rates of change from the first quarter of 1986 to the second quarter of 1986. Rates of change are rounded to two decimal points.
41
Table 6. Oil Price (WTI) and percentage change.
WTI Price Exchange rate USD/barrel NOK/USD 1986
1987
1988
1989
1990
1991
1992
1993
1994
17,243 13,967 13,819 15,411 18,238 19,383 20,401 18,651 16,683 17,231 15,191 14,807 18,523 20,532 19,294 20,349 21,784 17,755 26,211 32,177 21,958 20,772 21,656 21,781 18,895 21,213 21,653 20,497 19,829 19,742 17,799 16,429 14,833 17,848 18,474 17,655
7,3233 7,5167 7,3867 7,4700 7,0367 6,7100 6,7267 6,4767 6,3633 6,2567 6,8367 6,6100 6,7233 7,0100 7,0367 6,8467 6,5333 6,4867 6,1500 5,8633 5,9733 6,7533 6,8133 6,3933 6,3533 6,3067 5,7900 6,3967 6,9533 6,8467 7,2533 7,3233 7,4500 7,2100 6,8433 6,7367
CPI Index 1,0000 1,0188 1,0493 1,0684 1,0998 1,1175 1,1322 1,1480 1,1768 1,1973 1,2069 1,2177 1,2329 1,2534 1,2617 1,2693 1,2866 1,3013 1,3094 1,3265 1,3359 1,3497 1,3551 1,3617 1,3683 1,3826 1,3879 1,3920 1,4031 1,4167 1,4159 1,4188 1,4206 1,4304 1,4382 1,4444
Real WTI price Real % change NOK per barrel WTI per barrel 126,2800 103,0500 97,2800 107,7600 116,6900 116,3900 121,2100 105,2200 90,2100 90,0400 86,0500 80,3800 101,0100 114,8300 107,6000 109,7700 110,6200 88,5100 123,1100 142,2300 98,1800 103,9400 108,8800 102,2600 87,7300 96,7600 90,3300 94,1900 98,2600 95,4100 91,1800 84,8000 77,7900 89,9600 87,9100 82,3400
-18,3971 -5,5971 10,7710 8,2916 -0,2608 4,1447 -13,1885 -14,2683 -0,1873 -4,4330 -6,5901 25,6671 13,6798 -6,2915 2,0113 0,7774 -19,9907 39,0986 15,5274 -30,9684 5,8623 4,7582 -6,0795 -14,2080 10,2897 -6,6441 4,2685 4,3272 -2,9042 -4,4361 -6,9918 -8,2747 15,6529 -2,2839 -6,3276
Real % change Total Index -7,6745 -0,3146 1,2385 -1,8565 8,5818 17,0827 -22,5050 -12,8923 5,2109 -1,4830 5,1118 32,3337 17,1175 5,6932 -3,6115 18,2397 2,3338 -2,1128 -22,0129 -5,9813 8,2160 0,8586 -14,1764 -2,4568 -0,0330 -20,7340 4,6296 12,4910 15,9804 14,5950 9,3144 11,3268 -7,4010 0,2059 -0,5883
42
WTI prices obtained from Standard & Poors Platt's Prices and Data. The CPI was calculated using the consumer price numbers given in Table 3.
43
Table 7. Oil Project Data.
Production
Real inve-
Real oper-
stment cost
ating cost
Mill. barrels
Mill USD
MUSD
Sum
442,4
1402,9
1533,3
0
0,00
28,60
0,90
1
0,00
417,10
10,30
2
0,00
588,60
20,40
3
0,00
257,90
41,80
4
55,50
72,10
115,80
5
57,10
38,60
120,20
6
56,80
0,00
119,50
7
54,00
0,00
117,90
8
46,40
0,00
113,60
9
37,80
0,00
109,40
10
30,80
0,00
105,70
11
24,20
0,00
102,30
12
20,30
0,00
100,00
13
16,50
0,00
97,90
14
13,80
0,00
96,30
15
10,80
0,00
87,70
16
9,60
0,00
87,00
17
8,80
0,00
86,60
YEAR 13,7% 4,7%
44
Table 8. Project Cashflows and WACC method for calculating NPV
Total Tax payments
0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17
Nominal Net CF. before tax -29,5 -435,9 -633,6 -318,0 998,1 1085,5 1144,7 1105,2 954,2 772,7 622,1 474,6 388,1 300,2 237,1 172,7 144,1 125,2
0,0 0,0 0,0 0,0 111,7 653,5 670,9 706,0 683,2 584,0 478,6 370,2 302,7 234,2 184,9 134,7 112,4 97,6
Total Cashflow after tax -29,5 -435,9 -633,6 -318,0 886,4 432,0 473,8 399,2 271,0 188,7 143,5 104,4 85,4 66,1 52,2 38,0 31,7 27,5
Tax on revenue cashflow 0,0 0,0 0,0 0,0 937,2 983,5 997,9 967,7 848,1 704,7 585,7 469,4 401,6 333,0 284,1 226,8 205,6 192,2
Tax on cost cashflow 0,0 0,0 0,0 0,0 -825,5 -329,9 -327,0 -261,7 -164,9 -120,7 -107,1 -99,2 -98,9 -98,8 -99,1 -92,1 -93,2 -94,6
Revenue Cashflow after tax 0,0 0,0 0,0 0,0 264,3 277,4 281,5 272,9 239,2 198,8 165,2 132,4 113,3 93,9 80,1 64,0 58,0 54,2
Cost Cashflow after tax -29,5 -435,9 -633,6 -318,0 622,1 154,6 192,4 126,2 31,8 -10,1 -21,7 -28,0 -27,9 -27,9 -28,0 -26,0 -26,3 -26,7
18 19 20 21 22 23
0,0 0,0 0,0 0,0 0,0 0,0
0,0 0,0 0,0 0,0 0,0 0,0
0,0 0,0 0,0 0,0 0,0 0,0
0,0 0,0 0,0 0,0 0,0 0,0
0,0 0,0 0,0 0,0 0,0 0,0
0,0 0,0 0,0 0,0 0,0 0,0
0,0 0,0 0,0 0,0 0,0 0,0
