Economic Terms

This page provides background information on important economic termsfinancial figures of merit.

Discount rate

The discount rate is an input parameter to calculate levelized costs. This rate takes the time value of money into account, i.e. money earned in the future has less value than received today. An appropriate discount rate has to be selected by an economic analyst to be used for the market that the analyst is considering for deployment of an NPP. The analyst has to determine and gather the information needed to make this judgment. If the analyst is from a utility (the future owner/operator of the NPP), he/she would have ready access to this information. In other situations, the analyst might need the assistance of a specialist who is knowledgeable about the capital markets in the country or region in which the NPP is to be deployed.
As shown in many studies, the results of an economic assessment, and particularly the cost comparisons between energy alternatives, can be sensitive to the discount rates used. The choice of a discount rate for decision making by a given analyst will depend on its specific situation and the overall economic, regulatory and commercial framework of the country. Although there is extensive published literature on discount rates and their relationship with financial risk and required rates of return for private or public investor, there is no consensus view on the matter.
As a rule of thumb, real discount rates for a government owned utility in a regulated market could be expected to vary in the range from about 3–5%, for a private sector utility operating in a regulated market from about 5–10%, and for a private utility operating in a deregulated market from about 10–15%.
The value of the discount rate is linked to the interest that an investor has to pay for long term bonds, i.e. in the case of the government as investor the discount rate used should not be lower than the interest the country has to pay on its long term bonds.

Load factor and anticipated plant lifetime

Load factor and anticipated plant lifetime are important since they determine how capital costs are accounted for. A constant (plant life average) load factor might be used, or a time dependent load factor might be used to reflect time dependent factors such changes in thermal efficiency resulting from changes in fouling factors, clearances, etc. The approach to be followed will depend on the information available to the assessor and on the level of detail that the assessor wishes to include in the assessment. However, to be consistent, when a given factor associated with plant ageing is taken into account for a nuclear plant in a given assessment, similar ageing effects should be included for the alternative energy sources, such as the decrease in the efficiency of gas turbines resulting from blade erosion, combustion chamber depositions and debris, etc. The aim is to make an unbiased comparison of equivalent costs.

Costs for generating electricity

The costs for generating electricity are usually divided into capital investment (CI) costs, operating and maintenance (O&M) costs and fuel (F) costs. Information on CI, O&M and F costs and on the timing of such expenditures, over the plant lifetime, should be provided by the (potential) supplier(s) — based on a cooperation agreement — to the analyst, who can then discount them using an appropriate discount rate to determine the NPV of these costs, and hence the LUEC. As noted above, it is the responsibility of the analyst to determine the discount rate to be used.
For simplicity, a useful approximation is to assume that the amortization time over which costs are recovered from revenues for a given plant is the plant lifetime. This avoids the complexity associated with power upgrading and updating that might be undertaken for a plant that has already been fully amortized. But requirements for and the costs of back fitting that are foreseen to be undertaken during the plant lifetime need to be taken into account. This is especially important for technologies with relatively short durations between necessary major refurbishments, such as gas turbines or wind turbine technologies.
After fixing the time base for all the calculation of an economic assessment, all the costs, obtained from different sources need to be compared in constant money terms and expressed for a reference time base. Because it is almost certain that all necessary (published) price data will not be expressed in constant money terms for the same date, appropriate currency deflationary or inflationary factors will be needed to convert cost and prices to values for the reference year. This is important when the results of an assessment using the INPRO methodology are to be compared with results from other studies, and when comparing costs between different technologies for a given INPRO assessment.

Investment costs

1. Direct construction costs (also called overnight capital cost): These costs include the cost of the plant components and materials, and the labour required for installation. Additionally, they contain costs for land and land rights, structures and improvements, plant equipment including generator and electrical equipment such as switch gear and transformers, and special materials (such as the moderator for a HWR or the coolant inventory for a lead bismuth reactor).
2. Contingency allowances: The plant investment should include a contingency allowance to provide for unforeseen or unpredictable costs. Often, the designer can determine an appropriate allowance item by item or as a lump value for all the direct construction costs. The contingency allowance will depend on the maturity level of the design and on gaps in engineering knowledge. It also depends on the source of cost estimation (based on ordered plants, paper analysis, quotation, feasibility study or previous experience), or the degree of innovation (proven design, extrapolated design, or innovative design).
3. Indirect construction costs: A number of indirect construction costs must be added to the direct construction cost to obtain the total plant investment. These often include the cost of contracting, design, engineering, inspection, startup, and interest during construction. Indirect costs also cover construction facilities, equipment and services, including buildings and other facilities that are removed after construction has been completed. Indirect costs also include taxes and insurance, if they are applicable (see the discussion of fiscal regimes presented in Section A.1.2). Costs for staff training and for plant startup as well as costs incurred by the owner in carrying out the project, such as the costs of licensing, public relations and administrative overheads are also in the category of indirect costs. Indirect construction costs can vary considerably depending on differences in accounting systems and the experience of the contractor in building a specific plant.
   

What is included in direct costs and in indirect construction costs can depend on contractual arrangements. In a fixed price ‘turnkey’ contract many indirect costs listed above maybe be included in the fixed price. Thus, care needs to be taken to ensure that all costs have been identified and evaluated but also to ensure that costs are not double counted.

1. Backfitting cost: This cost includes all the major refurbishment costs not included in the annual O&M costs, and required to keep the performance of the plant within declared values. Examples include costs for steam generator replacement, or, in the case of pressure tube reactors, pressure tube replacement, or, in the case of pressure vessel reactors, vessel refurbishments such as replacement of internals or annealing. The total cost for such backfitting, and the time when the capital expenditure is required, need to be included when calculating levelized generating costs, consistent with the assumed plant lifetime over which costs and revenues are levelized.
2. Decommissioning, waste management and waste disposal costs: The costs of decommissioning, waste management and, in particular, waste disposal, also need to be estimated and taken into account when calculating levelized costs as defined in the INPRO methodology requirements in the area of waste management [12]. The costs of decommissioning and waste management, including placing the waste into its end state, are often converted to annual costs and are treated as such, either as a fuel cost or an operating cost or some combination of the two, by calculating the NPV of the funds that have to be set aside on an annual basis to cover the cost of decommissioning and residual waste management costs at the end of plant life. The costs of ongoing waste management activities, such as waste processing and interim storage of wastes, are usually included as an operating or fuel cost. The analyst should obtain information on such costs from the plant developer/supplier.

Fuel costs

Fuel expenses are the second major component of nuclear power costs, and the most important cost for fossil fuel plants. If, in the NES description, the assessor proposes a system with fuel fabricated or negotiated in detail inside the system (and not bought as a single item at fixed price), the analysis becomes more complicated. A detailed accounting of fuel cycle costs is relatively complicated, since a number of operations are involved and levelized costs are sensitive to the irradiation time in the reactor as well as to numerous financial and process variables.

1. Fuel element costs: In nuclear plants, the classical fuel costs are expressed in $/kg of heavy metal included in the fuel (uranium, plutonium or thorium), and the way to perform the assessment of such costs depends on the scope of the system. In a system with a single contract for the fuel supply during the entire plant life without any concern about external price evolution, resource depletion, etc., only the price of the final (fabricated) fuel elements and schedule for payment are needed. This approach may or may not include the spent fuel management costs.
   

In a detailed fuel cycle assessment, three main items are required:

• Fuel material costs. These include the costs of mining, milling and processing the original ore, and, for enriched fuels, the costs for enrichment and conversion.
• Costs of manufacturing fuel elements and of processing the irradiated material. In general, larger production volumes lead to lower unit costs so purchasing fuel from a manufacture supplying many units would be expected to be significantly cheaper than building a dedicated plant to supply a small number of units.
• Levelized costs. Since the time required for one complete fuel cycle operation could be of the order of two–six years [26], levelized costs are sensitive to the discount rate used and the timing of expenditures, and these considerations need to be specifically addressed.

1. Fuel loading costs. The costs for two types of fuel loadings (into the reactor) can be distinguished, namely the cost for the first reactor core and the costs for routine refuelling. The cost of the first reactor core load of fuel represents an investment that is amortized over the plant life. This fuel needs to be supplied prior to plant startup. The costs can be significant, particularly for low power density cores, high enrichment cores, or long life cores. The second cost covers the ongoing periodic expenditures for new fuel necessary to replace the losses of fissile material (e.g. uranium) by burnup due to the power generation between refuelling. The first core implies a fuel demand bigger than any refuelling demand during the plant life, and the payment needs to be done in advance of commercial operation. Thus, it can be a significant contributor to LUEC, particularly if a high discount rate is used.
2. Spent fuel costs and credits. Two other costs are relevant for the fuel cycle, i.e. the spent fuel management cost, and the reprocessing cost; the related high level waste (HLW) management costs need to be accounted for. In the latter case, a credit for fissile content in spent fuel may be included. Such costs include the costs for interim storage and for disposal.

Operation and maintenance costs

The O&M expenses include the direct and indirect payroll costs for plant personnel, the cost of special materials, makeup, e.g. of heavy water or of special coolants, and general supplies. Miscellaneous O&M costs include items such as public relations, training, rents and travel. It also includes liability insurance and the fixed charges for the working capital to pay for items in the O&M category. O&M is usually divided into fixed O&M costs, including those that do not depend on the energy generated each year, and variable O&M costs, including those that depend on the energy generated. Usually variable O&M costs are proportional to the annual electricity output.

Consistency of cost data

The approach used in INPRO methodology requires the comparison of costs and other financial data for different alternatives for investment into energy sources. Thus, it is important to use cost data that are consistent for the different types of energy systems and for different options of the same type of energy system.
Consistency of cost data can be a major challenge when the assessor is dealing with different types of technology. For example, care must be taken when comparing data from commercial facilities that have already been deployed with estimated data for a future deployment of a plant for which an FOAK has not yet been constructed. The reliability and the basis of estimating costs for the two types of facilities could be so different that, even with the best of intentions, estimates may still be biased in favour of one option or another. Another source of inconsistency could be produced when costs for different scopes of supply are classified under the same name. This type of wording mismatch could happen in the comparison of the direct cost of a nuclear reactor and a fossil fuel plant. For example, if a nuclear reactor requires a cooling tower, the cost will usually be included in the direct plant cost, but for some fossil fuel plants (e.g. some combined cycle gas turbines contracts) the cooling tower could be included as an owner’s cost. Thus, it is very important to be clear about what is really included in the investment cost component for one system compared with that for an alternative.
Some authors recommend that particular care be taken when fossil fuel alternatives are considered, to be clear as to what is included in the cost of a turnkey project’s scope. For example, gas turbines fuelled with natural gas could require additional investment in gas pressure reduction systems, if they are supplied from a high pressure pipeline, or natural gas compressors, if the turbine is supplied from a low pressure pipeline. Gas turbines fuelled with liquefied natural gas require storage and transfer facilities. It needs to be ascertained whether the cost of such facilities are included in the fuel price or in the project investment or have not been included.
As well, what is included within the definition of direct cost could change from one technology to another. For example, some technology suppliers could include the cost of the condenser in the direct cost, but it may not be included in the published data of a supplier of a different technology.
Standardized accounting systems are available for nuclear power plants. The IAEA has developed a well known comprehensive accounting system capable of addressing a wide spectrum of costs. Some countries use their own cost accounting system . For INPRO methodology, only a very simple cost definition is required.

Financial figures of merit

Levelized unit energy costs are recommended in the INPRO methodology to be used for comparing energy costs. However, other financial figures of merit are needed to perform an INPRO assessment in the area of economics, for example to evaluate the profitability of investment and hence its attractiveness.
To calculate the profit produced by the electricity generation, two different types of financial figures could be used, and different data are required:

• Undiscounted profit measurement: Using real values for measuring profitability without using the levelized concept, several figures could be used, such as payback time or ROI. In the current version of the INPRO Manual, ROI is used. To do so, requires the value for the PUES. The method of calculating the PUES may vary between Member States. In some Member States, it may be obtained by modelling the grid load dispatch from published values for the grid, or by comparison with other active generation plants costs in the grid.
• Discounted profit measurement: Using real values, the classical figures for the discounted profit calculation is either IRR or NPV of profit. For both of them, the only additional variable is the reference PUES, as is required by ROI. So they could be easily used by INPRO. As the INPRO methodology provides some reasonable flexibility in selecting economic indicators, both NPV and IRR will be used.

These figures of merit are not unique, and the INPRO assessor could define his or her own figures of merit depending on the country or company investment policy. For example, a country interested in nuclear energy as an introduction of a 21st century technology will be interested in the total levelized investment. Such a country might compare investing in a small power reactor in competition with investing in a research reactor.
To calculate the PUES, state of the art computational tools, such as MESSAGE, WASP or BALANCE, could be used. As well, simple price estimation methods could also be applied, depending on the scope of the assessment and the expertise and time commitment of the assessor.
To use computer codes to calculate PUES requires judgment with regard to the use of the results to be obtained from the assessment. Different codes have been developed with different objectives utilizing different approaches to model a complex reality. The codes available tend to be more complementary than an alternative. Some codes have been programmed in order to simulate long term energy evolution; others have been developed for short term very detailed modelling.
Thus, expert judgment needs to be applied when an assessor wants to use complex codes and modelling. International agencies and institutes, such as the IAEA can provide assistance to help interested code users in energy studies and planning.

Fiscal regimes

Fiscal regimes, including for example taxation policies, central bank rate policies, exchange rate policies, have a significant impact on the calculated generating cost of electricity. These vary from country to country and also on a local, national, and regional basis. The introduction of simulated harmonization of fiscal regimes has not been possible and only a common very high level fiscal regime policy could be considered, for example a special tax or insurance for a given technology, etc. The calculations of generating costs usually are carried out without income and profit taxes because such taxes do not affect the relative competitiveness of different energy sources. On the other hand, taxes on fuels, emissions and plant specific taxes that may differ from plant to plant should be included in the cost if they are relevant for the assessor.

Constant and current money term

Cost elements could be expressed in constant or current money terms. Current money means money as spent or earned. Future payments in current money are calculated using nominal inflation and nominal interest rates. Constant money means money of constant value, i.e. ignoring inflation. Future payments in constant money are calculated using real escalation and real interest rates.
Cost elements used in the calculation of the generating costs of power plants are normally expressed in constant monetary terms, as it is generally accepted that calculations performed in constant money are best suited for comparison. So, no inflation correction needs to be included in time dependent cash flows and variation in future prices of the components are considered as a drift in the constant money price. Hence the so-called real discount rate needs to be used for present value calculations.

Currency exchange

The choice of a common currency unit is essential when different economic data sources are used for different components and systems in a given NES and for alternative technologies. The assessor should be extremely cautious in comparing cost data from different countries even when they are expressed in a common monetary unit. Usually, the use of constant prices properly accounts for most deviations, but as pointed out in several studies, exchange rates do not necessarily reflect purchasing power parities accurately, and so their use might affect cost comparisons between countries in a way that does not correspond to actual cost differences.

Price setting

Usually, the costs discussed in the INPRO methodology will refer to the cost of new power supplied to the station bus bar, where electricity is fed to the grid. Thus, it would exclude costs of transmission and distribution to end users. But, for some energy scenarios the cost to transport electricity may need to be included in the assessment in order to study, e.g. the advantages and disadvantages (trade off) of small and medium size, dispersed power systems compared with large centralized plants. While such an issue is usually not considered in economic assessments it could be relevant for some assessors.

Source of capital

In many countries, domestic savings are the main source of capital for infrastructure projects, including energy and electricity infrastructure. The availability of domestic capital will be most constrained in developing countries. Even where domestic savings comfortably exceed the energy sector’s demand for capital, energy companies will still have to compete with other sectors for domestic financial resources. In addition, energy investment may involve large projects, even mega projects, and in such cases the excess of domestic savings over energy investment requirements could be much smaller. Furthermore, domestic savings need to be mobilized through financial markets.
The shortfall between investment requirements and domestic savings in some countries highlights the need to mobilize capital inflows from abroad, especially from developed countries, where domestic savings exceed investment. Dependence on external financing brings both benefits and risks. Financing from abroad often reduces the cost of capital and provides longer debt maturity. At the same time, overdependence on foreign investment flows can strain a national economy, large capital inflows can affect exchange rates, and future currency depreciations would increase the debt burden.
Energy projects are usually more capital intensive than projects in most other industries and often involve large initial investments before production can begin. The electricity sector is the most capital intensive of all the major industrial sectors, measured by capital investment per unit of value added. The more capital intensive an industry, the more exposed it is to financial risks such as changes in interest rates and other events in financial markets. Energy investments are exposed to differing types and degrees of risk, with consequences for the cost and allocation of capital. The higher the risk associated with an investment, the higher the cost of capital and the higher the return required by investors and lenders.
Profitability is the key factor in company’s ability to raise funds for investment, whether on a corporate or a project basis. If the capital employed in a company is not generating an adequate return (measured in its own criteria) the company will have limited access to new capital.