WÄRTSILÄ TECHNICAL JOURNAL 02.2010

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Lifecycle cost knowledge will impact power plant investment decisionsAU T H O R : A n d re a s B a c k , M a n a g e r, W ä r t s i l ä D e v e l o p m e n t a n d F i n a n c i a l S e r v i c e s

A power plant’s long term profitability should be calculated using realistic lifecycle costs rather than being based on new and clean ISO values. How should these lifecycle costs (LCC) be determined and incorporated into the investment decision process?

The long term global trend towards increasing demand has put ever growing pressure on power supply investment decisions. Even though electricity is not explicitly mentioned in Maslow’s hierarchy of needs, one can easily understand the importance of power supply security for the wellbeing of the population. Due to the recent turbulence in the financial markets and the subsequent global investment hesitation, decisions are now being made faster than ever for areas in need of electricity to secure a sufficient supply, but slower than ever elsewhere. Consultants and decision makers tend to assess the alternatives the easy way by looking only at today’s

Definitions: ■ NPV = Net present value. The value today of future cash flows. ■ IRR = Internal rate of return. The higher a project’s internal rate of return, the more desirable it is to undertake the project.

■ Pay-back time = The time span required to recover the cost of an investment. ■ Discount rate = The rate of return that could be earned on an investment in the financial markets with similar risk.

price tag, and are less concerned with the effects of lifecycle costs and their impact on the long term profitability and competitiveness of the power plant.

Determining the LCC has become an art in itself, thanks to the various characteristics of the different means of power generation. At one end we have renewable energy sources, like wind and hydro power, with high capital expenditures but low operational costs. Then there are small, diesel-fired generators, which have quite the opposite cost structure, with reasonably low investment costs but having modest efficiencies and expensive fuel. The purpose behind the plant also has an effect on the LCC. It may be a developer looking at an

Independent Power Producer (IPP) project, or perhaps an industrialist looking to increase his own electricity production capacity. Different decision criteria apply when planning investments in new power generation.

Nonetheless, the key criteria when choosing the optimal power generation technology are still the basic parameters of net present value (NPV) of project cash flows, the internal rate of return (IRR) in relation to the perceived risk of the investment, and pay-back time. Hence, understanding the concept of LCC, as well as the accuracy of the assumptions underlying the LCC calculations, remains crucial for power industry decision makers.

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The role of assumptionsIn order to analyze different options for electricity production, LCC financial models are used. However, the results of a model, be it at any level of complexity, is never better than its inputs. You’d think that the more sophisticated and detailed the financial model is, the more accurate the calculated results will be. This is unfortunately not the case, as the calculated results will always depend on the reliability of the underlying assumptions. If we take the fuel cost component, which is usually the largest component of the LCC in thermal power production, it is not enough merely to know what the fuel consumption of the proposed power plant will be on day one; i.e. the ISO heat rate guaranteed by the EPC contractor or the manufacturer. We also need to evaluate the impact of time and ambient conditions on the actual heat rate during the full lifetime of the power project.

The plant’s dispatch and load curve will likewise have an important influence on the LCC. It is noteworthy that many manufacturers tend to market their products applying ISO conditions, displaying a performance based on the maximum tolerances stated at generator terminals. Hence, the actual average heat rate at reference conditions over the plant’s lifetime will be substantially higher than that stated in the marketing material. Such unrealistic input can distort any realistic comparison. In particular, technology specific or solution specific figures should always be verified and guaranteed by the EPC contractor/manufacturer.

Lifecycle cost parametersThe LCC of a power generation facility

incorporates all foreseen costs associated with the acquisition and the long-term ownership of the asset over its entire life. The up-front acquisition cost is usually the most easily quantifiable, and also the single largest factor in the LCC. But it is certainly not the only item, nor necessarily the largest component of the total LCC seen over the measured time period. The list of parameters varies a lot but most drivers can nevertheless be summarised under the following headlines:

Capital cost related parameters ■ Up front investment costs (equipment, buildings etc.)

■ Implementation time (engineering, development, construction etc.)

■ Debt parameters (interest during construction, interest rates, debt service reserves etc.)

■ Other costs (fuel reserves, working capital, consulting etc.)

■ Contingencies.Fuel cost related parameters

■ Fuel price and quality ■ Plant efficiency ■ “New and clean” vs. lifetime efficiency ■ Part load efficiencies ■ Start up time and efficiency impact ■ Load following capabilities and efficiency impact

■ Plant output ■ Derating over time (heat rate and power output)

■ Ambient conditions.

Operating parameters ■ Variable costs related to generation ■ Fixed fees irrespective of generation ■ Fuel flexibility ■ Availability and reliability.

Of these parameters the consequences of part load, ramp-up, and load following are the ones most likely to be disregarded by evaluators, even though they play a crucial role in the LCC calculations.

Some renewable production forms, such as wind and solar, are not exposed to the price of fuel but rather to the availability of their respective natural forces. Calculating their LCC deviates considerably from that of thermal power production because of their nature of high unpredictability, and will not be further commented upon in this article.

Thermal production alternativesEntrepreneurs looking at investing in thermal power production have in theory a number of options to consider, even though external factors such as legislation and fuel availability often restrict the range of opportunities. Coal is still, in many parts of the world, the number one choice for large baseload power plants. But emission aspects are playing an ever greater role in investment decisions, something that doesn’t work in favour of coal fired power generation.

At the smaller end, diesel generators dominate, as they are flexible and easy to operate. Burning light diesel fuel is, however, an expensive way of generating electricity, which naturally lowers the feasibility and use of diesel generating sets. Heavy fuel oil (HFO) is used in boilers, engines and turbines, but World Bank Guidelines on emissions constrain that market as well. The main alternative left for the entrepreneur to consider for small and mid-scale power production is, providing the fuel is available, natural gas fired generation; often meaning either

Table 1 – Technology specific assumptions.

Wärtsilä assumptions10*20 MW units, Wärtsilä 50SG

CCGT assumptions1*200 MW unit, USD 535/kW

EPC cost 400 EUR/kW 412 EUR/kW

Total investment cost (incl. IDC) 82 MEUR 86 MEUR

Contruction time 12 months 24 months

Efficiency (ISO) 47% 52%

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Total life cycle costs CCGT (ISO, 20 years)

Fuel Var O&M Fixed O&M Interest Repayment

Total life cycle costs Wärtsilä (ISO, 20 years)

Fuel Var O&M Fixed O&M Interest Repayment

68%11%

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combined cycle gas turbines (CCGT) or an internal combustion engine solution.

In the following chapter we will analyse some of the diff erences between these alternatives. How do we determine the LCC of a gas power plant as accurately as possible? Which factors are critical for the life time economics of the plant? And how can one recognise misleading information circulating on the market?

Gas engines or gas turbines?Before conducting any numerical analysis,the customer should ask himself some elementary questions:1. Why am I investing in power generation?2. What will the electricity be used for?3. How am I going to run my plant?4. What do I value?5. What do reliability, availability and fl exibility mean to me?6. What is the cost of time?

In a standardised ISO world, where the ambient conditions are perfect and good quality gas always available, and where the plant is dispatched fl at out at 100% load all year long, the customer should probably opt for a CCGT for plants sized 200 MW and above. Unfortunately the ISO world doesn’t exist, altitudes and temperatures vary, plants are started and stopped and run on part load, fuel interruptions may occur, and construction time does have a price. Th erefore, it is critically important to conduct an objective and all-inclusive LCC analysis before jumping to any conclusions.

Let us now analyse a power plant investment, starting from the brochure data and moving closer to a real scenario. We’ll focus on the main components of a gas power plant’s LCC:

■ Fuel ■ Investment cost ■ Operations and maintenance (OAM).

Th e following parameters are used in the simulations:

■ Project size: 200 MWe ■ Gas cost: 6.5 USD/MMBtu ■ Annual operating hours: 6000 ■ Lifetime: 20 years ■ 100% debt fi nancing, 10 year tenor at 5% interest p.a.

■ Fixed costs: EUR 200,000/month ■ Discount rate: 12% ■ USD/EUR FX rate: 1.3.

Fig. 1 – Combined cycle plant prices 2010. Source: Gas Turbine World.

Fig. 2 – Apportioned discounted lifecycle costs. (Iso conditions over 20 years.)

Furthermore, the following solution specifi c assumptions have been made. Th e engine option is a Wärtsilä 50SG solution. Th e EPC price for the CCGT is taken fromthe Gas Turbine World Handbook 2010,p. 53.

Based on the above assumptions, at 100% load and plant effi ciency (net ISO conditions) of 52.2% (“new and clean”), the total discounted LCC (comprising fuel, O&M, interest and repayment) of the CCGT power plant is EUR 411 million. Th e corresponding fi gure for the

Wärtsilä solution is EUR 459 million, a diff erence of EUR 48 million in favour of the CCGT. Th e fuel component, at 60–70% of the total LCC, is by far the single largest item (Figure 2).

Load correctionAs plant performances are quoted at full load, to begin with we have to adjust the values to refl ect reality. Assuming a 100% plant load level over the 20 year time period can hardly be justifi ed. A more

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Budget prices are expected to decline from an average price ratio of USD 900 per kW

for a 10 MW plant to USD 500 for 400 MW and level off beyond that at close to USD 430 per kW.

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reasonable level would be at 80% plant load, since equipment requires maintenance, which results in downtime. Even though CCGTs don’t loose efficiency as rapidly as simple cycle gas turbines, there is still an estimated 2.5% loss in heat rate if the turbines are run at 80% part load. This is notably different from the Wärtsilä engine, where the part load efficiency remains virtually unchanged, even at extremely low loads. The revised LCC calculation for the respective options is, therefore, EUR 351 million for the CCGT solution and EUR 383 million for the Wärtsilä solution, the difference now being down to EUR 32 million.

Impact of ambient temperature and altitude As discussed earlier, optimal ISO conditions and brochure figures do not mirror real life. The physical location of the plant and the ambient air pressure are both factors that should be taken into consideration. When both altitude and ambient temperature impact standards, the resultant derating on output and efficiency might substantially affect the CCGT, whereas the performance of a Wärtsilä based power plant remains

virtually unchanged, regardless of ambient conditions. If we include the impact of a 35°C site temperature and a 500 m altitude, versus the ISO standard (15ºC and 0 m), the LCC of the CCGT increases by EUR 2 million, and the CCGT would in theory have to be run an additional 1000 h per year to produce the same amount of power as the Wärtsilä solution.

This will have an impact on the installed capacity required, which is discussed later in this article.

Impact of ageing and dispatch Analysing output and efficiency at site conditions takes us one step closer to more realistic LCC numbers. The next step is to evaluate how the heat rate and output change as a factor of time. Figure 3 shows the changes in heat rate and output during the life of a CCGT. When we compare the two solutions we will see that as time elapses, both the heat rate and the output of a gas turbine power plant are hit, whereas the Wärtsilä plant has a negligible output decrease due to ageing, and only a 0.5% increase in heat rate between overhauls. Given the higher heat rate degradation of the CCGT, the LCC for that solution will increase

by EUR 5 million compared to EUR 1 million for the Wärtsilä solution.

Moreover, the daily dispatch patterns (baseload/intermittent load/peaking load/starts and stops/ramping up/load following) need to be considered. The monetary impact of flexibility requires detailed calculations, but in general the customer should be aware of the advantages that Wärtsilä offers with respect to smooth operations. If the plant is started once a day and ramped up to 80% load, the engine solution is ready in 5 minutes, while it is not unusual for a CCGT to require 45 minutes for start up.

The first hour’s production is hence 155 MWh for the engine solution, and 101 MWh for the CCGT (assuming linear ramp-up rates and 200 MW derated outputs in both cases). Say the market price for electricity is 100 EUR/MWh, and the customer has to buy the delta (5 MWh respective 59 MWh) from other sources, then the LCC increases by EUR 1 million for the Wärtsilä plant, and by EUR 16 million for the CCGT. It should also be noted that the efficiency during ramp-up is considerably lower than at operating load. While the engine reaches its derated efficiency of 46.5% after 5

Fig. 3 – CCGT degradation as a factor of time.

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Fig. 4 – Summarised effects of lifecycle cost adjustments.

minutes, the CCGT requires another 40 minutes to reach its derated lifetime efficiency of 49.4%. During the starting hour the average efficiency, somewhat simplified using a linear increase, is 45.4% for the engine and 30.9% for the CCGT.

Impact on capital costAt these given conditions, the output of the CCGT decreases by about 20%. The gross output of the CCGT should, therefore, be 250 MW to cover the lost output, which leads to an additional investment and a boost of EUR 16 millionto the LCC, assuming the same kW price as for the base investment. As one can understand, this calculation must be done before any investment decision is made, since another type of turbine might be required. If the Wärtsilä solution is chosen, the customer is not faced with this problem.

The O&M cost component Uncertainty in the power market and large fluctuations in fuel prices create additional challenges for power plant investors. A power plant with a long-term Power Purchase Agreement (PPA) originally designed to run in baseload mode can easily find itself becoming a peaking plant if,

for example, fuel prices increase or if additional power with lower operating costs,such as hydropower, becomes available. The move from baseload to peaking could have a substantial influence on the O&M cost, especially in the case of a CCGT.

In the LCC calculations above, we have assumed that the O&M cost is EUR 4 per MWh for the CCGT. If a plant is operating in peaking mode with frequent starts and stops, most CCGTs would have to reduce the time between overhauls, as their equivalent operating hours increase, leading to higher O&M costs. If we assume that the O&M cost in our example case increases from EUR 4 to EUR 6 per MWh due to the daily start and fast ramping up time, the LCC will increase by EUR 14 million for the CCGT. As the Wärtsilä solution is designed for flexible operation, no additional costs will occur from such varying dispatch patterns.

CONCLUSIONThis article has merely scratched the surface of the concept of lifecycle costs, and each case is unique and should be calculated based on the criteria applicable to that specific case. It should also be noted that in this example case we compared a simple

cycle solution to a combined cycle solution. In a future number of In Detail we will return to the topic of lifecycle costs comparing gas engine and gas turbine based combined cycles. The characteristics of such an evaluation differ somewhat from the ones applicable to this article.

In summarising the findings, we saw that by simply adding ambient conditions like temperature and altitude, ageing, and some corrections for starts and stops, part load operation and equivalent operating hours, the LCC gap between the two competing solutions vanished. In the end the LCC for the CCGT was EUR 453 million, and 436 million for the Wärtsilä solution, a difference of EUR 19 million in favour of Wärtsilä. If the plant is used for frequent load following, if fast start capability is valued higher than merely the alternative cost of electricity, if availability and reliability are important issues, then the Wärtsilä simple cycle solution will end up being the superior choice for the customer.