INVESTMENT OPPORTUNITIES AND TECHNOLOGY · PDF file3 Because of the longer startup time of the GE 7FA.05 and increased maintenance costs associated with frequent starts, the 7FA.05

A WHITE PAPER BY WÄRTSILÄ

INVESTMENT OPPORTUNITIES AND TECHNOLOGY SELECTION: IPP VALUE PROPOSITION FOR ERCOT

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INDEX


Executive summary1 Introduction 42 Business logic behind hedging 53 How does the heat rate call option work? 74 Evaluating power plant technology options for hedging 84.1 Technical performance of Wärtsilä 18V50SG and GE 7FA.05 84.2 Calculating the heat rate cell levels for Wärtsilä 18V50SG and GE 7FA.05 104.3 Derating impacts maximum contracted capacity 114.4 Calculating minimum requirement for option fee 135 Value of a heat rate call option in ERCOT 145.1 Back-cast value for a heat rate call option in ERCOT 146 Financial feasibility of Wärtsilä 18V50SG and GE 7FA.05 166.1 Day-Ahead Market participation only 186.2 Day-Ahead + Real-Time Market optimization 196.3 Day-Ahead + Real-Time + Ancillary Services Market optimization 20

6.4 Conclusions of the back-cast analysis 227 Future sensitivity analysis 237.1 Price curves for the “year 2015” 237.2 Fair value of a heat rate call option with the “year 2015” data 247.3 Financial analysis with the “year 2015” 258 Conclusions 26APPEDIX A: Project Finance Calculation Tables for the Modeled Cases 27

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EXECUTIVE SUMMARY:

The Electric Reliability Council of Texas (ERCOT), which operates the electric grid for most of the state of Texas, has experienced steadily growing demand over the last several years. In a state where 1,000 new residents are added each day, ERCOT has set new demand records, particularly during 2011. Along with rising demand, recent generating unit retirements and the cancellation or postponement of several capacity projects has presented new challenges to maintaining adequate planning reserve margins. Studies indicated that ERCOT could see reserve margins drop below established reliability targets in the coming years. Prices in ERCOT’s energy-only market had been unable to attract sufficient investment to ensure adequate capacity reserves, so the system-wide scarcity pricing cap was increased, reaching $9,000 per MWh in 2015.

Adjustments to scarcity pricing have spurred investment activity in ERCOT, with 8000 MW of capacity –primarily industrial gas turbines – planned for development. Many of these projects are based on the GE 7FA.05 gas turbine. The IPP investment business case is to provide Day-Ahead Market heat rate call option backed by the 7FA.05 to a Load-Serving Entity. Back-cast analysis using historical price and temperature conditions during 2011–2014 has shown that the fair market value of a heat rate call option based on a Wärtsilä 18V50SG internal combustion engine (ICE) power plant is higher than the 7FA.05 power plant. This is because the Wärtsilä 18V50SG has higher efficiency and less derating at high temperatures than the 7FA.05. However, the average value of both technology options is lower than the required option fee to cover the debt service and operations and maintenance costs, and does not justify investment purely based on hedging.

To examine project feasibility and internal rate of return (IRR), Wärtsilä has conducted detailed dispatch and financial modeling for a GE 7FA.05 and a Wärtsilä 18V50SG power plant in the ERCOT Day-Ahead (DA), Real-Time (RT), and Ancillary Services (AS) Markets for 2011–2014. The Wärtsilä 18V50SG power plant financially outperforms the GE 7FA.05 due to the flexibility of Wärtsilä ICE technology. The ability of the Wärtsilä 18V50SG to start up within five (5) minutes, reduce load to 20% of full capacity, and incur no maintenance penalties from frequent starts and stops allows the Wärtsilä plant to participate in ERCOT’s Ancillary Services Market, offering a variety of ancillary service products as shown in Figure E.1.

Figure E.1. The Wärtsilä 18V50SG generates more revenue than the GE 7FA.05 due to greater dispatchability in markets

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Because of the longer startup time of the GE 7FA.05 and increased maintenance costs associated with frequent starts, the 7FA.05 project could only offer limited ancillary services. As a result, the Wärtsilä 18V50SG is able to achieve 19.3% equity IRR and a 10.3% project IRR offer limited amount of ancillary services or participate in the Real-time market while the GE 7FA.05 is only able to achieve a 9.2% equity IRR and a 6.4% project IRR (back-cast analysis for 2011–2014). The IRR performance of the 7FA.05 and the Wärtsilä 18V50SG in different market participation cases are shown in Figures E.2 and E.3. Extending this analysis to the hypotetical year 2015, the Wärtsilä 1850VSG power plant achieves a 19.9% return on equity while the 7FA.05 is only able to reach 9.6% return on equity.

As market conditions predict there will be higher price spikes in ERCOT in coming years, and increasing demand for hedging products which will drive up the hedge prices. The more valuable heat rate call option, ability to earn revenue for several markets, and higher IRR makes the Wärtsilä 18V50SG power plant a superior investment for IPPs compared to 7FA.05.

Figure E.2. Project IRR in the different market participation cases

Figure E.3. Equity IRR in the different market participation cases

5,2% 5,2% 6,4%5,9%7,3%

10,3%

0,0%

2,0%

4,0%

6,0%

8,0%

10,0%

12,0%

DA DA + RT DA + RT +AS

Project IRR - 7FA.05 Project IRR - Wärtsilä 18V50SG

1,26 1,26 1,381,32 1,471,79

0,00

0,50

1,00

1,50

2,00


DSCR - 7FA.05 DSCR -Wärtsilä 18V50SG

5,9% 5,9%9,2%7,7%

11,6%

19,3%

0,0%

5,0%

10,0%

15,0%

20,0%

25,0%


Equity IRR - 7FA.05 Equity IRR - Wärtsilä 18V50SG

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During 2011 the Electricity Reliability Council of Texas (ERCOT) experienced several significant weather events coupled with extensive unexpected generator outages that prompted emergency procedures. ERCOT has been carefully monitoring its system resource adequacy, recognizing a threat of declining reserve margin in upcoming years. These concerns have spurred consideration of a capacity mechanism (project 40000) in ERCOT to attract new investment. However, in 2014 the Public Utility Commission of Texas decided to continue with the energy-only market design.

In energy-only markets, the only sources of revenues for generators are energy and ancillary services, while capacity is not rewarded, as in some other ISO markets. To attract new investments, there must be sufficient scarcity pricing events in this type of market design. ERCOT has worked on the market enhancements during the past few years, with the target to provide adequate scarcity price signals together with enhancements in Real-Time Market design (Operating Reserve Demand Curve, ORDC B+). A real-time price adder was increased from $3000 to $9000 per megawatt-hour (MWh) to reflect the value of spinning and non-spinning reserves based on the value of lost load (VOLL) and the loss of load probability.

These enhancements, together with declining market reserve margin, have boosted investment activity in ERCOT. Currently, there is more than 8000 MW of new peaking gas capacity in the development pipeline, but only a couple hundred megawatts of capacity is actually under construction. A great majority of this 8000 MW planned capacity will be industrial gas turbines, specifically GE’s 7FA.05 industrial gas turbine.

There are several Independent Power Producers (IPPs) pursuing the 8000 MW capacity additions. Because IPPs are subject to the ups and downs of the electricity market, the investment business logic is to provide Day-Ahead Market heat rate call option to load serving entities. A load serving entity (LSE) is willing to purchase this type of insurance product, as without it they risk being in short position during a price spike. In return, the IPP requires a long-term heat rate call option to finance the project.

Current market prices and forward curves do not indicate the need for new peaking capacity yet, and therefore IPPs have not managed to sell their heat rate call options to off-takers. Basically, all IPPs are selling the same product, which is the Day-Ahead heat rate call option. As the product is same, the off-taker is picking up the cheapest offer that it can find in the market. Consequently IPPs are developing low capital cost projects, and in this field the large GE 7FA.05 gas turbine seems to be the most economical solution.

Wärtsilä has analyzed historical ERCOT market pricing and the performance of the GE 7FA.05 gas turbine plant compared with the Wärtsilä 18V50SG internal combustion engine (ICE) power plant under various market participation cases. This report will show the feasibility for both solutions, as well as more advanced business cases and value proposition for flexible peaking capacity. Based on this analysis, the cheapest capacity to construct might not be the winner for internal rate of return. By providing a more valuable product to off-takers, leading IPPs ensure financing before other IPPs and reach higher return on equity.

1. INTRODUCTION

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The energy-only market design in Texas should create scarcity pricing events when the available reserve capacity reaches a low threshold. These pricing events are typically driven by hot weather or unexpected plant failures in the market. Generators, especially merchant plants, would like to see as many of these pricing events as possible, as they are able to cover their fixed costs and get return on investment during these events. These pricing events are particularly essential for peaking capacity that would not be able to cover fixed expenditures during normal operations, when the market price is set by the operating cost of the marginal unit needed to meet load. However, these scarcity pricing events cannot be predicted years ahead, which makes the financing of peaking plants challenging. Therefore, IPPs are looking for an off-taker willing to pay a fixed fee for the capacity.

As these pricing events typically occur during the summer months, the system load is also close to its peak. This creates a risk for load serving entities (LSEs) that are obliged to serve their load in all conditions. If the load serving entity does not have adequate capacity or financial contracts to meet its load, it needs to buy the remaining energy from the market. The table below shows an illustrative example of the financial impact of a price spike from the LSE perspective for three cases: capacity shortage during the price spike, in balance, and a capacity surplus. The illustrative example in Table 2.2 shows the financial impact of multiple price spikes for a utility with a 200 MW capacity shortage.

2. BUSINESS LOGIC BEHIND HEDGING

IMPACT OF MARKET PRICE 1 Price spike5 Price Spikes

10 Price Spikes

15 Price Spikes

Market price [$/MWh]

Capacity shortage

Number of price spikes

Financial impact Maximum price for hedge [$/kW/month]

9,000 9,000 9,000 9,000

(200) (200) (200) (200)

1 10 15(1,800,000) (9,000,000) (18,000,000) (27,000,000)

0.8 3.8 7.5 11.3

5

9,000 9 000 9,000

800 800 800

600 800 1,000

(200) - 200

Customer load to be served [MW]

Contracted capacity [MW]

Market price [$/MWh] ,

Capacity shortage/Surplus [MW]

Financial impact ($1,800,000) - $1,800,000

IMPACT OF MARKET PRICE Capacity shortage In balance

Capacity surplus

Table 2.1. Illustrative example of a price spike from the LSE perspective

Table 2.2. Illustrative example of financial impact of multiple price spikes

The simplified example illustrates the financial impacts from severe price spikes, but it also provides a good basis for the hedge contract pricing. If the utility believes there will be only one scarcity price event for which it is 200 MW short, the maximum price it should pay for the hedge is $0.75/kW/month. With 15 price spikes, the maximum price for the hedge fee rises to $11.25/kW/month. The IPP can calculate the contract value to cover its debt service, fixed operations and maintenance expenses, and evaluates if the LSE is willing to pay

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the required hedge fee. For example, if the IPP needs $5.0/kW/month for seven years to finance an investment, and the LSE believes that there will be 15 price spikes, there is a good chance that the IPP and the LSE will agree to a contract.

The illustrative example clearly shows the severe financial impact of a price spike if the LSE is in short position during the price spike. Just one hour could cost $1,800,000 and will have negative impact on profitability. With the increase in the ERCOT scarcity price cap from $3,000/MWh to $9,000/MWh, the impact and probability of these severe price spikes have increased.

Nobody knows exactly how many price spikes there will be next year or in future years, so estimating the impact of price spikes is difficult. The probability of price spikes will increase when the capacity margin decreases. IPPs would sell their project based on this uncertainty and the potential financial impact of scarcity pricing events. Ultimately, different LSEs have varied assumptions and sensitivities about the frequency and economic consequences of price spikes.

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3. HOW DOES THE HEAT RATE CALL OPTION WORK?

The most typical hedging product that IPPs are selling is the so called ‘Day-Ahead heat rate call option’. The call option means that the off-taker (the LSE in this case) has the right to use the contracted capacity, but it is not obliged to do so. For this right, the off-taker is willing to pay an upfront fee to the seller. The value of the call option can be only calculated afterwards; therefore call options are seen as a type of insurance product. For instance, if the LSE paid $3.75/kW/month for a 200 MW call option (based on the example in the previous table), but there were ten price spikes during the year, then the LSE actually made $9,000,000 profit with the call option (or did not lose this amount). On the other hand, the IPP could have made more profit with the higher call option price. Consequently, the price of hedge is based on the future expectations of prices.

The heat rate call option consists of two components: the option fee and utilization fee. The option fee is paid upfront and is based on the same calculation principles shown in Table 2.2. From the IPP perspective, the role of the option fee is to cover the debt service and annual fixed expenses of the capacity investment. The utilization fee is based on the operational economics of the power plant that underlies the heat rate call option. The utilization fee is shown typically as MBtu/kWh and is based on the operational cost the power plant. The typical utilization fee for a 7FA.05 gas turbine is about 13,000−14,000 MBtu/kWh. If the off-taker calls the option, it will cover the operational expenses during the operation. We will show the calculation of the heat rate call option utilization fee in the next section.

Typically, heat rate call options are financial contracts which mean that there is no physical obligation to deliver the energy, but the contract value is settled afterwards. The utilization fee is often called the strike price for the call options, so there is no need to actually “call” the option, but it is assumed that the contracted capacity will come online when the price is high enough. The following example shows the financial settlement of a typical heat rate call option in different situations.

The example in Table 3.1 demonstrates the importance of plant availability during the price spike situations. When the plant is available, the option seller returns the difference between the market price (market heat rate) and the strike price to the off-taker and receives only the utilization fee. If the plant is not available during the price spike, the financial impact for the option seller is severe, as it only receives the utilization fee, but does not receive anything from the market.

Typically, industrial gas turbines derate during the hot temperatures. This must be taken into account especially in Texas, where majority of the price spikes occur during the summer. The option seller can either carry the risk or sell only the derated capacity.

FINANCIAL SETTLEMENT Plant available Not availableSummer derating

Market price [$/MWh] Gas price [$/MBtu} Implied market heat rate [Btu/kWh] Heat rate call level [Btu/kWh] Heat rate settlement [Btu/kWh] Heat rate settlement [$/MWh] Contracted capacity [MW] Capacity available [MW] Financial settlement to off-taker [$] Financial settlement to seller [$]

9,000 9,000 9,0004.0 4.0 4.0

2,250,000 2,250,000 2,250,00013,000 13,000

2,237,000 2,237,000 2,237,0008,948 8,948 8,948200 200 200200 170

1,789,600 1,789,600 1,789,60010,400 (1,789,600) (259,600)

13,000

-

Table 3.1. Heat rate call option financial settlement

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4. EVALUATING POWER PLANT TECHNOLOGY OPTIONS FOR HEDGING

One of the most popular power plant solutions in Texas for hedging purposes is the GE 7FA.05 industrial gas turbine. There are several projects under development with 2-4 x 7FA.05 configuration to drive down the investment cost on $/kW basis. 7FA.05 is low capital cost capacity with high heat rate of about 10,000 Btu/kWh. In the traditional hedging business case, the heat rate is not very important as the power plant is only operating a couple of hundred hours per year. However, in the following sections we will look closer into the performance of GE 7FA.05 industrial gas turbine compared to the Wärtsilä 18V50SG internal combustion engine (ICE) power plant. Using this analysis we can demonstrate new hedging business cases in which the Wärtsilä 18V50SG power plant enables to increase the rate of return.

The operating characteristics of a Wärtsilä 18V50SG power plant consisting of 12 x 18.4 MW reciprocating engines and a GE 7FA.05 power plant were examined. Both plants have a nominal capacity of 220 MW. The operational characteristics of both plants are shown in Table 4.1. The modular plant architecture of the Wärtsilä 18V50SG power plant has significant value in the IPP business case. First, the shaft risk, which is the resource’s probabilistic loss of load in the event of failure, is twelve times smaller than the 7FA.05 gas turbine. This is important in the hedging business case due to the importance of availability, as discussed in the previous section. Second, the modular design would allow several off-takers for the plant and more modular contract specifications. ICEs can be dispatched individually with the same heat rate as the whole plant. In other words, full efficiency is maintained even at part load.

The efficiency, expressed as heat rate, of the Wärtsilä 18V50SG power plant is significantly better than the 7FA.05 power plant at full load and at minimum stable load. The Wärtsilä 18V50SG plant can operate at 20% minimum load which enables more revenue opportunities in the ancillary services markets. The higher efficiency also provides more operations in the energy market as the plant moves lower up in the merit than the 7FA.05.

The big difference between 7FA.05 and Wärtsilä 18V50SG is startup operations and cost. Due to thermal stress during startup, the 7FA.05 incurs a maintenance impact every time the turbine is started. Several studies have estimated the start-up cost for 7FA.05, and we have used a start-up cost for this analysis based on published data, shown in Table 4.2. The start-up cost of the gas turbine is $15,000 per start, while Wärtsilä engines do not have a startup cost. Further, the number of starts does not affect the maintenance cost for Wärtsilä engines. The starting of a Wärtsilä 18V50SG engine uses compressed air for combustion, enabling virtually instantaneous start. In a gas turbine, the compressor must accelerate to reach firing speed and then self-sustaining speed. To prevent thermal stress, limits on airflow velocity and combustion temperature constrain how quickly a gas turbine can start and reach full load. The startup cost has a big impact on plant economics and dispatch, as the plant must be able to cover its startup cost when it operates in the market.

The variable operations and maintenance (O&M) cost, or VOM, is calculated differently for 7FA.05 than for Wärtsilä 18V50SG. The 7FA.05 VOM of $0.9/MWh includes only consumables, whereas the major maintenance is covered through the startup cost. The $5.5/MWh VOM of Wärtsilä 18V50SG shown in Table 4.1 includes all major maintenances, as well as the consumables (lube oil, urea etc).

Plant flexibility is another important factor that will impact availability and revenue opportunities. The Wärtsilä 18V50SG power plant can be synchronized to the grid in 30 seconds and reach full load in less than five (5)

4.1 Technical performance of Wärtsilä 18V50SG and GE 7FA.05

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0.91

0.91

0.91

0.91

2 Southwest Mid-Atlantic area

3 Rest of RTO areas

4 Western Mid-Atlantic

1 Eastern Mid-Atlantic area

VOM ($/MWh) LTSA ($/FFS)1

5 Dominion service territory 0.87

Gas CT

CONE Area

19,846

17,501

18,565

16,968

16,887

Output (ISO) 18.4 MW

12 x 18.4 = 221 MW

Efficiency (ISO)

Minimum stable load

Efficiency at minimum stable load

Output (sea level, ISO temp)

18V50SG 7FA.05

Start-up time to full load

Start-up fuel

Start-up cost (maintenance)

VOM

8,266 Btu/kWh

20 %

10.064 Btu/kWh

5 min

0.3 MBtu/MW/start 1.5 MBtu/MW/start

0 USD/start 15,000 USD/start

5.5 USD/MWh 0.9 USD/MWh

227 MW

227 MW

9,838 Btu/kWh

40 %

13.899 Btu/kWh

15 min

1Long-term service agreement( LTSA) payments and major maintenance events depend on gas turbine operations typi-cally measured through factored fired starts, or FFS.

2http://brattle.com/system/news/pdfs/000/000/196/original/Cost_of_New_Entry_Estimates_for_Combustion-Tur-bine_and_Combined-Cycle_Plants_in_PJM_Spees_et_al_Aug_24_11.pdf?1377791290

Table 4.2. 7FA.05 start-up cost and variable operation and maintenance cost (VOM)2

Table 4.1. The Wärtsilä 18V50SG outperforms the GE 7FA.05 in heat rate, startup time and startup economics

minutes. The plant can be shut down completely in less than a minute, and does not require a minimum up-time nor down-time. While the 7FA.05 can start within 10 minutes, frequent starts come with a maintenance penalty which limits the plant dispatch, especially in the Real-Time Market. In addition, the 7FA.05 typically requires six hours minimum run-time when it is used to back-up a heat rate call option. There are technical limitations behind the long minimum run-time, but the main reason is the start-up cost, which will be explained in the next section.

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As was discussed earlier in this analysis, the Day-Ahead heat rate call option has a utilization fee or implied utilization heat rate. This heat rate defines the minimum strike level for the option contract. The lower the heat rate, the more valuable the option contract, as the better heat rate covers a wider price band in the market. The components that are included in the implied heat rate in this analysis are the following:

• Plant heat rate at full load at 95° Fahrenheit (summer temperature)

• Variable O&M cost (VOM)

• Start-up cost divided by minimum run-time

The calculation of the implied heat rate for Wärtsilä 18V50SG and GE 7FA.05 is shown in Table 4.3.

4.2 Calculating the heat rate call levels for Wärtsilä 18V50SG and GE 7FA.05

Plant size [MW]

Gas price [$/MBtu]

Heat rate at 95 F [Btu/kWh] Variable O&M [$/MWh]

Heat rate -Variable O&M [Btu/kWh] Start-up cost [$/start]

Minimum run time [h]

Start-up cost [$/MWh]

Heat rate - Start-up cost [Btu/kWh] Implied heat rate for call option [Btu/kWh]

IMPLIED HEAT RATE

227221

4.0

10,0478,2820.9

1,00015,000

0.1

11.1-

2,77813,0509,282

4.0

5.5

225

-

6

-

GE 7FA.05W18V50SG

Table 4.3. Wärtsilä 18V50SG has a lower implied heat rate than the 7FA.05 gas turbine

The implied heat rate (and the minimum heat rate for call option) for 7FA.05 is 13,050 Btu/kWh and for Wärtsilä 18V50SG is 9,282 Btu/kWh. The difference between the implied heat rates means that an IPP with a Wärtsilä 18V50SG power plant could ask higher value for the heat rate option contract, as the lower implied heat rates enables lower strike price and therefore more valuable price impact mitigation. The value of this heat rate difference in the ERCOT market will be reviewed later in this analysis.

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4.3 Derating impacts maximum contracted capacity

Thermal power plants suffer derating at high temperatures, as the inlet air mass flow decreases. However, different technologies have varied performance and extent of derating. The derating curves for Wärtsilä 18V50SG and GE 7FA.05 are shown in Figure 4.1.

It is evident from Figure 4.1 that the GE 7FA.05 derates significantly at high ambient temperatures, while the Wärtsilä 18V50SG plant only begins to slightly derate at 97°F. As was previously shown, derating can be costly to the IPP if the full contracted capacity is not available when the capacity is called. To estimate the impact of derating for the IPP business case we have analyzed the hourly temperature data in the Houston area from 2011 to 2014 to assess the impact of actual ambient temperatures on both technologies.

It can be seen from the derating graphs (Figures 4.2 to 4.5) that 2014 was quite a mild year, with minimal derating for a Wärtsilä 18V50SG power plant. The summer of 2011 was very hot, as evidenced from the amount of derating in Figure 4.2. As weather cannot be forecasted years ahead, the IPP needs to decide the acceptable capacity derating level when signing the heat rate call option contract. In this analysis, we select a conservative strategy, and contract only the maximum available summer capacity for both plants during the hottest days:

• GE 7FA.05 derates several times to 87% of its maximum capacity. For a 227 MW plant this means that only 197 MW can be contracted.

• Wärtsilä 18V50SG derates to 97% of its maximum capacity. For a 221 MW plant this means that 214 MW can be contracted.

80%

85%

90%

68

95%

100%

105%

50 57 57 61 64 7575 79

7FA.05

82 86

18V50SG

Temperature [F]

Capa

city

out

put

104100979393

Figure 4.1. The Wärtsilä 18V50SG experiences less derating at high temperatures than the 7FA.05 gas turbine

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Figure 4.4. Available capacity in 2013 based on historical temperatures


80%85%90%95%

100%105%

1.1 2.1 3.1 4.1 5.1 6.1 7.1 8.1 9.1 10.1 11.1 12.1

Capa

city

ava

ilabl

e

Date

7FA.05 2011

18V50SG 2011

80%85%90%95%

100%105%

1.1 2.1 3.1 4.1 5.1 6.1 7.1 8.1 9.1 10.1 11.1 12.1

Capa

city

ava

ilabl

e

Date

7FA.05 2012

18V50SG 2012

80%85%90%95%

100%105%

1.1 2.1 3.1 4.1 5.1 6.1 7.1 8.1 9.1 10.1 11.1 12.1

Capa

city

ava

ilabl

e

Date

7FA.05 2013

18V50SG 2013

80%

85%

90%

95%

100%

105%

1.1 2.1 3.1 4.1 5.1 6.1 7.1 8.1 9.1 10.1 11.1 12.1

Capa

city

ava

ilabl

e

Date

7FA.05 2014

18V50SG 2014




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The overall investment cost for the Wärtsilä 18V50SG plant is $42 million more than the 7FA.05 plant. This means that to receive financing, Wärtsilä 18V50SG requires higher heat rate call option fee than the 7FA.05. The need for fixed cash flow is highest during the first year of operation, since the debt interest is the highest. Consequently, we can estimate the minimum required option fee based on the first year fixed costs. The calculation for the required minimum option fee is shown in Table 4.5, which is based on the debt service, minimum debt-service-credit-ratio (DSCR) and O&M costs.

Due to the higher capital and fixed O&M costs, the required option fee is greater for the Wärtsilä 18V50SG power plant. The difference in required option fee between 7FA.05 and Wärtsilä 18V50SG is $1.3/kW/month which equates to approximately $3.3 million difference annually. In other words, the heat rate call option provided by Wärtsilä 18V50SG must be at least $3.3 million more valuable than the option provided by 7FA.05. It should be noted that the required option fees would only cover the fixed operating costs and debt service, but not return on equity.

4.4 Calculating minimum requirement for option fee

To calculate the minimum required option fee, we need to estimate the capital cost of GE 7FA.05 and Wärtsilä 18V50SG, the capital structure, cost of capital, fixed operations and maintenance cost, and construction period. Based on market intelligence and Wärtsilä’s in-house expertise, we have estimated $500/kW overnight EPC cost for GE 7FA.05 and $700/kW for Wärtsilä 18V50SG. The financial assumptions used in the modeling for both plants are shown in Tables 4.4 and 4.5.

ASSUMPTIONS

Capacity [MW] 227

500

Project lifetime [years] 20

75

Tax rate 37.5%

14

Interest rate 5%

133

Overnight EPC cost [$/kW]

Owner's cost [$/kW]

Construction period [months]

Total investment cost [$ Mn]

30%

70%

20

W18V50SG

221

700

30%

20

75

70%

37.5%

14

20

5%

175

11

GE 7FA.05

Equity share

Debt share

Loan term [years]

Fixed O&M [$/kW] 6.4

20

Table 4.4. Financial assumptions for Wärtsilä 18V50SG power plant

12,081,105 9,206,751

11,048,101 14,497,326

4,545,105 5,964,090

Total debt service [$]

Requided income for debt service

Debt interest [$]

Debt repayment [$]

REQUIRED OPTION FEE

Fixed Operations & Maintenance [$] 1,448,260

1.2

2,435,420

4,661,646 6,117,015

W18V50SG GE 7FA.05

Minimum DSCR 1.2

Required debt service + Fixed O&M [$] 12,496,361 16,932,746 Contracted capacity [MW] 197 214

Required heat rate call option fee [$/kW/month] 5.29 6.59

Table 4.5. Required option fee to finance the plant

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5 VALUE OF A HEAT RATE CALL OPTION IN ERCOT

As discussed previously in this analysis, the value of a heat rate call option is based on the expectations of future prices and market participation. Consequently, there is always uncertainty over the real value or so called fair value of the option. Currently, there are many peaking projects under development, but it is often difficult to sell a heat rate call option at a price that would justify investment in new generation. A majority of the market players are not willing to pay the asking price for a heat rate call option, and current forward option prices are way below to incentivize new capacity construction. To analyze the value of a heat rate option for a GE 7FA.05 power plant and Wärtsilä 18V50SG plant in the ERCOT market, and to better understand the role of market prices on the heat rate call option fair value, we have performed a back-cast analysis for the years 2011−2014.

To analyze the value of heat rate call options in ERCOT during 2011−2014 we have modeled the financial settlement for technology-specific call options against hourly Day-Ahead market prices. In the analysis, the implied heat rate varies from year to year according the average natural gas price. Based on the years 2011−2014, the average minimum implied heat rate for the GE 7FA.05 would be 13,828 Btu/kWh, while the Wärtsilä 18V50SG power plant achieves an implied heat rate of 9,395 Btu/kWh. The results for Wärtsilä 18V50SG and GE 7FA.05 are shown in Tables 5.1. and 5.2.

5.1 Back-cast value for a heat rate call option in ERCOT

Table 5.1. Value of heat rate call option in ERCOT for Wärtsilä 18V50SG based on 2011–2014 back-cast analysis

Contracted capacity [MW]Average gas price [$/MBtu]

Heat rate at 95 F [Btu/kWh]

Variable O&M [$/MWh]Start-up cost [$/start]


Implied heat rate for call option [Btu/kWh] Hours when price over implied heat rate [h]

Option called [times]

Option called [hours]

Heat rate call option fair value [$]

Heat rate call option fair value [$/kW/month]

214 214 214 214 214

4.0 2.7 3.7 4.4 3.7

8,282 8,282 8,282 8,282 8,282

0 0 0 0 0

0.1 0.1 0.1 0.1 0.1

9,286 9,737 9,355

9,201

9,395

2,692 2,906 2,590 2,527 2,679

456 443 483 480 466

2,692 2,906 2,590 2,527 2,679

28,825,712 9,715,036

6,751,048

10,192,327

13,871,030

11.22 3.78

2.63

3.97 5.40

5.5 5.5 5.5 5.5 5.5

BACK-CAST VALUE OF HEAT RATE CALL OPTION IN ERCOT - W18V50SG

W18V50SG W18V50SG W18V50SG W18V50SG W18V50SG2011 2012 2013 2014 Average

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Contracted capacity [MW] 197 197 197 197 197

Average gas price [$/MBtu] 4.0 2.7 3.7 4.4 3.7

Heat rate at 95 F [Btu/kWh] 10,047 10,047 10,047 10,047 10,047

Variable O&M [$/MWh] 0.9 0.9 0.9 0.9 0.9Start-up cost [$/start] 15,000 15,000 15,000 15,000 15,000

Minimum run time [h] 6 6 6 6 6

Implied heat rate for call option [Btu/kWh] 13,457 14,990 13,693 13,171 13,828

Hours when price over implied heat rate [h] 819 611 555 693 670

Option called [times] 120 94 68 98 95

Option called [hours] 768 575 421 608 593

Heat rate call option fair value [$] 21,087,006

4,627,501 1,481,314 3,486,195 7,670,504

Heat rate call option fair value [$/kW/month] 8.92 1.96 0.63 1.47 3.24

BACK-CAST VALUE OF HEAT RATE CALL OPTION IN ERCOT - 7FA.05

GE 7FA.05 GE 7FA.05 GE 7FA.05 GE 7FA.05 GE 7FA.052011 2012 2013 2014 Average

The GE 7FA.05 heat rate call option is called on average 95 times per year and an average 593 operating hours during a four-year period. The implied market heat rate is above the 7FA.05 heat rate strike level 670 hours per year on average, it is not economical to call the option about 10 percent of the time because the 7FA.05 is not able to cover its start-up costs. As the Wärtsilä 18V50SG power plant does not have start-up costs and the minimum run-time is less than an hour, the Wärtsilä 18V50SG can respond economically every time the plant is called. Because of the lower implied heat rate of Wärtsilä 18V50SG, the option is called more often – an average 2679 hours per year, which is over 2000 hours more than the 7FA.05 heat rate call option.

The Wärtsilä 18V50SG heat rate call option is called more often and can mitigate the impact of price spikes more efficiently than the 7FA.05 call option, so it should be also more valuable to the off-taker. Based on the back-cast analysis over 2011−2014, the fair value for Wärtsilä 18V50SG heat rate call option on average would have been $5.40/kW/month, while the fair value for 7FA.05 call option would have been $3.24/kW/month. The Wärtsilä 18V50SG heat rate call option is therefore $2.14/kW/month more valuable than the 7FA.05 plant call option. Based on the calculation of required option fees for 7FA.05 and Wärtsilä 18V50SG shown in Table 4.5., the required minimum option fee for Wärtsilä 18V50SG is $1.3/kW/month due to higher capital expenditures. As the value of Wärtsilä 18V50SG heat rate call option is $2.14/kW/month more than the 7FA.05 call option, it can be concluded that the market value of the Wärtsilä 18V50SG heat rate call option sufficiently covers the difference in higher capital expenditures by 1.55 times. As a result, the Wärtsilä 18V50SG power plant provides more valuable heat rate call option for the off-taker than the 7FA.05 power plant.

However, the average value of the heat rate call option for both technology alternatives is lower than the required minimum option fee to cover the debt service and fixed O&M costs. For 7FA.05 the deficit is $2.04/kW/month, and for Wärtsilä 18V50SG the deficit is $1.19/kW/month. Only in 2011 would the fair value of heat rate call option for both plants been high enough to provide adequate income.

As was stated before, the value of heat rate call option is based on the expectations on the future prices, and predicting prices accurately years ahead is impossible. Following the summer of 2011, there could have been several contracts that would have justified investments in new hedge capacity as similar pricing spikes in future years presented risks to LSEs. In the next section, we analyze this type of scenario, where an off-taker signed a heat rate call option with 7FA.05 power plant or a Wärtsilä 18V50SG power plant with the minimum required option fee in early 2011 and called the option according the analysis shown in Table 5.1. and Table 5.2.

Table 5.2. Value of heat rate call option in ERCOT for GE 7FA.05 based on 2011–2014 back-cast analysis

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6 FINANCIAL FEASIBILITY OF WÄRTSILÄ 18V50SG AND GE 7FA.05

The analysis described in the previous section showed that ERCOT Day-Ahead Market prices over the period 2011−2014 were too low to justify investment in GE 7FA.05 or Wärtsilä 18V50SG power plants purely based on hedging purposes. If a heat rate call option with the required price was purchased, there was a premium paid as the anticipated market risk did not materialize. This does not mean that the decision to sign a heat rate call option was wrong, as it provided insurance against potential price spikes in future years.

In our next part of the analysis, we assume the following investment situation:

• Two different IPPs and two different off-takers:

• The first IPP has signed a heat rate call option with a 7FA.05 power plant backing up the contract prior to 2011 and received the required minimum option fee of $5.29/kW/month for 197 MW.

• The second IPP has signed a heat rate call option with a Wärtsilä 18V50SG power plant backing up the contract prior to 2011 and received the required minimum option fee of $6.59/kW/month for 214 MW.

• The first IPP builds a 227 MW 7FA.05 power plant, while the second IPP builds a 221 MW 18V50SG power plant. Both plants come online 1/1/2011.

• Both plants are dispatched against the Houston HUB Day-Ahead prices and the heat rate call option is financially settled against the HUB prices.

• As the target of the analysis is to compare the competitiveness and feasibility of 7FA.05 and Wärtsilä 18V50SG power plants, the financial settlement of the call option needs to be done on the same basis. If the off-taker of 7FA.05 call option pays $5.29/kW/month for the capacity, even though the fair value of the option is only $3.24/kW/month, then the premium paid by the off-taker is $2.05/kW/month. For the Wärtsilä 18V50SG call option, the premium is only $1.19/kW/month. We assume the same rationality in the market and between market participants. We also assume that the IPP with the Wärtsilä 18V50SG could receive the same margin from the option contract. The off-taker could analyze the difference in value between the 7FA.05 and Wärtsilä 18V50SG and draw the conclusion that the market-based value of Wärtsilä 18V50SG heat rate call option is $2.16/kW/month more valuable (see Tables 5.1 and 5.2.). Therefore, a utility that is willing to pay $5.29/kW/month for the 7FA.05 heat rate call option would be willing to pay $7.45/kW/month ($5.29 + $2.16) for the Wärtsilä 18V50SG heat rate call option.

The financial model consists of several modeling steps. The modeling approach for both plants is shown in Figure 6.1.

The technical inputs for the Wärtsilä 18V50SG and GE 7FA.05 are listed in Table 4.1. The market inputs are gathered from ERCOT’s webpage and the daily gas prices from the U.S. Energy Information Administration (EIA).3 The site modeled is close to Houston, with an elevation at approximately sea level. Hourly temperature data is used to calculate the derating of the capacity and the impact on the heat rate (at hourly resolution). Weather data was gathered from the National Centers for Environmental Information webpage.4

Technical, market and site inputs are used in the modeling platform to optimize plant dispatch against market prices. The market modeling platform runs with five-minute granularity and can optimize plant operation over Day-Ahead, Real-Time and Ancillary Services markets. The outputs of this dispatch optimization against

3http://www.eia.gov/dnav/ng/hist/rngwhhdd.htm

4http://www.ncdc.noaa.gov/

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Market model outputs

• Running hours and number starts

• 5 minute dispatch profile• Revenue per market• Operating costs (fuel,

VOM, start-up costs)• Gross margin from the

market operations

Investment input

• Investment cost• Fixed Operation and

Maintenance costs• Capital structure

• Cost of capital

Technical input

• Heat rates (GTPro)

• Part load heat rates

• Variable O&M cost

• Capacity derating

• Start-up times

• Start-up costs

Modeling platform

• Excel tool for backcast analysis

• 5 minutes granularity to analyze the Real-Time Market

• Optimize the operation of asset against the LMP and offer capacity optimally between energy and Ancillary Service

Market input

• Day-ahead prices

• Real-Time Market prices

• Ancillary Services prices

• Daily gas price

Site input

• Elevation

• Price node information

• Hourly temperature data

Option model

• Option fee income

• Option settlement

Financial model

• Project feasibility

• Project IRR

• Equity IRR

• Cash flows

• Assumes that capacity fits into the merit if it is feasible to operate the plant

• Takes into account tempera-ture derating on hourly level

market prices along with investment inputs and option fee income are then used to evaluate project feasibility. The financial model is a cash flow model over 30 years that provides metrics relevant to project feasibility, such as project and equity internal rate of return (IRR).

The dispatch for Wärtsilä 18V50SG and GE 7FA.05 power plants is modeled over the years 2011−2014, and the average dispatch is used as an input for future feasibility analysis. Average option fee and option settlement data for 2011 – 2014 are similarly used in the model. In other words, we assume that the average economic outcome of years 2011−2014 will take place over next 30 years.

An IPP that sells a heat rate call option for full capacity with the minimum implied heat rate at fair market value would be able to cover the fixed operations and maintenance costs and debt service. However, that IPP would not be able to generate return on equity if the plant is used only in the Day-Ahead market. When the market heat rate is above the strike level (implied heat rate) of the option contract, the plant would operate but the option seller receives only the utilization fee. The difference between the market price and the strike price is returned to the off-taker. Consequently, to generate additional income, the IPP must operate in the Ancillary Services or Real-Time markets. The following case studies further clarify this dilemma and show the importance of other market cash flows.

Figure 6.1. Financial feasibility modeling steps

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In this case study, both plants (Wärtsilä 18V50SG and GE 7FA.05) are used in the Day-Ahead Market only during 2011−2014. Based on the results of the dispatch model, the operating profiles over these years differ for the two technologies. Both plants are offered into the market at their short-run marginal cost, while taking into account daily gas prices and the impact of ambient temperature on heat rate. On average, the 7FA.05 plant would operate 1123 hours per year with 101 annual starts. The Wärtsilä 18V50SG plant would operate on average 2628 hours with 432 starts – over twice as many hours. The average operating time per start for the Wärtsilä 18V50SG plant is 6.1 hours, while the 7FA.05 is 11.1 hours. The higher average operating hours per start for the 7FA.05 plant is due to start-up cost, which makes the short operating pulses (less than 6 hours) uneconomical in most cases. However, the Wärtsilä 18V50SG plant would operate pulses as short as one hour, whenever the market price is above its short-run marginal cost. There is a slight difference between the actual operating hours and modeled option called hours (tables 5.1 and 5.2.), because in the dispatch calculation daily gas price was used, while in the option calculation we used average yearly gas price to define the implied heat rate. The annual operating hours, number of starts and average operating profiles for 2011−2014 are shown for Wärtsilä 18V50SG and GE 7FA.05 power plants in Figure 6.2.

6.1 Day-Ahead Market participation only

Figure 6.2. Operational profiles of Wärtsilä 18V50SG and GE 7FA.05 in the Day-Ahead Market only case

The operating hours are high for both plants, as both plants offer their capacity to the market without any margin. If for example a margin of $6.0/MWh was added on top of the short-run marginal cost, the number of operating hours would decrease without major impact on the gross margin.

Revenues from the Day-Ahead Market are based on the hourly market prices, and operating cost is based on dispatch profiles and daily gas prices. The project financing calculations for the Day-Ahead Market only case is provided in Appendix A, Table A.1 for Wärtsilä 18V50SG and Table A.2 for GE 7FA.05.

The 221 MW Wärtsilä 18V50SG plant is able to provide 7.7% IRR for equity and 5.9% IRR for the project. The 227 MW GE 7FA.05 project can reach only 5.9% IRR for equity and 5.2% for the whole project. Consequently, a project with Wärtsilä 18V50SG technology is able to provide higher return on investment than the 7FA.05. Someone could argue the higher IRR is the reason behind the higher heat rate call option fee for the Wärtsilä 18V50SG plant, but this is not true. The outcome of the heat rate call option settlement (option fee – option settlement) is equal for both plants, since they receive the same premium on the contract as discussed earlier in this analysis.

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The overall IRRs for both plants are quite low in the Day-Ahead Market only, and would probably not attract investments even though the financing has been secured through the heat rate call options. As the heat rate call options were sold with the cost-based implied heat rate, the plants are not able to make any additional money in the Day-Ahead Market, even though there would be more price spikes. In the case of additional price spikes, the revenue from energy production would increase, but simultaneously the financial settlement of the heat rate call option would increase. However, there are possibilities to get additional gross margin from other markets than the traditional Day-Ahead Market. The flexible Wärtsilä 18V50SG power plant could operate in the Real-Time Market in two different ways. First, the plant could be started to take advantage of Real-Time Market price spikes. Second, the plant could be shut down and the Day-Ahead commitment fulfilled through the Real-Time Market purchases when the price is below the short-run operating cost of the plant. When including the Real-Time Market into the analysis, the operational profile for the Wärtsilä 18V50SG power plant changes compared to participation in only the Day-Ahead Market. The 7FA.05 power plant has almost the same operational profile for both cases, as shown in Figure 6.3.

6.2 Day-Ahead + Real-Time Market optimization

Figure 6.3. Operational profiles of Wärtsilä 18V50SG and GE 7FA.05 in Day-Ahead + Real-Time Markets case

On average the Wärtsilä 18V50SG plant operates almost 1000 hours less than in the Day-Ahead Market only case. The reason behind this change is the market procurement. If the price in the Real-Time Market is lower than the operating cost of the plant, it does not make sense to start the plant, but rather to fulfill the commitment through market procurement. This type of flexible behavior is not possible for the 7FA.05 plant due to its operational characteristics. Imagine a situation where the plant operator decides not to start the 7FA.05 plant as Real-Time prices are low, and then suddenly the price for next five-minute interval is at $9000/MWh and the 7FA.05 plant misses the price spike. Not starting the plant is a very costly and risky strategy. As the Wärtsilä 18V50SG power plant is able to reach full output in less than five minutes and maintenance is not impacted by the number of starts, chasing price spikes in the Real-Time Market is possible for the Wärtsilä plant. The project finance calculations for the Wärtsilä 18V50SG and GE 7FA.05 plants are provided in Appendix A, Tables A.3 and A.4, respectively.

The project economics for 7FA.05 are the same whether participating in the Day-Ahead Market or the Day-Ahead + Real-Time Markets, as only very small adjustments could be made to the operational profile of the

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plant in the Real-Time Market. The project IRR is 5.2% and the Equity IRR is 5.9% for the 7FA.05 plant. For the Wärtsilä 18V50SG plant there is a very positive impact from the Real-Time Market operations. The project IRR is 7.3% and the Equity IRR 11.6%, which are acceptable numbers. Real-Time Market participation also improves the debt service capability of Wärtsilä 18V50SG plant, and the minimum DSCR is 1.5 which is above the minimum accepted level.

Let’s look a bit closer where the additional income for Wärtsilä 18V50SG plant comes from in this case. The revenue is about $3 million higher than in the Day-Ahead only case. This means that the plant is started in the Real-Time Market and is able to capture $3 million additional revenue from the market. The big change is in the operating cost of the plant which is about $7 million lower than in the Day-Ahead case. The lower operating costs are realized due to market procurement; when the plant is not operated in the Real-Time Market because prices are low, the Day-Ahead commitment is met by market procurement.

6.3 Day-Ahead + Real-Time + Ancillary Services Market optimization

Figure 6.4. Operational profiles of Wärtsilä 18V50SG and GE 7FA.05 in the Day-Ahead + Real-Time + Ancillary Services Markets case

The Ancillary Services market is cleared in co-optimization with energy in ERCOT’s Day-Ahead Market. As there is not a secondary market for ancillary services in the Real-Time Market, the ancillary service commitment is binding. Therefore, a plant which has sold ancillary services in Day-Ahead must also deliver the product in Real-Time. This market feature reduces the role of Real-Time market for the Wärtsilä 18V50SG power plant if it decides to sell ancillary services in ERCOT.

There are currently four different ancillary services in ERCOT: Regulation Up, Regulation Down, Responsive Reserve and Supplemental. The first three products require that the resource providing the service must be synchronized to the grid, but the Supplemental service can be provided by non-synchronous generation. The Regulation Down and Responsive Reserve products require that the resource is operating at part-load to sell the head room for ancillary services. The minimum stable load for the Wärtsilä 18V50SG plant is 20%, so it is able to sell 80% of its capacity for upward ancillary services products. The minimum stable load for the 7FA.05 plant is 40%, so the headroom for ancillary services is 60%. While the plant is providing regulation down service, it would operate at full load and sell the capacity down to minimum stable load for the service.

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It is assumed in the dispatch modeling that the 7FA.05 and Wärtsilä 18V50SG plants are able to sell all types of ancillary services, and if the capacity is competitive in the ancillary services market, it will get ancillary services commitment. In other words, the modeling assumes the capacity always fits into the ancillary services merit order if it is economical. The operational profiles in this case for the Wärtsilä 18V50SG and 7FA.05 power plants are shown in Figure 6.4.

Compared to the previous cases, there is a massive change in the operational profile for the Wärtsilä 18V50SG power plant. The plant is operating on average 3387 hours which is 759 hours more than Day-Ahead Market only case and 1753 hours more than the Day-Ahead + Real-Time Market case. The wide load range (lower turndown) together with good part-load heat rate enables participation of the Wärtsilä plant in the ancillary services market. For the GE 7FA.05 plant there is not a significant change in the operational profile compared to the previous cases. As the plant is idle most of the time, it has been committed for supplemental reserve. The revenue split between the energy and different ancillary services products for the Wärtsilä 18V50SG and 7FA.05 plants are shown in Figure 6.5.

Figure 6.5. Revenues from different market products per installed megawatt (MW)

The importance of the supplemental reserve ancillary product is evident for the 7FA.05 investment. Basically, there is very minor improvement of the 7FA.05 gross margin compared to the Day-Ahead + Real-Time case without supplemental reserve. As the revenue from supplemental reserve is more or less pure margin, it helps to improve the project financial performance. However, it should be stated once again that this analysis overestimates the revenues from supplemental reserves, as the analysis assumes the price taker approach for supplemental reserve.

Regardless of the improved project finance outcome of the 7FA.05 plant, the Wärtsilä 18V50SG plant is still clearly a more profitable investment. The Wärtsilä 18V50SG is able to reach 10.3% project IRR and 19.3% IRR on equity, while the 7FA.05 returns only 6.4% and 9.2%, respectively.

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6.4 Conclusions of the back-cast analysis

The back-cast analysis is a good way to analyze the competitiveness of different solutions as there is no uncertainty on the prices. However, it is not a crystal ball to predict future performance, but helps to elucidate the competitiveness of technology alternatives in different market situations. In the ERCOT back-cast analysis of the Wärtsilä 18V50SG and GE 7FA.05 power plants, it is evident that the Wärtsilä 18V50SG provides a more valuable hedge for the off-taker and provides significantly better return on investment for the IPP. In all modeled cases, the Wärtsilä 18V50SG solution outperformed the GE 7FA.05 for project IRR, equity IRR and DSCR. A summary of the project financial outcomes for the Day-Ahead (DA) Market only, DA + Real-Time (RT) Markets, and DA + RT + Ancillary Services (AS) Markets cases is shown in Figures 6.6, 6.7 and 6.8.

Figure 6.6. Project IRR in the different market participation cases

5,2% 5,2% 6,4%5,9%7,3%

10,3%

0,0%

2,0%

4,0%

6,0%

8,0%

10,0%

12,0%



1,26 1,26 1,381,32 1,471,79

0,00

0,50

1,00

1,50

2,00



5,9% 5,9%9,2%7,7%

11,6%

19,3%

0,0%

5,0%

10,0%

15,0%

20,0%

25,0%


Equity IRR - 7FA.05 Equity IRR - Wärtsilä 18V50SG

5,2% 5,2% 6,4%5,9%7,3%

10,3%

0,0%

2,0%

4,0%

6,0%

8,0%

10,0%

12,0%



1,26 1,26 1,381,32 1,471,79

0,00

0,50

1,00

1,50

2,00



Figure 6.7. Equity IRR in the different market participation cases

Figure 6.8. Minimum Debt-Service-Credit-Ratio (DSCR) in the different market participation cases

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7 FUTURE SENSITIVITY ANALYSIS

As previously shown in Sections 4 and 5, prices between 2011 and 2014 did not justify investment in new capacity. The value of a heat rate call option for the Wärtsilä 18V50SG power plant was higher than for the GE 7FA.05 plant, but neither call option was adequate to cover the debt service and fixed O&M costs. As has been stated previously, the value of the heat rate call option is based on the future expectations of prices, not on historical prices. With the updated market rules in ERCOT, the impact of severe price spikes and the probability of the price spikes have increased. Therefore, it would be interesting to test the impact of the potential $9,000/MWh future price spikes on the value of heat rate call options and project financing. The Wärtsilä 18V50SG power plant was more competitive in all market situations during 2011−2014, but would it be also be more competitive in such a potential future scenario?

To analyze this question, we need to develop a potential price series for future years. There is no need to analyze years when the prices are relatively low and stable, since we have seen that already in 2012, 2013, and 2014. In the next analysis we test the case that extreme weather like what occurred in 2011 would hit Texas during the summer of 2015 and cause similar price patterns. The difference would be that the scarcity prices would not be capped at $3,000/MWh but instead at $9,000/MWh.

To test the impact of “year 2015” we need to define the scarcity pricing level. We have locked the scarcity price level to the implied heat rate of 100,000 Btu/kWh, which corresponds to $500/MWh Day-Ahead market price in 2011. In 2011, there were 67 hours when the implied heat rate was over 100,000 Btu/kWh. For these hours we have multiplied 2011 prices with the factor 9,000/3,000, which indicates the impact of higher price cap in “year 2015.” This methodology is of course a simplification of real life, but will give insight on the impact of severe pricing events. The price duration curves of the 100 most expensive hours for 2011 and for “year 2015” are shown in Figure 7.1.

7.1 Price curves for the “year 2015”

Figure 7.1. Price curves of 100 most expensive hours in 2011 and “year 2015”

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7.2 Fair value of a heat rate call option with the “year 2015” data

The “year 2015” price curve has a significant impact on the fair value of a call option, as the price spikes are quite extreme. This could be a realistic scenario. The fair value of a heat rate call option for the Wärtsilä 18V50SG and GE 7FA.05 power plants over 2011−2015 is shown in Table 7.1.

W18V50SG W18V50SG W18V50SG W18V50SG W18V50SG W18V50SG2011 2012 2013 2014 "2015" Average

Contracted capacity [MW]Average gas price [$/MBtu]Heat rate at 95 F [Btu/kWh]Variable O&M [$/MWh]Start-up cost [$/start]Minimum run time [h]Implied heat rate for call option [Btu/kWh] Hours when price over implied heat rate [h]Option called [times]Option called [hours]Heat rate call option fair value [$] Heat rate call option fair value [$/kW/month]

"FUTURE" VALUE OF HEAT RATE CALL OPTION IN ERCOT- W18V50SG

214 214 214 214 214 2144.0 2.7 3.7 4.4 4.0 3.8

8,282 8,282 8,282 8,282 8,282 8,282

0 0 0 0 0 00.1 0.1 0.1 0.1 0.1 0.1

9,286 9,737 9,355 9,201 9,286 9,3732,692 2,906 2,590 2,527 2,692 2,681

456 443 483 480 2692 9112,692 2,906 2,590 2,527 456 2,234

28,825,712 9,715,036 6,751,048 10,192,327 65,137,762 24,124,37711.22 3.78 2.63 3.97 25.37 9.39

5.5 5.5 5.5 5.5 5.5 5.5

GE 7FA.05 GE 7FA.05 GE 7FA.05 GE 7FA.05 GE 7FA.05 GE 7FA.05

2011 2012 2013 2014 "2015" Average

Contracted capacity [MW]

Average gas price [$/MBtu]

Heat rate at 95 F [Btu/kWh]

Variable O&M [$/MWh]

Start-up cost [$/start]


Implied heat rate for call option [Btu/kWh] Hours when price over implied heat rate [h]

Option called [times]

Option called [hours]

Heat rate call option fair value [$]

Heat rate call option fair value [$/kW/month]

"FUTURE" VALUE OF HEAT RATE CALL OPTION IN ERCOT - 7FA.05

197 197 197 197 197 197

4.0 2.7 3.7 4.4 4.0 3.8

10,047 10,047 10,047 10,047 10,047 10,047

0.9 0.9 0.9 0.9 0.9 0.9

15,000 15,000 15,000 15,000 15,000 15,000

6 6 6 6 6 6

13,457 14,990 13,693 13,171 13,457 13,754819 611 555 693 819 699

120 94 68 98 120 100

768 575 421 608 768 628

21,087,006 4,627,501 1,481,314 3,486,195 54,604,709 17,057,345

8.92 1.96 0.63 1.47 23.10 7.22

The value of the heat rate call option is attractive for the off-taker over the five-year period. This example highlights well the role of a heat rate call option: it is an insurance product against future uncertainty. Compared to our back-cast analysis, now the fair value of the option is higher than the option fee: $5.29/kW/month for the 7FA.05 plant and $7.45/kW/month for the Wärtsilä 18V50SG plant. This means that the option contract had upside value for the off-taker, while the IPP seller could have asked for more for the option. From the project financing point of view, the pricing changes mean that the IPP is not making money with the option fee and option fair value spread, but it is still able to finance the plant with the option fee. The only problem occurs if the plant is not available during the price spikes, but we have not taken this into account in the analysis.

Table 7.1. Value of heat rate call option with "year 2015" price data

It can be seen from Figure 7.1 that there is a step change by the hour 75 when the implied heat rate exceeds 100,000 Btu/kWh in 2011. This step change indicates the increased market power to set higher prices (according the increased price cap) in scarcity situations. The rest of the “year 2015” prices are the same as in 2011. The same gas price and temperature profiles are used for both years.

25

7.3 Financial analysis with the “year 2015”

To analyze the financial impact of the year 2015, we have done the dispatch modeling with the “year 2015” data as was similarly modeled for the years 2011−2014. The average dispatch profile, market revenues, and gross margin over the period 2011−2015 have been used in the financial analysis. As the most lucrative operational case was Day-Ahead + Real-Time + Ancillary Services Markets, we have modeled only this scenario for both capacity assets. The detailed results of the project finance calculation are provided in Appendix A, Tables A.7 and A.8.

The “year 2015” does not change the project economics of the plants dramatically. As the option fair value increases, the plants are not making loss with the option as they cover the difference through the higher market prices. On the other hand, the plants are making only slight improvements in project economics even though the prices are high in “year 2015,” as the higher fair value of the option contract eliminates the uplift. The slight improvement is due to the difference between plant actual output and contracted capacity. The price spikes do not always occur when the capacity is derated, so there is a slight share of capacity for both units that can be sold as “merchant” during price spikes.

The most important result of the “year 2015” analysis is that it does not change the competitiveness between the GE 7FA.05 power plant and the Wärtsilä 18V50SG power plant. The Wärtsilä 18V50SG plant can reach 19.9% IRR equity while the 7FA.05 plant is able to reach only 9.6% equity IRR. Even though ERCOT market prices would provide signals to invest in new capacity in near future, a plant with 7FA.05 technology is not the best alternative for IPPs. The Wärtsilä 18V50SG plant provides higher return on investment, more valuable heat rate call option for the off-taker, and offers a less risky strategy as the plant is not dependent on primarily a single source of revenue as is the 7FA.05.

26

8 CONCLUSIONS

The ERCOT energy-only market has gone through market enhancements during the past couple of years, which have made the market more volatile and risky for load serving entities (LSE). This change in the market environment has also attracted many IPPs, which are developing GE 7FA.05 gas turbine projects with the intention to sell Day-Ahead heat rate call options to the LSEs.

These IPPs are competing against each other and trying to sell the heat rate call option to finance their project. In our analysis, we have estimated that the IPP would need an option fee of $5.29/kW/month to finance the project. In the analysis, we have analyzed the value of a Wärtsilä 18V50SG internal combustion engine power plant with similar business logic as IPPs developing 7FA.05 power plants. If there is a LSE that is willing to pay the minimum required option fee of $5.29/kW/month for the GE 7FA.05 plant heat rate call option, we have shown why they should consider a proposal from an alternative IPP that is willing to sell the option backed-up with Wärtsilä technology at $7.45/kW/month.

While the Wärtsilä 18V50SG heat rate call option fee is more expensive due to the higher capital and fixed O&M costs, this difference in fee compared to the 7FA.05 plant is easily covered by a more valuable heat rate call option. Based on the back-cast analysis, we concluded that the fair value of Wärtsilä 18V50SG heat rate call option is $2.16/kW/month more valuable than the 7FA.05 heat rate call option. The difference in value is due to better heat rate (higher efficiency), no-start-up costs and greater flexibility of the Wärtsilä 18V50SG power plant.

In this analysis, we tested the financial performance of the Wärtsilä 18V50SG and GE 7FA.05 plants in the ERCOT market over 2011−2014. Both plants received the required and correctly valued heat rate call options, and tried to maximize their market-based gross margin over the years. In the best case for both plants (Day-Ahead + Real-Time + Ancillary Services Markets) the Wärtsilä 18V50SG project IRR is 10.3% and equity IRR is 19.3%, while the 7FA.05 can only reach project IRR of 6.4% and equity IRR of 9.2%. The Wärtsilä 18V50SG is not only more valuable hedging product for the off-taker but it also provides better return on investment for the investor.

The prices from 2011 to 2014 do not reflect the need for a heat rate call option hedge, from the standpoint of the LSE.. If a LSE decided to purchase a heat rate call option in late 2010, it might have overpaid for the contract. However, if we witness similar price patterns as in 2011, but at new (higher) market price caps, the fair value of a heat rate call option would look completely different. As market participants predict that there will be more price spikes in ERCOT in the future, and in general the price patterns are more unpredictable, there will be increased demand for a valuable hedging product.

Regardless of the price patterns in the future years in ERCOT, a heat rate call option with Wärtsilä 18V50SG technology is a better option than a GE 7FA.05 heat rate call option.

27

APPEDIX A: PROJECT CALCULATION TABLES FOR THE MODELED CASES

28

AS

SU

MP

TIO

NS

- 1

8V50

SG

Capa

city

[MW

]22

1Ov

erni

ght E

PC c

ost [

$/kW

]70

0Eq

uity

sha

re30

%Co

ntra

cted

Cap

acity

[MW

]21

4Pr

ojec

t life

time

[yea

rs]

20Ow

ner'

s co

st [$

/kW

]75

Debt

sha

re70

%He

at r

ate

optio

n fe

e [$

/kW

/m]

7.45

Tax

rate

37.5

%Co

nstr

uctio

n pe

riod

[mon

ths]

14Lo

an te

rm [y

ears

]20

Heat

rat

e op

tion

settl

emen

t [$/

kW/m

]5.

40In

tere

st r

ate

5%To

tal i

nves

tmen

t cos

t [$

Mn]

175

Fixe

d O&

M [$

/kW

]11

.0Im

plie

d he

at r

ate

[Btu

/kW

h]9,

395

Fin

anci

al M

od

el

Inco

me

Stat

emen

t ($

Mn)

Ener

gy R

even

ue

Anci

llary

ser

vice

s Re

venu

e

Heat

rate

cal

l opt

ion

fee

Tota

l Rev

enue

Fuel

Cos

t

Varia

ble

O&M

Star

t-up

O&M

Star

t-up

fuel

Mar

ket p

rocu

rem

ent

Gros

s Pr

ofit

Fixe

d O&

M

EBIT

DA

Inte

rest

Taxe

s

Net I

ncom

e

Free

cas

h flo

w to

pro

ject

Proj

ect I

RR

Free

cas

h flo

w to

equ

ity

Equi

ty IR

R

DSCR

min

Year

0Ye

ar 1

Year

2Ye

ar 3

Year

4Ye

ar 5

Year

6Ye

ar 7

Year

8Ye

ar 9

Year

10

Year

11

Year

12

Year

13

Year

14

Year

15

Year

16

Year

17

Year

18

Year

19

Year

20

D&A

EBIT

EBT

Heat

rate

cal

l opt

ion

settl

emen

t

3434

3434

3434

3434

3434

3434

3434

3434

3434

3434

00

00

00

00

00

00

00

00

00

00

1919

1919

1919

1919

1919

1919

1919

1919

1919

1919

5353

5353

5353

5353

5353

5353

5353

5353

5353

5353

1818

1818

1818

1818

1818

1818

1818

1818

1818

1818

22

22

22

22

22

22

22

22

22

22

00

00

00

00

00

00

00

00

00

00

00.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

1

00

00

00

00

00

00

00

00

00

00

1414

1414

1414

1414

1414

1414

1414

1414

1414

1414

1919

1919

1919

1919

1919

1919

1919

1919

1919

1919

22

22

22

22

22

22

22

22

22

22

1717

1717

1717

1717

1717

1717

1717

1717

1717

1717

99

99

99

99

99

99

99

99

99

99

88

88

88

88

88

88

88

88

88

88

66

55

54

44

43

33

22

21

11

00

22

33

34

44

45

55

66

67

77

88

11

11

11

12

22

22

22

22

33

33

11

22

22

23

33

33

44

44

45

55

(175

)16

1616

1615

1515

1515

1515

1515

1414

1414

1414

14

5.9%

(52)

44

44

55

55

56

66

66

77

77

78

7.7% 1.3

Tabl

e A.

1. P

roje

ct fi

nanc

e ca

lcul

atio

n fo

r Wär

tsilä

18V

50SG

in th

e Da

y-Ah

ead

Mar

ket o

nly

case

29

AS

SU

MP

TIO

NS

- G

E 7

FA.0

5Ca

paci

ty [M

W]

227

Over

nigh

t EPC

cos

t [$/

KW]

500

Equi

ty s

hare

30%

Cont

ract

ed C

apac

ity [M

W]

197

Proj

ect l

ifetim

e [y

ears

]20

Owne

r's

cost

[$/k

W]

75De

bt s

hare

70%

Heat

rat

e op

tion

fee

[$/k

W/m

]5.

29Ta

x ra

te37

.5%

Cons

truc

tion

perio

d [m

onth

s]14

Loan

term

[yea

rs]

20He

at r

ate

optio

n se

ttlem

ent [

$/kW

/m]

3.24

Inte

rest

rat

e5%

Tota

l inv

estm

ent c

ost

[$ M

n]13

3Fi

xed

O&M

[$/k

W]

6.4

Impl

ied

heat

rat

e [B

tu/k

Wh]

13,8

28

Fin

anci

al M

od

elYe

ar 0

Year

1Ye

ar 2

Year

3Ye

ar 4

Year

5Ye

ar 6

Year

7Ye

ar 8

Year

9Ye

ar 1

0Ye

ar 1

1Ye

ar 1

2Ye

ar 1

3Ye

ar 1

4Ye

ar 1

5Ye

ar 1

6Ye

ar 1

7Ye

ar 1

8Ye

ar 1

9Ye

ar 2

0

Inco

me

Stat

emen

t ($

Mn)

Ener

gy R

even

ue19

1919

1919

1919

1919

1919

1919

1919

1919

1919

19

Anci

llary

ser

vice

s Re

venu

e0

00

00

00

00

00

00

00

00

00

0

Heat

rate

cal

l opt

ion

fee

1313

1313

1313

1313

1313

1313

1313

1313

1313

1313

Tota

l Rev

enue

3131

3131

3131

3131

3131

3131

3131

3131

3131

3131

Fuel

Cos

t8

88

88

88

88

88

88

88

88

88

8

Varia

ble

O&M

00

00

00

00

00

00

00

00

00

00

Star

t-up

O&M

22

22

22

22

22

22

22

22

22

22

Star

t-up

fuel

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

Mar

ket p

rocu

rem

ent

00

00

00

00

00

00

00

00

00

00

88

88

88

88

88

88

88

88

88

88

Gros

s Pr

ofit

1313

1313

1313

1313

1313

1313

1313

1313

1313

1313

Fixe

d O&

M1

11

11

11

11

11

11

11

11

11

1

EBIT

DA12

1212

1212

1212

1212

1212

1212

1212

1212

1212

12

D&A

77

77

77

77

77

77

77

77

77

77

EBIT

55

55

55

55

55

55

55

55

55

55

Inte

rest

54

44

43

33

32

22

22

11

11

00

EBT

11

11

12

22

23

33

34

44

45

55

Taxe

s0

00

01

11

11

11

11

11

22

22

2

Net I

ncom

e0

01

11

11

12

22

22

22

33

33

3

Free

cas

h flo

w to

pro

ject

(133

)12

1111

1111

1111

1111

1111

1111

1010

1010

1010

10

Proj

ect I

RR5.

2%

Free

cas

h flo

w to

equ

ity(4

0)2

23

33

33

34

44

44

44

55

55

5

Equi

ty IR

R5.

9%

DSCR

min

1.3

Heat

rate

cal

l opt

ion

settl

emen

t

Tabl

e A.

2. P

roje

ct fi

nanc

e ca

lcul

atio

n fo

r GE

7FA.

05 in

the

Day-

Ahea

d M

arke

t onl

y ca

se

30

AS

SU

MP

TIO

NS

- 1

8V50

SG

Capa

city

[MW

]22

1Ov

erni

ght E

PC c

ost [

$/kW

]70

0Eq

uity

sha

re30

%Co

ntra

cted

Cap

acity

[MW

]21

4Pr

ojec

t life

time

[yea

rs]

20Ow

ner'

s co

st [$

/kW

]75

Debt

sha

re70

%He

at r

ate

optio

n fe

e [$

/kW

/m]

7.45

Tax

rate

37.5

%Co

nstr

uctio

n pe

riod

[mon

ths]

14Lo

an te

rm [y

ears

]20

Heat

rat

e op

tion

settl

emen

t [$/

kW/m

]5.

40In

tere

st r

ate

5%To

tal i

nves

tmen

t cos

t [$

Mn]

175

Fixe

d O&

M [$

/kW

]11

.0Im

plie

d he

at r

ate

[Btu

/kW

h]9,

395

Fin

anci

al M

od

el

Inco

me

Stat

emen

t ($

Mn)

Ener

gy R

even

ue

Anci

llary

ser

vice

s Re

venu

e

Heat

rate

cal

l opt

ion

fee

Tota

l Rev

enue

Fuel

Cos

t

Varia

ble

O&M

Star

t-up

O&M

Star

t-up

fuel

Mar

ket p

rocu

rem

ent

Gros

s Pr

ofit

Fixe

d O&

M

EBIT

DA

Inte

rest

Taxe

s

Net I

ncom

e

Free

cas

h flo

w to

pro

ject

Proj

ect I

RR

Free

cas

h flo

w to

equ

ity

Equi

ty IR

R

DSCR

min

Year

0Ye

ar 1

Year

2Ye

ar 3

Year

4Ye

ar 5

Year

6Ye

ar 7

Year

8Ye

ar 9

Year

10

Year

11

Year

12

Year

13

Year

14

Year

15

Year

16

Year

17

Year

18

Year

19

Year

20

D&A

EBIT

EBT

Heat

rate

cal

l opt

ion

settl

emen

t

3737

3737

3737

3737

3737

3737

3737

3737

3737

3737

00

00

00

00

00

00

00

00

00

00

1919

1919

1919

1919

1919

1919

1919

1919

1919

1919

5656

5656

5656

5656

5656

5656

5656

5656

5656

5656

1111

1111

1111

1111

1111

1111

1111

1111

1111

1111

11

11

11

11

11

11

11

11

11

11

00

00

00

00

00

00

00

00

00

00

00.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

10.

1

77

77

77

77

77

77

77

77

77

77

1414

1414

1414

1414

1414

1414

1414

1414

1414

1414

2222

2222

2222

2222

2222

2222

2222

2222

2222

2222

22

22

22

22

22

22

22

22

22

22

2020

2020

2020

2020

2020

2020

2020

2020

2020

2020

99

99

99

99

99

99

99

99

99

99

1111

1111

1111

1111

1111

1111

1111

1111

1111

1111

66

55

54

44

43

33

22

21

11

00

55

56

66

77

78

88

99

99

1010

1011

22

22

22

33

33

33

33

34

44

44

33

34

44

44

55

55

56

66

66

67

(175

)18

1818

1717

1717

1717

1717

1616

1616

1616

1616

16

7.3% (52)

66

66

67

77

77

88

88

89

99

99

11.6

%

1.5

Tabl

e A.

3. P

roje

ct fi

nanc

e ca

lcul

atio

n fo

r Wär

tsilä

18V

50SG

in th

e Da

y-Ah

ead

+ R

eal-

Tim

e M

arke

ts c

ase

31

AS

SU

MP

TIO

NS

- G

E 7

FA.0

5Ca

paci

ty [M

W]

227

Over

nigh

t EPC

cos

t [$/

KW]

500

Equi

ty s

hare

30%

Cont

ract

ed C

apac

ity [M

W]

197

Proj

ect l

ifetim

e [y

ears

]20

Owne

r's

cost

[$/k

W]

75De

bt s

hare

70%

Heat

rat

e op

tion

fee

[$/k

W/m

]5.

29Ta

x ra

te37

.5%

Cons

truc

tion

perio

d [m

onth

s]14

Loan

term

[yea

rs]

20He

at r

ate

optio

n se

ttlem

ent [

$/kW

/m]

3.24

Inte

rest

rat

e5%

Tota

l inv

estm

ent c

ost

[$ M

n]13

3Fi

xed

O&M

[$/k

W]

6.4

Impl

ied

heat

rat

e [B

tu/k

Wh]

13,8

28

Fin

anci

al M

od

elYe

ar 0

Year

1Ye

ar 2

Year

3Ye

ar 4

Year

5Ye

ar 6

Year

7Ye

ar 8

Year

9Ye

ar 1

0Ye

ar 1

1Ye

ar 1

2Ye

ar 1

3Ye

ar 1

4Ye

ar 1

5Ye

ar 1

6Ye

ar 1

7Ye

ar 1

8Ye

ar 1

9Ye

ar 2

0

Inco

me

Stat

emen

t ($

Mn)

Ener

gy R

even

ue

Anci

llary

ser

vice

s Re

venu

e

Heat

rate

cal

l opt

ion

fee

Tota

l Rev

enue

Fuel

Cos

t

Varia

ble

O&M

Star

t-up

O&M

Star

t-up

fuel

Mar

ket p

rocu

rem

ent

Gros

s Pr

ofit

Fixe

d O&

M

EBIT

DA

D&A

EBIT

Inte

rest

EBT

Taxe

s

Net I

ncom

e

Free

cas

h flo

w to

pro

ject

Proj

ect I

RR

Free

cas

h flo

w to

equ

ity

Equi

ty IR

R

DSCR

min

Heat

rate

cal

l opt

ion

settl

emen

t

1919

1919

1919

1919

1919

1919

1919

1919

1919

1919

00

00

00

00

00

00

00

00

00

00

1313

1313

1313

1313

1313

1313

1313

1313

1313

1313

3131

3131

3131

3131

3131

3131

3131

3131

3131

3131

99

99

99

99

99

99

99

99

99

99

00

00

00

00

00

00

00

00

00

00

22

22

22

22

22

22

22

22

22

22

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

0.1

00

00

00

00

00

00

00

00

00

00

88

88

88

88

88

88

88

88

88

88

1313

1313

1313

1313

1313

1313

1313

1313

1313

1313

11

11

11

11

11

11

11

11

11

11

1212

1212

1212

1212

1212

1212

1212

1212

1212

1212

77

77

77

77

77

77

77

77

77

77

55

55

55

55

55

55

55

55

55

55

54

44

43

33

32

22

22

11

11

00

11

11

22

22

23

33

34

44

45

55

00

00

11

11

11

11

11

12

22

22

01

11

11

11

22

22

22

23

33

33

(133

)12

1111

1111

1111

1111

1111

1111

1010

1010

1010

10

5.2%

(40)

23

33

33

33

44

44

44

45

55

55

5.9%

1.3

Tabl

e A.

4. P

roje

ct fi

nanc

e ca

lcul

atio

n fo

r GE

7FA.

05 in

the

Day-

Ahea

d +

Rea

l-Ti

me

Mar

kets

cas

e

32

AS

SU

MP

TIO

NS

- 1

8V50

SG

Capa

city

[MW

]22

1Ov

erni

ght E

PC c

ost [

$/kW

]70

0Eq

uity

sha

re30

%Co

ntra

cted

Cap

acity

[MW

]21

4Pr

ojec

t life

time

[yea

rs]

20Ow

ner'

s co

st [$

/kW

]75

Debt

sha

re70

%He

at r

ate

optio

n fe

e [$

/kW

/m]

7.45

Tax

rate

37.5

%Co

nstr

uctio

n pe

riod

[mon

ths]

14Lo

an te

rm [y

ears

]20

Heat

rat

e op

tion

settl

emen

t [$/

kW/m

]5.

40In

tere

st r

ate

5%To

tal i

nves

tmen

t cos

t [$

Mn]

175

Fixe

d O&

M [$

/kW

]11

.0Im

plie

d he

at r

ate

[Btu

/kW

h]9,

395

Tabl

e A.

5. P

roje

ct fi

nanc

e ca

lcul

atio

n fo

r Wär

tsilä

18V

50SG

in th

e Da

y-Ah

ead

+ R

eal-

Tim

e +

Anc

illar

y Se

rvic

es M

arke

ts c

ase

Fin

anci

al M

od

el

Inco

me

Stat

emen

t ($

Mn)

Ener

gy R

even

ue

Anci

llary

ser

vice

s Re

venu

e

Heat

rate

cal

l opt

ion

fee

Tota

l Rev

enue

Fuel

Cos

t

Varia

ble

O&M

Star

t-up

O&M

Star

t-up

fuel

Mar

ket p

rocu

rem

ent

Gros

s Pr

ofit

Fixe

d O&

M

EBIT

DA

Inte

rest

Taxe

s

Net I

ncom

e

Free

cas

h flo

w to

pro

ject

Proj

ect I

RR

Free

cas

h flo

w to

equ

ity

Equi

ty IR

R

DSCR

min

Year

0Ye

ar 1

Year

2Ye

ar 3

Year

4Ye

ar 5

Year

6Ye

ar 7

Year

8Ye

ar 9

Year

10

Year

11

Year

12

Year

13

Year

14

Year

15

Year

16

Year

17

Year

18

Year

19

Year

20

D&A

EBIT

EBT

Heat

rate

cal

l opt

ion

settl

emen

t

2525

2525

2525

2525

2525

2525

2525

2525

2525

2525

1313

1313

1313

1313

1313

1313

1313

1313

1313

1313

1919

1919

1919

1919

1919

1919

1919

1919

1919

1919

5757

5757

5757

5757

5757

5757

5757

5757

5757

5757

1313

1313

1313

1313

1313

1313

1313

1313

1313

1313

22

22

22

22

22

22

22

22

22

22

00

00

00

00

00

00

00

00

00

00

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

00

00

00

00

00

00

00

00

00

00

1414

1414

1414

1414

1414

1414

1414

1414

1414

1414

2828

2828

2828

2828

2828

2828

2828

2828

2828

2828

22

22

22

22

22

22

22

22

22

22

2626

2626

2626

2626

2626

2626

2626

2626

2626

2626

99

99

99

99

99

99

99

99

99

99

1717

1717

1717

1717

1717

1717

1717

1717

1717

1717

66

55

54

44

43

33

22

21

11

00

1111

1212

1213

1313

1414

1414

1515

1516

1616

1717

44

44

55

55

55

55

66

66

66

66

77

77

88

88

89

99

99

1010

1010

1011

(175

)22

2221

2121

2121

2121

2120

2020

2020

2020

2020

19

10.3

%

(52)

1010

1010

1010

1111

1111

1112

1212

1212

1313

1313

19.3

%

1.8

33

AS

SU

MP

TIO

NS

- G

E 7

FA.0

5Ca

paci

ty [M

W]

227

Over

nigh

t EPC

cos

t [$/

kW]

500

Equi

ty s

hare

30%

Cont

ract

ed C

apac

ity [M

W]

197

Proj

ect l

ifetim

e [y

ears

]20

Owne

r's

cost

[$/k

W]

75De

bt s

hare

70%

Heat

rat

e op

tion

fee

[$/k

W/m

]5.

29Ta

x ra

te37

.5%

Cons

truc

tion

perio

d [m

onth

s]14

Loan

term

[yea

rs]

20He

at r

ate

optio

n se

ttlem

ent [

$/kW

/m]

3.24

Inte

rest

rat

e5%

Tota

l inv

estm

ent c

ost

[$ M

n]13

3Fi

xed

O&M

[$/k

W]

6.4

Impl

ied

heat

rat

e [B

tu/k

Wh]

13,8

28

Tabl

e A.

6. P

roje

ct fi

nanc

e ca

lcul

atio

n fo

r GE

7FA.

05 in

the

Day-

Ahea

d +

Rea

l-Ti

me

+ A

ncill

ary

Serv

ices

Mar

kets

cas

e

Fin

anci

al M

od

elYe

ar 0

Year

1Ye

ar 2

Year

3Ye

ar 4

Year

5Ye

ar 6

Year

7Ye

ar 8

Year

9Ye

ar 1

0Ye

ar 1

1Ye

ar 1

2Ye

ar 1

3Ye

ar 1

4Ye

ar 1

5Ye

ar 1

6Ye

ar 1

7Ye

ar 1

8Ye

ar 1

9Ye

ar 2

0

Inco

me

Stat

emen

t ($

Mn)

Ener

gy R

even

ue

Anci

llary

ser

vice

s Re

venu

e

Heat

rate

cal

l opt

ion

fee

Tota

l Rev

enue

Fuel

Cos

t

Varia

ble

O&M

Star

t-up

O&M

Star

t-up

fuel

Mar

ket p

rocu

rem

ent

Gros

s Pr

ofit

Fixe

d O&

M

EBIT

DA

D&A

EBIT

Inte

rest

EBT

Taxe

s

Net I

ncom

e

Free

cas

h flo

w to

pro

ject

Proj

ect I

RR

Free

cas

h flo

w to

equ

ity

Equi

ty IR

R

DSCR

min

Heat

rate

cal

l opt

ion

settl

emen

t

1616

1616

1616

1616

1616

1616

1616

1616

1616

1616

55

55

55

55

55

55

55

55

55

55

1313

1313

1313

1313

1313

1313

1313

1313

1313

1313

3434

3434

3434

3434

3434

3434

3434

3434

3434

3434

88

88

88

88

88

88

88

88

88

88

00

00

00

00

00

00

00

00

00

00

33

33

33

33

33

33

33

33

33

33

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

00

00

00

00

00

00

00

00

00

00

88

88

88

88

88

88

88

88

88

88

1515

1515

1515

1515

1515

1515

1515

1515

1515

1515

11

11

11

11

11

11

11

11

11

11

1414

1414

1414

1414

1414

1414

1414

1414

1414

1414

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

54

44

43

33

32

22

22

11

11

00

23

33

34

44

44

55

55

66

66

77

11

11

11

11

22

22

22

22

22

23

12

22

22

22

33

33

33

44

44

44

(133

)13

1313

1212

1212

1212

1212

1212

1211

1111

1111

11

6.4%

(40)

34

44

44

44

55

55

55

66

66

66

9.2% 1.4

34

Fina

ncia

l Mo

del

Year

0Ye

ar 1

Year

2Ye

ar 3

Year

4Ye

ar 5

Year

6Ye

ar 7

Year

8Ye

ar 9

Year

10

Year

11

Year

12

Year

13

Year

14

Year

15

Year

16

Year

17

Year

18

Year

19

Year

20

Inco

me

Stat

emen

t ($

Mn)

Ener

gy R

even

ue37

3737

3737

3737

3737

3737

3737

3737

3737

3737

37

Anci

llary

ser

vice

s Re

venu

e13

1313

1313

1313

1313

1313

1313

1313

1313

1313

13

Heat

rate

cal

l opt

ion

fee

1919

1919

1919

1919

1919

1919

1919

1919

1919

1919

Tota

l Rev

enue

6969

6969

6969

6969

6969

6969

6969

6969

6969

6969

Fuel

Cos

t14

1414

1414

1414

1414

1414

1414

1414

1414

1414

14

Varia

ble

O&M

22

22

22

22

22

22

22

22

22

22

Star

t-up

O&M

00

00

00

00

00

00

00

00

00

00

Star

t-up

fuel

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

0.2

Mar

ket p

rocu

rem

ent

00

00

00

00

00

00

00

00

00

00

Heat

rate

cal

l opt

ion

settl

emen

t24

2424

2424

2424

2424

2424

2424

2424

2424

2424

24

Gros

s Pr

ofit

2929

Fixe

d O&

M2

22

22

22

22

22

22

22

22

22

2

EBIT

DA26

2626

2626

2626

2626

2626

2626

2626

2626

2626

26

D&A

99

99

99

99

99

99

99

99

99

99

EBIT

18

Inte

rest

66

55

54

44

43

33

22

21

11

00

EBT

1212

1213

1313

1314

1414

1515

1516

1616

1717

1717

Taxe

s4

45

56

67

Net I

ncom

e7

78

88

99

99

910

1010

1010

1111

11

Free

cas

h flo

w to

pro

ject

(175

)22

2222

2222

2121

2121

2121

2121

2020

2020

2020

20

Proj

ect I

RR10

.5%

Free

cas

h flo

w to

equ

ity(5

2)10

1010

1011

1111

1111

1212

1212

1213

1313

1313

14

Equi

ty IR

R19

.9%

DSCR

min

1.8

2929

2929

2929

2929

2929

2929

2929

2929

2929

1818

1818

1818

1818

1818

1818

1818

1818

1818

18

88

55

55

55

66

66

66

6

AS

SU

MP

TIO

NS

- 1

8V50

SG

Capa

city

[MW

]22

1Ov

erni

ght E

PC c

ost [

$/kW

]70

0Eq

uity

sha

re30

%Co

ntra

cted

Cap

acity

[MW

]21

4Pr

ojec

t life

time

[yea

rs]

20Ow

ner'

s co

st [$

/kW

]75

Debt

sha

re70

%He

at r

ate

optio

n fe

e [$

/kW

/m]

7.45

Tax

rate

37.5

%Co

nstr

uctio

n pe

riod

[mon

ths]

14Lo

an te

rm [y

ears

]20

Heat

rat

e op

tion

settl

emen

t [$/

kW/m

]9.

39In

tere

st r

ate

5%To

tal i

nves

tmen

t cos

t [$

Mn]

175

Fixe

d O&

M [$

/kW

]11

Impl

ied

heat

rat

e [B

tu/k

Wh]

9,39

5

Tabl

e A.

7. P

roje

ct fi

nanc

e ca

lcul

atio

n fo

r Wär

tsilä

18V

50SG

with

the

“yea

r 201

5” v

alue

s in

clud

ed

35

AS

SU

MP

TIO

NS

- G

E 7

FA.0

5Ca

paci

ty [M

W]

227

Over

nigh

t EPC

cos

t [$/

kW]

500

Equi

ty s

hare

30%

Cont

ract

ed C

apac

ity [M

W]

197

Proj

ect l

ifetim

e [y

ears

]20

Owne

r's

cost

[$/k

W]

75De

bt s

hare

70%

Heat

rat

e op

tion

fee

[$/k

W/m

]5.

29Ta

x ra

te37

.5%

Cons

truc

tion

perio

d [m

onth

s]14

Loan

term

[yea

rs]

20He

at r

ate

optio

n se

ttlem

ent [

$/kW

/m]

7.22

Inte

rest

rat

e5%

Tota

l inv

estm

ent c

ost

[$ M

n]13

3Fi

xed

O&M

[$/k

W]

6.4

Impl

ied

heat

rat

e [B

tu/k

Wh]

13,8

28

Tabl

e A.

8. P

roje

ct fi

nanc

e ca

lcul

atio

n fo

r GE

7FA.

05 w

ith th

e “y

ear 2

015”

val

ues

incl

uded

Fin

anci

al M

od

elYe

ar 0

Year

1Ye

ar 2

Year

3Ye

ar 4

Year

5Ye

ar 6

Year

7Ye

ar 8

Year

9Ye

ar 1

0Ye

ar 1

1Ye

ar 1

2Ye

ar 1

3Ye

ar 1

4Ye

ar 1

5Ye

ar 1

6Ye

ar 1

7Ye

ar 1

8Ye

ar 1

9Ye

ar 2

0

Inco

me

Stat

emen

t ($

Mn)

Ener

gy R

even

ue

Anci

llary

ser

vice

s Re

venu

e

Heat

rate

cal

l opt

ion

fee

Tota

l Rev

enue

Fuel

Cos

t

Varia

ble

O&M

Star

t-up

O&M

Star

t-up

fuel

Mar

ket p

rocu

rem

ent

Gros

s Pr

ofit

Fixe

d O&

M

EBIT

DA

D&A

EBIT

Inte

rest

EBT

Taxe

s

Net I

ncom

e

Free

cas

h flo

w to

pro

ject

Proj

ect I

RR

Free

cas

h flo

w to

equ

ity

Equi

ty IR

R

DSCR

min

Heat

rate

cal

l opt

ion

settl

emen

t

2626

2626

2626

2626

2626

2626

2626

2626

2626

2626

66

66

66

66

66

66

66

66

66

66

1313

1313

1313

1313

1313

1313

1313

1313

1313

1313

4444

4444

4444

4444

4444

4444

4444

4444

4444

4444

88

88

88

88

88

88

88

88

88

88

00

00

00

00

00

00

00

00

00

00

33

33

33

33

33

33

33

33

33

33

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

0.3

00

00

00

00

00

00

00

00

00

00

17 1515

1515

1515

1515

1515

1515

1515

1515

1515

1515

11

11

11

11

11

11

11

11

11

11

1414

1414

1414

1414

1414

1414

1414

1414

1414

1414

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

77

54

44

43

33

32

22

22

11

11

00

33

33

34

44

45

55

56

66

67

77

11

11

11

12

22

22

22

22

22

33

22

22

22

23

33

33

33

44

44

44

(133

)13

1313

1312

1212

1212

1212

1212

1212

1111

1111

11

6.6%

(40)

44

44

44

45

55

55

55

66

66

66

9.6% 1.4

1717

1717

1717

1717

1717

1717

1717

1717

1717

17

WÄRTSILÄ® is a registered trademark. Copyright © 2015 Wärtsilä Corporation.

Wärtsilä Energy Solutions is a leading global supplier of flexible baseload power plants of up to 600 MW operating on various gaseous and liquid fuels. Our portfolio includes unique solutions for peaking, reserve and load-following power generation, as well as for balancing intermittent power production. Wärtsilä Energy Solutions also provides LNG terminals and distribution systems. As of 2015, Wärtsilä has 58 GW of installed power plant capacity in 175 countries around the world.

www.wartsila.com

Contact:

Matti Rautkivi, Wärtsilä Energy Solutions

[email protected]


Documents

INVESTMENT OPPORTUNITIES AND TECHNOLOGY · PDF file3 Because of the longer startup time of the GE 7FA.05 and increased maintenance costs associated with frequent starts, the 7FA.05