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Investment in flexible generation makes sense in North America

Time flies. It already has been several years since Wärtsilä started to talk about the need for flexible power generation. That was back in 2002, when Wärtsilä sold the Plains End (Figure 1) Power Station, which started to operate with flexible capacity. The dispatcher called that plant Wind Chaser as well as Dispatcher’s Dream.


In 2016, it is widely accepted that flexibility is needed in current power systems, but it will be increasingly necessary in the future due to the growth of renewable power generation. However, it still seems to be the case that, in general, investors do not see the value of flexible power generation in the USA because, they argue, the market is not rewarding the fast starting and fast ramping technology. Of course, market rules can be enhanced, but the organized electricity markets in the USA and Canada already reward flexible generation today. It is just the mindset and the traditional approach to analysing power plant investments that does not reward flexibility. 

But there are always the first adopters in a fast-changing environment who see opportunities and are willing to capture those opportunities. Since 2014, Wärtsilä has worked closely with investors in North America to build a case for flexible power generation. Now, in early 2016, the first investment cases have started to materialize. This paper describes why and how progress is being made.

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Fig. 1 - Plains End power plant.
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Fig. 2 - Organized electricity markets in North America.

Favourable market environment

The prevailing mindset is that flexible power generation can be profitable if there are a lot of renewable resources in the market. This definitely helps the business case, but the main source of value is price volatility. The increasing amount of renewable generation helps to increase volatility, but in the end, the market rules define the level of volatility that we see. In other words, if the market rules are not reflecting the value of flexibility, the additional renewable generation will not help. On the other hand, if the market rules reward flexibility, then every additional MW of renewable generation makes a more compelling case for flexible generation. 

Let’s look first at the market setup in North America. There are nine organized electricity markets on the continent (Figure 2), typically called ISO markets (Independent System Operator market). These ISO markets represent around 66% of generation capacity in the USA and are expanding their service territory constantly. The ISO markets provide a solid model to analyze the competitiveness of different generation technologies, since there is price information on the energy and various system services. 

 All ISO markets are centrally dispatched. Typical dispatch granularity is 5 minutes so there is a price for electricity in every 5-minute period. However, in many markets, the price paid for generation is not set every 5 minutes, but instead the settlement is based on longer periods of time, e.g. 1 hour. This will change in the near future, as the Federal Energy Regulatory Commission (FERC) has said that market operators need to move to finer granularity in their price setting and that all costs that occur in a dispatch period should be reflected in the market prices. This means that ISO markets are moving to 5-minute settlement periods and that the price volatility will increase due to better cost allocation. This is the first market element that makes the business case more attractive and transparent for truly flexible generation. 

The second element that makes the market environment more favourable is the increasing amount of renewables. Already two-thirds of new power capacity in the USA comes from renewables, and the decreasing price of renewables will boost this development even further. So why are we, as a flexible power source, interested in increasing the amount of renewables? We hear comments like, “You can balance the wind,” or “You guys can help the system.” These are valid points, but they do not really serve the interests of investors. An investor or utility wants either to lower their cost to serve load or make more money in the market. The return on investment is made through more volatile market prices.

Volatility describes the variation in prices. The higher the volatility, the greater the variation in prices. Renewables increase volatility in two ways. First, when the wind is blowing or the sun is shining, the market price for power drops. Second, when renewables stop providing energy, thermal capacity like gas generation needs to kick in and balance the power load in the system. The first element lowers the price, and the second increases the price. So both elements increase the volatility (just in opposite directions). 

Figure 3 shows the average prices and volatility for different price nodes in the USA. The bigger the bubble, the greater the volatility, and the darker the colour, the higher the average price. For instance, in northwest Texas, there is a lot of volatility driven by the massive amount of wind generation in the area. Also, the Pennsylvania-New Jersey-Maryland (PJM) market area shows some volatility and quite a high average price for energy. We forecast that the sizes of the bubbles will get larger in the future, making the case for flexible gas generation even more attractive to North American markets. 

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Fig. 3 - Volatility heat map.
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Fig. 4 - Day-ahead price and dispatch.

Value of flexible operation mode

So far, we have talked about increasing market price volatility, why this is important for flexible gas generation, and how the volatility helps justify an investment case. There are two main elements in the American ISO markets: day-ahead market and real-time market. The first one sets the price for each hour the day before, while the latter one sets the price for every 5 minutes, just 5 to 10 minutes in advance. 

The next couple of examples demonstrate how flexible gas generation is able to exploit market opportunities in different market situations.

Flexible gas plant description

  • Capacity = 200 MW
  • Efficiency = 50%
  • Gas price = USD 10/MWh
  • Variable O&M = USD 3.0/MWh
  • Short run marginal cost (SRMC) = (USD 10/MWh / 50% + USD 3.0/MWh) = USD 23/MWh
  • The flexible gas plant will run if the market price is above USD 23/MWh
  • Start-up time to full load = 5 min, no minimum up time
  • No start-up penalty

Case 1: Traditional day-ahead dispatch

Figure 4 shows a traditional day-ahead dispatch where the price has been set for each hour. The day-ahead price is between the hours ending at 9:00 and 20:00. So the plant will be started at 8:00 and stopped at 20:00, operating 12 hours during the day. We are able to calculate profit for the plant by subtracting the SRMC from the market price during the hours when the plant is operating. The profit for this 200 MW plant over the 12-hour period is USD 44,000. 

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Fig. 5 - Real-time market example with a price spike.
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Fig. 6 - Real-time market example with low prices.

Case 2: Price spikes in the real-time market

On average, the real-time price is very close to the day-ahead price over a longer period, e.g. a year. But in the short term, there can be large deviations from the day-ahead price. Figure 5 shows an example from the Texas market (ERCOT), where the price can hit a price cap of USD 9000/MWh in a scarcity situation. In Figure 5, this type of event happens at 6:00 and lasts only 15 minutes. This type of situation can be caused by a large plant failure or a problem in the transmission line. 

As this kind of event comes “out of the blue,” the traditional generation that is not online is not able to react. Fast-starting gas generation, however, is able to exploit this opportunity by starting fast and catching the price spike. The plant will come online and run only 15 minutes. The price is USD 9,000/MWh and the plant runs 15 minutes with the SRMC of USD 23/MWh, when the margin from this 15 minutes is USD 448,850 ((9000 USD/MWh – 23 USD/MWh)*200 MW/4) = USD 448,850.

The flexible gas unit that was able to react to the price signal was able to make 10 times higher margin during 15 minutes in the real-time market than running for 12 hours in the day-ahead market. 

Case 3: Price below the short run marginal cost in the real-time market

The real-time price can be also below the day-ahead price – for instance, if there is more wind generation available than was predicted 24 hours before. This type of situation has been illustrated in Figure 6. The real-time prices start to deviate from the day-ahead price at 9:00, and the same happens in the evening around 20:00. This could happen, for instance, if the wind starts to blow earlier than predicted and calms down earlier than predicted. 

A flexible gas power plant can also exploit this situation. It has the day-ahead commitment, but it can fulfil its commitment by buying the electricity from the real-time market. This makes sense, if the electricity price in the real-time market is below SRMC. In our example, the plant would have been started at 9:00, and shut down at 9:10 when the real-time market prices go below SRMC. The plant comes online again at 11:25 when the real-time price is above SRMC. By shutting down the plant and fulfilling the commitment from market-based resources, the plant makes USD 6916 additional margin. The same kind of situation takes place in the evening, when the plant is able to generate USD 1582 additional margin. In total, the plant makes USD 8498 additional margin during the lower real-time market price periods. 

 By exploiting the opportunities, the flexible gas plant is able to make a profit of USD 501,348 during the day, which is more than 11 times the profit when compared to day-ahead dispatch only. Of course, the operational profile looks different than the day-ahead dispatch (Figure 7). Now the plant will start three times during the day, with an aggressive ramping. On the other hand, this is not a big deal since the flexible plant is designed for this type of operation with unlimited starts and stops. 

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Fig. 7 - Planned and realized operational profile.
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Fig. 8 - SPP market based dispatch analysis.

Case studies from the North American market

Illustrative examples are good to demonstrate the basis of a value proposition, but the real life situation is a different story. To demonstrate the value of Wärtsilä’s flexible gas power plants, we have carried out several market-based analyses where the power plants are dispatched against historical and future prices. The following case studies talk about the value and business case of a Wärtsilä flexible gas power plant in the PJM and Southwest Power Pool (SPP) markets in the USA. 

Load-serving entity looks for “cheap” capacity in Southwest Power Pool 

SPP launched a so-called Integrated Marketplace in March 2014. The Integrated Marketplace introduced market-wide system balancing through the real-time market, which totally changed the operational profile of existing Wärtsilä assets in the market. The Antelope Station owned by Golden Spread Electric Cooperative experienced around 10 starts per engine in the month prior to the market change. Since March 2014, the Antelope station has started each engine on average 80 times per month and 3 times on average daily.

Wärtsilä wanted to understand the value of this type of operation from a cooperative perspective that tries to minimize the cost to serve load for its customers. Wärtsilä analysed the first 12 months of operations of the SPP market and replicated the market dispatch with its analysis tool. 

In the analysis, Wärtsilä compared three potential alternatives for a typical load-serving entity in the SPP. The load-serving entity has to serve a load of 200 MW, and it is looking for 200 MW of generation capacity to serve that load. The generation alternatives are Wärtsilä 18V50SG, Industrial Gas Turbine and Aeroderivate gas turbine (Table 1). 

The analysis tool dispatched all generation alternatives against the market prices based on their variable costs (SRMC) and technical capabilities. The dispatch analysis was first done only for the day-ahead market, and then for day-ahead, real-time and ancillary services markets. The results of these dispatch simulations are shown in Figure 8.

 The full optimization case takes into account the real-time market opportunity as well as the ancillary services market. Due to its better heat rate as well as flexibility, Wärtsilä’s solution will operate a lot more than the gas turbines. The plant will operate more than 4000 hours and start about 1550 times per year. 

Load-serving entities use “net cost to serve load” as the metric to estimate the most affordable generation option to meet their load. This approach assumes that all electricity needed to serve its load is bought from the market, and all generated electricity is sold to the market. The formula and explanations are shown in Figure 9.

 In our analysis, we used the dispatch results from the first 12 months of the SPP Integrated Marketplace, and filled in the other cost elements of the net cost to serve load calculation (Figure 10). 

 The net cost to serve load analysis clearly shows that the 200 MW Wärtsilä option provides the lowest cost to serve load. Annualized cost with the Wärtsilä solution is USD 55 million, while the lowest capital cost product, the industrial gas turbine, ends up at USD 72 million. Traditionally, load-serving entities have been looking for only the lowest capital cost products, but in today’s market environment, that option does not provide the lowest cost to serve load. Wärtsilä’s 200 MW option is able to provide USD 17.5 million savings on an annual basis compared to the industrial gas turbine. The higher capital cost of Wärtsilä’s solution is compensated by the higher utilization of the asset in the market, providing additional revenues and gross margin from the market. 

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Table 1 - Generation alternatives.
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Fig. 9 - Net Cost to Serve Load formula.

Independent Power Producer looking for the best rate of return

Another interesting investor group in the USA, Independent Power Producers (IPP), is trying to maximize the return on investment. The utilization of the asset is the same as with the load-serving entity case (maximize utilization), but the financial perspective is a bit different. An IPP will put its own money (equity) into a project and try to maximize the return on this investment. The typical metrics used in the industry is internal rate of return (IRR) for leveraged project, or equity IRR. 

Wärtsilä did a market analysis from an IPP perspective for the PJM market in the USA, which is the biggest electricity market in the world. The IPP was looking for an investment between the most efficient Combined Cycle Gas Turbine (CCGT) and Wärtsilä 18V50SG simple cycle configuration (Table 2). 

The IPP was interested in analysing the performance of both alternatives against the future price curves (Figure 11). Wärtsilä ran the market dispatch tool against the future price curves, while assuming the same historical volatility levels for day-ahead, real-time and ancillary services prices. The results of the dispatch analysis are shown in Figure 12.

When the comparison is made against the high efficiency CCGT, Wärtsilä’s solution runs less. Once again, there is a big difference if we include only the day-ahead market (dotted line), or in addition the real-time and ancillary service market opportunities. For a flexible gas plant, the real-time market and ancillary service market are essential. Taking them into account almost doubles the economical running hours. These markets also have significant impact on the IRR numbers, which can be seen in Figure 13.

 The day-ahead only analysis shows that the CCGT option is slightly better than the Wärtsilä solution. The full optimization case, which also contains the real-time market and ancillary services market, gives totally different results. Return on equity more than doubles to 30%, and now Wärtsilä’s solution is clearly a better investment case than CCGT. The traditional day-ahead analysis does not add value for flexibility. Rather, it looks only at the heat rate and capital expenditure, while the full optimization is able to demonstrate the value of flexibility on top of the day-ahead analysis. The PJM analysis has been an eye-opener in the market, as this is the first time that Wärtsilä is able to show better return on investment with a large-scale reciprocating engine solution than the state-of-the-art CCGT.


The electricity market environment in North America is becoming more favourable for flexible gas. The increasing renewables, together with enhanced market rules, are increasing price volatility across the markets, making the investment case for flexible gas power very attractive. 

Wärtsilä’s existing plants in the USA are already experiencing this change, and their operational profiles are very flexible: for instance, starting and stopping the engines 1400 times per year, and ramping up and down constantly, in order to balance the system more economically. The mindset among investors to date has been, “This is great, but we’re not able to quantify the value.” But Wärtsilä has done extensive modelling to quantify the value of flexibility across the North American ISO markets, and the results are impressive. 

Figure 14 summarizes the notable results of the analyses done so far. Across the ISO markets, Wärtsilä’s solution is able to provide either lower cost to serve load or higher return on investment than gas turbines. If you want to learn more about the analysis, please visit 



SPP white paper

Real life cases

ERCOT white paper


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Fig. 10 - Results of Net Cost to Serve Load analysis.
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Table 2 - Input parameters in the PJM analysis.
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Fig. 11 - PJM forward price curves.
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Fig. 12 - Operational profiles of Wärtsilä and CCGT in the PJM future analysis.
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Fig. 13 - Equity IRR (leveraged IRR) in PJM.
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Fig. 14 - Results of the ISO market analysis - Leveraged IRRs and Savings for load serving entities (SPP and MISO).

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