2015_2 Value of Smart Power Generation master

Value of Smart Power Generation for utilities in the national electricity market of Australia

In the National Electricity Market (NEM) of Australia, open cycle gas turbine (OCGT) plants have traditionally been used as peaking plants to hedge utilities against the market price volatility. A state-of-the-art modelling framework shows that a Wärtsilä Smart Power Generation (SPG) peaking power plant can provide a significant gross margin to the utility, compared to OCGT alternatives. At the same time, SPG decreases the risk exposure of the utility by reducing the volatility of annual returns. The benefits are based on the inherent operational flexibility of the internal combustion engine (ICE) technology, especially the capability to reach full load in less than 5 minutes.


Why National Electricity Market of Australia is special?

The National Electricity Market (NEM) is probably the most developed and economically efficient electricity market in the whole world. The market design of the NEM is a gross mandatory pool, where all generators are obligated to sell all produced electricity to the market. Correspondingly, electricity is bought by retailers from the pool. The market aggregates all generation and simultaneously schedules generators to meet the demand. This is managed through a central dispatch process, operated by the Australian Energy Market Operator (AEMO). Based on generation offers and demand bids, AEMO defines the most cost-efficient dispatch for every 5 minutes. The first indicative dispatch is computed a week ahead before delivery. Redispatching, based on the adjusted bids, continues until 5 minutes before the actual 5-minute dispatch interval. At the gate closure, the final dispatch and the dispatch interval prices are defined for the five NEM regions across Australia. Six consecutive 5-minute dispatch interval prices are averaged every half-hour to determine spot prices for each 30-minute trading period.

Most of the utilities in NEM are so-called gentailers (generator + retailer). They have generation assets and load to serve. One important task for gentailers is to balance their own thermal generation according to their expected retail load and intermittent renewable output. This causes active re-bidding just prior to the gate closure, occasionally creating significant price spikes.

Spot prices are highly volatile in the NEM, and market participants have to manage their exposure to risks created by the price volatility. Generators and retailers manage their market price risk by using long- and short-term financial contracts, which ensure a firm price for electricity. These contracts are so called Contracts for Differences and include swaps, caps, options and futures. In addition, the majority of gentailers own flexible peaking power plants as a physical hedge against price spikes in the market.

State-of-the-art modelling framework is required to capture the value of flexibility

Wärtsilä expected that superior start time of SPG could be perfect match with 5-minute electricity dispatch on NEM. Therefore, Wärtsilä engaged Ernst & Young (EY) to study the potential of SPG power plants within a large utility portfolio in South Australia. The entire NEM is modelled in this study, but the main focus is on the South Australian (SA) market region in the fiscal year of 2020–2021. SA has the highest share of intermittent renewable generation, and historically high levels of market price volatility. The selected utility has a broad mix of thermal and renewable generation assets, and a large retail position in the market.

The analysis has been carried out using EY’s 2-4-C market modelling software, which replicates closely the real dispatch executed by AEMO. To capture the effects of the inflexibility of the current generation assets, the entire NEM is modelled with 5-minute granularity, just as it is dispatched in real life. In the model, generation is dispatched according to the offers for meeting the demand. The dispatch is also subject to certain constraints, such as limited transmission capacity. The price of electricity for each 5-minute dispatch interval, in each NEM region, is defined by the marginal generator.

Based on historical bidding data, multiple bidding strategies are developed for each utility in the NEM. For example, a utility can bid its entire generation with the marginal cost, withhold capacity by moving bids to a higher price, or bid all its generation at the market floor price to ensure maximum generation volume after a price spike. Each utility chooses the best bidding strategy for each 5-minute dispatch interval while trying to minimize the total cost of serving the load over a 30-minute trading period. The total cost of serving the load includes also revenues derived from frequency control ancillary services (FCAS). (Figure 1)

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Fig. 1 – Quantified value components of portfolio analysis.
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Fig. 2 – SPG is able to prevent disadvantageous price spike and reduce retail cost when portfolio is net load position.

Each gentailer has its own load to serve. The load is based on the forecasted regional demand profile and expected market share of the utilities in the SA retail market. The retail revenues are excluded from the analysis, as they are relatively fixed. The additional risk analysis is essential to ensure that the added value of SPG was not produced at the expense of increased risk for the utility. For the assessment of a portfolio risk, 25 separate Monte Carlo simulations are conducted for the selected year. Monte Carlo simulation varies the forced outage pattern of generators and interconnectors, as well as the time series for wind, large-scale and rooftop solar PV generation. A standard deviation of the total cost to serve the load, over multiple Monte Carlo simulations, is used as a risk factor. (Figure 1)

Three different future cases of the utility portfolio are analysed separately. 200 MW of the oldest existing capacity will be demolished and replaced by either

  • 200 MW heavy duty OCGT GE 9E plant,
  • 200 MW aeroderivative OCGT GE LM6000, or
  • 200 MW SPG plant

SPG is capable to capture or prevent disadvantageous price spikes on the market

SPG has a higher thermal efficiency than both the OCGT solutions. This enables more profitable running hours for SPG in the market. However, when the peaking plant is running at full output, the value of operational flexibility is already being utilised. This is because flexibility derives from the capability to increase generation as quickly as possible. From a gentailer portfolio point of view, the value of additional energy is sometimes minor compared to the value of flexibility. Therefore, the utility has to accept a trade-off between flexibility (withholding capacity) and profitable generation (running the plant against the market). When comparing the three cases, SPG has superior flexibility, as well as the highest thermal efficiency. Examples of how flexibility can create added value for a gentailer are explained using the following examples.

As shown in Figure 2, in this particular 30-minute trading period, prices are high, but during the previous 30-minute period they were low. The utility does not have any generation online and is, therefore, exposed to possible high prices. In the OCGT 9E case, the plant is not capable of providing energy during the first 5-minute dispatch interval. Hence, it is not able to prevent the price spike. After the first 5-minute interval, the OCGT 9E is brought online to maximize generation during the remainder of the 30-minute trading period. Since the trading period price is averaged at the end of the period, one 5-minute price spike increases the price of the trading period to as high as 2193 AUD/MWh. During this trading period the gentailer is strongly in a net load position, meaning that its retail load is larger than its own online generation. During the 30-minute trading period, maximized generation revenues and a hedging contract settlement cannot compensate for the high retail cost. As a result, the total cost to serve the load over this 30-minute period is as high as AUD 251,101. (Figure 2)

 As Figure 2 indicates, in the SPG case the gentailer bids its capacity with a marginal cost, because price spikes would be harmful for its portfolio in a net load position. For the first 5-minute dispatch interval, a part of the SPG plant is dispatched. It is started for just 5 minutes and the price spike is prevented. For the second 5-minute interval, the price drops below the SPG plant’s short run marginal cost and the plant is shut down. The price spike is avoided, thus resulting in significant value for the portfolio during this 30-minute trading period. Compared to the OCGT 9E case, SPG provides savings of AUD 222,830 for the portfolio during the 30-minute trading period. This is achieved as a result of the SPG plant’s capability to go from stand-by to full load in less than 5 minutes. (Figure 2)

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Fig. 3 – SPG is able to generate more energy after the price spike and thus increases significantly the benefit for the utility during the 30-minute trading period.
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Fig. 4 – Compared to the OCGT 9E and OCGT LM600 cases, Smart Power Generation enables significant added value due to the higher generation net revenue, lower retail cost and superior revenue in frequency control ancillary services.
As shown in Figure 3, for the 30-minute trading period examined here, the market price is low during the first 5-minute dispatch interval, but hits almost the price cap of 13,500 AUD/MWh during the second 5-minute interval. The OCGT 9E plant reacts to the price spike immediately, but due to its slow starting time, it can deliver only 48 MWh during the 30-minute trading period. The SPG plant also misses the price spike interval as it is offering capacity at a price that is too high. For the third 5-minute interval, the utility changes its bidding strategy. It bids the SPG plant at the market floor price and starts the plant immediately to its full 200 MW load. The SPG plant runs at full load over the remaining four 5-minute intervals. It is able to generate 133 MWh during the trading period, compared to the 48 MWh by the OCGT plant. As a result, the benefit for the selected utility in the SPG case is almost AUD 90,000 higher than in the OCGT 9E case. (Figure 3)

SPG is superior replacement investment compared to open cycle gas turbines

To maximize portfolio level benefits, the SPG and OCGT plants are exposed to an extreme operation regime in the model. Due to the limited flexibility of both OCGT solutions, they cannot capture all the emerging market opportunities. In addition, they cannot reach full output in the dispatch intervals after a market opportunity (price spike) has emerged. Nevertheless, the OCGT 9E plant is started 434 times per year, and runs for only one hour per start on average. It reaches 395 running hours during the year. In the summer, when the probability of the price spikes is highest, the output of the OCGT is derated to 180 MW due to the high ambient temperature. Similar derating is not applicable to the SPG, due to the heat resistant ICE technology. As a result, the superior flexibility of the SPG plant opens more market opportunities and full output can be employed each time as required. The entire plant is started 1054 times per year, with 933 running hours. The plant is started 433 times to run for only a single 5-minute pulse, which demonstrates the value of the quick-start capability in peaking operation.

As the study excluded retail side revenues, the cases can be evaluated by comparing the total cost needed to serve the retail load. The analysis indicates that the gentailer’s annual net generation revenues increase when it invests in SPG instead of the OCGT 9E or OCGT LM6000. In addition, the retail cost decreases simultaneously. Only SPG earns frequency control ancillary services (FCAS) revenues, since it can provide 5-minute delayed rise ancillary services, even when offline. From the risk perspective, the SPG and the OCGT LM6000 cases have the lowest risk, measured as a standard deviation of total cost, as per 25 Monte Carlo simulations (Figure 4). Comparing alternative investments, SPG enables an additional gross margin per year of AUD 12.4 million compared to the aeroderivative gas turbine OCGT LM6000 case, and AUD 14.6 million compared to the heavy duty gas turbine OCGT 9E case. In addition, the highest potential for savings is reached with a portfolio risk similar to the OCGT cases.

SPG enables higher profit for the utility while reducing electricity price for consumers

In the National Electricity Market of Australia, OCGT plants have traditionally been used as peaking plants. Gentailers have utilized these plants as a physical hedge to protect their retail arm against market price volatility. However, this study shows that the superior flexibility of SPG power plants enables more efficient market price risk mitigation, as well as significantly higher generation revenues.

A 200 MW SPG power plant enables an additional gross margin per year of AUD 12.4 million compared to the aeroderivative gas turbine OCGT LM6000 case, and AUD 14.6 million compared to the heavy duty gas turbine OCGT 9E case. This is due to the SPG plant’s capability to capture more market opportunities in the 5-minute electricity market. By being able to start to full load in less than 5 minutes, the SPG plant can take advantage of price spikes.

As a part of the gentailer portfolio, the SPG plant is also used to prevent disadvantageous price spikes. This may be necessary when the gentailer is strongly in a net load position during a 30-minute trading period, meaning that its retail load is larger than its own online generation. In a single 30-minute period, compared to the OCGT 9E case, SPG can provide savings of AUD 222,830 for the portfolio.

Preventing price spikes brings also system level benefits. In the SPG case, the number of dispatch interval prices per year over 10,000 AUD/MWh drops to 23 compared to 36 in the OCGT 9E case. As a result, the average electricity price for consumers in the SA region falls by 4%.

Challenging market conditions continue

Dynamics of the National Electricity Market of Australia are changing. Electricity demand growth is flattened or even declining in some regions. At the same time, interest for small-scale PV has drastically increased and over 1.1 million households have installed own solar panels on their rooftops. Investments for large-scale renewable generation sustain on high level, while the AEMO is targeting for 33,000 GWh renewable generation by 2020. Subsequently, market prices have significantly dropped and price volatility has declined.

These developments have set utilities under pressure. As a result, until now over 1000 MW of baseload and mid-merit generation running on coal and gas generation has withdrawn from the market. AEMO’s recent Electricity Statement of Opportunities (ESOO) report indicates that a new thermal power generation is not necessarily required during next 10 years. However, the study has shown that SPG’s value is inevitable and SPG peaking power plant can provide a significant gross margin to the utility, compared to OCGT alternatives. Due to increasing share of renewables, most probably new investments are firstly in flexible peaking power segment. Wärtsilä is continuously following momentum of the market and meeting utilities regular basis to be prepared for a next wave of investments.

In addition, Wärtsilä has utilised learnings of this study in the US. There are several electricity markets with rather similar market structure and thus markets are rewarding agile flexibility of SPG. In these markets increasing load and thermal plant retirements bring surely interesting opportunities for Wärtsilä Smart Power Generation.


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More information: ville.rimali@wartsila.comluca.febbraio@wartsila.com

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