Operators of smaller distributed generation plant can be faced with a complex task to successfully sell power to the local electricity market, even if they are allowed to participate in the market at all. A European research project – MASSIG – has addressed the problem and here presents a procedure to succeed, writes Christian Sauer.
The Weingarten CHP installation of badenovaWÄRMEPLUS
Distributed generators (DG), especially renewable energy sources (RES) and local cogeneration units will gradually replace a good part of conventional energy generation in future according to the European Commission targets. Up until now, in most European countries, small and medium size generation units – frequently located in areas of high electricity demand and owned and operated by smaller companies or private investors – receive subsidies or are eligible for feed-in tariffs making the investment profitable. Yet, for the medium-term development, it is clear operators of such power generators must be motivated to adjust energy output as much as possible to momentary market requirements and electricity demand.
This can be done by offering promising market options for paying off the investments and operation of the distributed generators. Yet this is quite a challenge in practice, since the plant operators need to know those market options in their country, need to be able to assess profitability of different market options (e.g. spot or reserve market products) and must implement measures to meet technical requirements mandatory for certain market products.
Most owners of smaller size generation units have neither the competence nor the capacity to exploit all the opportunities and overcome the challenges, and need guidance on what to do. The European research project MASSIG (www.iee-massig.eu) evaluated the situation of marketing electricity from RES and DG in exemplary countries with very different legal framework conditions: Denmark, Germany, Poland and the UK, and elaborated concepts and tools for finding the most promising market options adjusted to the corresponding national situation.
In the following, the most relevant project results are presented by discussing a concrete showcase example and demonstrating the step-by-step procedure of checking market options, technical requirements, undertaking a gain-loss evaluation and formulating the first actions. Typical market options under consideration are power exchange markets or markets for balancing and reserve energy. Those market options are compared to ‘default’ marketing options, such as feed-in tariffs.
Amongst renewable and efficient power conversion technologies at a distributed level cogeneration (CHP) plays a special role. A growing number of generators are installed at distributed locations and the cost level for decentralized cogeneration makes this technology cost-competitive to conventional power plants in many cases. what’s more, cogeneration has its special role as a controllable and relatively flexible electricity generation technology.
Therefore, a representative CHP installation in a medium power range has been chosen for the Showcase evaluation. This installation is operated by the German utility badenovaWÄRMEPLUS and includes two gas engines with a total of 5.8 MWe installed (thermal power 6.3 MWth), three additional gas boilers with a total of 28 MWth for covering thermal peak loads, and a thermal storage capacity of 360 m³. The installation is connected to a 40 km district heating grid.
In Germany, where cogeneration already contributes 12% to gross electricity production, many plants are not eligible to feed-in tariffs anymore since January 2010 because of their age. Operators of these plants need to think of alternative electricity marketing options if they do not want to shut down the whole systems. In our showcase this describes the current situation for the Weingarten plant.
|Figure 1. Weingarten CHP operation for January 2010 (bilateral contract)|
In order to continue operation of the plant a peak/off-peak contract was negotiated with badenova electricity sales for the CHP electricity. In the first quarter of 2010 the average price of €38.2/MWh was paid by this trader on the basis of this individual bilateral contract. The last quarter of 2009 still covered by the CHP Act had given a higher average price of €42/MWh. Also, peak electricity prices at the power exchange EPEX are often even higher. Therefore, alternative marketing options to this bilateral contract will be assessed in this article.
ELECTRICITY MARKETS AND PRODUCTS
For any power generation unit, the most obvious market product is active power, which could either be consumed locally or can be sold directly to customers or freely traded at the power exchange. Besides active power, there are a number of other market options, addressing e.g. regulating power or ancillary services. Investigations in the MASSIG project showed some of the market options are more promising for distributed generation. These options are identified following a step-by-step approach.
First, information on available products on power markets, mechanisms for the procurement of ancillary services and framework conditions for the use of other marketing options is investigated. Then the minimum bid size – a principal barrier for DG – is identified for all available options. For the remaining options the availability of data needed for subsequent profitability analysis is investigated. Marketing options that are restricted neither by technical requirements nor by the lack of data and that also seem to be economically feasible, are indicated as most promising.
Table 1 summarizes the most feasible marketing options for DG in Germany.
Apart from spot trading into the power exchange, tertiary reserve (in Germany called ‘Minutenreserve’) is an attractive option for direct electricity marketing. Tertiary reserve is part of the regulating power market products. It has a minimum bid size of 15 MW with 1 MW increment; aggregation of several generators to reach the minimum bid size is allowed. Tertiary reserve is split into availability and activation, where availability is paid with a price for the reserve power, and activation is paid for the amount of energy delivered or withdrawn when being called by the transmission grid operator being responsible for balancing.
Net metering means that an electricity consumer which either owns an electricity generator or is located closely to such an installation first covers his own electricity consumption and then feeds surplus electricity generated into the electricity network. Net metering, especially for smaller consumers such as private households with comparably high fixed tariffs for electricity consumption, has become of growing importance. This development is supported by legislation, as both the German CHP Act (KWKG) and the Renewable Energy Acct (EEG) promote net metering by defining bonus payments since January 2009.
Figure 2. Weingarten CHP operation for January 2010 (optimized spot market trading)
PRECONDITIONS, RESTRICTIONS AND ADAPTATIONS
Before undertaking an economic evaluation of different market options it is essential to clarify which technical and legal pre-conditions are mandatory for an entity to become an actor on the market, and which technical criteria must be fulfilled to implement certain marketing options.
As described in the electricity markets and products section, the most promising market options seem to be the participation in the day-ahead and intraday markets at the power exchange EPEX, and offering of tertiary reserve at the regulating power market platform (www.regelleistung.net). Regarding the technical preconditions, each installed generator needs to comply with the rules on grid interconnection and needs to be equipped with corresponding metering technology.
For trading energy into the day-ahead spot market, the market actors selling electricity are obliged to produce a prescribed power volume at a definite time, facing at least financial risks when there is deviation from the sold volumes. This presents some difficulty for someone owning a CHP installation, as with CHP heat and electricity production must always be considered. Predication accuracy for heat demand is limited, depending on weather forecasts and heat consumers’ behaviour. Therefore, if no sufficient heat storage capacities or alternative heat producers (e.g. boilers) are available, there is a significant risk about the predictable electricity generation of the CHP plant.
When offering tertiary reserve, the CHP plant operator must ensure being able to deliver the amount of energy he is told within 15 minutes. Activation follows a merit order and is done manually (telephone call). Therefore, required information and communication technology (ICT) infrastructure can be easily arranged. Nevertheless, for clustering several generators some ICT may be necessary for activation of such an aggregated pool of power plants.
Generally, a creation of aggregations of smaller CHP generators helps to increase total output to the range of several MW and decreases the influences of weather and heat prognoses error. Also, the use of larger thermal stores always helps to decouple heat and electricity delivery times.
From a legal point of view, smaller size CHP installations may be unable to afford the financial requirements (e.g. required deposits and capital reserve) or technical conditions of power markets with respect to established minimal bid/offer sizes (1 MWh/h in UK and Poland, 0.1 MWh/h in Germany and 1 MWh/h in Denmark). Therefore, they are unable to participate in electricity market trade independently and could consider the following options:
- bilateral trade based on PX price indicators
- bilateral trade with fixed (negotiated) price
- build up an aggregation of power generation units of arbitrary RES/DG generation types, including conventional types of power generation
- participate in a virtual power plant’s activity by joining a cluster of different power generation units of different technologies to obtain cumulative output necessary for electricity market trade
- make use of broker’s services.
With the knowledge of the most promising market options, the technical and non-technical requirements and information about cost factors and uncertainties, it is possible now to make an assessment about gains and losses for the different market options.
The economic feasibility of the participation in competitive energy and ancillary service (AS) markets is based on a cash flow analysis using historical data. Records of at least one year of spot and balancing market prices and tertiary reserve results are used for the assessment of different market options.
The cash-flow analysis accounts for a multitude of components, including entrance fees, fixed and variable costs at the power exchange, reference incomes from support schemes, balancing market profits and losses, and others.
In order to show the value of participating in the EPEX spot market, the CHP operation was simulated (in modelling software called energyPRO) for January 2010 as operation period of the Weingarten CHP installation – see Figure 1.
Figure 1 shows the results of operation management for remuneration after the bilateral electricity contract. The CHP plant is almost running non-stop, even if off-peak electricity prices (marked red in the upper graph in the figure) are not very attractive.
Figure 2 shows operation management for optimized trading into the spot market.
The result shows that the CHP plant only produces when spot prices are above the marginal electricity generation costs (marked green in upper graph in the figure). We see that the CHP operation time is reduced during times of low spot market prices (marked red in upper graph), being replaced by the gas boilers.
After performing the gain-loss evaluation it turns out that, with optimized trading into the spot market, the operating income can be increased by 10% compared to the bilateral contract. Now, as a rough estimation, if the CHP installation would have offered negative tertiary reserve in January 2010 during scheduled operation, the operating income could have been increased by at least another 3% compared to the bilateral contract.
HOW TO PROCEED?
It is suggested that the procedure of finding profitable electricity markets for a small scale generation unit should be divided into the following four steps (all work package reports mentioned below can be found at www.iee-massig.eu):
Step 1 – select the electricity markets to be considered for your generation unit
An analysis of the electricity markets currently available in your country will give a starting point about the market options to be considered. A summary of most common market places is given in the MASSIG report, but it is unavoidable to cross-check with the current situation, since electricity markets are rapidly evolving.
Step 2 – find out if it is technical possible to enter the selected electricity markets
Assessment of technical and non-technical preconditions for entering the markets identified in step 1 is inevitable for successful market participation. Those preconditions have been assessed in for Denmark, Germany, Poland and the UK.
Step 3 – find out if it is economically feasible for you to enter these electricity markets
The gain and loss evaluation tool developed in the MASSIG-project is a good hint about economic feasibility for entering some of the electricity markets. Also, knowledge about how feasible it is to participate in the electricity markets often comes from similar plants that already operate in these markets.
Step 4 – contact an energy trader offering to operate your plant in these electricity markets
A number of energy traders should be contacted to hear what they are able to offer. Depending on the type of service offered, a skilled energy trader might be needed, to be sure that the plant is operated in an intelligent way. A skilled energy trader will also often have the capability to calculate the prospective income from a smaller plant being operated in selected electricity markets.
There may be the serious problem that a skilled energy trader does not exist yet. Then it might be worth considering getting together with other small size generators and initiating the establishment of a new company which can offer to operate the plant in these markets. A tough task – but it might show profitable for you to take such an initiative.
The ability and willingness of owners and operators of DG and RES to participate in energy markets and gain money from actually selling power to customers is one cornerstone in the process of establishing this sort of power generators in the overall system of energy supply. With the MASSIG project, tools and procedures have been developed that help those actors to discover and assess market options and to give them help regarding the necessary actions.
Certainly the ‘how-to’ procedure described above could easily be adapted to a variety of scenarios and help during the decision making process to find the most promising market options. And it could even give incentives at a very early stage of planning of new investments by making it possible, for example, to estimate the profit that could be gained by using storage systems or combining different types of generators.
In any case, marketing of power from distributed generation especially from smaller size generators will continue to be a challenging job and most certainly for quite a number of situations the final recommendation must be: go to a professional service provider and let them do all the difficult work for you.
Christian Sauer is with the Fraunhoher-Institut für Solare Energiesysteme ISE, Freiburg, Germany.