Electrolysis for energy storage and grid balancing in West DK

West Denmark has a large endowment of modern wind turbines, amounting to 2,374 MW capacity (2003), while peak winter load during 2003 was 3,746 MW. The Danish Government is committed to extend this capacity before 2010, to about 2,700 MW. High wind power output often occurs out of phase with demand and often unpredictably. Wind power output also ramps up and down continuously, sometimes by large amounts. The resulting imbalance is most often handled across West Denmark's inter-connections with Sweden (150 TWh), Norway (120 TWh) and Germany (500 TWh), all three systems being many times larger than West Denmark's (20 TWh) . In addition, because half of Sweden's and all of Norway's power plants are hydro, there is an excellent match between wind and fast responding hydro, from an overall operating and grid balancing point of view. However, when built, the wind capacity in 2008 - 2010, will be roughly equivalent to the export capacity of all West Denmark's inter-connectors. These may become bottlenecked at times of high wind turbine output. The inter-connectors themselves, cannot be relied upon all the time. There was an extended, 5-month outage of the 500 MW Skagerrak 3 inter-connector during 2003 (July thro' December), preceded by another failure in one of the older Konti-skan connectors to Sweden in the winter of 2002-2003. Measures are already being taken to reduce further risk of bottle-necking by changing the conditions under which the decentralized power stations operate and amending the law that forbids the use of electricity for heating at these power stations. Denmark's well functioning, district heating generation plants (CHPs) are in almost every town and village (1,656 MW in 560 units). Provided that the right market conditions can be created, West Denmark can use them to develop a transport hydrogen infrastructure, based on using 'over-flow' wind energy, sooner and more economically, than possibly anywhere else on Earth. The high pressure, electrolysers, of the type studied and proposed in this report, can be delivered in unit sizes up to 3.5 MW. They are very fast acting, being capable of a ramping up and down from zero to full load in 200 milli-seconds and are therefore technically attractive to the power regulating market. This is expected to grow as wind capacity is added. Built in sufficiently large numbers, soon enough, these can partly address the foreseen inter-connector bottle-necking, and assist grid balancing and grid stabilisation. To develop an infrastructure that can reduce Denmark's total dependence on hydrocarbons for transport, which consumes 200 PJ per year, and produces about 11.5 million t/y of CO_2 emissions , is an enormous task, requiring decades of development time and still uncalculated but very large amounts of money. Energistyrelsen's terms of reference required us to investigate the economy of constructing electrolyser systems at these decentralized power plants. The hydrogen would be stored and spiked into the natural gas that fuels the engines and turbines. The electrolysers would be upgraded to hydrogen filling stations as vehicles became available, locally, which are fueled by hydrogen. In the first instance, these are foreseen as local fleets, with high rates of utilization, such as buses, taxis, ambulances, delivery vans, etc. The use of hydrogen as a natural gas substitute in the power plants is envisaged as an intermediate application, prior to its adoption as a transport fuel. Around 5.5 TWh of wind energy will be produced in 2008 - 2010 from West Denmark. If all of this were used to manufacture hydrogen, it would produce 1.3 billion Nm3 of hydrogen with an LCV of 14 PJ. From this, it can be seen that existing wind energy can deliver a substantial fraction of West Denmark's transport needs when hydrogen-powered vehicles become available. The construction and development of an electrolyser system at Ringkøbing Fjernvarmværk, was pre-engineered and priced to test whether the intermediate use of hydrogen, as a natural gas substitute, could justify building and operating the electrolyser plants commercially, under present day market conditions. The calculations tested various ways to ensure that the hydrogen that would be generated would be from renewable energy sources and thus would not cause any incremental CO2 emissions. In this case, special fiscal treatment might be justified. One reliable way to ensure this, is to document that the consumption of renewable electricity, by way of tradable 'Renewable Energy Certificates'. When the European (CO_2) Emissions Trading System (ETS) begins next year, 2005 environmental externalities will be partly internalized in the electricity price. Everything else being equal this will increase the price of electricity to the benefit of renewable energy generators with no CO_2 emissions. However, no account of benefits from such trading could be used in our calculations, due to the lack of any reliable information about special tax treatment or ETS and likely CO2 price levels. It was assumed that the electrolyser can bid successfully into the downward regulating market, reducing the price paid for energy by the average amount recorded in ELTRA's data base, of each year from 2000 thro' 2003. The average, untaxed cost of electricity to the electrolyser, had it been able to bid, successfully, into the downward regulating market during 2000 thro' 2003 was as follows: Year 2000, Øre per kWh 5.5; 2001, 10.6; 2002, 9.5 and 2003, 13.2. In addition, during the last, record, wet year, the average price for West Denmark was 12.2 øre/kWh. The results show that it is not feasible to displace power station gas with hydrogen, even when that gas is taxed and the hydrogen is not. Taxed gas costs the power station DK 57/GJ while tax-free hydrogen needs a sales price in the range of DKK 150/GJ . This is more due to the capital costs of plant constrained to run about half the year. On the other hand, Danes are paying (without excessive complaint) DKK 250/GJ for transport fuel when they pay DKK 8 per liter for petrol. Of course, about 75% of this is tax. Therefore, if the project is to advance further, on a commercial basis, requiring no public subsidy, the price paid for hydrogen must reflect its value as a high fraction of the price of taxed transport fuel. Special fiscal arrangements will need to be developed to encourage this. This will also probably require that companies experienced in and motivated by the retailing of transport fuel become involved. The costs shown demonstrate that its intermediate use as power station fuel will require that the host CHP be compensated for consuming a more expensive fuel