• Energy Research

Since the liberalization of electricity markets power prices are considered as highly volatile. Thus investment in new power plants is exposed to higher risks. Traditional capital budgeting methods lack the integration of flexibility. This can be overcome by applying real options analysis. In the context of an increasing electricity production by highly volatile renewable power plants, new solutions need to be found to ensure security of supply and to accommodate intermittent generation. Energy storage is seen as a possible solution. The Compressed Air Energy Storage (CAES) technology provides many key features that are relevant to deal with arising problems by renewables. Lately an advanced adiabatic version with higher roundtrip efficiencies has been discussed. However, high capital expenditures limit the economically viable implementation. As conventional CAES uses natural gas for production, it is exposed to price fluctuations on two markets. Depending on the configuration of component sizes, CAES storage units can be used for different purposes. A price model is set up to produce, in combination with the application of a Monte Carlo simulation, possible future price paths for power, natural gas and demand rate for minute reserve. Based on these price paths costs and revenues for different CAES applications are calculated. For the economic evaluation three different configurations are considered for both diabatic and adiabatic CAES. Investment in a diabatic CAES used for load-leveling purposes is found to be the most economical option.

Since the liberalization of electricity markets power prices are considered as highly volatile. Thus investment in new power plants is exposed to higher risks. Traditional capital budgeting methods lack the integration of flexibility. This can be overcome by applying real options analysis. In the context of an increasing electricity production by highly volatile renewable power plants, new solutions need to be found to ensure security of supply and to accommodate intermittent generation. Energy storage is seen as a possible solution. The Compressed Air Energy Storage (CAES) technology provides many key features that are relevant to deal with arising problems by renewables. Lately an advanced adiabatic version with higher roundtrip efficiencies has been discussed. However, high capital expenditures limit the economically viable implementation. As conventional CAES uses natural gas for production, it is exposed to price fluctuations on two markets. Depending on the configuration of component sizes, CAES storage units can be used for different purposes. A price model is set up to produce, in combination with the application of a Monte Carlo simulation, possible future price paths for power, natural gas and demand rate for minute reserve. Based on these price paths costs and revenues for different CAES applications are calculated. For the economic evaluation three different configurations are considered for both diabatic and adiabatic CAES. Investment in a diabatic CAES used for load-leveling purposes is found to be the most economical option.

AbstractThis paper investigates the economic feasibility of Power-to-Gas (P2G) systems and gas storage options for both H2 and renewable methane. The study is based on a model-based analysis using the net present value (NPV) method, as well as Monte Carlo simulation for taking fuel and electricity price risks into account. We study three investment cases: a Base Case where the gas is directly sold, a Variant A where temporal arbitrage opportunities between the electricity and gas market are exploited, and a Variant B where the balancing markets (secondary reserve market for electricity, external balancing market for natural gas) are addressed. Centralized and decentralized storage facilities are compared with each other and the optimal type and size determined. In a detailed sensitivity analysis and cost analysis we identify the key factors which could potentially improve the economic viability of the concepts assessed. We find that P2G for bridging the balancing markets for power and gas cannot be operated profitably. For both temporal arbitrage and balancing energy, pipe storage is preferred. Relatively high feed-in tariffs (100 € MW-1 for H2, 130 € MW-1 for methane) are required to render pipe storage for P2G economically viable.

AbstractThis paper investigates the economic feasibility of Power-to-Gas (P2G) systems and gas storage options for both H2 and renewable methane. The study is based on a model-based analysis using the net present value (NPV) method, as well as Monte Carlo simulation for taking fuel and electricity price risks into account. We study three investment cases: a Base Case where the gas is directly sold, a Variant A where temporal arbitrage opportunities between the electricity and gas market are exploited, and a Variant B where the balancing markets (secondary reserve market for electricity, external balancing market for natural gas) are addressed. Centralized and decentralized storage facilities are compared with each other and the optimal type and size determined. In a detailed sensitivity analysis and cost analysis we identify the key factors which could potentially improve the economic viability of the concepts assessed. We find that P2G for bridging the balancing markets for power and gas cannot be operated profitably. For both temporal arbitrage and balancing energy, pipe storage is preferred. Relatively high feed-in tariffs (100 € MW-1 for H2, 130 € MW-1 for methane) are required to render pipe storage for P2G economically viable.

This work aims at the economic evaluation of a semi-underground pumped hydro storage power plant erected in an abandoned open-pit mine. For the exploratory model-based analysis, we develop and apply both a simple deterministic and a stochastic net present value (NPV) approach, the latter of which uses a Monte Carlo simulation to account for revenue uncertainty from electricity price fluctuations. The analytical framework developed is applied to two promising sites in the Rheinland region in Germany, Hambach and Inden, making reasonable parameter value assumptions and considering and ignoring the lengthy duration of lower reservoir flooding. The investor’s value-at-risk is computed for alternative performance indicators (NPV, net cash recovery, profit-to-investment ratio, and specific production costs) to compare the different outcomes in terms of the project’s financial risk distribution. Calculations show that a semi-underground pumped hydro storage power plant in an abandoned open-pit mine can be constructed at reasonably low investment costs and operated at low specific production costs. However, because the investment has to be made long before the pit lake is (naturally) flooded—a process that for realistic flow rates may take up to 20 years—the project is highly uneconomical and would require substantial subsidies, as compared to a situation where flooding happens immediately.

This work aims at the economic evaluation of a semi-underground pumped hydro storage power plant erected in an abandoned open-pit mine. For the exploratory model-based analysis, we develop and apply both a simple deterministic and a stochastic net present value (NPV) approach, the latter of which uses a Monte Carlo simulation to account for revenue uncertainty from electricity price fluctuations. The analytical framework developed is applied to two promising sites in the Rheinland region in Germany, Hambach and Inden, making reasonable parameter value assumptions and considering and ignoring the lengthy duration of lower reservoir flooding. The investor’s value-at-risk is computed for alternative performance indicators (NPV, net cash recovery, profit-to-investment ratio, and specific production costs) to compare the different outcomes in terms of the project’s financial risk distribution. Calculations show that a semi-underground pumped hydro storage power plant in an abandoned open-pit mine can be constructed at reasonably low investment costs and operated at low specific production costs. However, because the investment has to be made long before the pit lake is (naturally) flooded—a process that for realistic flow rates may take up to 20 years—the project is highly uneconomical and would require substantial subsidies, as compared to a situation where flooding happens immediately.