Plant efficiency electricity pricing

After allowing for the performance penalties arising from the CO2 removal, Lozza and Chiesa estimated an efficiency of 46.1%, for a maximum gas turbine temperature of 1641 K and a pressure ratio of 15 (compared with the basic CCGT plant efficiency of 56.1%). They concluded that the plant cannot compete, in terms of electricity price, with a semi-closed combined cycle with CO2 removal (Cycle A2). 

Many of these plants may be built before CCS is ready and we will need to use our electricity more efficiently to slow the demand for such power plants, while building as many cleaner power plants as possible. Natural gas is far more cleaner for this power than coal. Generating hydrogen with renewables may be needed in order to avoid building coal-fired plants. More electricity from renewable power would reduce the pressure on the natural gas supply and reduce prices. The United States could have essentially carbon-free electricity before 2050 with hydrogen fuel playing a key role. 

The abundant solar energy resources are challenging potential option for hydrogen production. The solar cell costs are important element of the PV economic viability. The modules account for about 50% of cost of a PV power plant. The solar cells themselves account about half of the module cost, or 20% of total system cost. Thin film polycrystalline technology may make possible to have the module cost about 50 USD/m and electricity price of 6 cents/kWh. This is only a planning target for 10% efficiency. 

The levelized H2 and PV electricity price estimates are presented in Table 3. The PV electrolysis plant dominates H2 production cost. The PV electrolysis plant component of the levelized H2 pump price ranges from 3.75- 4.67 per kg H2 contingent on PV module efficiency and PV area cost. The total levelized H2 pump price ranges from 5.53— 6.48 per kg H2. The levelized H2 pump price estimates do not include fuel use taxes. In the U.S., fuel use taxes typically range from 0.40-0.50/gallon of gasoline, which translates into a H2 pump price of 6.52- 7.47/kg with tax. 

The capital investment for a PV electrolytic H2 system to support one million FCVs ranges from 12.4 billion for systems using 10% efficient PV modules to 10.4 billion for systems using 14% efficient PV modules. The PV power plant accounts for 59-51% of total H2 system capital investments. The levelized PV electricity price ranges from 0.064/kWh to 0.047/kWh for 10% and 14% efficient PV modules respectively. 

Hydrogen production by the electrolysis of water is currently less important, accounting for less than 3% of the hydrogen produced, due to the low overall efficiency of 20 to 25% including the electricity production. Large plants are only constructed where favorable conditions obtain, mainly near dams e.g. in Egypt (a plant at the Assuan dam has an ammonia capacity of 33 000 m- /h), India, Peru and in countries with low electricity prices or where there is a favorable demand for the byproduct oxygen e.g. in Norway. 

In addition to using energy more efficiently in the process, another common strategy is to produce energy more efficiently. Many plants have their own on-site power plants that primarily exist to provide steam and power to the process units, but may also supply electricity to the grid when electricity price is high. 

But for power station applications, the thermal efficiency is not the only measure of the performance of a plant. While a new type of plant may involve some reduction in running costs due to improved thermal efficiency, it may also involve additional capital costs. The cost of electricity produced is the crucial criterion within the overall economics, and this depends not only on the thermal efficiency and capital costs, but also on the price of fuel, operational and maintenance costs, and the taxes imposed. Yet another factor, which has recently become important, is the production by gas turbine plants of greenhouse gases (mainly carbon dioxide) which contribute to global warming. Many countries are now considering the imposition of a special tax on the amount of CO2 produced by a power plant, and this may adversely affect the economics. So consideration of a new plant in future will involve not only the factors listed above but also the amount of CO2 produced per unit of electricity together with the extra taxes that may have to be paid. 

Chiesa and Consonni [1 gave another detailed analysis for this plant in comparison with Cycle A1. They found that the efficiency dropped by 5% from that of the basic CCGT plant this is. somewhat surprising as the ab.sorption plant is smaller than that for Cycle A1 and it might have been expected that the penalty on efficiency of intrcxlucing the absorption plant would have been much less than that of Cycle Al. With this calculated efficiency and a detailed estimate of capital cost, the price of electricity was virtually the same as that of Cycle Al, i.e. 40% greater than that of the basic CCGT plant. 

This surprising equality arises because an efficient appliance saves expensive electricity at the meter, at an average retail price of 8 cents/kWli whereas one kWh of new wholesale supply is worth only 2-3 cents at the power plant. Thus, even if electricity from some future new remote power plant is too cheap to meter, it still must be transmitted, distributed, and managed for 5—6 centsAWh. It is impossible to disentangle the contribution of standards and of accelerated improvement in technology, but clearly the combination has served society well. 

Example 6.7 In Example 6.1, the required plant capacity is 218 kW and the running time is 2000 h/year at an electricity cost of 5 p/ (kW h) and a motor efficiency of 75%. In order to achieve the condensing temperature of 85°F (29.4°C) the condenser would cost 7250, while a smaller condenser for a temperature of 100°F (37.8°C) would cost 4600. (Prices of evaporative condensers at April 1987.) Estimate the break-even time if the larger condenser is fitted. 

However, if the major source of hydrogen is reformed natural gas, the cost of generating electricity with a low-temperature fuel cell would be about 0.20 per kilowatt-hour. This is more than double the average price for electricity. It would also produce 50% more carbon dioxide emissions than the most efficient natural gas plants which are combined cycle natural gas turbines. Low-temperature fuel cells operating on natural gas are not as efficient at generating electricity. A stationary fuel cell system achieves high efficiency by cogeneration. 

An allocation that is not differentiated between different fuel types (uniform benchmark, output-based) reduces opportunity costs of emitting C02 and thus reduces the impact on the product price. This reduces incentives to substitute less C02-intensive products, e.g. from cement to wood as a building material, or from electricity consumption to investment in energy efficiency but there is not an incentive to keep plants operating above some minimum threshold purely to get allowances. If such output-based updating allowance allocation is differentiated between production processes and fuel types, then additional distortions create an incentive to increase operation of more C02-intensive fuels and production processes. 

These closure rules have two consequences for the power system. First, with more plants staying on the system, there is more electricity supply and therefore prices can initially be reduced. Secondly, as inefficient old plants are artificially retained on the system, investment in more efficient new plants is delayed. This increases power prices and C02 emissions. 

Without reference to a particular HTGR, an input parameter of USD 30/MWt-h was used for the cost of nuclear heat was. Electricity cost was set based on a 2008 price of USD 75/MWe-h. The H2A modelling tool, as published, is based on an assumption that all costs and the selling price have the same rate of inflation. However, for the Shaw assessments, energy costs are projected to rise more rapidly than general inflation, and so a modification to the H2A model was been made to add this analysis capability. For the analysis, real escalation, over and above any inflation, is included at 1%/yr over the plant life for the electric power bought or sold. The assumed reactor outlet temperature for evaluating component costs and process efficiencies was 950°C. 

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