Operation & maintenance costs consist of fixed and variable costs. Fixed costs include cooling and genera l maintenance at the site. Variable costs include recharging the batteries and periodically replacing the batteries. These O&M costs are presented as annual expenses in the prior table. The cooling charge is based on a power managemen t system which consists of eight modules, each one of which is the same size as the system being characterized here [18]. The unit must be installed in an air-conditioned room [4], and thus, the parasitic load for the cooling fans is quite small at 1.25 kW. At a peak or shoulder rate of 50/kWh, the annual cost of the cooling load for the 30 kW system is $548. The general maintenance cost of $1,000/year is based on the experience of CEMC with a larger flooded lead-aci d battery.
The recharging cost is calculated as the kW rating * discharge time * ( (1 – AC-to-AC efficiency) + 1) * off-peak 0/kWh rate * 100 days/year. The 30 kW unit requires a 37.2 kWh charge (given 76% efficiency [4]), at a 1.50/kWh off-peak rate, costs $56 annually in 1997.
The cost of battery replacement is based on an expected battery life of three years. Thus, on average, the annual cos t of battery replacement is one third the cost of the batteries. Expanded battery life increases to five years in 2000 an d ten years in 2010 and later, so replacement costs improve accordingly.
5.0 Land, Water, and Critical Materials Requirements
There are no water requirements for PV-battery energy storage systems. Land requirements are insignificant for th e battery system which occupies less than 2.3 m2.
The 1997 baseline system contains a lead-acid battery; 50% of the system weight (excluding the PV array) is lead. Battery system weight will decrease significantly when the advanced battery subsystem is introduced in 2020.
[1] Field O&M cost: The 1990’s effects of power sales contracts, i. e., lower payments for energy, establishe d under PURPA (the Public Utilities Regulatory Policies Act of 1978) are now driving geothermal operator s to identify co st-savings opportunities in plant O&M manpower. Also a result of improved chemistry an d materials, but smaller effects than for power-plant O&M.
[2] Advanced drilling technology: 20 to 30 years. Systems studies are in progress for drilling technologies tha t could substantially reduce the costs of both removing rock and maintaining the integrity of the wellbore durin g
[3] Change 1: The High Temperature system is that from Dixie Valley, Nevada. The initial reservoir temperatur e is 232°C (450°F). Dual flash technology is assumed for the 1997 system. Well depth is 3,050 m (10,000 ft) . The field costs here were raised about 50 percent from those reported in the NGGPP study, by reducing the assumed flow per production and injection wells by one third. That was done to get the field capital costs to be about 30 percent of the total capital costs, which is the more-or-less modal case for flashed steam system s analyzed in the NGGPP study. Note that in some cases today, flash-binary hybrid power plants are being use d at relatively high-temperature reservoirs. We assume that this may be the beginning of a trend, but stay wit h double-flash plants as our 1997 baseline technology for these reservoirs.
[4] Expensing of Intangible Fraction of Well Costs : This study assumes the intangible fraction is 100 percent fo r exploration wells and 70 percent for production-related wells.
[5] "6 100" means: 100 percent of the funds are spent in year 6 before startup. (The year immediately before the date of startup is counted as "year 1 before startup."
f Tax aspects: – idc: Fraction expensed as intangible drilling cost (remaining fraction is depreciated). – cd: Depletable fraction on which cost depletion may be taken. – dep: Depreciable fraction (land is not depreciable)
* The "6 year" delay shown here is a variable. See item eF in Table 5. This study estimates 6 years for 1997 – 2000, 5 years for 2005-2020, and 4 years for 2030 for all technologies.
* "Standard" spend pattern is 33% in year 2 and 67% in year 1 before startup.
[6] Customer-sited PV systems help minimize balance-of-system costs because there are minimal costs associated with site acquisition and preparation and there is generally a pre-existing utility connection to the site [5,6,7].
[7] PV can capture benefits of distributed electrical energy generation where utility costs associated with transmission and distribution are reduced by locating the electrical generation source close to the point of use [1,2,3,4].
[8] Customer-sited PV fits into the more flexible deregulated utility environment where the generation is no longe r necessarily owned by the utility. For example, the residential PV system could be owned by the utility, by a n independent power producer who “rents” the rooftop from the residential owner, or by the resident.
[9] Values indicate changes over the 1997-2030 time frame.
f $/Wp removes the effect of thermal storage (or hybridization for dish/engine). See discussion of thermal storage in the power tower TC and footnotes in Table 4.
(p) = predicted; (d) = demonstrated; (d’) = has been demonstrated, out years are predicted values Cost Versus Value
Through the use of thermal storage and hybridization, solar thermal electric technologies can provide a firm an d dispatchable source of power. Firm implies that the power source has a high reliability and will be able to produc e power when the utility needs it. Dispatchability implies that power production can be shifted to the period when it i s needed. As a result, firm dispatchable power is of value to a utility because it offsets the utility’s need to build an d operate new power plants. This means that even though a solar thermal plant might cost more, it can have a highe r value.
[10] Design specification for Solar Two. This efficiency is predicted for a mature operating year.
t Cost of these items at Solar Two are not characteristic of a commercial plant and have, therefore, not been listed.
1 Total plant cost for Solar Two are the actuals incurred to convert the plant from Solar One to Solar Two. The indirect factors listed do not apply to Solar Two.
# To convert to peak values, the effect of thermal storage must be removed. A first-order estimate can be obtained by dividing installed costs by the solar multiple (i. e., SM = {peak collected solar thermal power} + {power block thermal power}). For example, as discussed in the text, in 2010 the peak receiver absorbed power is 1400 MW t. If this is attached to a 220 MWe turbine (gross) with a gross efficiency of 42%, thermal demand of the turbine i s 520 MW t. Thus, SM is 2.7 (i. e., 1400/520) and peak installed cost is 2605/2.7 = $965/kWpeak. Solar multiples for years 1997, 2000, and 2005 are 1.2, 1.8, and 1.8, respectively.
[11] The +/- range bounds a technology envelope that includes emerging/leading technology characteristics on the + side for performance and on the – side for cost. The range also includes uncertainty of achieving technical success and sales volume, and the natural variation in projects from normal market demands.
[12] Plant (windfarm) construction period is assumed to require 1 year.
* Annual O&M is expressed as $/turbine and $/kW-yr. These are two expressions of one cost and are therefore not additive.
[13] Soiling losses – 1996 values are based on (1) tests of airfoil designs developed by NREL and availabl e commercially, that exhibit low sensitivity to soiling ("roughness") [28,29] and (2) the assumption that blade washing is conducted at economically optimal levels and the associated cost is included in the annual O&M. Introduction of variable pitch rotors in the 2000 TC design further reduces soiling losses; the pitch control is assumed to compensate for degradation of aerodynamic performance from soiling. Soiling losses decrease slightly after 2010, indicating that airfoil design and materials will not yet be fully optimized for roughness insensitivity until then.
[14] Reference 30 is a document for general public information. Actual market prices will vary depending o n many project-specific factors.
