Basis and Interpretation of Estimates

This section provides information regarding some of the starting assumptions for the two technology cases, an d provides information needed to use the cost and performance estimates in Tables 2 and 3 to derive estimates of the cost of electricity from geothermal systems.

Sources of Estimates and Assumptions: Most of the information used for characterization of the 1997 baselin e technologies here comes from a 1995 study of current and "Next Generation Geothermal Power Plant" (NGGPP) designs. Conducted by CE Holt, a respected geothermal power system design and A&E firm, this is the firs t comprehensive set of cost estimates for U.S. geothermal power plants placed in the public domain in about 15 years [1].

Until that report, the level of detail of publicly-available information about the performance and cost of U.S . commercial geothermal electric systems was generally low. This is due in large part to the fact that almost al l geothermal capacity built in the U.S. since 1985 was built under PURPA contracts. That shifted almost all geothermal power plant design and development from the Investor Owned Utility (IOU) domain to the Independent Powe r Producer (IPP) domain. IOU's have to report construction and operation costs, while IPP's do not. In addition, competition among IPP's intensified and contributed to a reduced flow of performance and cost information into th e open literature, after about 1982. Until 1996, most of the detailed geothermal electric cost information published since 1982 came from systems installed in Italy, Mexico, the Philippines, and Japan.

This "geothermal information gap" was especially unfortunate because the 1981-1990 decade saw the developmen t in the U.S. of two new major geothermal conversion schemes for liquid-dominated reservoirs: about 620 MW e of flash plants and about 140 MWe of binary plants [45]. The experience with these plants will define important aspects o f geothermal electric technology for much of the next decade, but the technical details on the effectiveness of desig n tradeoffs and varied managerial approaches are largely not public and likely to remain so. The publication of th e NGGPP study has now largely remedied this situation with respect to the performance and cost of geothermal powe r plants built, and to be built, in the U.S. However, details on the cost of geothermal wells and O&M costs in genera l are still mostly held closely in the private domain.

Three groups of changes were made to estimates from the NGGPP study, to make the results more reflective o f "typical" geothermal hydrothermal reservoirs in the U.S.

• 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.

• Change 2: The Moderate Temperature system is based at a 166°C (330°F) reservoir. Well depth is about 305 m (1,000 ft). The system assumes a partially-optimized Organic Rankine Cycle (ORC ) conversion technology, using mixed working fluids, for the 1997 system. In the NGGPP study, thi s system was designed for an estimated reservoir at Vale, Oregon. Even though no working syste m exists at Vale, or is likely to in the near future, the Vale estimate was selected for use here because the initi al resource temperature in that NGGPP case is a temperature for which there are working cost estimates from other sources. A reservoir with similar characteristics, but less expensive wells, is that at Steamboat Springs, Nevada, where a modest amount of ORC capacity is operating. Well costs were changed to approximately $450,000 per well in 1993 dollars, estimated by an industry enginee r familiar with drilling at Steamboat. So the Moderate Temperature system here is a composite o f Steamboat Hills and Vale.

• Change 3: Certain costs were added or modified:

a. Wildcat exploration costs. Costs were added (see Table 7, equation FA) to account for "wildcat" exploration that accomplishes the initial discovery of hot fluid in a geothermal reservoir. Th e exploration included in the NGGPP cost estimates covered only the costs to confirm that a new power plant can be supported at a new site in a reservoir that has already been discovered.

b. Impacts of reservoir management. Effects of reservoir pressure decline were added, using simpl e models not documented here. The base cases assume 6 percent decline in pressure per year. Makeup production wells are added during the middle years of project life, and system output allowed t o decline in the last years. The effects of this are (1) added costs for makeup wells and (2) calculatio n of the appropriate levelized capacity factor that includes effects of production decline. In addition , costs were added to account for a certain number of injection wells that are drilled ("relocated") afte r production begins to reduce cooling of productive zones.

c. Financing costs. The financing costs estimated in the NGGPP report were removed from the costs shown here. Finance costs are included in the estimate of COE in Chapter 7.

Special Note on Power Plant Costs: Geothermal flashed-steam power plants now cost about 40% less than four years ago (the NGGPP cost estimates were completed mid-1993). This applies not just to major equipment, but also to engineering services and plant construction. This is due to factors whose effects are difficult to quantify an d differentiate, including: (1) intense competition in the electric equipment and power plant construction industry ; (2) fluctuations in currency exchange rates; and (3) some simplifications and improvements in the designs o f geothermal flash power plants.

Geothermal flash plants that cost $1,100 to $1,200 per kW in early 1994, now (in early 1997) cost about $600 to $800 per kW. It is believed that the same degree of cost change has not occurred for binary plants, due to a lack o f competition in that segment of the geothermal market.

This general status of intense competition across the electric power industry, world-wide, was noted recently i n Independent Energy magazine [46]. "Competition has driven down the price of new power plants -- as much as 4 0 percent in the last six years. A major reason for this is fierce competition among suppliers." The article states that only about 50 percent of world power-plant manufacturing capacity was being used in early 1997.

This Technology Characterization takes those effects into account by:

After the adjustment, that cost was set at $575 per kW, which was then escalated to $629 in 1997 dollars. (There are at least four firms making flash turbo-generator units, and many plant construction firms.)

• The NGGPP estimate for the cost of the binary power plant was not changed, except for converting to 1997 dollars. (There is only one company that is very active in the manufacture and construction of binary powe r plants.)

Given these large recent variations in costs, the users of this Technology Characterization are urged to be cautious i n applying the numerical values herein to real world situations without consulting engineering firms with substantia l experience in estimating costs for geothermal power systems.

Cost Deviation Estimates: The error range ascribed to the base year (1997) estimates, for capital and O&M costs, is set at +/-10 percent to reflect best estimates of the general accuracy of the information on which the cost estimates are based. The upper bound set for the error range is assumed to grow linearly by an additional 10 percentage point s between 2000 and 2030 to reflect the uncertainties associated with R&D forecasts.

Note that these cost estimates internally account for one of two other dominant sources of uncertainty:

Cost Contingency: The construction cost contingency is about 15 percent for field-related costs and 10 percent for power plant-related costs.

Reservoir Uncertainties: Uncertainties in measurements on reservoir properties can add on the order of 15 to 25 percent to the levelized cost of delivered electricity. The estimates provided in this TC are not quantified wit h respect to such uncertainties; it is believed that the present estimates represent something akin to an "industry' s expected case."

These "measurement" uncertainties and the costs that are occasioned by them are subject to reduction through research and industry experience, and the scenario evaluated here estimates that such reductions will occur over time . Specifying and improving the quantification of these uncertainties is a continuing research priority.

Factors for Estimating Cost of Electricity: Costs of energy are not shown in this chapter. Such costs are shown and documented in Chapter 7 of this report. The reader should note that most U.S. geothermal electric systems installe d in recent years have been owned by independent power producers (IPPs) rather than investor-owned utilities (IOUs) . It is also the case that when IOUs have owned geothermal power plants in the U.S., they have almost always turne d to a geothermal specialty company to develop and operate the field (wells and pipes). When this is the case, differen t tax write-offs apply to the field operation and the power plant operation.

Certain specialized factors are required for correct analysis of the economics of the field components of the system , e.g., fluid royalties, intangible drilling expenses, and depletion allowances. The values assumed for these factors are :

• Life for Federal Income Tax: Five years.

• Renewable Energy Tax Credit: This is 10 percent of capital cost of the system, up to but not including transmission equipment (Section 48 of Federal Tax Code). The basis for depreciation must be reduced by 5 0 percent of the credit taken.

• 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.

• Percentage Depletion Allowance: 15 percent per year of field-related revenues (fraction of annual revenue s attributable to field-specific investments, operating costs, and profits). In any year, percentage depletion ma y not exceed 50 percent of taxable income. If the field part of the project shows an annual loss, cost depletion may be taken.

• Geothermal Fluid Royalty Payments : The rates for royalties on Federal geothermal properties are a reasonabl e basis for estimating typical royalty costs. Federal royalties for liquid-dominated reservoirs are 10 percen t annually of [project gross revenues minus power plant-related costs and returns to capital]. This is roughly equivalent to 10 percent of annual field-related costs and returns.

• Given the breadth of some of these incentives, Federal and state income tax calculations need to adhere t o provisions for Alternative Minimum Tax.

Working Model for Cost Estimation: The estimates of project costs in Tables 2 and 3 are derived from more -fundamental estimates than shown in those tables. The primary technical estimates used are shown in Tables 5 (variables) and 6 (constants). Tables 7 and 8 document the formulas needed to derive capital and O&M costs, and system performance (levelized capacity factor and output.) Table 8 includes a column that documents the tempora l pattern of expenditures. Note especially that wildcat exploration precedes other project costs by a considerable period. All costs in these tables are in 1997 dollars.

Solar Stirling Engine Basics Explained

Solar Stirling Engine Basics Explained

The solar Stirling engine is progressively becoming a viable alternative to solar panels for its higher efficiency. Stirling engines might be the best way to harvest the power provided by the sun. This is an easy-to-understand explanation of how Stirling engines work, the different types, and why they are more efficient than steam engines.

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