Sixty-one reservations or TJSAs, which have 50 percent of the Indian population on Indian lands, appear to have resources that could be developed for less than 2 cents per kWh above their regional wholesale prices. With renewable incentives at the State or Federal level (discussed below), these projects might be cost-effective depending on the cost of transmission required to connect the new capacity to the grid.

Four reservations could generate central station renewable-based electricity cheaper than the wholesale cost of power sold to those reservations, assuming EPACT production incentive payments were available. These reservations are: the Eastern Cherokee Reservation (NC), the Alabama and Coushatta Reservation (TX), the Coushatta Reservation (LA), and the Mississippi Choctaw Reservation and Trust (MS). Biomass is the renewable resource of choice on all these lands. The renewable electricity cost premium ranges from 0.1 cents per kWh to 0.7 cents per kWh.

For the 13 areas that have both wind and biomass resources, the biomass development cost is projected to be lower than the wind development cost. However, if a Production Tax Credit (PTC) or Renewable Energy Production Incentive (REPI) credit were available, the wind costs would be lower in a few cases. This is because biomass resources on Indian lands are not expected to be "closed loop," and therefore not eligible for these tax credits. In addition, some type of State renewable portfolio standard or public benefits funds are available for 24 of the reservations.

A major assumption regarding the above cost premiums is that transmission and distribution systems (T&D) are available to these reservations. If this is true, the reservations could either market power to the grid or use the power themselves. If only transmission lines are available, then marketing power to off-reservation customers is likely to be the only feasible option, as costs for new distribution systems to sparsely arrayed reservation households will be quite high. Marketing power from new plants also requires intertie costs, not included. Unfortunately, reservations with high electricity nonuse rates probably may have neither accessible transmission nor distribution (T&D) systems capable of reaching a large number of households without electricity. The need to put even just a distribution system in for such households would raise the cost of delivering any central station-generated electricity substantially. Renewables are unlikely to be differentially affected in this regard, except for possible power conditioning provisions for wind energy.

There appear to be 82 reservations and TJSAs, having 22 percent of the Indian population on Indian lands, which have central station renewable development costs for renewables more than 10 cents per kWh higher than the regional wholesale price. These are areas with only central PV and/or solar concentrator resources. For these areas, it is unlikely that any renewable subsidy could make these resources attractive.

Hydropower would be competitive at the low end of its estimated cost range (about 5 cents per kWh). However, because this study could not determine the existence of undeveloped water resource potential on Indian lands, hydropower was excluded from consideration. Further, the difficulty in licensing hydropower projects in recent years makes it questionable whether such projects could be approved on Indian lands without special dispensation for Indian land hydropower projects.

Distributed Generation

Renewable distributed generation generally is only cost-effective in areas that are remote and are unconnected to the electrical grid. Therefore, distributed generation is probably most appropriate for reservations with a relatively large fraction of households without electricity, such as the Navajo reservation.⁽¹²⁾ The renewable generation options and prices for the reservations with greater than the national average of 1.4 percent of households without electricity is shown in Table 5. The results suggest that PV rooftop modules may be a feasible way to provide limited electric service (without backup power) to large numbers of households on the Navajo reservation, and possibly others. The levelized costs for distributed PV generation ranges from 28.0 to 40 cents per kWh. While higher than the average residential price of electricity by 15 to 34 cents per kWh,⁽¹³⁾ the Navajo reservation has many households extremely remote from transmission/distribution lines. This raises distribution costs to a level far higher than average. DOE's National Center for Photovoltaics indicates that a distance from the nearest utility line of only a quarter mile raises distribution costs sufficiently to make PVs cost-effective at 25 to 50 cents per kWh. In addition, if the cost of the PV system can be paid for through a 30-year home mortgage, its levelized cost can be reduced to 15 to 20 cents per kWh.

A major point of emphasis regarding the above costs is that they are for PV rooftop only electricity. These estimates exclude the cost of back-up power or energy storage, which could raise the cost of full-service PV rooftop-based electricity by a factor of 3 or 4. By comparison, for the same reservations, the cost of central station renewables above the wholesale generation price is roughly 0.7 to 15 cents per kWh. It is important to note that these costs are not reduced by any incentive payments, (e.g., the wind tax credit), and they do not reflect transmission costs (which might add another 0.7 to 2.0 cents per kWh) or distribution costs, which could be substantial for remote locations. However, as mentioned earlier, the cost of distribution systems to areas without electric service is likely to be the same for most generating technologies.

Resource Potential and Cost

Wind and biomass are generally the most cost-effective renewable resources, so they will be treated first. When the distribution of renewable resources is shown for the Indian lands, only those lands which are inhabited are included.

Wind

Wind resources vary significantly with topography and meteorological conditions and in some cases the best wind class can be surrounded by areas with no potential. As a result, the assignment of wind classes to reservations based on mapping of resources can only be approximate.

Roughly 45 reservations were identified that have areas with Class 5 or 6 winds, which are the best for wind development (Table 6). Another 48 reservations have Class 4 winds, while 205 reservations have only wind, classes of 3 or below and would not have areas suitable for wind development. In terms of the percent of Indian population on reservations and the TJSAs slightly more than half are in areas with good wind resources (Class 4 or above), while the rest are not. Most of the reservations with good wind resources are in the West and Upper Midwest, primarily California, New Mexico, Nevada, Utah, Wyoming, Arizona, Montana, and North Dakota. The one reservation in the East with good potential is the Eastern Cherokee Reservation in North Carolina. Of the 17 Oklahoma Tribal Jurisdictional Areas, only 3 of them, representing 24 percent of their Indian populations, contain areas with Class 4 winds. The remaining TJSAs have only Class 3 winds.

In evaluating the economic potential of wind, the technology characteristics from the AEO2000 were used. In the year 2000, the national average capital cost is assumed to be $980 per kW, with operating costs of $26 per kW-year. This is for a 50-MW wind farm using 750-kW turbines. In the AEO2000, a cost of $167 to $440 per kW is added for transmission facilities for all technology types, depending on the region. For wind an additional cost of $8 to $80 per kW is included depending on how far the facility will be from existing transmission lines. The capacity factor assumed varies by wind class including: 32 percent for Class 6, 29 percent for Class 5, and 26 percent for Class 4. For those reservations with the best (Class 5 and 6) resources, the average levelized cost of production before considering transmission costs or any renewable incentives is estimated to be 4.7 to 5.9 cents per kWh. For Class 4 winds the cost is 6.2 to 6.6 cents per kWh. The levelized costs are higher for Class 4 areas because the expected capacity factor is lower at lower wind speeds. Figure 17 shows the distribution of wind costs by Indian population on the reservations and the TJSAs. The actual development costs are highly dependent on transmission costs. These would add an additional 0.7 to 2 cents per kWh, depending on the distance and terrain in connecting to existing transmission lines. As a result, the total cost of a project to export power would range from roughly 5 to 9 cents per kWh before credits (Figure 18). Wind sites with better transmission access may have lower costs than those with better wind conditions, so both factors need to be considered for siting specific plants. As mentioned earlier, if Federal or State incentives of 1.5 cents is available, the cost could be reduced to as low as 2.7 cents per kWh in the most favorable circumstances. In most regions if this could be achieved, wind would compete favorably with the current wholesale price.

Figure 17. Distribution of Wind Development Costs Excluding Transmission Costs

Figure 18. Example of Wind Levelized Costs Including Transmission for Northwest Power Region

An alternative wind turbine configuration would be small-scale turbines for use within a Native American community. In this case the turbine costs would likely be higher per kilowatt and costs for backup power capacity would be necessary, but the potential transmission costs would be significantly reduced. There would also be local distribution costs if the area was currently not connected to the grid.⁽¹⁴⁾

Biomass

The NREL characterization of biomass provides three levels of resource: 0-5 MW, 5-40 MW, and greater than 40 MW per county. Because biomass fuel sources have relatively low energy content for their mass, they cannot be transported economically very far--generally 50 miles. For the purposes of this report, we have assumed that Indian lands in counties with the lowest level of biomass resource would not be candidates for biomass development. There are 180 reservations and/or TJSAs that fall into this category, as shown in Table 7.

The categories of biomass capacity potential are based on assumptions of an efficiency of 35 percent and an annual capacity factor of 65 percent. In the AEO2000, the  characterization  of  biomass  generation  assumes  a 5-percent higher efficiency and a 23-percent higher capacity factor, which together lead to roughly 14 percent less  capacity  for each dry ton of biomass. Given the otherwise conservative estimate of the biomass resources based on only two agricultural crops, the difference in assumptions would not likely lead to a significant difference in the categorization of Indian lands.

Figure 19. Distribution of Biomass Development Costs Excluding Transmission Costs

The biomass levelized costs for reservations with potential ranges from 4.4 to 6.7 cents per kWh based on AEO2000 technology and regional fuel costs assumptions. These assumptions include a capital cost of $1,865 per kW, $44 per kW-year operating costs, and a variable cost of 0.53 cents per kWh. Figure 19 illustrates that roughly 32 percent of reservations (populated weighted) have a cost of 4.5 to 5.0 cents per kWh, while another 22 percent are in the 5.0 to 5.5 cents per kWh range. Because biomass fuels are transportable over some limited distance (usually 50 miles), power plants may be able to be situated closer to transmission lines than wind plants and therefore have lower transmission costs.

Geothermal

As shown previously, geothermal resources can be characterized as sufficient for electricity production, for direct heating or simply for geothermal heat pumps. Based on the maps produced by NREL, 57 reservations may have some potential for electricity production, representing roughly 10 percent of the Indian population on reservations and TJSAs. Another 72 reservations and the TJSAs appear to have potential for geothermal direct heat applications, such as district heating. The remaining Indian lands have the potential for geothermal heat pump use. It is important to note that there are currently 51 sites where exploratory geothermal wells have been drilled to determine the feasibility of electricity production. None of these are on Indian tribal lands. The cost to develop geothermal resources is very site-specific. The levelized costs calculated from the AEO2000 for the 51 sites included in the model data base average from 3.7 cents per kWh to 5.6 cents per kWh for the three regions in which they are considered. Generic development costs for geothermal plants (EE/EPRI Technology Characteristics) report a range from 3.3 cents per kWh for flash-steam (high temperature) systems to 4.1 cents per kWh for binary systems (moderate temperature).⁽¹⁵⁾ Other sources have indicated that most resources are in the 5.0 to 7.0 cents per kWh range. Once again the cost of transmission from a remote site to a market might add another 0.7 to 2.0 cents per kWh.

Geothermal heat pumps provide heating and cooling, as in an air heat pump, but use the ground rather than the air as the source of heat. They cost significantly more than standard heat pumps, but are several times more efficient.

Solar Thermal

Figure 20. Distribution of Resources for Concentrated Solar Applications

Concentrated solar systems are significantly more expensive than most other renewable technologies. Areas with higher levels of solar insolation will be more economically favorable because higher capacity factors can be achieved. We have assumed that a minimum of 5-6 kWh/m²/day insolation is required to even consider concentrated solar technologies, although the likeliest development is in regions with 7-8 or 6-7 kWh/m²/day. There are 17 reservations with some areas having this highest level of insolation, and 66 with the 6-7 level. Figure 20 illustrates the distribution of solar resources for the reservations by Indian population and by number of reservations.

Based on solar technology characteristics used for the AEO2000 projection, the levelized costs range from 11.0 cents per kWh (without transmission) to 15.0 cents per kWh for the 6-8 kWh/m²/day areas. The average capital cost for a 100 MW solar-only power tower with 6-hour molten salt thermal storage is assumed to $3,040 per kW, and the capacity factors vary from 42 percent for the best areas to 26.5 percent for the 5-6 kWh/m2/day areas.⁽¹⁶⁾ Annual operating costs are assumed to be $47 per kW. Because solar insolation is relatively uniform over large areas, concentrated solar plants could be located to minimize the interconnection costs to existing transmission lines. The cost, however, may still be substantial for some Indian lands.

Photovoltaics

The solar resources for photovoltaics (PV) are somewhat different than that for solar concentrator systems because PVs use diffuse as well as direct sunlight. The same areas generally are favorable for both. Figure 21 shows the distribution by both number of reservations and Indian population on reservations and TJSAs for the PV resource. The TJSAs in Oklahoma all receive the 5-6 kWh/m²/day insolation.

Figure 21. Distribution of Resources for Photovoltaics

The AEO2000 estimated installed capital cost for 2 kW residential rooftop PV systems is $5,500 per kW installed, with an annual operating cost of $10 per kW. Some states offer income or other tax benefits which are not considered here. The resulting levelized costs for distributed generation range from 28.0 to 51.6 cents per kWh, which is significantly higher than the average residential price of electricity. However, for remote areas where distribution costs would be far higher than average, PVs can be the cost-effective choice. In fact, DOE's National Center for Photovoltaics suggests that a distance from the nearest utility line of only a quarter mile is sufficient to make PVs cost-effective at 25 to 50 cents per kWh. In addition, if the cost of the PV system can be paid for through a 30-year home mortgage, the levelized cost can be reduced to 15 to 20 cents per kWh.⁽¹⁷⁾

State and Federal Regulatory Policies Affecting
Renewable Energy Feasibility on Indian Lands

Several States have enacted legislation to stimulate renewable energy development. In some States, renewable portfolio standards are being used to insure that a minimum level of renewable generation is used to meet future electricity requirements. There are 7 States having Indian lands which have enacted renewable portfolio standards (Table 8). If the portfolio standard allows for tradeable credits,⁽¹⁸⁾ projects developed on Indian lands could have additional value. Another method of encouraging renewable development has been to establish system benefits funds that are created through customer charges. The funds are often used to promote energy efficiency and provide subsidies to low-income customers in addition to funding renewable projects. As indicated in Table 8, there are 8 States where renewable development on Indian lands might benefit from such funds. Because many State legislatures and commissions are actively considering electricity restructuring, the States that offer renewable incentives may change over the next few years.⁽¹⁹⁾ Roughly two-thirds of the Indian lands, representing half of the Indian reservation and TJSA population, are in States which have either a renewable portfolio standard or a system benefits fund.

In several States, utilities have been allowed or required to establish "green power" marketing options so consumers can voluntarily pay more for power generated from renewable or other clean sources. In States that have adopted retail competition, green power marketers are among those companies vying for customer market share. This allows the market to establish a premium for renewable power that the Indian tribes may be able to capture. However, the relative geographic isolation of some tribes may prohibit the cost-effective export of power into these markets.

There are also existing and proposed Federal policies to encourage renewables. The Energy Policy Act of 1992 created a 1.5 cents per kWh (adjusted for inflation) production tax credit (PTC) for wind and closed-loop biomass projects, where biomass crops are grown on a sustainable basis. This credit expired at the end of June 1999, but was retroactively extended until the end of December 2001. The tax credit increases with inflation and is available for the first 10 years of a project. On a levelized cost basis over a 20-year project life, the equivalent credit is 1.2 cents per kWh (1998 dollars). Because the credit is tax-based, Indian tribes would not benefit unless a private developer was the owner of the project. There is a corresponding renewable energy production incentive (REPI) for public utilities, which is paid through Congressional appropriations, and might be applicable.

The Clinton Administration's proposed Federal electricity restructuring legislation calls for a Federal renewable portfolio standard of 7.5 percent by 2010, with a marginal cost cap of 1.5 cents per kWh. There is also a provision to give projects on Indian lands double tradeable credits. If this type of legislation passes, it would make renewable project development on Indian lands much more attractive.

Wholesale Electricity Rates

Central station renewable generators will compete against wholesale purchased power whether the power is used on the reservation or for export. Until very recently, wholesale prices were dictated by cost-of-service contracts. In some parts of the country, wholesale prices are now being set by competitive markets and the trend will continue, as FERC's orders concerning wholesale competition continue to be implemented.⁽²⁰⁾ Over time, with competitive electricity markets, wholesale prices roughly equilibrate to the long-run marginal cost of generation or, in other words, the lowest cost of building new generation facilities. The competitive nature of the market may also lead to lower costs than occur under cost-of-service. During the transition period, wholesale prices may be lower or higher than the long-run marginal cost, depending on whether there is surplus supply or shortages, respectively. Table 9 shows the 1998 average wholesale electricity prices by NERC subregion.

Currently, the lowest cost wholesale power is, on average, in the western regions, partly due to the presence of large-scale Federal hydropower facilities that sell power for resale to utilities. These facilities will likely continue using cost-of-service pricing.⁽²¹⁾ Regional variations in wholesale prices will remain in any case because the underlying marginal generation prices vary with regional fuel prices and other factors.

For example, the Western Area Power Authority (WAPA) sold power at an average rate of 1.6 cents per kWh in 1998 from all of its several facilities.⁽²²⁾ There are six reservations that receive power from two of the WAPA projects at rates of 0.6 to 1.8 cents per kWh.⁽²³⁾ In the past, WAPA and other Federal Power Marketing Administrations (PMAs) sold power only to utilities, which included Tribal Utility Authorities and the BIA, who then resold the power to preference customers. Recently, they have begun to allow sales to groups other than utilities and have been actively marketing to tribal groups. When the contracts from a project or program expire, some allocation is set aside for new customers and Native Americans. WAPA has completed contracts with 25 tribes in the Upper Midwest for the year 2001 and beyond. Other WAPA facility contracts expire in 2004 and 2008, so there will be additional opportunities for tribes to receive Federal power allocations.

The Bonneville Power Administration (BPA) is also marketing to tribes. The option to sign long-term relatively low cost contracts with Federal power may make development of central station renewables less attractive for many reservations, but also could be used to back up intermittent power from renewables.

Project Criteria

This section presents an analysis of factors that influence the economic and technical feasibility of two types of projects: distributed generation and central station plants. While the scope and risks of central station power plants are fundamentally greater than that of distributed generation, the basic evaluation process should address the same factors. In the case of the central station plant, the studies and assessments should be of greater detail, employing more sophisticated forecasting techniques. Assessments of distributed generation (in this instance assumed to be associated with individual dwellings or clusters of dwellings), must necessarily consider the alternative of taking power from a central station power plant. In the evaluation of a project to bring or expand electricity use on Tribal lands, both distributed generation applications and central station power plants require careful consideration. Further, substantial overlap exists in the factors that need to be considered.

As will be discussed in greater detail below, a first step in any project evaluation is a clear statement of the objectives of the project. The assessment should avoid the narrow definition of the specific electricity needs on the reservation and recognize the broader considerations of Tribal cultures and infrastructure development needs.

Because of the scale of typical central station power facilities and the potential disruption to the reservation brought about by these types of large projects, a holistic approach may offer the only chance to completely succeed with a project's broader objectives. Most likely, employing this type of approach will enhance the acceptance and adoption of distributed generation.

Evaluating alternative approaches for electricity use on Indian lands should consider all the conventional alternatives. However, the use of renewable energy resources may be more consistent with historical Tribal cultures. The consideration of the use of a more environmentally benign renewable resource will require a fuller consideration of "externalities" than may otherwise enter the evaluation process. The project criteria discussed below are intended to provide a broad checklist to ensure  the  wider consideration of these "externalities." A summary guide has been prepared to facilitate the evaluation of expanded electrification through the use of renewable technologies. "A Guide to Project Criteria for Renewable Project Planning Assessments," provides a list of major activities and products, major tasks involved in the various assessments, and the areas of investigation and information requirements. The Guide is subdivided into six basic areas for discussion and lists the typical information requirements and approach to assessing project feasibility.

A detailed and complete discussion of all the factors and areas of investigation identified in the Guide are beyond the limited scope of this paper. This paper will discuss each of the major activities and highlight some of the factors more directly tied to the application of renewable technologies. While the Guide lists each activity in a specific order, the activities are interrelated, interdependent, and would typically proceed in parallel.

Revenue Assessment

We list the revenue assessment first because it has the greatest number of considerations unique to the application of renewable technologies. Revenue assessment is defined here to include all sources of funding that can be identified to support the project. Once a project and its objectives have been defined, the revenue assessment should begin.

There are a wide variety of potential funding vehicles and sources that should be investigated. As identified in the column of areas of investigation, the spectrum of funding sources ranges from grants to customer revenues. The National and State interest in providing incentives for the development of renewable technologies, energy efficiency, and conservation offers project developers a number of places to seek funding at various stages of the project. For example, DOE grants may be available to fund specific feasibility studies. State level initiatives may provide revenue support for renewable projects. The Guide footnotes a good source for reviewing lending sources available for select renewable technologies. Finally, the Federal and State level initiatives for restructuring the electric power industry have fundamentally altered the available opportunities and make it necessary to carefully consider these initiatives when seeking revenue sources and assessing market opportunities. In particular, one should consider the potential impact of "green power" and "renewable portfolio standards" that may be included in these State level initiatives.

Demand Planning

Again, with an eye to the application of renewable technologies, understanding energy use and more specifically the opportunities for electricity use are critical. The intermittent nature of many renewable technologies suggests the need for storage or backup supplies. However, consumer awareness of these limitations may allow for changes in typical consumer behavior that may facilitate the use of these technologies. Further, if electricity is being introduced for the first time, then these behavioral patterns may yet to be formed allowing for an easier adoption of the technology.

The introduction or expansion of electricity use requires careful consideration of the spatial distribution of load. Scattered and low densities (consumers per mile) make the distribution of electricity relatively costly. Alternative applications of distributed generation technology such as solar thermal space and water heating or PV electrical applications, may be able to avoid much investment in the transmission, distribution and central station generation facilities.

Finally, the daily and seasonal cycle in electricity use tends to translate into low load factors.⁽²⁴⁾ A lower load factor requires a greater investment in capacity per unit of energy used. Since renewable technologies tend to have higher investment costs, low load factor applications tend to be less attractive. Marginal cost pricing of electricity should lead to shifting patterns of electricity use to increase load factors, thereby creating greater opportunities for economical application of renewable technologies.

Indirect Impacts

Expanding the availability of electricity on Tribal lands can have a dramatic impact on the lives of all the residents. Careful consideration of the economic development needs, cultural factors, and environmental impacts of alternative technologies will allow the application of the holistic approach mentioned above. Given the changing nature of the electricity industry and the increased volatility in market prices, these factors should be a key project criteria and play an important part in the overall project assessment.

Infrastructure Assessment

The introduction of expanded electricity use on Tribal lands requires a review of the associated infrastructure needs of the alternatives. A holistic approach would ask about the opportunities for employment, the associated educational and training needs associated therewith, and other factors. The project(s) can bring economic development to the reservations but careful planning and coordination are required to fulfill the potential of these projects.

Financial Condition Assessment

The costs and impact of electrification of Tribal lands will require the commitment of Tribal resources. The impact of the project on the economic vitality of the reservation and the drain or expansion of its financial resources should be an important project criterion. Structured appropriately, the financial exposure and risks to the reservation should be balanced with the anticipated returns.

Specific Project Assessment

Absent a holistic approach, this might be the only major activity contributing to the evaluation of alternative electricity production and use alternatives. However, as discussed above, there can and should be a much broader approach taken to the question of expanded use of electricity on Tribal lands. The major tasks identified in this section of the Guide represent the typical project assessment considerations of any project whether it employs renewable technologies or not. It is important that the alternatives are identified and the factors that make the selected project the best choice should be highlighted in the financial plan.

While there can be many formats or methods of documenting the evaluation and selection of projects for expanded electrification and central station power production on Tribal lands, we have chosen to recommend that all the considerations be brought together in a summary document we are calling the "Financial Plan." This document could be used to present findings to potential financial sponsors, community groups, and key Tribal organizations to gain acceptance and approval. The effort to prepare a financial plan and present it to key players will be critical to successfully marketing the project to the various funding sources (identified in the revenue assessment activity) and to the Tribal community.

A Guide to Project Criteria for Renewable Project Planning Assessments

Renewable technologies have both distinct advantages and disadvantages in the production of electricity. Their most obvious and attractive attributes are their reliance on energy resources that are viewed as inexhaustible and environmentally benign. However, as with other technologies, renewable technologies have their limitations.

This section will highlight some of these in meeting the energy needs on Tribal lands. A complete delineation of all the attributes, costs and performance factors of renewable technologies is beyond the scope of this paper. The highlights that follow are intended to be illustrative of the barriers associated with the use of renewable technologies as electricity producing facilities. Central station power production and distributed generation (generation at or near the final end use location) are discussed separately. Most of the limitations that will be discussed apply to both applications of renewable technology. However, distributed applications can potentially avoid significant delivery costs (costs of transmission and distribution) and in certain specific situations, this will improve their overall economic competitiveness.

High up-front capital costs represent one of the most significant economic barriers to the adoption of renewable technology. For central station power plant applications, the capital costs for renewable technologies are from 3 to 15 times that of conventional technology (Figure 22). The overall savings in fuel and annual operations and maintenance costs of the renewable technology must overcome the high front-end capital costs for the technology to become competitive. For virtually all the renewable technologies in central station applications, it is difficult to overcome the front-end capital cost disadvantage under current and projected economic conditions absent special circumstances or subsidies.

Figure 22. Capital Costs of Electric Generating Technologies

The situation is not quite as bleak for distributed generation applications of renewable technology. The high up-front capital costs still persists in these applications, but the avoided transmission and distribution costs can, on occasion, overcome this disadvantage. To determine the potential economic opportunity for distributed generation applications requires site specific facts regarding the energy and capacity requirements and the alternative costs of generation, transmission, and distribution. Unfortunately, the potential range in these costs is very large. Further, these costs vary with terrain, the extent of existing facilities and their utilization levels. Thus, generic cost are calculations without site specific data are too uncertain to be of use. Therefore, any estimate of the full potential of distributed generation applications to meet the energy needs on Tribal lands lacks sufficient data to be credible.

Another major hurdle for the solar and wind renewable technologies is their intermittent output. This intermittence results in a relatively low annual capacity factor and in many situations, there is a need for some form of energy storage or a backup source of power. This additional requirement adds to the system costs and limits the economic applications of the technology. In the case