Excerpts from 44 page: NREL. April 2012. Geothermal power and interconnection. The Economics of Getting to Market. National Renewable Energy Laboratory. Technical Report NREL/TP-6A20-54192
[My comment: this is an excellent paper for understanding how the grid works, and why so much renewable generation will be forever stranded. Unless it exists near a demand center or transmission lines, then it can only be developed if it’s an enormous resource, which is very rare for geothermal. Therefore, the only geothermal that can be developed needs to be near another renewable which combined can generate enough power to justify the cost of transmission lines, which are expensive as shown below in Table 2 and figure 9]
Geothermal technologies have the potential to contribute significantly to the U.S. electricity portfolio. To do that, however, the industry needs to be knowledgeable about transmission planning and grid operations. This need will become more crucial as new geothermal technologies emerge from the development stage and begin to become commercialized.
Hydrothermal: Conventional geothermal electric generation from naturally occurring underground steam, or from pressurized underground hot water. These are the most common geothermal generating technologies in use today. In the United States, most conventional hydrothermal generating capacity is in Nevada and California.
Enhanced geothermal systems (EGS): Electric generation using heat by creating subsurface fractures in high-temperature formations. Water injected into the fractures returns as steam or pressurized hot fluid, which is used to generate electricity. EGS is an emerging geothermal technology, but demonstration projects are proving advances in several crucial component areas.
Coproduced fluids: Electric generation using high-temperature water from oil and gas production. The electric generating capacity for wells with co-production capability tends to be small and depends on the amount of water present with oil and gas production.
Geopressured geothermal resources: Like electric generation from co-produced fluids, except that the fluids are under geological pressure. The Gulf Coast of Texas and Louisiana has the largest potential in the United States, but geopressured conditions exist in other basins as well. While not new— geopressured systems were evaluated as far back as the 1970s—technological improvements could make geopressured systems economically viable.
It assumes hypothetically that geothermal generation will increase by orders of magnitude over the next one to two decades. Without such growth, interconnection issues will tend to be project specific and anecdotal, and the systematic issues addressed in this report will be less pertinent. Several technical challenges stand in the way of such growth and are the subject of ongoing research by DOE and others. The purpose here is not to predict whether growth will occur,
Transmission is the high-voltage component of the electricity delivery system; distribution is the low-voltage component. Transmission is the electric system’s superhighway, carrying bulk power long distances along a few high-volume paths. Distribution is a collection of many widely dispersed small-volume paths leading to homes, businesses, and other end-use customers in one area. Substations are the points at which power steps down from the high-voltage transmission system to the lower voltage distribution system, essentially functioning as the off-ramp from the electric superhighway to a local neighborhood. One transmission system feeds many distribution systems.
Good geothermal resources are more widespread throughout the West, and nearly all of the existing geothermal development within the United States to date has happened in California, Nevada, Utah and Idaho
Because the zones in southern California and western Utah include large amounts of solar potential in addition to geothermal, these hubs have a larger estimated energy potential than the REZs in northern Nevada, southern Oregon and Idaho, which have significant geothermal potential but little else.
Blue circles indicate hubs with significant geothermal potential: Oregon south, Idaho southwest, Idaho east, Idaho southwest, Nevada north, Utah west, and California south.
A hub represents a conceptual step-up transformer where the electricity generated by all renewable resources in the REZ would get onto the transmission system. Hub circles are scaled to show relative annual production potential of all renewable resources in the REZ. Circles are not intended to indicate precise location of a new substation; actual collection point may be anywhere in the vicinity of the hub.
Figure 4. Western Renewable Energy Zones with known geothermal potential
Source data for deep EGS includes temperature at depth from 3 to 10 km provided by Southern Methodist University Geothermal Laboratory (Blackwell & Richards, 2009) and analyses performed by NREL (2009) for regions with temperatures =150°C. Map does not include shallow EGS resources located near hydrothermal sites or USGS assessment of undiscovered hydrothermal resources. “N/A” regions have temperatures <150°C at 10 km depth and were not assessed for deep EGS potential.
[MY NOTE: EGS is not likely to ever be developed, but if it were, below are the best locations in the WECC]
Figure 5. Geothermal resource favorability in the western
Of the seven geothermal REZs, all but one are in areas with very little native load. This means the geothermal industry generally has limited local commercial opportunity in many of its highest-potential areas, and that development at scale depends on access to larger markets. The West’s largest demand center is California, which has about 60% of the West’s forecasted demand for renewable power.
Infrastructure decisions nearly always give priority to the integrity of the entire network rather than to the economic needs of individual projects.
Plant size is perhaps the most significant factor affecting where geothermal fits into the larger picture. This report uses 80 MW as a heuristic dividing line between small and large plants, as it is the threshold used in the Federal Power Act to define “small power production facilities.” Eligible renewable energy facilities below 80 MW may become qualifying facilities (QFs), which affords certain benefits with respect to securing power purchase agreements. For example, many geothermal QFs have “must-take” power purchase arrangements with their interconnecting utilities. These arrangements essentially exempt a geothermal plant from having to provide operating reserves and ancillary capacity services to support grid reliability. The utility is obligated to receive everything the geothermal plant can produce, while reliability functions are allocated to other units on the system.
Figure 6 illustrates the relative size of most existing hydrothermal facilities in the Western Interconnection [it shows five less than 20 MW, 9 20-80 MW, six 80-323 MW, one 720 MW, and one 1,725 MW). The categories along the horizontal axis show amount of commercially developed hydrothermal electric generation in the same locality (i.e., plants whose addresses are in the same city); the vertical axis is the number of such localities in that size category. More precisely, the chart shows how many megawatts from existing geothermal resources are close to a single generation step-up transformer (as illustrated previously in Figure 1).
California’s Sonoma and Lake counties (north of San Francisco) have the largest amount of geothermal capacity in one locality. This area includes the Geysers, currently the largest geothermal operation in the United States. Cerro Prieto in Baja California is second with 720 MW. All of the remaining capacity exists in concentrations of 323 MW or smaller; nearly two-thirds of the localities that have operating geothermal plants have less than 80 MW nearby.
A new geothermal plant’s small size, per se, would not be a barrier to becoming a network resource and obtaining network transmission service, but several other factors outside the control of the geothermal developer may limit the commercial opportunities. If network load is not growing, or if no network resources are likely to be retired, the utility may be reluctant to acquire new network resources. If supplies are adequate to serve expected load, the utility may have no need for further procurements. Sierra Pacific Power, for example, currently has more than 500 MW of geothermal resources in its generation portfolio—nearly two dozen merchant projects averaging 22 MW, and ranging from 2 MW to 49.5 MW in capacity. The geothermal projects constitute a quarter of Sierra Pacific’s total resource needs for 2012, and are equivalent to about half of the utility’s base load needs. 8 The utility forecasts that system demand will shrink at an annual rate of 0.6% over the next five years, followed by a post-recession growth rate of about 1.5%. However, Sierra Pacific also anticipates that 330 MW of coal base load capacity will retire by 2022.
A utility may have a disincentive against obtaining additional network resources if doing so would result in stranded capital costs. Stranded costs would occur if (for example) one of the utility’s major network units was not fully depreciated, and adding a geothermal plant as a new network resource would require idling that unit. In most cases, a utility’s stranded costs end up being borne by its ratepayers. The utility’s regulatory body might not approve adding a new geothermal resource in such a case if it finds that doing so would unreasonably increase the rates paid by end users. So overall, the size of local demand is the main factor that determines the opportunities for new network resources. A network serving a sparse population with a small amount of load will need fewer network generation resources and a relatively smaller amount of network transmission than would be required by a system with a larger load.
Point-to-point transmission service is used for power deliveries from a specific generator or injection point to a specific delivery point, sometimes within the same BA area but often to a point outside the BA area. Unlike network service, the amount of point-to-point service available is not restricted to load within the BA. A transmission path is one or more lines that are capable of supporting power transfers between the same two points. A path’s rating indicates the maximum amount of transfer capability it can provide, taking into account all safety and reliability limitations. Path ratings act as a hard limit to the amount of point-to-point transmission service that is available to connect a generator to its market.
Various factors affect the availability of point-to-point service across a given transmission path. The voltage of path lines might be undersized relative to the commercial demand to move power across the path. Even if the main path is not fully loaded, there may be congestion points on closely related lines that limit the amount of power that can enter or leave the path, due to the instability it might cause elsewhere on the system. WECC regularly studies power flows across the major transmission paths in the Western Interconnection. In early 2010, WECC released a draft study that compared actual flows with scheduled flows to examine how fully the major transmission paths were utilized.9 The study observed generally that the amount of unused capacity on most paths was relatively small, thus “the existing WECC transmission system may be considered near full capacity given current uses.
Data on ATC and line utilization indicate limited transfer capability from the areas with the best geothermal resources. The best opportunity appears to be from geothermal area ID_SW to the Pacific Coast. The path has 245 MW of ATC on a consistent basis.
Line capability can vary over time due to changes in network conditions. Nevada’s Path 24 provides an example. Figure 7 shows the northern Nevada network and its main transmission lines. The amount of power that can be exported across Path 24 into California changes based on load in the Reno area. Figure 8 shows the path’s monthly export rating, as a function of peak demand in Reno for the same month. As Reno’s load increases from 499 MW to 803 MW, the east-to-west export rating for Path 24 decreases from 100 MW to 40 MW. What this means is that if a geothermal developer in northern Nevada intends to sell into the California market, the transmission needed to deliver the output may be physically insufficient in the summer months when Reno’s network load is high. This would limit the amount of power that could be sold as a consistent base load product in the California market. Load growth in Reno could further reduce the amount of ATC available over time.
In short, a geothermal plant’s ability to sell power into markets outside its home BA by way of existing transmission corridors may be as location-constrained as the geothermal resource itself. Among the variables affecting the amount of transmission available are the transmission owner’s network obligations, long-term contractual obligations for point-to-point transmission service, consistency in the amount of ATC available, and seasonal changes in network conditions that could affect a path’s export rating.
Geothermal’s greatest challenges with respect to new transmission are rooted in basic transmission economics. A new line’s cost effectiveness depends on how much power it carries, and small quantities pose a greater economic challenge. Small lines (230 kV or less) cost more per megawatt of carrying capability. A larger line costs less per megawatt, but that efficiency is lost if the line’s capability is not fully utilized. Distance magnifies the effects of these factors, posing an extra economic challenge for small generation resources that are far from load.
Table 2 breaks out the cost of transmission at different voltage levels. It also shows the total cost per megawatt of carrying capability at distances of 100 miles and 600 miles. A 500 kV DC line is nearly seven times as cost effective as a single-circuit 230 kV AC line, measured by line cost as a function of transfer capability ($millions per MW capability) over a distance of 600 miles. The efficiency is due to the fact that as line voltage increases, power transfer capability increases at a much faster rate than do line costs and substation costs. In addition, line losses are much less on higher voltage lines. More energy gets on the line, and less is lost along the way.
Table 2. Approximate Cost of Transmission by Size and Capability
Whether a large line actually achieves economies of scale depends on how much of the capability is used. For example, if a 500 kV DC line is underutilized by 50%, all of the line’s cost has to be recovered from the 50% that is being used. That effectively doubles the cost per megawatt of capability. Another useful metric, therefore, is a line’s effective revenue requirement per megawatt-hour of energy delivered. This represents the theoretical charge that would have to be added to each megawatt-hour delivered to customers in order to recover all of the line’s capital and operating costs, applied evenly over the line’s economic lifetime.
Transmission is an enormously “lumpy” capital investment, in that the entire cost of a project happens all at once, with very little opportunity to phase in costs incrementally as usage increases. Here, the effective revenue requirement metric captures some of this inevitable lumpiness by assuming a lifetime utilization rate of 85%. Effective revenue requirement captures important factors that enter into regulatory approval of a line. A regulated utility normally recovers the cost of a transmission line from the rates it is allowed to charge its retail customers.11 Before it can do so, however, the utility must demonstrate to its regulators that the new line is financially prudent, that it will be “used and useful” in serving the needs of the public, and that the costs and resulting rates are “just and reasonable.”12 If the likelihood of low utilization increases the proposed line’s effective cost per megawatt-hour of delivered power, prudence is difficult to prove—especially if there are alternatives that would impose less of a burden on ratepayers.
Figure 10. Effective revenue requirement for transmission per megawatt-hour
Figure 10 shows the effective revenue requirements of three sizes of transmission lines at different rates of utilization, for line distances of 100 miles and 600 miles. To better illustrate the cost issues as they apply to geothermal, the data shown apply a geothermal only scenario for new transmission. In other words, the figures show what the transmission owner theoretically would need to collect per megawatt-hour to meet the revenue requirements for that line if nothing but geothermal generation connected to the line.13
Based on the above assumptions, if eight 50-MW geothermal plants (400 MW of net capacity in all) were the only generators connecting to a 100-mile line, the effective revenue requirement would be: • $7/MWh in the case of a single-circuit 230 kV line • $13/MWh in the case of a double-circuit 345-kV line • $28/MWh in the case of a 500-kV DC line.
In this example, eight plants would fully utilize the smaller 230-kV line but would leave 87% of the 500-kV line unused.
The estimates also assume the line has an economic life of 30 years, and the cost of capital is 12%.
Revenue requirements could fall as low as $3/MWh for the 345-kV line if more plants connected. However, achieving that amount of savings would require connecting 1,500 MW of geothermal capacity, equivalent to thirty 50-MW plants in concentrations comparable to the Geysers in Northern California or Cierra Prieto in Baja California. (See Figure 6.) Regulators would consider the line a prudent financial risk only if they had reasonable assurances that 30 plants would actually be built. Transmission costs over a 600-mile distance tend to be prohibitive for anything but a large line with a high utilization rate. At that distance, a fully utilized 345-kV double-circuit line would have revenue requirements of $22/MWh, making the power economically uncompetitive on the basis of all-in delivered cost.economically uncompetitive on the basis of all-in delivered cost. kV DC line connecting 40 to 60 typically sized geothermal plants would have revenue requirements ranging from $12/MWh to as low as $8/MWh.
Access to a DC line is difficult and expensive due to the high cost of substations, however. (See Table 2.) Typically, the only points for electricity to get on or off the line are the two terminal points. Not only would the line need 3,000 MW of generating capacity in order to be fully utilized, all of that capacity would have to be near the same substation.
Wholesale power prices in California illustrate the magnitude of the trends shown in Figure 10. Average wholesale prices (spot market for next-day delivery) for the 12 months ending in April 2011 were $37/MWh for peak hours and $25/MWh for off-peak hours.15
The largest and most potentially lucrative markets are generally far from the best geothermal resource areas. New lines could bring these resources to market, but the economics of building new transmission are extremely problematic for plants that are the size of most geothermal projects operating today. The previous discussion showed that a long-distance line sized to a handful of small projects is costly and loses a great deal of power along the way; a high-capacity line brings greater efficiency, but only if the capacity connecting to it is enough to keep the utilization rate high. These complications offset geothermal’s comparative advantage with respect to providing base load power.
Figure 12 shows the distribution of generation capacity in WECC by size. Plants that are between 5 MW and 80 MW in size outnumber larger plants two to one in the West.
The most rigorous planning for future transmission involves the fourth category of resource: larger resources intended to serve load in a distant BA by means of new transmission expansion. Because of the magnitude of the capital investment and the risk involved in major transmission expansion, the present-day commercial maturity of a potential generation technology plays a significant part in regional planning. A technology with a commercial track record brings information to the planning process that enables plausible modeling of how the grid is likely to operate 10 years into the future under various assumptions and scenarios. These data points include the technology’s capital cost, marginal cost, capacity value, the downtime required for normal maintenance, the amount of reactive power it can provide, and other operational information. While improvements and cost efficiencies may occur over the span of a decade, the technology’s current state provides a commercially validated baseline for the purposes of modeling and analysis.
Technology still in the R&D stage has no such baseline. There may be research goals for costs and operational efficiency, but such goals exist within a probabilistic band of uncertainty and are, therefore, difficult to incorporate into production cost models and other tools used in long-term transmission planning. Recall the effective cost curves depicted in Figure 10 earlier in this report. If utilization of a new line turns out to be less than anticipated because an “emerging” technology in fact failed to emerge as expected, the effective cost of the line can increase significantly. The risk to utility ratepayers would be high, because the cost would be passed on to them. Billions of dollars are at stake for any major long-distance transmission project, and completion can take seven years or longer. Therefore, regulators who decide whether a major transmission project is prudent enough for rate recovery seldom approve projects that rely on pre-commercial generation technologies.
Consequently, conventional hydrothermal can be a player in future long-distance transmission intended to bring distant resources to major markets, because it brings sufficient information to the table for planning. Its main handicap is plant size. Strategies to combine several plants in the same vicinity (or alternatively, to include hydrothermal in a multi-resource portfolio of generation feeding into the same bulk transmission line) could alleviate concerns about a future line’s utilization. The Geysers, for example, comprises a dozen individual units, each with an operating capacity between 45 MW and 90 MW. It and other geothermal facilities near Middletown, California, have nearly 2 GW of nameplate capacity capable of providing base load power to the California market.
Emerging Geothermal Technologies, Enhanced geothermal systems (EGS) have proven to be technically feasible but still lack a demonstration of commercial capability, at least for the present. While engineered reservoirs have been created successfully, none has enough history to support conclusions about how long an engineered reservoir can provide heat at commercially useful levels.22 Especially with respect to planning, siting, and approving a major regional transmission line, technical feasibility is not enough to make up for the absence of demonstrated commercial interest. This is the main reason that, at least for the present time, EGS does not enjoy the same visibility in regional transmission planning that wind power and solar power do. Even though wind power’s intermittency and variability pose integration challenges that (in theory) would not be present with the emerging geothermal 23technologies, grid operators have learned how to model and manage those challenges. The ability to manage known problems means wind power poses less risk, as compared to a technology that is not yet economical.
Massachusetts Institute of Technology, “The Future of Geothermal Energy: Impact of Enhanced Geothermal Systems (EGS) on the United States in the 21st Century,” 2006, sec. 5 pp. 18-19 and sec. 9 p.
Table 3. Generation Groupings and Transmission Requirements Distributed Generation Local Network Generation Indicative plant size <5 MW 5
Table 4. Base Load Opportunities in BAs with Access to Significant Geothermal Resources 2009 system demand Base load resources Annual Peak Base (a)energy load load Coal Nuclear Hydro (GWh) (MW)
new projects will need to either: • Find sites within California that are both commercially viable and reasonably close to existing transmission • Take advantage of regional transmission corridors currently used by the out-of-state coal-fired generators that California utilities plan to drop from their resource portfolios • Collaborate in the creation of a renewable energy zone, as discussed later in this section.
if a prospective area for geothermal development has little or no available transmission, the likelihood of aggregating several projects in the same area will be a crucial factor in justifying a new line. One 50-MW plant would hardly justify a long corridor of a new high-voltage transmission, but several such plants may.
For geothermal power, the market of least resistance with respect to interconnection is in serving local base load—that is, as a generating resource serving load within the same BA using network transmission service. Local transmission access is easier, quicker, and does not entail the uncertainties involved in planning new regional transmission lines. Moreover, several areas with known geothermal potential have foreseeable opportunities for new local base load generation in the near future. Geothermal power’s successful transition to widespread commercialization will depend on taking advantage of these relatively easy opportunities.
Black & Veatch. (September 2010). “Utah Renewable Energy Zone Phase 2 Final Report.”
Bonneville Power Administration. (March 2006). “2006 Pacific Northwest Loads & Resources Study.”
Driesen, J.; Belmans, R. (18-22 June 2006). “Distributed Generation: Challenges and Possible Solutions.” 2006 IEEE Power Engineering Society General Meeting, Montreal, Canada, Federal Energy Regulatory Commission, 18 CFR Parts 35 and 37 (Order 890).
Geothermal Energy Association. “The State of Geothermal Technologies,” Part 1 (2007) and Part 2 (2008).
Hurlbut, D.J. (2010). “Multistate Decision Making for Renewable Energy and Transmission: An Overview.” University of Colorado Law Review (81); pp. 677-703.
Massachusetts Institute of Technology. (2006). “The Future of Geothermal Energy: Impact of Enhanced Geothermal Systems (EGS) on the United States in the 21st Century.”
North American Electric Reliability Corporation. (April 2009). “Accommodating High Levels of Variable Generation,” special report.
National Renewable Energy Laboratory. (May 2010). Western Wind and Solar Integration Study. Report No. SR-550-47434. Golden, CO: National Renewable Energy Laboratory.
Pletka, R.; Finn, J. (October 2009). “Western Renewable Energy Zones, Phase 1: QRA Identification Technical Report.” NREL/SR-6A2-46877. Golden, CO: National Renewable Energy Laboratory.
Rocky Mountain Oilfield Testing Center. (March 2010). “Ormat: Low-Temperature Geothermal Power Production,” final report. Accessed April 19, 2012: http://www.rmotc.doe.gov/PDFs/Ormat_report.pdf.
U.S. Department of Energy. (September 2010). “Low-Temperature, Coproduced, and Geopressured Geothermal Technology Strategic Action Plan.”
Western Electric Coordinating Council. (20 April 2010). “2010 Western Interconnection Transmission Path Utilization Study: Path Flows, Schedules and OASIS ATC Offerings.”
Western Governors’ Association. (June 2009). “Western Renewable Energy Zones: Phase 1 Report.”