Analysis Methodology

The projections and quantitative analysis for this chapter were prepared using the Electricity Market Module (EMM) of the National Energy Modeling System (NEMS). NEMS is a computer-based, energy-economic model of the U.S. energy system for the mid-term forecast horizon, through 2020. NEMS projects production, imports, conversion, consumption, and prices of energy, subject to assumptions about macroeconomic and financial factors, world energy markets, resource availability and costs, behavioral and technological choice criteria, cost and performance characteristics of energy technologies, and demographics. Using econometric, heuristic, and linear programming techniques, NEMS consists of 13 submodules that represent the demand (residential, commercial, industrial, and transportation sectors), supply (coal, renewables, oil and natural gas supply, natural gas transmission and distribution, and international oil), and conversion (refinery and electricity sectors) of energy, together with a macroeconomic module that links energy prices to economic activity. An integrating module controls the flow of information among the submodules, from which it receives the supply, price, and quantity demanded for each fuel until convergence is achieved.⁶

Domestic energy markets are modeled by representing the economic decision-making involved in the production, conversion, and consumption of energy products. For most sectors, NEMS includes explicit representation of energy technologies and their characteristics. In each sector of NEMS, economic agents—for example, representative households in the residential demand sector and producers in the industrial sector— are assumed to evaluate the cost and performance of various energy-consuming technologies when making their investment and utilization decisions. The costs of making capital and operating changes to comply with laws and regulations governing power plant and other emissions are included in the decisionmaking process.

The EMM simulates the capacity planning and retirement, operating, and pricing decisions that occur in U.S. electricity markets. It operates at a 13-region level based on the North American Electric Reliability Council (NERC) regions and subregions. Based on the cost and performance of 27 different generating technologies, the costs of fuels, and constraints on emissions, the EMM chooses the most economical approach for meeting consumer demand for electricity. As new technologies penetrate the market in NEMS, their costs are assumed to decline to reflect the expected impact of technological learning.  During each year of the analysis period, the EMM evaluates the need for new generating capacity to meet consumer needs reliably or to replace existing electric power plants that are no longer economical. The cost of building new capacity is weighed against the costs of continuing to operate existing plants and consumers’ willingness to pay for reliable service.

The EMM includes the representation of programs aimed at increasing the amount of generation coming from renewable fuels – both state and federal programs. For example, 10 States currently have State renewable portfolio standards or targets.  To represent these programs, estimates of the types of renewable capacity expected to be encouraged by these programs are made and entered into the model. All cases in this analysis include estimates of new renewable energy capacity expected to be stimulated by State-level renewable programs. Over the 2001 to 2020 timeframe, these estimates include 4,859 megawatts of capacity resulting from State RPS programs, and 2,178 megawatts expected under other State renewable stimulus programs. Capacity built under State RPS programs reduces the incremental quantity needed to comply with a Federal RPS and lowers its costs. The costs of complying with the State RPS programs are not included in the costs attributed to the Federal RPS program in this analysis.

All cases in this analysis include the 10 percent investment tax credit for new geothermal and solar-electric power plants that was permanently extended in the Energy Policy Act of 1992. However, this analysis does not assume that the Federal production tax credit (PTC) for generation from new wind and closed-loop biomass plants will be extended beyond its current expiration date of December 31, 2001. Senator Murkowski, in his letter of December 20, 2001, stated that this analysis not assume any changes in tax policy.  For the same reason this analysis does not assume that the renewable energy production incentive (REPI) program, will be extended beyond its current 2003 expiration date.

S. 1766 allows new (incremental) hydroelectric capacity at existing facilities or repowering upgrades at other existing renewable facilities to qualify for renewable credits.  While, it is possible that incremental hydroelectric capacity could play a small role in meeting the RPS, EIA believes that it is not likely to have a large impact on this analysis and, thus, it is not directly represented.  The U.S Hydropower Resource Assessment found that upgrades at existing hydroelectric facilities could add 7.8 gigawatts to total hydroelectric capacity.⁸   However, after adjusting this value to reflect environmental concerns, the report authors reduced this value to 4.3 gigawatts of possible upgrades at existing sites.  The report also included estimates of additional hydroelectric capacity at currently undeveloped sites, but since S. 1766 does not provide renewable credits to new hydroelectric sites their development will not be encouraged by the RPS. Assuming a 45 percent capacity factor for typical hydroelectric facilities, this means that, at most, the 4.3 gigawatts of incremental hydroelectric facilities could provide 17 billion kilowatt-hours of additional generation, or approximately 4 percent of the increase in renewable generation needed to comply with the RPS called for in S. 1766. However, because costs estimates for these potential upgrades are not available it is impossible to determine if they would be economical.  If any of these upgrades proved to be uneconomical, the contribution from incremental hydroelectric facilities would be even smaller.  If they were economical, their development would be expected to lower the costs of implementing the RPS slightly below what is reported in this report.

Similar to existing hydroelectric facilities, a small amount of additional capacity may be available through the repowering at existing geothermal plants. While very uncertain, it is estimated that U.S. geothermal capacity might be able to increase up to 5 percent at costs of $500 per kilowatt or less for a total potential increase of a few hundred megawatts of capacity.  However, S. 1766 does not specify what actions at geothermal facilities would qualify as repowering and how the resulting change in capacity would be measured. For example, some existing geothermal capacity has been derated – its currently reported capacity is lower than its originally installed capacity.  The potential amount of repowered geothermal capacity that might be stimulated by an RPS would be very sensitive to whether capacity changes were based on increases from original or current capacity.  If it were based on original capacity the potential increase would be less than is reported above.

It is also possible that a small amount of renewable credits will be generated by utility sponsored small-scale renewable generators installed at customer sites that reduce the amount of electricity they purchase from the grid. However, these types of facilities tend to be much more expensive than larger grid-serving facilities and it is expected that an RPS would have little impact on their development.

To represent the specific requirements of the RPS program in S. 1766, the annual renewable share of sales called for in S. 1766 were converted into the total nonhydroelectric renewable shares used in NEMS. As shown in Table 1, the shares used in NEMS differ from the annual RPS shares called for in S. 1766 because the NEMS shares represent the total non-hydroelectric renewable generation share⁹ - including the generation from facilities that began operation before January 1, 2002 - required to comply with the RPS requirement (NEMS does not distinguish between generation coming from new or existing facilities so total nonhydroelectric renewable shares are used). Also, as called for in S. 1766, the share represented in NEMS accounts for the exclusion of utilities with sales fewer than 500,000,000 kilowatt-hours, and the exclusion of renewable generation from sales when applying the RPS share. For example, in 2005 the S. 1766 RPS share is 2.5 percent, total electricity sales are projected to be 3,793 billion kilowatt-hours, sales from small utilities are assumed to be 270 billion kilowatt- hours, the generation from non-qualifying non-hydroelectric renewable generators (those coming on prior to January 1, 2002) are assumed to be 81 billion kilowatthours and the generation from hydroelectric facilities is projected to be 300 billion kilowatt-hours.¹⁰ Using this information, the amount of qualified renewables required is calculated as follows:

0.025 X (3,793 – 270 – 81 – 300) = 79 billion kilowatt-hours.

Converting this into the total non-hydroelectric share used in NEMS gives:

(79 + 81) / 3,793 = 4.2 percent.

As shown, through 2016 the adjusted shares used in NEMS exceed the shares called for in S. 1766 because the effect of including existing non-hydroelectric renewables in the NEMS values exceeds the adjustments for excluding small utility sales and total renewable generation from the base. After 2017, however, the exclusion of total renewable generation from the baseline when applying the RPS share causes this relationship to reverse. In the 20 percent RPS case, the effective share of non- hydroelectric renewables required in 2020 to comply is 16.1 percent of total sales.

S. 1766 says that a civil penalty of up to 3-cents per kilowatt-hour may be imposed on retail electricity suppliers who do not submit sufficient renewable credits to cover their sales.  For analysis purposes, this maximum 3-cent per kilowatt-hour noncompliance penalty is treated as an upper bound (cap) on the renewable credit price. In other words, if the calculated credit price exceeds 3-cents per kilowatt-hour, retail electricity suppliers are assumed to pay a 3-cent per kilowatt-hour penalty rather than purchase additional credits.  If this occurs, the required level of qualifying renewables will not be achieved. It is possible that some companies may be willing to purchase renewable credits for more than 3-cents per kilowatt-hour to avoid the negative perception associated with facing a civil penalty. However, it is impossible to determine how much above the 3-cent penalty they might be willing to pay.

The results from two main cases, the Reference case (from the Annual Energy Outlook 2002) and the RPS 10 case, are discussed in the results section.  The results of the RPS 10 case are compared to those from the Reference case to illustrate the impacts of the RPS under the most likely scenario. However, given the importance of some of the RPS provisions in S. 1766 and uncertainty involved in any 20-year projection, the impacts of the RPS under alternative assumptions are also discussed. One key provision in the S. 1766 proposal is the sunset provision ending the program in December 31, 2020. To illustrate the importance of this provision a case without it is also discussed.

A key uncertainty with respect to the RPS is the future cost and performance of renewable generation technologies. If their costs fall and/or their performance improves more than is expected in the Reference case, the RPS program could be less expensive. As a result, two additional cases with more optimistic assumptions about the improvements in renewable energy technology cost and performance – the High Renewable Technology case (from AEO 2002) and the High Renewable Technology case with RPS are also discussed. These cases were prepared to examine the impact of the more optimistic assumptions on the renewable credit and the required renewable share achieved.  The high renewable technology cases are meant to illustrate the impact of the RPS with more optimistic assumptions about improvements in the cost and performance of new renewable generating technologies. The key assumptions in the High Renewable Technology case include:

• Biomass:  Capital and operating costs are consistent with estimates prepared by Department of Energy Office of Energy Efficiency and Renewable Energy and the Electric Power Research Institute (EERE/EPRI) (Table 2). In addition, biomass supplies are increased by 10 percent.

• Geothermal: Capital costs are assumed to decline by 3 percentage points per year from 2000 to 2010, and 0.6 percentage point per year from 2011-2020. These changes were made to be consistent with estimates prepared EERE/EPRI.

• Photovoltaics (Central Station): Reduced capital and operations and maintenance costs, corresponding to EERE/EPRI utility scale flat plate, “Thin Film” technology.

• Solar Thermal:  Significantly improved performance (as measured by capacity factor) is assumed together with higher capital costs. The values used correspond to the Central Receiver (Solar Power Tower) technology from EERE/EPRI.

• Wind: Reduced costs and improved performance is assumed in all wind classes to make them consistent with EERE/EPRI estimates for 2020.

It is impossible to assign a probability that the improvements in renewables assumed in the High Renewable Technology cases might occur. The results in the cases should be viewed as illustrative of what might occur if the assumed changes in cost and performance could be realized. The costs and performance characteristics used in the Reference case are considered most likely.

Of course, it is also possible that costs will not improve even as much as is shown for the reference case, or that costs will increase more rapidly than expected after the best renewable resource sites are developed. To represent this possibility, a Low Renewable Technology case was prepared where total overnight costs were held constant at the 2001 level in Table 2. This case is meant to show the sensitivity of the results to today’s renewable technology costs, assuming no improvement in cost and performance.

The Indian lands and generation offset provisions of S. 1766 are not explicitly addressed in this analysis. There is substantial uncertainty about the quality of renewable resources on Indian lands and the costs of bringing those resources to market.  To assess the potential impact of the Indian lands provision, a Geographic Information System (GIS) was used to identify renewable resources available on Indian lands. The analysis concluded that the available biomass supply on Indian lands is relatively scarce and too high a cost to be stimulated by the provision. Similarly, only small amounts of geothermal resources were found to be on Indian lands. However, this analysis found that about 8 percent of relatively high-quality (wind classes 4, 5, and 6) windy land is on Indian lands. However, there are significant concerns about whether these wind resources could be developed economically.  Many factors besides the simple cost of the generating equipment can make otherwise high quality wind sites unattractive. These include environmental or cultural concerns such as those associated with building in national parks or national monument areas.  For example, wind projects (such as the proposed Columbia Hills project in Washington) have been abandoned in part because of visual impacts on Native American cultural sites.  The need to upgrade weak transmission systems or build on rough terrain with poor infrastructure can also impact the economic attractiveness of many potential high quality sites. While definitive data is not available, the remote nature of many Indian Lands may make these factors more important than they are on non-Indian land. EIA estimates that approximately 5 percent or 10 gigawatts of the wind resource on Indian lands could become economical under an RPS. In addition, the special status of Indian Lands as sovereign territories held under Federal trust imposes additional bureaucratic burden and legal risk that may not be present when developing on non-Indian lands.

Notes