The future purchase prices for most alternative-fuel vehicles are estimated to be higher than those for conventional gasoline-powered vehicles, and additional driving costs are projected to be incurred as the result of lower vehicle range and limited availability of fuel; With higher projected fuel prices in the EIA analysis, vehicle-miles traveled are expected to be reduced for all vehicles, including those that use alternative fuels, and; The higher estimated efficiencies of alternative-fuel vehicles would lower their total fuel consumption per mile traveled. Furthermore, since approximately 43 percent of all AFV sales in 2020 are projected to come from alcohol flex vehicles in the EIA Report's reference case, the amount of gasoline displaced is limited. Alcohol flex vehicles can use either straight gasoline or a mixture of 85 percent alcohol and 15 percent gasoline (the alcohol component is either ethanol or methanol). In addition, survey data indicate that these vehicles currently use E85 or M85 a very small fraction of the time, filling up with gasoline instead. 10 Although CAFE standards may lead to some additional sales of AFV's, without a price signal or large subsidies, consumers are not expected to purchase a great number of them in the 2010 or 2020 timeframe. And with most of these AFV's projected to use gasoline in the EIA analysis, very little energy efficiency improvement occurs. ACEEE's second strategy of a size class feebate is likely to be limited to effectiveness, because it does not encourage consumers to switch from light trucks to cars. By contrast, the EIA Study incorporates a shift from light trucks to cars based on historical experience and relative fuel prices, when projected fuel prices increase to reflect a carbon price. The EIA Report also includes consumer shifting to smaller size classes, which the ACEEE feebate strategy would not achieve because it applies to consumer shifts to more efficient vehicles in a given size class. Feebates also may provide an opposite result from what was intended because consumers may purchase vehicles in a larger vehicle class than they had originally planned as a result of the subsidy (e.g., they may purchase the smallest of the large vehicles rather than a mid-size vehicle). A third strategy detailed in the ACEEE study relies on tax incentives to increase penetration of advanced automobile technologies, which will improve their costeffectiveness. Although the exact nature of the ACEEE vehicle tax incentives is not specified, it cites the fuel efficient vehicle tax credit proposed by President Clinton in the FY99 budget as an example. That proposal provides a credit of 1o Greene, D.L., Oak Ridge National Laboratory, Survey Evidence On the Importance of Fuel Availability $3000 in 2000 for vehicles with double the base fuel economy within a size class, dropping to $1000 a year beginning in 2004. Vehicles which achieved triple the base fuel economy within a size class would receive a $4000 tax credit beginning in 2003, with the tax credit reduced by $1000 a year beginning in 2007. These proposed tax credits are unlikely to achieve further penetration of advanced automobile technologies for several reasons. Our analysis indicates that with fuel prices in the neighborhood of AEO98, vehicles with three times the base fuel economy are unlikely to be marketed in the U.S. by 2010. Further, as indicated by the finding of the National Research Council on PNGV vehicles, vehicles with three times the base fuel economy may not be achievable from an engineering/cost perspective. However, even if such technologies were feasible, they are likely to be too costly to make significant market inroads in the U.S. The incremental costs for the two most likely advanced automobile technologies, gasoline or diesel hybrid vehicles and fuel cells, currently have an incremental cost that is from $20,000 to $50,000 higher than their conventional gasoline counterparts. Even if the diesel electric hybrid and fuel cell incremental vehicle costs were reduced to $12,000 and $17,000 respectively, assuming mass production of these vehicles", the full $4000 tax credit likely would not reduce the incremental vehicle prices enough to entice many consumers to purchase these vehicles in EIA's view since the net capital cost differences exceeds net fuel cost savings by at lease $6,000 under the most optimistic conditions (assuming 5% discount rate, 15 year consumer horizon, and a $2/gallon real gasoline price). So, without a very high subsidy to close the gap between the advanced vehicle price and a comparable gasoline vehicle or some other mechanism to reduce the net vehicle price to consumers substantially, EIA believes that consumers are unlikely to buy these vehicles. The Treasury estimate of $1 billion dollar uptake of the tax credit (50,000 vehicles per year or 0.3% of the new vehicle fleet annually) is optimistic in EIA's analysis but confirms our conclusion. Q19.4 Combined Heat and Power The ACEEE Study's fourth strategy is "combined heat and power." The “Our strategy addresses all of the major barriers to CHP "Energy and Environmental Analysis, Inc., Updates To The Fuel Economy Model, prepared for EIA, We estimate that taking these actions would result in a The ACEEE Study claimed that this strategy would avoid 43 million metric tons of carbon emissions by 2010 and 111 million metric tons by 2020. Further, the Study claimed that net present value of costs and savings for measures installed during 1999-2010 would be $22 billion and $73 billion, respectively, for a net benefit of $51 billion (ACEE Study, page xi). Please comment on the ACCEE Study's methodology, assumptions, and findings with respect to this strategy. A19.4 While EIA believes that there is potential for expanding the capacity of cogeneration (combined heat and power), it may be very difficult for those facilities to be widely competitive. Most of the existing cogeneration capacity is in industrial facilities that have large heat/steam and electricity requirements industries like paper and chemical production. These industries make good sites for cogeneration because their production facilities are heavily utilized often operating 24 hours per day — making it economical to build and operate these units. According to EIA's Manufacturing Consumption of Energy 1994, about 3.7 quadrillion Btu of fossil energy was consumed in boilers in 1884, or about a third of the total fossil energy for heat, power, and electricity. Of this boiler fuel use, approximately 4 quadrillion Btu was used for the electricity portion of cogeneration. About one quadrillion Btu of this energy consumption can be attributed to the steam portion of the cogeneration, given the steam-to-power ratio of 2.5 for most cogeneration plants now in use. In other words, roughly 1.4 quadrillion Btu, or some 37 percent of fossil energy used in industrial boilers is already used for cogeneration. Since cogeneration has already penetrated the industrial market in the most favorable industries, continued rapid growth, even given ACEEE assumptions of regulatory reform and tax incentives, seems optimistic. Shipments of new boilers to large industrial facilities have been very low by historical standards in recent years. Lighter industrial (i.e., manufacturers of industrial equipment, fabricated metal products, or electronic equipment) or commercial facilities are not expected to find cogeneration opportunities as attractive because of their lower energy service when regulated utilities were required to purchase their excess power (because of the Public Utility Regulatory Policy Act (PURPA)) at administratively set avoided costs which provided much higher sales revenue than would be the case today. In today's market, avoided costs are generally set by competitive bid rather than being set administratively. As pointed out by ACEEE, the development of new cogeneration facilities has slowed in recent years. EIA believes that the major reasons for this are the relatively low level of wholesale power prices and the creation of exempt wholesale generators (EWG) in the Energy Policy Act of 1992. With the creation of EWGs, powerplant developers, including regulated utilities, are able to develop independent projects without being designated a public utility subject to extensive regulation under the Public Utility Holding Company Act (PUCHA). This has reduced the incentive of powerplant developers to try and build a qualifying cogeneration plant rather than an independent power facility. EIA expects this trend to continue in the future. The greatest potential for district energy systems such as those envisioned by ACEEE may be in cooling systems for downtown areas where there is a large amount of commercial floor space located in a relatively small area. However, in cities that do not already have some type of district energy facility (e.g., district heating or steam distribution), there may be significant costs associated with building and installing new units. The costs associated with the installation, maintenance, and repair of lines to carry steam and hot or chilled water supplies in cities with heavy under-street congestion from gas, water, sewage, and electricity lines may overwhelm the available energy efficiency cost savings. In light of these considerations, the ACEEE estimate of 15 gigawatts of cogeneration capacity for district energy systems by 2010 seems high. While the ACEEE methodology seems internally consistent, given its assumptions about regulatory reform and incentives, the energy and economic savings attributed to CHP by ACEEE are high compared to the alternatives presented in EIA's study. That is, when compared to a business as usual case, ACEEE's calculation of energy savings from CHP assumes the displacement of the least efficient central station generation and industrial boilers. However, in an integrated analysis framework, cogeneration investments implicitly compete with alternative opportunities, such as investments in new, advanced gas combinedcycle plants or fuel switching in industrial boilers. If savings are estimated compared to the marginal alternative, rather than against the least efficient alternatives, then the economics are not as attractive. For example, boiler fuel switching may be the first reaction to a market-based carbon dioxide reduction program as prices for the most carbon-intensive fossil fuels rise the most. A CHP investment evaluated “after” the fuel switch is contemplated is not as attractive as one made assuming continued use of the more expensive fuel. Similarly, if carbon dioxide emissions reductions from CHP are compared with other alternatives, the Two other methodological assumptions can be questioned. First, the estimated up-front investment cost for CHP plants of $650 per kilowatt seems low, given the small size and site-specific engineering and construction usually associated with these installations. These facilities are much smaller than the typical 100-300 megawatt combined-cycle units which are assumed to cost just under $600 per kilowatt initially and are expected by EIA to decline to $440 per kilowatt at full commercialization. Second, the ACEEE analysis appears to assume that there is no cost to providing tax incentives (accelerated depreciation) to the industrial CHP facility. Presumably, other tax payers must pay for this program and these added costs should be factored into the analysis. Our analysis shows that the most economical carbon dioxide reduction option in the electricity sector is the replacement of existing coal plants with advanced natural gas plants. In the most stringent case estimated by EIA, more than 300 gigawatts of new advanced natural gas technologies are expected to be built (see table below for natural gas combined-cycle capacity additions in each case). These new natural gas plants could include a mix of advanced turbines, combined-cycle, fuel cells and cogeneration (combined heat and power) units. The role played by each of these technologies will depend on how their cost and performance characteristics evolve over the next 10 to 20 years. In today's market new combined-cycle units appear to be poised to capture the lion's share of the market for new advanced natural gas technologies. They are both relatively low cost and very efficient. In comparison, fuel cells are over 4 times as expensive and only about 15 percent more efficient. Beyond the next 10 years or so, it becomes very difficult to point to which of the advanced natural gas technologies will be most important. It may be best to think of the natural gas plants built after 2010 as simply "advanced gas" rather than trying to label them as a specific technology. Natural Gas Combined-Cycle Capacity Additions in Alternative Cases |