2. Analytical Issues

All long-term projections contain considerable uncertainty. It is difficult to foresee how existing technologies might evolve or what new technologies might emerge as market conditions change, particularly when those changes are expected to be fairly dramatic. Also, it is difficult to estimate the extent to which consumers will adopt new technologies. Given such uncertainties, meeting the Policy mandates—a 25-percent RPS in the electric power sector and a 25-percent RFS in the motor fuels market by 2025—could be very challenging.

Specifically, the magnitude and pace of infrastructure investments needed, together with uncertainty about the feasibility, cost, and initial date of commercial availability of advanced technologies that do not exist today or currently play a very small role, raise significant concerns. Further, success of the proposed Policy will depend critically on the passage of future enabling legislation compatible with the S.23⁷ provisions on FFVs and on the installation of pumps for E85 and biodiesel to make the fuels available to consumers.

Infrastructure, Market, and Technology Concerns

In the electricity sector, the amount of qualifying renewable generation needed to comply with the RPS of the proposed Policy would require about a 13-fold increase over the next 18 years from the current U.S. level of nonhydropower renewable generation. In the transportation sector, the amounts of ethanol and biodiesel production needed to comply
with the RFS would require more than a 12-fold increase from current levels. While not impossible, such rapid development would be very challenging, and it would carry substantial risk.

Infrastructure Concerns

Meeting the 25-percent RPS target could require more than 100 gigawatts of new wind capacity. Because some of the best wind resources are located in unpopulated areas, distant from demand load centers, significant investments in transmission infrastructure may be needed to develop them. In other cases, offshore wind resources could be an attractive option; and again, new transmission infrastructure would be needed to connect offshore plants to the grid. Developing the necessary transmission infrastructure to take advantage of the best wind resources is certainly technically possible; however, costs and public acceptance are uncertain. For example, recent plans to expand the transmission system through relatively undeveloped areas have met considerable resistance.

Currently, most biofuel production facilities are located close to corn and soybean acreage in the Midwest in order to minimize the transportation costs for bulky, unrefined materials. The facilities are therefore situated far from major consumption centers on the East and West coasts. Additionally, biofuel production generates large supplemental streams of bulky co-products with limited marketability.

Further complicating matters is the fact that biodiesel and ethanol cannot be blended at petroleum refineries and batched through existing pipelines. Ethanol is easily contaminated by water, and biodiesel dissolves entrained pipeline residues. Consequently, railroad cars and tanker trucks made from biofuel-compatible materials must be used to transport large volumes of biofuels to market. Many biofuel producers locate their facilities near dedicated feedstock supplies or large demand centers in order to minimize transportation costs and susceptibility to bottlenecks. Still, limited rail and truck capacity has complicated the delivery of ethanol and contributed to regional ethanol supply shortages and price spikes, as occurred between April and June 2006.

The potential transportation bottlenecks and costs for the biofuels industry are likely to become much more problematic with the proposed Policy than they are today. At the 25 percent RFS level mandated by the Policy, biofuels would significantly penetrate motor fuels markets across the entire United States. The necessary infrastructure for collecting,
processing, and distributing large volumes of biofuels would have to be expanded or, in many cases, created. Without substantial infrastructure investment, it would be difficult or impossible for producers to avoid bottlenecks in the transportation and delivery of biofuels to market.

There are also other factors that could hamper the distribution of biofuels to end-use markets. Although E10 (“gasohol”) is readily dispensed throughout the United States, there are limited numbers of fueling stations for biodiesel and E85—currently, less than 1 percent of the total number of U.S. vehicle fueling stations. S.23, if passed, would require approximately 50 percent of “majors and branded” motor fuel dispensing stations (roughly 25 percent of all U.S. fueling stations) to install “high biofuel blend” pumps for E85 and/or B20.

Recent EIA estimates for replacing one gasoline dispenser and retrofitting existing equipment to carry E85 at an existing fueling station range from $22,000 to $80,000 (2005 dollars), depending on the scale of the retrofit. By these estimates, the total investment cost for installation of biofuel pumps would range from about $0.8 billion to about $3 billion. To recoup the investment costs over a 15-year period, assuming that an E85 pump would dispense one-half the volume of an average unleaded gasoline pump (about 160,000 gallons per year), the retail price of E85 would have to be raised by 2 to 7 cents per gallon.

The total infrastructure investment costs that would be required to support the 25-percent RFS have not been estimated. Further, some of the majors and branded dispensing stations may choose to sell their less profitable station holdings (they would become unbranded and non-major owned) to avoid the expense, and that could reduce the availability of E85 dispensing stations to consumers, making market acceptance of E85 slower.

Market Concerns

Market concerns arise both from the uncertainty inherent in petroleum and agricultural markets and from the linkage of food and fuel markets that would result from implementation of the RFS policy. With respect to petroleum, the current volatility of crude oil markets casts doubt on the potential for biofuels to remain competitive in the future without government mandates, such as the S.23 and this RFS policy proposal. With an RFS, fuel price risks are shifted to consumers through the price of credits; however, consumer acceptance, awareness, and willingness to use biofuels, as well as manufacturers’ willingness to produce FFVs, are unknown (and unlikely without a government mandate). The costs associated with vehicle manufacturing also are shifted to consumers under an RFS mandate, but again there is no guarantee that consumers will choose to purchase E85 or biodiesel fuels in the quantities needed to fulfill the mandate.

The RFS, which requires biofuels production to reach approximately 65 billion gallons by 2025, could require more than 25 billion gallons of corn-based ethanol and 25 billion gallons of cellulosic ethanol, a technology that is not commercially available at present. It could also require a roughly 8-fold increase in ethanol imports as well as about 5 billion gallons of domestic biodiesel production. As a result, domestic corn and soybean prices could increase dramatically from current levels, significantly increasing domestic prices for food and feed and reducing exports.

In agricultural markets, production of corn and biomass is subject to agricultural risks, such as crop failure caused by disease or drought. Moreover, the competition for arable land that would result from increased corn production at the levels needed to satisfy the 25-percent RFS could significantly raise all food and feed prices in the United States. The current generation of corn and soy biofuels crops are grown almost exclusively on prime agricultural land in the Midwest. It is not clear that sufficient land resources would be available for large-scale expansion of corn and soybean cultivation, given the intense competition with conventional agricultural products for arable land.

The markets for biofuels, biofuel co-products, and crop commodities are linked, and they are susceptible to changes in the prices and availability of the crops. Surging demand for biofuel feedstocks under the RFS policy would exert upward price pressure on corn and soybean commodities and influence the markets for food, feed, industrial feedstocks, and exports. Additionally, the generation of co-products increases directly with biofuel production. At high levels of biofuel production, co-products may be oversupplied, resulting in depressed prices and lower revenues to offset fuel production costs.

In 2005, co-products from the 3.9 billion gallons of ethanol produced were significant, including 10 million tons of dried distillers’ grains and solubles (DDGS), 473,000 tons of corn gluten meal, 2.6 million tons of corn gluten feed, and 283,000 tons of corn oil.⁸ As biofuel production grows to the 7.5 billion gallons mandated in the Energy Policy Act of 2005 (EPACT2005), DDGS production is expected to grow to more than 15 million tons. With the RFS policy, more than 25 billion gallons of corn-based ethanol would be required in 2025, and DDGS production would exceed 50 million tons—probably causing a dramatic drop in its market-clearing price. At that point, the value of DDGS could be as low as the value of biomass or fertilizer.

Biodiesel production also results in some valuable co-products. Current biodiesel production uses surplus soybean oil generated as a co-product in the soybean meal industry, with little effect on other soybean commodity markets. Annual production levels approaching 300 to 600 million gallons of soybean oil would, however, begin to compete with food and feed markets for soybeans.⁹ Ten pounds of crude glycerol is generated as a co-product for every 100 pounds of biodiesel, and the glycerol generated from 300 to 600 million gallons of biodiesel production per year would be equal to nearly one-half of the current glycerol market in North America, causing a substantial oversupply and depressing prices.

Technology Concerns

Meeting the 25-percent RFS and RPS mandates in the Policy proposal would require successful and early development of currently unproven and noncommercial technologies, including those that convert cellulose to sugars and, ultimately, to cellulosic ethanol. The success of the Policy would also depend on the cost, performance, and first date of commercial availability of advanced biomass electricity generation technology and the development of the energy crop industry needed to support it.

While it is expected that both technologies—advanced biomass generation and cellulosic ethanol production—will be feasible, their actual costs, performance, and first dates of commercial availabilities are uncertain, because no such commercial plants exist at present. If the technologies became commercially available in the first few years of the next decade and their costs were lower than expected, then the costs of meeting the RPS and RFS could be lower than projected here. On the other hand, if the costs of early commercial plants were much higher than projected¹⁰ and/or the first dates of commercial availability were delayed into the second half of the next decade or beyond, then the actual costs of the policy could be much higher than estimated in this analysis. In that event, meeting the RFS by 2025 could require potentially implausible levels of corn-based ethanol production or unprecedented levels of ethanol imports from Brazil. With the success of the Policy dependent on noncommercial technologies with significant uncertainty in cost,
performance, and date of commercial availability, significant economic risks would be imposed on the market.

In the case of electricity generation from biomass, the technology consists of a biomass handling preprocessor that reduces the biomass to a treatable consistency; a gasifier and scrubber to remove noxious or corrosive gases in the mix; and a combined-cycle generating plant. In concept, the technology is much like an integrated gasification combined-cycle (IGCC) plant with coal as the feedstock; however, no full-scale commercial IGCC plants have been built. The major engineering issue with biomass remains the “front end handling and processing” component, which tends to jam or clog. Small-scale pilot plants have not attained utilization rates exceeding 60 percent. Because the front end is an expensive component, either the engineering problem must be solved or the unit will have to be built with a “spare front end handler” to maintain high overall utilization, significantly increasing its capital and nonfuel operating and maintenance costs.

In the case of cellulosic ethanol, current estimates of capital costs for a 50 million gallon per year cellulosic ethanol plant are expected to be high: about $365 million (2005 dollars), as compared with $65 million for a corn-based plant of similar size. With no commercial cellulosic ethanol plants currently in operation, investment risk is high for a first-of-its-kind, large-scale cellulosic ethanol production facility. EPACT2005 provides financial incentives that are expected to bring the first 250 million gallons per year of cellulosic ethanol production capacity on line between 2010 and 2015; however, it is not certain what the initial plant and operating costs will be or how quickly the costs and investment risk will fall as a result of manufacturing experience and further research.

Other Concerns and Uncertainties

In addition to the concerns discussed above, there are several other areas of uncertainty that could affect the feasibility and costs of meeting the RPS and RPS policy goals.

• The supply and cost of biomass energy crops to generate electricity and produce cellulose-based ethanol will be critical in determining credit prices and the prices of delivered energy under the main Policy. The critical uncertainty involves the availability and cost of biomass for use in electric power generation and ethanol production, as well as the cost, performance, and first dates of commercial availability of the technologies. To the extent that this analysis overstates the cost and understates  the availability of biomass technology, the impact on the U.S. energy market and economy could be smaller than indicated here; however, if biomass supply is overstated and prices are understated here, the impact could be larger.
• The projected level of about 25 billion gallons of corn ethanol production per year in 2025 under the Policy would significantly increase U.S. corn demand and likely require much higher prices to clear the market, with a significant impact on food and feed markets and a large cut in, or elimination of, U.S. corn exports. Also, several recent studies that are less optimistic about yield growth and expansion of corn acreage suggest a maximum level of U.S. corn ethanol production that is below 20 billion gallons, which would make the feasibility of meeting the RFS much more uncertain.
• The impacts of rising corn prices on the prices of other domestic and international agricultural food and feed products—and ultimately on U.S. economic growth—is highly uncertain but potentially larger than the direct energy price impacts alone. Analysis of those impacts would require the application of an integrated model that examines agricultural competition across the economy and energy sectors both domestically and internationally. For this study, EIA used an integrated domestic model to derive biomass and corn prices; however, the model is not integrated with the rest of the domestic or international economy.
• The availability and pricing of ethanol exports from Brazil will be critical in determining domestic RFS credit prices. Further, the availability of ethanol exports will depend on the extent to which additional land resources are used for ethanol production, which is highly uncertain. Although Brazil may be willing to make such investments, it is unclear at what market price the investments would be made or how they would be funded.
• As indicated in the request for analysis, this study assumes the enactment, in some form, of legislation (like portions of S.23) that will facilitate the development of biofuels transportation and distribution infrastructure and the production of only dualfuel capable light-duty vehicles after 2016. The enactment of such legislation is highly uncertain. Its details could determine what the costs are, who bears the costs of building the infrastructure, and the likelihood that the intended goals will be achieved.

Uncertainties in the Reference Case

NEMS, like all models, is a simplified representation of reality. Projections are dependent on the data, methodologies, model structure, and assumptions used to develop them. Because many of the events that shape energy markets (including severe weather, technological breakthroughs, and geopolitical developments) are random and cannot be anticipated, energy markets are subject to uncertainty. Moreover, future developments in technologies, demographics, and resources cannot be foreseen with certainty. Nevertheless, well-formulated models are useful for analyzing complex policies. They can provide valuable insight, because they ensure consistency in accounting and represent (albeit imperfectly) key interrelationships.

EIA’s projections are not statements of what will happen, but what might happen, given technological and demographic trends and current policies and regulations. The Reference Case used for this analysis, based on the AEO2007 reference case, incorporates current laws and regulations as of September 1, 2006. Thus, it provides a policy-neutral starting point that can be used to analyze energy policy initiatives. In its reference cases, EIA does not propose, advocate, or speculate on future legislative or regulatory changes. Laws and regulations generally are assumed to remain as currently enacted or in force (including sunset or expiration provisions); however, the impacts of scheduled regulatory changes, when clearly defined, are reflected.

Notes