The Renewable Fuel Standard as amended under the Energy Security and Independence Act of 2007 (RFS2) mandates that 35 billion gallons of ethanol-equivalent biofuels—15 billion gallons of conventional biofuels, 4 billion gallons of advanced biofuels, and 16 billion gallons of cellulosic biofuels—and 1 billion gallons of biomass-based diesel be consumed in the United States by 2022. As noted in Chapter 2, the United States has the capacity to produce 14.1 billion gallons per year of corn-grain ethanol that can be counted toward conventional biofuel consumption and 2.7 billion gallons per year of biodiesel that can be counted toward biomass-based diesel consumption. Therefore, the committee judges that consumption mandates of those two categories of biofuels will likely be met by 2022. However, cellulosic biofuel is a developing industry, and some formidable barriers could prevent the production and consumption of the combined 20 billion gallons of advanced biofuel1 and cellulosic biofuel in 2022. Those challenges include producing biomass feedstock and converting it to transportation fuels economically, mitigating environmental effects to meet regulations, social barriers, and constraints to blending ethanol into the fuel supply.
Chapters 4 and 5 describe the potential economic and environmental consequences to inform policymakers of the tradeoffs of meeting RFS2. This chapter discusses barriers to achieving the consumption mandates for advanced and cellulosic biofuels in RFS2. The chapter is organized on the basis of four types of barriers: economic, environmental, policy, and social barriers to achieving RFS2. Economic barriers are ones that maintain the unsubsidized price of biofuels above the price of gasoline. Environmental barriers can be resource limitations or practices or environmental discharges that violate environmental regulations. There could be technical or policy solutions to economic and environmental barriers. For example, a subsidy for biofuels is a policy solution to overcome the economic barrier. Technological improvements that reduce biomass feedstock costs or enhance conversion efficiencies of biomass to fuels reduce cost of production. Better technology also can reduce the environmental effects of
1 The advanced biofuel consumption mandate can be met by biofuels made from cellulosic feedstock, as long as the life-cycle GHG emissions of the fuel product is at least 50 percent lower than that of petroleum-based fuels.
each unit of biofuel produced. Technical barriers often require technical solutions to resolve; most technical challenges are addressed in research and development and demonstrated in pilot plants. However, if the solutions to technical and environmental barriers are too costly, there is still an economic barrier. Policies that could stifle the development of the cellulosic biofuels industry present barriers to achieving RFS2. Social barriers involve potential producers’ and consumers’ perception of, attitude toward, and acceptance of biofuels.
Should policymakers continue to believe that the consumption mandate of RFS2 is to be met in 2022, the barriers described in this chapter would have to be resolved. Unless these barriers are overcome, the committee concludes that the RFS2 mandate is unlikely to be attained by 2022. Removing barriers to the successful establishment of a cellulosic-biofuel industry at the scale mandated by RFS2 involves identifying potential problems at every stage of the biofuel production process and opportunities to resolve them.
The discovery, extraction, manufacture, distribution, and use of petroleum fuels have been developed and improved for over 150 years. Overcoming the barriers and displacing a significant amount of petroleum with biofuels will require time, innovation, and changes in many fundamental economic, technical, and social processes. Doing so in 11 years would be difficult, costly, and complex. Implementing changes in liquid transportation fuel while avoiding socially unacceptable disruptions requires a deep understanding of each affected component and strong commitment to change. “Drop-in” biofuels that can easily be included in the existing petroleum infrastructure are the simplest way of undertaking a fuel transition. The identification of barriers to transitioning to most other biofuels requires combining knowledge of existing infrastructure with an assessment of the desired properties of future biofuels. In some cases, opportunities to achieve economic, environmental, or social benefits are provided by the need to address particular barriers. As of 2011, the key barrier to achieving RFS2 is economic because technologies for producing cellulosic biofuel are available but not economically viable at a commercial scale,2 even with the current subsidies and mandates, under 2011 oil prices. Biofuels will only be adopted on a commercial scale if their cost to consumers is competitive with other liquid fuels. Moreover, many barriers identified in this chapter have solutions that are technically feasible, but they could increase the economic and environmental costs of biofuel production. If the economic barrier is removed, environmental and social concerns could pose barriers to producing 20 billion gallons of advanced and cellulosic biofuels in 2022. Although barriers to achieving RFS2 are identified in this chapter, the extent to which each barrier inhibits production and market penetration of biofuels is uncertain. Some barriers might not be obvious or will only be discovered when the technologies of cellulosic biofuel are implemented at a commercial scale. Therefore, commercial-scale demonstrations are critical to proving economic and environmental feasibility.
RFS2 cannot be attained without sufficient biomass availability at attractive costs. As discussed in Chapter 4, unless the prices that farmers are paid for bioenergy feedstocks delivered to the biorefinery gate reach $75-$133 per dry ton, farmers are not likely to grow or harvest the necessary amounts of bioenergy feedstock. The price a biorefinery pays for its feedstock is likely to be the largest expense in producing biofuels (Chapter 4). Some reports
2 The National Renewable Energy Laboratory defines a commercial-scale demonstration for biofuel refinery as a facility that has the capacity to process 700 dry tons of feedstock per day.
estimated feedstock costs to be one-third to two-thirds of the cost of corn-grain ethanol and cellulosic biofuel (Foust et al., 2007; NAS-NAE-NRC, 2009; Swanson et al., 2010; Wright et al., 2010). Improving yield; reducing crop loss from drought, pests, and diseases; and reducing costs of harvest, storage, and transportation present opportunities to decrease the costs of bioenergy feedstocks. However, demand from the biofuel market and competition for feedstock with other sectors (for example, bioelectricity generation to meet the state-level Renewable Portfolio Standards) could also drive up feedstock costs and present a barrier to producing biofuels that are cost competitive with petroleum-based fuels (Chapter 3). Furthermore, the exclusion of a large number of forest options by law from the definition of renewable biomass (for example, exclusion of residues from federal forests and from nonplantation forests) poses another limit to biomass supply (Chapter 2).
Storage and Delivery
The year-round operation of biorefineries requires that biomass feedstock produced seasonally be stored until use (Chapter 2). Stored biomass could be susceptible to spoilage so that methods and standards for monitoring feedstock quality would be necessary (DOE-EERE, 2004). Furthermore, the bulky biomass would have to be transported to biorefineries. Cellulosic biomass, regardless of its source, is a high volume, low-density material, and long-distance transport is expensive. Research to address the storage and transport of biomass could improve the economic viability of cellulosic biofuel.
Storage and transportation of biomass feedstock could require additional initial investments and operating costs for producers as well. (See Tables M-5 and M-6 in Appendix M for a list of estimated costs.) Opportunities to address this barrier involve growing multiple feedstocks and having production facilities combine crops grown for feedstock with agricultural, forest, or urban wastes. Several technologies have been suggested as potential solutions to the storage and transportation issues, including torrefaction, liquefaction, and densification (NAS-NAE-NRC, 2009; Sadaka and Negi, 2009; Yan et al., 2009), but implementing those technologies on a commercial scale will require infrastructure and incur additional operational costs, which might not reduce overall production and delivery costs. Studies to solve the transportation and storage problems are under way, including an Idaho National Laboratory analysis of a supply chain of wheat and barley straw to a biorefinery system at a scale of 800,000 dry tons per year (Grant et al., 2006). Corn stover logistics have been analyzed by the National Renewable Energy Laboratory (NREL; Atchison and Hettenhaus, 2003), and Oak Ridge National Laboratory’s Bioenergy Feedstock Information Network (ORNL, 2010) provides documents and tools related to logistics for multiple ethanol feedstocks. Those studies provide information on supply logistics with associated costs, identifying opportunities to improve the economic feasibility of harvest, collection, storage, handling, and transport of biomass feedstocks.
Absence of Price Discovery Institutions in Bioenergy Feedstock Markets
The price discovery process is defined as “the process by which buyers and sellers arrive at specific prices and other terms of trade” (Tomek and Robinson, 1983, p. 199).3 The grain sector relies on a well-developed set of public and private price discovery institutions,
3 “Price discovery” is different from “price determination.” Price determination is based on “the theory of pricing and the manner in which economic forces (that is, supply and demand) influence prices under various market structures and lengths of run” (Tomek and Robinson, 1983, p. 213).
but no such institutions exist to facilitate markets in nontraditional feedstock sources. In the absence of such institutions, at least two dimensions of the price discovery process pose potential barriers to the expanded use of biofuels.
First, given the high transportation cost (as discussed earlier) that is likely to exist for such feedstocks, the geographic regions over which such feedstocks are traded is likely to be restricted. A more likely scenario is that a specific geographic region would be served by a few biorefineries. Thus, given the small number of buyers in the region, patterns of spatial price variations are unlikely to communicate price information across regions as in the case of grain markets.
A second dimension of the price-discovery process that could act as a barrier to the expanded use of biofuels is the high cost of information about the quality of feedstock (Hess et al., 2007; Lamb et al., 2007; Anderson et al., 2010). The price of feedstock would be determined, in large part, by the quantity and price of biofuel that can be extracted from that feedstock. To the extent that the quality of feedstock (for example, the yield of biofuel that can be produced from a unit of feedstock) is variable, buyers of feedstock will face uncertainty about the value of that feedstock. If the cost of evaluating feedstock quality is high, this quality uncertainty would, in turn, be reflected in the price that feedstock buyers would offer to feedstock sellers. In particular, buyers faced with a high cost of determining the quality of a good would be expected to discount the price of all such goods, regardless of their high or low quality (Aklerlof, 1970; Stiglitz, 1987, 2002). As a consequence, the expansion of the cellulosic biofuel industry is likely to face a barrier in the high cost of determining the quality of feedstock for biofuels and the high cost of quality information in the price discovery process. However, if the cost of measuring quality is low, a quality incentive program could easily be implemented by biorefineries.
Because of uncertainty about price, quantity, or quality of cellulosic feedstock and the absence of low-cost price-discovery institutions, buyers and sellers will turn to alternative forms of conducting transactions (Williamson, 1996). Market participants are likely to shift to a variety of nonmarket price-discovery mechanisms, such as the use of negotiated contracts, as a means of discovering the information needed by buyers and sellers (Williamson, 1996; Saccomandi, 1998). Such contracts can provide specific expectations regarding price, quantity, quality, delivery timing, or delivery location that are to be met by market participants and the economic incentives or penalties for failing to do so.
Reliance on contracting can provide assurances to buyers and sellers in a new industry such as advanced biofuels. For example, investors in a cellulosic biofuel refinery might be unwilling to invest in new or expanded capacity unless they are certain about the quantity, quality, or price of feedstock available to the refinery. Feedstock producers, on the other hand, would be unlikely to make the investments necessary for feedstock production (for example, specialized harvesting equipment) without the assurance of a long-term buyer commitment. In such cases, contracting can provide the information necessary for the creation and growth of a new industry.
Feedstock Conversion Technologies and Costs
Converting the cellulosic biomass into liquid fuel is the other major cost component. The technical feasibility of conversion has been demonstrated for some time, but lowering the cost to a competitive level is a barrier to achieving RFS2. The first step is finding a technology with high yield, flexibility in terms of feedstocks, and low cost. Both government and companies have sponsored research, development, and demonstration of conversion technologies (see Tables 2-2 and 2-3 in Chapter 2), and there appear to be promising candidates. However, moving a new technology from the laboratory to a commercial operation
requires both money and time. Government and private equity can provide the capital, but the time required to commercialize a new technology is difficult to compress. Many potential operational problems and associated costs are only discovered as the process scale is increased. Hettinga et al. (2009) and van den Wall Bake (2009) describe cost reduction and increases in efficiency for corn-grain ethanol in the United States and sugarcane ethanol in Brazil. Technology for corn-grain ethanol for fuel has been developing for over 30 years in the United States. Cost reduction of corn-grain ethanol in the United States was attributed to economies of scale as the ethanol refineries became larger over time, improved ethanol yields, reduced enzyme costs, improved fermentation, better technologies for distillation, dehydration, energy reuse, and automation, and a market developed for coproducts. The cost of conversion at biorefineries decreased by 40-50 percent from the early 1980s to 2005 (Hettinga et al., 2009). Processes for distillation and dehydration are the same for corn-grain and cellulosic ethanol so that cellulosic ethanol (once the sugars have been released) could benefit from the experience gained from corn-grain ethanol. Many economic evaluations for cellulosic ethanol already include cost savings that are assumed to take place as the technology advances (NAS-NAE-NRC, 2009; Tao and Aden, 2009).
Currently, close to half of the commercial companies with secured funding for demonstration of nonfood-based biofuel refineries are planning to use biochemical-based approaches (see Figure 2-18 in Chapter 2) that are roughly analogous to corn-grain ethanol production. However, production of ethanol from corn starch via fermentation is technically simple and efficient compared to production from lignocellulose-rich feedstocks such as herbaceous and woody crops, agricultural and forest residues, and municipal solid waste (MSW) (Table 6-1). Starch is a temporary storage pool for glucose in a plant, and starch is designed to be quickly and easily mobilized by a small number of enzymes. Conversely, cellulose functions as a stable structural component of plant cell walls and is chemically associated with a variety of complex macromolecules, including lignin and hemicellulose, which increase its resistance to physical and biological degradation. Wood consists of about 30-percent lignin, 40-percent cellulose, and 30-percent hemicellulose. Ratios of these macromolecules vary somewhat across the different potential feedstocks (Schnepf, 2010). Ethanol production from cellulosic biomass will not reach the mass efficiency or economic viability of ethanol production from grain unless techniques are developed to break down both cellulose and hemicellulose effectively into sugars (Gírio et al., 2010).
Many herbivores, such as cows, house a complex ecosystem of dozens of species of bacteria and protozoa that efficiently ferment cellulose and hemicellulose over a period of several days. Accomplishing similar efficiency in an industrial setting requires the optimization of a complex series of engineering steps. One complicating factor is that lignin is resistant to enzymatic degradation and protects cellulose and hemicellulose from physical or enzymatic decomposition. Current ethanol production schemes use various pretreatment steps to disassociate lignin and partially hydrolyze hemicellulose. However, this step is expensive and often yields products that are toxic to subsequent enzymatic and fermentation steps.
Technology for producing ethanol from cellulose has been refined to the point of pilot-scale application (Chapter 2), but simultaneous production of ethanol from hemicellulose has proven to be much more difficult. The physiochemical differences between cellulose and hemicellulose compel the use of different and often more complex pretreatment, enzymatic, and fermentation procedures. Thus, the efficiency of conversion of biomass to ethanol is currently low, and economically competitive processes await development of enzymes and organisms for efficiently using hemicelluloses in processes that can be consolidated with the bioprocessing of cellulose. The huge biodiversity of microorganisms and the powerful techniques in biotechnology, particularly microbial evolutionary engineering and
|Grain Ethanol||Cellulose Fraction||Hemicellulose Fraction|
|Characteristic of substrate||Corn is about 70% starch, which is composed exclusively of glucose and easily freed from cellular matrix.||Cellulose makes up 35-60% of biomass and is composed exclusively of glucose but is difficult to disassociate from lignin.||Hemicellulose makes up 15-40% of biomass and is composed of numerous hexose and pentose sugars. It is difficult to disassociate from lignin.|
|Pretreatment||None||Extensive and typically involves application of heat, acids, bases, or oxidizing agents depending on feedstock.||Extensive and typically involves application of heat, acids, bases, or oxidizing agents depending on feedstock; however, the optimal solution for hemicellulose differs from that for cellulose.|
|Conditioning||Hydration with water||Neutralization of acid or base and removal of toxic products.||Neutralization of acid or base and removal of toxic products.|
|Release of sugars||Amylase and glucoamylase release glucose.||Three or more different cellulase enzymes release glucose.||A complex cocktail of xylanases and mannases are needed depending on the feedstock. Mannose, galactose, glucose, xylose, and arabinose are the primary end products.|
|Fermentation of sugars||Glucose is fermented by a single microbial species, often Saccharomyces cerevisiae.||Glucose is fermented by a single microbial species, often S. cerevisiae.||A mixture of bacteria, yeast and/or fungi is required for fermenting the complex mixture of hexose and pentose sugars.|
recombinant DNA, are being applied to address this barrier; however, the time required to develop appropriate solutions and to implement them on a large scale is not readily predictable and will not likely be quick.
Infrastructure Investments for Biorefineries
A major impediment to increasing cellulosic biofuel production is the large capital investment required for commercial production facilities. A 2009 report estimated the capital cost of a cellulosic-ethanol biorefinery with a capacity of 40 million gallons per year to be about $140 million (2007$) (NAS-NAE-NRC, 2009). Capital costs for building cellulosic biorefineries vary by the choice of feedstock, the conversion technology, and the size of biorefinery. For example, $140 million was the estimated cost of a biorefinery if a high-sugar biomass is used as feedstock. The cost would be higher if biomass with high lignin content is the primary feedstock because of the additional cost of the boiler and steam electrical generator for processing large quantities of lignin. Biorefineries benefit from economies of scale so that the larger the biorefinery, the lower the capital cost per unit capacity (NAS-NAE-NRC, 2009).
In a 2002 report, NREL estimated it would cost $197 million (2000$) to build the nth cellulosic-ethanol biorefinery to produce 69.3 million gallons per year of ethanol from 2,200 dry tons per day of feedstock (Aden et al., 2002). In a 2010 report, NREL updated those cost estimates to about $380-$500 million (2007$) to build the nth plant that has a capacity to convert 2,200 dry tons per day of cellulosic feedstock to produce about 50 million gallons per year of ethanol (Kazi et al., 2010).
Capital costs for biorefineries that use gasification to convert biomass to drop-in fuels were estimated to have even higher capital costs than those that use biochemical conversion. One report estimated the capital cost for a biorefinery that uses gasification and Fischer-Tropsch to convert about 4,000 dry tons of biomass per day to be about $600 million (NAS-NAE-NRC, 2009), while another report estimated the capital costs to be about $500 million for a biorefinery that uses 2,200 dry tons of biomass per day (Swanson et al., 2010). NREL also estimated capital cost for a biorefinery that uses fast pyrolysis to convert 2,200 dry tons of biomass to bio-oil followed by upgrading to drop-in fuels. The capital cost was estimated to be about $200 million (Wright et al., 2010). (See Table 4-3 in Chapter 4.) In 2007, the U.S. Department of Energy (DOE) announced funding of six advanced biofuel projects with a total expected production of 130 million gallons per year of ethanol. The total cost of these projects, including both government and industry funding, was estimated at $1.2 billion (2007$).
Depending on the average capacity of cellulosic biorefineries, about 200-350 refineries would have to be built and in operation between now and 2022 to achieve 16 billion gallons of ethanol-equivalent cellulosic biofuels mandated by RFS2 (Anex et al., 2010; Kazi et al., 2010; Swanson et al., 2010; Wright et al., 2010). The number of biorefineries would be even higher if the 4 billion gallons of advanced biofuel are to be met by cellulosic biofuel as well. The total capital costs would be at least $50 billion. Current economics, exclusive of government subsidies and taxes, do not favor the production of biofuels. Biofuel production is only an economically viable business because of the current tax and subsidy structure (Chapter 4). Companies are reluctant to invest capital in a business venture that depends on government subsidies, which can change at any time. To attract investment capital, any subsidy or tax program designed to encourage investment in biofuel production would have to contain provisions that result in rapid or guaranteed payback for the investor. Rapid returns would attract private investment, whereas guaranteed returns would make the fledgling biofuel industry similar to a regulated public utility. The U.S. and global financial crisis at the end of the 2000-2010 period also discouraged investments in biofuels (IEA, 2010). Stable economic and policy conditions are needed to encourage biofuel investment. Sustained high oil prices (for example, $190 per barrel) also would encourage private investment in biorefineries (Chapter 4).
Infrastructure Investments for Fuel Distribution
Developing infrastructure necessary to transport biofuels from biorefinery to point of sale is a barrier to commercial implementation of the RFS2 mandate. Current transport costs for corn-grain ethanol are high. Existing pipeline infrastructure can be used to transport some finished biofuel products to the refineries and blending facilities depending on the fuel properties. If RFS2 is mostly met by ethanol, the need for fuel distribution infrastructure could pose a challenge to market penetration of the fuel.
Pipelines are a cost-effective way of moving large volumes of liquids only if they are to be used for long periods of time. However, ethanol is not compatible with existing petroleum pipelines because of its higher corrosiveness and affinity for water and because it is a better solvent than petroleum products (Farrell et al., 2007; Singh, 2009). Although
existing pipelines could be retrofitted to become multipurpose ones that accommodate ethanol transport, they were designed to flow from petroleum refineries to end users. Ethanol transport would require pipelines that link locations where biorefineries exist and are projected to be built to the existing petroleum distribution infrastructure. Alternatively, dedicated ethanol pipelines could be built. The annual operating costs are low, but building a biofuel pipeline system requires a large investment with significant financial risk (DOE, 2010). Also, ethanol volumes would be low compared to petroleum pipelines’ throughput. With the use of biofuels currently dependent on short-term government subsidies, private investors are hesitant to invest in dedicated ethanol pipelines. If the government subsidies are removed, then the economic incentive to use ethanol disappears and the value of the pipeline investment is lost. As a result, ethanol might continue to be transported mostly by tanker truck, barge, and rail; each form carries with it inherent cost and risk, including increase in road accidents, spills, and degradation of road surfaces as a result of increased loads. These delivery methods also require unloading racks, possibly new rail sidings or wharf facilities to accept delivery, and manpower to connect the unloading facilities to the delivery vessel. Although ethanol can displace a fraction of the United States’ liquid transportation fuels, investment in a fuel delivery and blending infrastructure would be needed.
Infrastructure for refueling would have to be built if an increasing amount of ethanol is used to meet the biofuel consumption mandate (NAS-NAE-NRC, 2009; NRC, 2010). As of 2011, there were about 2,400 E85 refueling stations across the United States (DOE-EERE, 2010).
If the production of fuel ethanol exceeds the amount that can be blended in gasoline, as explained below, then it reaches the so-called “blend wall.” Most ethanol in the United States is consumed as a blend of 10-percent ethanol and 90-percent gasoline. If every drop of gasoline-type fuel consumed in U.S. transportation could be blended, then a maximum of about 14 billion gallons of ethanol could be blended. However, most experts believe the effective blend limit4 is about 9 percent, which is about 12.6 billion gallons, less than current industry production capacity. In 2010, EPA increased the blend limit to 15 percent for vehicles built since 2001. However, even with a blend limit of 15 percent, the blend wall will be reached again around 2014. Thus, the blend wall is a major barrier for increasing ethanol production beyond about 19 billion gallons even if the blend limit is 15 percent.
Appendix N, based on work by Tyner et al. (2011), provides a complete analysis of alternative scenarios for meeting the RFS2 mandate. In that analysis, it becomes clear that production of ethanol from cellulosic feedstocks becomes problematic because of the blend wall. It would require large and rapid investments in fuel dispensers for E85 plus millions of flex-fuel vehicles produced and sold each year. For example, if the blend limit remained at 10 percent, 8.7 million flex-fuel vehicles would have to be sold each year, and 24,000 fueling dispensers would have to be added each year.5 Even if economic incentives were
4 The proportion of gasoline that actually gets blended with ethanol as a result of infrastructure limitations and total expected gasoline type fuel consumption.
5 According to Energy Information Administration, the U.S. fuel-flex vehicle (FFV) fleet will grow from 8.0 million vehicles in 2009 to 39 million by 2022. The annual EIA stock of FFVs is adjusted up or down so that the fleet reflects the volume of E85 consumed in the six scenarios reported in Appendix N. From 2010 to 2022, the annual miles driven averaged 12,369 miles while the E85 average fuel efficiency was 17.9 miles per gallon. EPA (2010d) assumes that the average E85 utilization rate will be no more than 40 percent per FFV, given availability, consumer preferences, and price. Thus, a FFV will consume no more than 274 gallons of E85 per year.
provided, accomplishing this level of investment in infrastructure would be a significant challenge. Raising the blend limit to 15 percent and blending all gasoline for transportation with that proportion of ethanol would only alleviate the problem to a small extent.
On the other hand, if cellulosic feedstocks produce hydrocarbons directly via a thermochemical process, the blend wall becomes much less of an issue. Biogasoline and green diesel are not subject to the blend limits; therefore, the blend wall only applies to ethanol.
Another issue with expanding E85 is the challenge of attracting consumers. E85 contains 78 percent of the energy of E106 and so would have to be priced at 78 percent or less of the E10 price. If E10 were $3.00 at the pump, E85 could be no more than $2.34 based on the mileage difference and less if consumers considered the cost of more frequent fill-ups. The extent to which this is a challenge depends on the relative prices of gasoline and ethanol. In November 2010, wholesale gasoline was about $2.15 and ethanol about $2.50. Under these conditions, marketing E85 would require very large incentives. At these prices, the required ethanol subsidy would be $0.475 per gallon, which for 16 billion gallons of cellulosic ethanol would be $7.6 billion per year.
Uncertainties in Government Policies
RFS2 does not provide a market guarantee for biofuels, but instead an assurance of a market under most ordinary circumstances. RFS2 as passed by Congress in 2007 was intended to guarantee a market for biofuel producers and thereby eliminate one of the important sources of uncertainty for potential investors in biofuel refineries. The objective is largely achieved for corn-grain ethanol, at least until the blend wall constraint is reached. However, language in the legislation gives EPA the right to waive or defer enforcement of RFS2 under a variety of circumstances. For example, if it is deemed that enforcing RFS2 would result in significant economic dislocation, the EPA administrator has the right to reduce or waive RFS2. Under that provision, the Governor of Texas in 2008 petitioned EPA to waive RFS2 because of high corn prices and the damage to the livestock sector. EPA denied that request, but economic dislocation waivers are still possible. Undoubtedly, uncertainty of enforcement of the mandate is an impediment for private-sector investment. If cellulosic biofuels are likely to be more expensive than fossil fuels as indicated in Chapter 4, the only guarantee of a market is the federal government. If the private investor perceives that the mandate is not iron-clad, then the effect of the mandate policy will be diminished.
For cellulosic biofuel, EPA is “required to set the cellulosic biofuel standard each year based on the volume projected to be available during the following year.” The 2011 standard that EPA set is 6.6 million gallons per year of cellulosic biofuel compared to the 250 million gallons per year in RFS2 (EPA, 2010a).
RFS2 is a quantitative mandate regulating minimum usage of renewable fuels in the United States. The mechanism used for enforcing the RFS2 is via renewable identification numbers (RINs) (Thompson et al., 2010). Each batch of biofuel that is produced or imported into the United States that meets the RFS requirements is assigned RINs by EPA. Each fall, EPA converts the overall quantitative RFS level to a share allocation based on fuel market share. For example, if fuel blender A has a fuel market share for fuel type G of 10 percent, and if the RFS for fuel type G is 15 billion gallons ethanol equivalent, then blender A has an obligation to acquire RINs for 1.5 billion gallons ethanol equivalent of biofuel. Blender A can meet the requirement by acquiring 1.5 billion gallons ethanol equivalent of biofuel
6 The energy content of ethanol is two-thirds that of gasoline on a per-gallon basis. Taking into account the energy content of ethanol and gasoline in E10 and E85 blends, E85 contains about 78 percent of the energy of E10 on average.
with its associated RINs and blending the biofuel into fuel type G. Alternatively, blender A could buy the RINs from blender B that has excess RINs; that is, blender B has blended more biofuel than required and has those extra RINs to sell. Blenders can meet the RFS requirement with any combination of actual blending or RIN purchase (Thompson et al., 2010).
Other factors complicate the RIN market. First, a blender can meet up to 20 percent of a given year’s (t) requirement with RINs from the previous year (t – 1). However, RINs cannot be carried forward more than one year (Thompson et al., 2010). They are worthless after that. Also, if a blender runs short in year t, the blender can meet the year t obligation in year t + 1. However, the blender is required to meet the full year t and year t + 1 obligation with no borrowing for the next year. Finally, if the cellulosic mandate is waived, as it has been in 2010 and 2011, then blenders can buy RINs from EPA at a price of $3.00 (inflation adjusted) minus wholesale gasoline price or $0.25, whichever is higher (Thompson et al., 2011).
RINs are freely traded among firms, and the RIN price is an indicator of the extent to which RFS is binding. The price rarely goes to zero because there are some transaction costs associated with holding and trading RINs. Ethanol RINs have often traded for about $0.03 per gallon, reflecting this transaction cost. However, the values had been much higher in periods when RFS2 became more stringently binding. Thus, RIN values are one estimate of the cost of RFS2 (Thompson et al., 2011).
There also is an escape clause that permits blenders to buy RINs that are used to track compliance with RFS2 directly from EPA instead of actually purchasing cellulosic biofuels when there is a RFS waiver. When the price of cellulosic biofuel is high relative to gasoline, this provision becomes operative. It was included in RFS2 apparently to provide a relief valve in case the price gap between cellulosic biofuel cost and gasoline got too wide. In other words, Congress did not want to require enforcement of RFS2 if using cellulosic biofuel would increase the price of fuel at the pump substantially. Specifically, blenders can buy RINs from EPA for the higher of $0.25 or $3 minus the wholesale gasoline price. For example, if the biofuel cost were $3.50 and wholesale gasoline were $2.10, it would cost the blender $1.40 to purchase and blend cellulosic biofuel. Alternatively, the blender could purchase RINs for $0.90 from EPA and get no biofuel. Suppose the blender intended to blend 10-percent biofuel. Doing the calculation for 100 gallons, the cost of purchasing and blending the biofuel would be $224 for 100 gallons, and the cost of using 100 gallons of gasoline plus buying ten RINs would be $219. Thus, it would be more attractive for the blender to buy the RINs and forego blending the cellulosic biofuel. While this provision accomplishes its objective of effectively limiting consumer exposure to very high-priced cellulosic biofuels (relative to gasoline), it limits the scope of the RFS market guarantee for potential investors.
The subsidies for biofuels are another source of policy uncertainty. In past legislation, Congress provided biofuel subsidies for a period of time, typically 4-5 years. To the extent investments depend on the subsidies, the uncertainty in subsidy renewal is another impediment for private investment. For example, the subsidy for each gallon of cellulosic biofuel is $1.01 (regardless of the energy content of the biofuel) in 2010, but the subsidy is set to expire in 2012. If an investor were to consider building a biofuel refinery today, not a gallon would be produced before the subsidy expired. Therefore, the subsidy is not likely to have a major effect on investor decisions in cellulosic biofuel. Similarly, the corn-grain ethanol subsidy was set to expire in 2010. A 1-year extension of the $0.45 per gallon subsidy was passed in December 2010. The biodiesel tax incentive, which lapsed in 2009, was extended retroactively until 2011. The corn-grain ethanol subsidy and biodiesel tax incentives demonstrate the barriers created by uncertainty in government policy.
Another area of uncertainty is the Biomass Crop Assistance Program (BCAP), which provides two years of assistance to farmers who participate in the program to provide bioenergy
feedstocks for use as biofuels. The congressional appropriation was insufficient to satisfy total demand, and whether the 2-year payment limit will be extended is unknown.
Tariff on imported ethanol is another area of uncertainty. Initially, the import tariff was created to offset the domestic ethanol subsidy, which is available to both domestic and foreign ethanol. However, over time the subsidy has fallen such that there is now a gap between the tariff and the subsidy. The effective tariff (specific plus ad valorem) is about $0.59 per gallon, and the subsidy is $0.45 gallon yielding a net tariff of $0.14 per gallon. Brazil and other countries have argued that the net tariff violates the World Trade Organization rules. How Congress will handle the tariff in the future is unclear.
Nonfederal Laws, Rules, Regulations, and Incentives Affecting Biomass Energy
Some states are implementing or considering low-carbon fuel standards (LCFS) that could affect the development and use of biofuels—for example, California, Oregon, and Northeast and Mid-Atlantic states (California Energy Commission, 2009; NESCAUM, 2010; Oregon Environmental Council, 2010). State-level regulations that are more stringent than national emission standards would create an issue of market fragmentation. Such fragmentation can increase the cost of producing, distributing, and storing a wider variety of fuel blends by reducing the economies of scale and the regional price arbitration that can be achieved when homogeneous national standards are created.
An example of the cost of such “regulatory heterogeneity” (Muehlegger, 2006b) are the national regulations related to air quality in the Clean Air Act Amendments of 1990 and subsequent state-level regulations of a more stringent nature (for example, in California). A variety of estimates have found that the state content regulations, imposed in addition to the national Clean Air Act regulations, can increase the cost of gasoline in the regulating state by $0.030 to $0.045 per gallon (Muehlegger, 2002, 2006b; Chakravorty et al., 2008). (See Chouinard and Perloff ) for a finding that state content regulations created no price effect.) In addition to the absolute cost of refining, distributing, and storing fuels, research suggests that such regulatory heterogeneity can increase fuel price variability on a seasonal basis throughout the year (Davis, 2009) or the variability of prices at times of unexpected supply disruptions (for example, refinery fires or other shutdowns) (Muehlegger, 2002, 2006b).7
California is the first state to establish an LCFS and is used in this section as an illustration (California Energy Commission, 2009). Under California’s Global Warming Solutions
7 Seasonal variability in fuel prices can increase because the fuel content regulations might not apply throughout the entire year. Thus, traditional seasonal price variations (resulted from regularly observed driving habits through the year) can be exacerbated by variations in regulatory content standards throughout the year (for example, the content regulations are often more stringent during those times of the year in which demand for fuel is the highest because driving activity is the greatest) (Davis, 2009). Price variations due to unexpected supply disruptions can increase with greater regulatory heterogeneity because the number and capacity of refineries capable of producing fuel that satisfies state content regulations may be quite limited or can only be converted to production of fuel that complies with state regulations at significant expense and with a significant time lag. Thus, other refineries may have very limited ability to supply fuel to the market with the heterogeneous regulatory standards, thereby increasing the price movement in that state. In essence, when state regulatory standards proliferate, refineries in other states or regions are less able to absorb a portion of supply disruption and subsequent price increase (Muehlegger, 2002, 2006a). It should also be noted that such regulations can act as a trade barrier that limits imports of gasoline from foreign sources at times of a disruption in supply (Fernandez et al., 2007). Such regulations may also contribute to the exercise of market power by the refineries that serve a specific regulated state or region because the competition from other refineries may be limited by their inability to satisfy the state content regulations, thereby preventing market arbitrage from occurring (Chakravorty et al., 2008). See Chouinard and Perloff (2007) for a finding of no market power effect on prices.
Act (AB32), an LCFS that mandates a reduction in greenhouse-gas (GHG) intensity of transportation fuels was established. The rules governing the LCFS differ in important ways from the federal RFS2 standard and present fuel blenders with different standards for compliance at the state and federal levels. LCFS is a GHG-performance standard that applies to all transportation fuels, including biofuels, compressed natural gas, electricity, and hydrogen. All suppliers of transportation fuels, including blenders, producers, and importers, are required to reduce the average GHG intensity of their fuels compared to GHG intensity of transportation fuels in 2010 (Yeh and Sperling, 2010). The timetable adopted increases the percent GHG reduction required progressively until it reaches 10 percent in 2020. The average GHG intensity of fuels is calculated as the sum of GHGs emitted from the covered fuels divided by the total energy of the fuel. In addition, the act allows trading and banking of GHG credits to encourage technology innovations that would result in low-cost and low-carbon fuels (Yeh and Sperling, 2010). In contrast, RFS2 is a consumption mandate for specific types of biofuels. Some fuels that can contribute to achieving RFS2 might not contribute to meeting LCFS. For example, corn-grain ethanol qualifies as a renewable fuel under RFS2 whether it is blended as E10 or E85. However, under LCFS accounting for GHG reduction (which also includes GHG emissions from indirect land-use change), gasoline blended with 10-percent corn-grain ethanol might not contribute to meeting LCFS’s GHG-performance standard (Zhang et al., 2010). Furthermore, the California Air Resources Board uses different approaches for estimating life-cycle GHG emissions than EPA for RFS2. State-level LCFS could be a barrier to meeting RFS2 if multiple states are implementing LCFS and if fuel suppliers use fuels other than biofuels to meet an LCFS target. Having different regulatory agencies using different methods to calculate GHG emission reductions could lead to legal challenges by industry that can delay the implementation of any GHG emission reduction legislation until there is consensus on life-cycle analysis.
Environmental effects of biofuel production can pose a barrier to achieving RFS2 if the effect results in biofuels that do not meet the RFS2 eligibility requirements, if the effect violates environmental regulations, or if a resource limitation constrains the amount of biofuels that can be produced. This section discusses some of the environmental effects at different stages of the supply chain and over the life cycle of biofuel production that could become barriers to producing volumes of biofuels to contribute to the RFS2 consumption mandate.
Life-Cycle GHG Emissions
In addition to the mandated volumes of renewable fuels to be used each year from 2008-2022, RFS2 specifies GHG reduction thresholds for different categories of fuels (Table 6-2). (See also section entitled “Renewable Fuel Standard” in Chapter 1.) That is, biofuels would be required to have life-cycle GHG emissions less than the specified thresholds to qualify as one of the four categories of renewable fuels for meeting the RFS2 consumption mandate.
Uncertainties in life-cycle GHG accounting can pose a barrier to achieving RFS2 because they affect investors’ confidence. Although EPA made a ruling on which fuels (that is, fuels produced from which feedstock and in what type of facilities) would meet the GHG reduction threshold, it recognizes the science of GHG accounting is evolving. EPA will reassess the life-cycle GHG determinations (EPA, 2010b) so that the methods and industry data that the agency uses to assess life-cycle GHG emissions could change over time. In
aGHG reduction threshold is the minimum percent reduction of life-cycle GHG emissions of the 2005 baseline average gasoline or diesel fuel that a renewable fuel replaces.
addition, the ruling on which fuels would meet the GHG reduction threshold could change as empirical data are collected for some parameters that could influence GHG emissions.
As discussed in Chapter 5, GHG emissions from land-use changes globally due to market-mediated effects of U.S. biofuel production are highly uncertain. Although data on land-use changes collected over time can improve knowledge on effects of U.S. biofuel policies on land-use changes worldwide and the precision of life-cycle GHG accounting of biofuels, some uncertainties will always remain because of difficulties in establishing a cause-and-effect relationship between biofuel production and land-use changes from market-mediated effects. Because GHG emissions from land-use changes could span a wide range depending on the actual extent of land-use changes (see Table 5-2 in Chapter 5), investors could not be certain that the biofuels that they plan to produce would meet the GHG reduction threshold set by RFS2. However, GHG emissions in some parts of the biofuel supply chain could decrease as feedstock production and conversion technologies improve.
Air and Water-Quality Effects from Biorefineries
Biorefineries are required to meet the standards of the federal Clean Air Act and the Clean Water Act to obtain permits to operate the facilities. Based on the water and air-quality effects from biorefineries and the environmental impact assessments of planned cellulosic biofuel refineries discussed in Chapter 5, the committee judges that the ability of individual refineries to meet the standards set by those laws is not likely to pose a technical barrier to achieving RFS2. However, in regions that are noncompliant with ambient air-quality standards established by the Clean Air Act, permit requirements can limit the establishment of biorefineries through increased cost for permits and control equipment, delays in the permit process, or outright prohibition. For projects receiving federal funding, a Department of Energy (DOE) Finding and Environmental Assessment would have to be conducted to establish that there will be no adverse impacts with respect to sound, traffic, air quality, water quality, or threatened or endangered species before permits are issued (VeroNews, 2010). (See also section “Regional and Local Environmental Assessments” in Chapter 5.) For example, the central valley of California, where large amounts of biomass are available from agriculture, MSW, and nearby forests, has emission requirements and mandates for Best Available Control Technology that in practice severely limit the capacity to site new industrial facilities (Orta et al., 2010). Fines for water and air-quality permit violations at existing biofuel facilities are relatively commonplace (Beeman, 2007; Smith, 2008; EPA, 2009; Buntjer, 2010; Meersman, 2010; O’Sullivan, 2010). Iowa alone had 394 instances of violations at biofuel facilities during the period 2001-2007 (Beeman, 2007).
There is an additional concern that the industry as a whole could cause a detrimental cumulative impact in large watersheds (Chapter 5). Dominguez-Faus et al. (2009) discussed the possibility that the biofuel industry could be limited by concerns of water quality in high-priority areas such as the Chesapeake Bay or the Mississippi River Basin (Gulf hypoxia) and could cause water shortages in places like the High Plains Aquifer (Ogallala).
Water Use for Irrigating Feedstock and in Biorefineries
Water scarcity in particular regions of the United States could limit the quantity of feedstock that could be grown and the total number of biorefineries that could be built. Although irrigation of bioenergy feedstock in some regions can substantially improve yield (Chapter 2), irrigation is a key factor in determining consumptive water use (Chapter 5).
As an example, the Republican River Basin loses water as it flows through Colorado, Nebraska, and Kansas. Its flow is connected to the Ogallala Aquifer, and the Republican River is subject to drought (UNL, 2011b). As the Ogallala Aquifer loses water (hydraulic head) due to irrigation demands for more corn, the Republican River also becomes at risk to more drought. According to the University of Nebraska water website, “Irrigation development has caused declines of groundwater levels (depth to groundwater from the soil surface) in some areas of the state. The most severely affected areas are the Box Butte area, western end of the Republican River Basin and parts of the Blue River Basin” (UNL, 2011a).
The environmental impact assessments of some of the planned cellulosic refineries discussed in Chapter 5 suggested that biofuel production in those specific facilities would not affect water availability. For example, the Abengoa facility passed the DOE’s environmental impact assessment of cumulative impacts on water and groundwater resources, but Abengoa passed because of favorable groundwater availability in that portion of southwest Kansas where the facility is located, a situation that does not exist throughout the state. However, as more biorefineries are built, water availability and consumptive water use would have to be considered locally and regionally to ensure that the water resources will be sustained. A determination of cumulative impact on groundwater availability could be a barrier for future expansion of the industry (Meersman, 2008), but that has yet to be done.
Fuel Certification Requirements
Section 211(f)(1)(A) of the Clean Air Act states, “Effective upon March 31, 1977, it shall be unlawful for any manufacturer of any fuel or fuel additive to first introduce into commerce, or to increase the concentration in use of, any fuel or fuel additive for general use in light duty motor vehicles manufactured after model year 1974 which is not substantially similar to any fuel or fuel additive utilized in the certification of any model year 1975, or subsequent model year, vehicle or engine under section 206” (108 P.L. 201).
EPA regulations prohibit the addition to gasoline of any component that has not been approved for use in gasoline. Ethanol and other aliphatic alcohols and ethers (except methanol) use is approved up to the current blend wall (2.7-percent oxygen by weight). Total oxygen content of fuels that do not contain ethanol or other aliphatic alcohols and ethers can only be 2 percent by weight. Many states have banned the use of methyl tertiary butyl ether (MTBE) or ethyl tertiary butyl ether (ETBE) in gasoline, leaving ethanol as the only commercially available oxygenate for gasoline blending. EPA certification is required before other “new” biofuels, such as those produced by gasification and Fischer-Tropsch or pyrolysis, can become part of the gasoline pool.
This certification is a two-tier system. If the new material is “substantially similar” to gasoline (that is, contains only hydrocarbons and aliphatic alcohols and ethers) or will only be blended at less than 0.25 percent by weight of any fuel batch, then the blender can petition EPA to approve its use based on limited testing (Tier 1 testing). If the potential fuel is not “substantially similar” to current gasoline, then extensive vehicle-based emissions testing is required for approval (Tier 2 testing). EPA has up to 270 days to approve or deny the waiver request. If EPA does not act within 270 days, the waiver is deemed to be granted.
Tier 1 testing requires about 50 gallons for the new material and the cost of producing and testing the fuel can exceed $1 million (NBB, 1998; Scoll and Guerrero, 2006). Tier 2 testing is much more extensive and can take up to a year to complete and cost several million dollars. Larger volumes of fuel are also required. As of 2011, EPA has not determined what level of testing will be required to certify gasification and Fischer-Tropsch fuels, pyrolysis oils, or any other new biofuel for use in gasoline.
In addition to EPA certification for gasoline, ASTM sets fuel property standards that have to be met for any material to be called gasoline, jet fuel, or diesel fuel. These standards currently incorporate the EPA regulations for fuels as well as other performance and marketability standards. The jet fuel standard currently only allows the use of biofuel components that are produced as synthetic paraffinic kerosene at less than 50 percent of the total fuel. The diesel fuel standard currently recognizes and controls the use of fatty acid methyl ester biodiesel, but is silent on other potential blend components as long as their use still allows the blended fuel to meet all other current standards.
Barriers to achieving RFS2 include social factors that deter producers from growing or harvesting bioenergy feedstocks and that deter consumers from purchasing biofuels. This section is divided into research that investigates barriers faced by farmers and land managers and research that investigates barriers to consumer acceptance and use of biofuels.
Knowledge, Attitudes, and Values of Farmers and Forest Owners
Barriers that farmers and nonindustrial private forest (NIPF) owners face in entering biofuel markets include the lack of information about emerging opportunities to grow and harvest bioenergy feedstocks, logistical barriers to harvesting and transporting bioenergy feedstocks, cultural barriers to introducing new crops into a monoculture landscape, the lack of sufficient economic incentives, and uncertainty around the duration of incentives and policies to support production and harvesting of bioenergy feedstocks. Sociologists and economists have long studied what compels farmers to adopt an innovation, such as a new crop or new technology, and how that innovation spreads or is “diffused” into the broader community. The adoption and diffusion model (Rogers, 2003) attempted to predict the adoption behavior of farmers on the basis of their personal characteristics (education, personality, age, income), the time factor, and the nature of the innovation itself. According to the adoption and diffusion model, innovators are those who are willing to take risks on new crops or new technology; innovators were often found to be independent and not as tightly integrated with their community. Early adopters of the innovation were found to be more integrated in their communities and, because they are often in leadership positions, they help to diffuse the innovation for the late adopters (Rogers, 2003). Adoption and diffusion researchers were also interested in the role that information played in farmer adoption and diffusion behavior—that is, how the type of information and from whom it is received
might affect adoption. The adoption and diffusion model has been subsequently criticized for overemphasizing the personal characteristics of the farmer to the neglect of the role of the broader structural, economic, and institutional environment shaping farming decisions, including the policy environment (Buttel et al., 1990).
Economists (Griliches, 1957) have also investigated the economic processes underlying the diffusion of technological innovations such as the spread of hybrid corn. Griliches’ foundational research demonstrated that the adoption of new technologies, such as hybrid corn, was not a single event, but was instead a series of developments that occurred at different rates across geographical space over a 20-year time frame (Griliches, 1957). His study shed light on the numerous individual decisions and economic calculations that drove new hybrid corn technology forward, demonstrating that the analysis of spatial patterns in the diffusion of innovation can provide important clues to understanding economic processes. The economics of innovation continues to be an important topic within the fields of economics, business, and the sociology of science.
Economists and other social scientists have begun to research some of the barriers faced by farmers and NIPF owners to entering biofuel markets. A recent study examined factors associated with the potential adoption of Miscanthus (a dedicated bioenergy crop) among farmers in Illinois (Villamil et al., 2008). The study concluded that information plays a key role in farmers’ consideration of adoption of such a new crop as Miscanthus. Researchers found that farmers had different information needs and preferred methods of receiving information when considering adopting Miscanthus in different regions of the state. Those farmers with the highest potential for adopting Miscanthus were most interested in information related to the agronomy and markets for Miscanthus. They preferred to receive the information from farm and agricultural organizations, as opposed to from other farmers.
Another study assessed the willingness of Tennessee farmers to grow switchgrass as an energy crop and the share of their farmland they would be willing to devote to switchgrass (Jensen et al., 2007). Findings showed that only 21 percent of 3,244 farmers who responded to a survey had ever heard of growing switchgrass as a bioenergy crop. About 30 percent said they would be interested in growing switchgrass while 47 percent said they were unsure or did not know if they would be interested. Farmers who had greater off-farm income, higher education levels, and were younger were more willing to convert some of their land to switchgrass production. Farmers with higher net farm income per hectare were less likely to convert a large amount of land, indicating the opportunity cost of planting switchgrass (Jensen et al., 2007). In addition to economic uncertainties, Jensen et al.’s (2007) study indicates the importance of considering farm characteristics and other demographic factors in farmer willingness to enter new markets and grow new crops.
In another study, Song et al. (2009) estimated that the minimum acceptable net return to induce conversion from an annual corn-soybean rotation to a perennial switchgrass crop to be much higher than the risk-free comparative breakeven net return. The reluctance to convert land from traditional row crops to a switchgrass crop was projected to be hindered by the volatility of biofuel prices and the costly reversibility of investment in a switchgrass crop (Song et al., 2009).
Other research investigated the cultural context of introducing different perennial crops (including dedicated bioenergy crops) into the Corn Belt agricultural landscape (Atwell et al., 2009, 2011). The study’s rationale was that stakeholder involvement is critical if dedicated bioenergy crops are to be planted on a large scale and that stakeholders’ landscape values can affect their decision to plant those crops. Previous research has shown that farm diversification and landscape heterogeneity often are not the cultural norms that define
how a well-operated farm would look (Nassauer, 1989; Napier et al., 2000). Atwell et al. (2009) found that most farmers and other stakeholders approved of growing dedicated bioenergy crops, but implementation of these practices was not a priority. They concluded that a shift in community norms about landscapes would be necessary to increase planting of dedicated bioenergy crops.
In a study of the intentions of farmers in the United Kingdom toward producing bioenergy crops for biofuel, Mattison and Norris (2007) surveyed 278 farmers about their interest in growing two bioenergy crops. They found that farmers had positive attitudes toward growing bioenergy crops, but obstacles noted by farmers were inadequate policies to encourage crop production and a lack of infrastructure for biomass processing.
Another study was undertaken with farmers and rural stakeholders in southern Iowa and northeastern Kentucky in 2006 and 2008 (Rossi and Hinrichs, 2011). In-depth interviews were conducted with 48 independent small farmers and stakeholders in two switchgrass bioenergy projects and revealed that farmers were skeptical that switchgrass bioeconomy would bring tangible economic benefits. Their experiences with the switchgrass projects indicated that there were many technological, economic, and logistical barriers yet to be overcome before the biofuel industry could develop further. Although many participants expressed enthusiasm about the potential of cellulosic ethanol to contribute to energy security and rural economic revitalization, they were skeptical that it was economically feasible. In addition to economic uncertainty, some farmers in these studies lacked knowledge and information about growing bioenergy feedstocks and some had concerns about inconsistent policy incentives for producing feedstock for biofuels, and norms and values toward the landscape. All of these factors have been shown to deter farmers from growing or harvesting bioenergy feedstock for biofuels.
Lack of reliable and steady supply of forest resources from NIPFs could be a barrier to achieving RFS. As discussed in Chapter 2, cellulosic biofuels made from feedstock from federal forests is not to be counted toward meeting RFS2. Given that the majority of timber harvested each year has come from NIPFs for the past 50 years (Adams et al., 2006), woody resources for cellulosic biofuel production will likely come from NIPFs. Yet, a large percentage of forest landowners were uncertain or unfamiliar with the idea of producing energy from woody biomass (Joshi and Mehmood, 2011). In particular older landowners, who were about one-quarter of survey respondents, were more uncertain and skeptical about wood-based bioenergy.
NIPFs might not be a reliable year-round source of forest resources for several reasons. First, not all NIPF owners are harvesters or active managers. Most often, owners of large-parcel NIPFs appear most likely to be harvesters or active managers of their forestland (Bliss et al., 1997; Johnson et al., 1997; Best, 2004), are better informed about forest management, and are more receptive to outreach programs administered by forest agencies or university extension programs (Kuhns et al., 1998). Second, many NIPF owners describe nonharvesting objectives, such as aesthetic enjoyment, as their primary reasons for forest ownership (Creighton et al., 2002; Kendra and Hull, 2005; Kilgore et al., 2008). A survey of 4,800 NIPF owners in Arkansas, Florida, and Virginia found similar results (Joshi and Mehmood, 2011). Although timber harvesting is a frequent activity of NIPF owners (Birch, 1994; Butler, 2008), the majority of harvesting activity is for personal, noncommercial uses, such as firewood. Few NIPF owners partake in harvesting for economic gain (Birch, 1994; Butler and Leatherberry, 2004). Third, many NIPF owners make timber harvesting decisions based on short-term financial needs rather than long-term management planning. Thus, uncertainty about the harvesting behavior of NIPF owners will create a barrier to
development of a reliable year-round supply of woody resources for cellulosic biofuel. That challenge is already faced by saw and paper mills across the United States.
Consumer Knowledge, Attitudes, and Values about Biofuels
Although some scientists in many countries have positive views of the potential for biofuels and bioenergy, research has shown that these positive views are not always shared by the public (McCormick, 2010). Renewable energy is often viewed favorably by the public, but research shows that often the public is not well informed about biofuels and bioenergy and does not think of biofuels as a form of renewable energy (Rohracher, 2010). Researchers found that this may be related to confusion over the terminology related to bioenergy because of the variety of feedstocks, conversion technologies, products, and markets involved (McCormick, 2010).
Previous research on public opinions on biofuels explored the social and psychological dimensions that shape thinking and behavior toward biofuels (Wegener and Kelly, 2008). In a telephone survey of 1,049 randomly sampled U.S. citizens, researchers found that participants generally had a favorable, but not strong, attitude toward the use of biofuels. Among the participants, 24 percent said they were not well informed about biofuels, such as ethanol. Seventy-one percent were not at all informed about the use of switchgrass to produce ethanol. Only 5 percent identified biofuels as a source of renewable energy. These results suggest that obstacles to public acceptance and adoption of biofuels among the public include a lack of knowledge and experience with biofuels and that policies need to consider the social factors that shape public acceptance and consumer behavior change.
In the U.S. Corn Belt, Delshad et al. (2010) explored public attitudes and knowledge toward biofuel policies and technology. Their findings showed that participants were much more knowledgeable about biofuel technologies than about the policies related to biofuels. Participants were opposed to expanded corn-grain ethanol production because of concerns about rising food prices and environmental impacts of corn-grain ethanol. Research in the Upper Midwest examined consumers’ knowledge about climate change and how this knowledge affects their “willingness to pay” more for cellulosic ethanol derived from farm residues, forest residues, and mill waste and municipal waste (Johnson et al., 2011). Findings showed that knowledge about climate change was linked to consumers’ willingness to pay more for biofuels, but that consumers only made minor differentiation between sources of biomass in terms of their preferences. Therefore, consumers’ attitudes are likely to be a lesser barrier than economics in achieving the RFS2 mandate.
Information and Outreach
As noted above, the lack of information and outreach to farmers and NIPF owners about the emerging energy markets were identified as barriers to the production of biomass for energy. In addition, more information about the price of biomass, the potential environmental and employment benefits, and other opportunities related to biomass production are considered to be important factors in providing incentives for more forest and farm landowners to enter these markets (Joshi and Mehmood, 2011). In addition, there is a recognized need for more education and communication to improve public awareness and acceptance of biofuels (Zoellner et al., 2008; Peck et al., 2009; McCormick, 2010). International efforts have been launched to provide the public with information about biofuels, including initiatives such as the World Bioenergy Association, the Global Sustainable Bioenergy Project, the Global Bioenergy Partnership, the Roundtable on Sustainable Bioenergy,
and Bioenergy Promotion. Several educational websites on biomass and bioenergy are currently in development, such as the website developed by the International Energy Agency (IEA, 2011).
Because cellulosic biofuel is a developing industry, there are multiple economic, policy, environmental, and social barriers to producing 16-20 billion gallons of ethanol-equivalent advanced and cellulosic biofuels to meet the consumption mandate of RFS2. Resolving most of the barriers is necessary to achieving RFS2, and many of them are interrelated as illustrated by the examples below.
A key barrier to achieving RFS2 is the high cost of producing biofuels compared to petroleum-based fuels and the large capital investments required to put billions of gallons of production capacity in place. As of 2010, biofuel production was contingent on subsidies, tax credits, the import tariff, loan guarantees, RFS2, and similar policies. These policies that provide financial support for biofuels will expire long before 2022 and cannot provide the support necessary for achieving the RFS2 mandate. Uncertainties in policies can affect investors’ confidence and discourage investment. In addition, if the cellulosic biofuel produced are mostly ethanol, investments in distribution infrastructure and flex-fuel vehicles would have to be made for such large quantities of ethanol to be consumed in the United States. Given the current blend limit of up to 15-percent ethanol in gasoline, a maximum of 19 billion gallons of ethanol can be consumed unless the number of flex-fuel vehicles increases substantially. However, consumers’ willingness to purchase flex-fuel vehicles and use E85 instead of lower blends of ethanol in their vehicles will likely depend on the price of ethanol and their attitude toward biofuels. Producing drop-in biofuels could improve the ability to integrate the mandated volumes of biofuels into U.S. transportation, but would not improve the cost-competitiveness of biofuels with petroleum-based fuels.
Opportunities to reduce the cost of biofuels are to reduce the cost of bioenergy feedstock, which constitutes a large portion of operating costs, and increase the conversion efficiency from biomass to fuels. Research and development to improve the on-farm yield of bioenergy feedstocks through breeding and biotechnology and conversion efficiency in biorefineries would reduce the cost of biofuel production and potentially reduce the environmental effects per unit of biofuel produced. However, a cellulosic-biofuel market will not be realized if farmers and landowners are unaware of the market opportunities for bioenergy feedstocks or are unwilling to participate in that market. If competition for bioenergy feedstocks intensifies because of low supply, the price will likely increase. Given the numerous barriers outlined in this chapter, the committee judges that the consumption mandate for cellulosic biofuel is not likely to be met by 2022 without substantial improvement in technologies in the next few years and a stable economic and policy environment to encourage accelerated demonstration and deployment of cellulosic biofuel.
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