Impact of Renewable Fuels Standard/MTBE Provisions of S. 1766
Introduction
On December 20, 2001, Sen. Frank Murkowski, the Ranking Minority Member of the Senate Committee on Energy and Natural Resources, requested an analysis of selected portions of Senate Bill 1766 (S. 1766, the Energy Policy Act of 2002) and House Bill H.R. 4 (the Securing America’s Future Energy Act of 2001).1 This request was further refined in a follow-up letter of February 6, 2002.2 In response, the Energy Information Administration (EIA) has prepared a series of analyses showing the impacts of each of the selected provisions of the bills on energy supply, demand, and prices, macroeconomic variables where relevant, import dependence, and emissions. The analysis provided is based on the Annual Energy Outlook 20023 (AEO2002) midterm forecasts of energy supply, demand, and prices through 2020.
Because of the rapid delivery time requested by Sen. Murkowski, each requested component of the Senate and House bills was analyzed separately, that is, without analyzing the interactions among the various provisions. Because of the approach taken:
- The combined impact of the individual policies cannot be determined by simply adding the individual policy impacts together. For example, a provision establishing a renewable portfolio standard (RPS) for electricity production, and one that establishes a biodiesel program for transportation fuels, each increases the use of biomass. The simultaneous enactment of the two provisions would be likely to increase biomass costs because of the competition for land and other needed resources. The estimated fossil energy displaced would, therefore, be lower than the sum of the two individual policy impacts because of the higher resource costs. Stated another way, the impacts of multiple simultaneous policies are non-linear.
- Some policies will interact to increase the overall response while others may interact to mitigate the impacts of each other. For example, when two separate policies increase demand and, consequently, production of an advanced technology, the reductions in manufacturing costs expected from increased production are likely to be accelerated, making the technology even more attractive in later years. The total adoption of the advanced technology in this case could be greater than the sum of the parts.
In addition, some aspects of the bills cannot be modeled because of lack of specificity. For example, several provisions of the bill require the Department of Energy (DOE) to evaluate the desirability of setting standards for stand-by power and other electronic devices. Because the legislation does not state what the standards will be, EIA cannot quantitatively analyze them.
EIA’s projections are not statements of what will happen but what might happen, given known technologies, technological and demographic trends, and current laws and regulations. Thus, AEO2002 provides a policy-neutral Reference Case that can be used to analyze energy policy initiatives. EIA does not propose, advocate or speculate on future legislative or regulatory changes. Laws and regulations are assumed to remain as currently enacted or in force in the Reference Case; however, the impacts of emerging regulatory changes, when clearly defined, are reflected.
Models are simplified representations of reality because reality is complex. Projections are highly dependent on the data, methodologies, model structure and assumptions used to develop them. Because many of the events that shape energy markets are random and cannot be anticipated (including severe weather, technological breakthroughs, and geopolitical disruptions), energy market projections are subject to uncertainty. Further, future developments in technologies, demographics and resources cannot be foreseen with any degree of certainty. These uncertainties are addressed through analysis of alternative cases in the AEO2002.
Specifications of this Study
This paper addresses the Renewable Fuels Standard (RFS)/methyl tertiary butyl ether (MTBE) provisions of S. 1766. H.R. 4 contains no RFS/MTBE provisions. The “S. 1766” Case reflects provisions of S. 1766 including a renewable fuels standard (RFS) reaching five billion gallons by 2012, a complete phase-out of MTBE within four years,4 and the option for States to waive the oxygen requirement for reformulated gasoline (RFG). It reflects provisions for a cellulose ethanol credit, an allowance for merchant MTBE plants to convert to other uses, and accounts for biodiesel as a renewable fuel. This analysis does not include the provision for a credit program; due to a lack of specificity about the structure of the program. The following provisions were not modeled in this analysis due to time constraints: the reduction of the maximum distillation index to 1200, or the removal of the one pound per square inch waiver of the Reid vapor pressure (RVP) limit for ethanol blended conventional gasoline east of the Mississippi.
Senator Murkowski also requested analysis of a variation on the RFS/MTBE provisions in S. 1766 which assumes the same RFS requirements and a Federal waiver of the oxygen requirement on RFG, but requires no ban on MTBE. This case is referred to as the “RFS/No MTBE Ban” Case. In neither case are the regional impacts of the bill evaluated due to the timing of the request for the results. The reader should be aware that there will be seasonal and localized impacts that differ from those of this analysis, because this analysis is based on average annual values at the national level.
 |
Background
As a result of the Clean Air Act Amendments of 1990 (CAAA90), the year-round use of reformulated gasoline has been required in cities with the worst smog problems since 1995 (Figure 1). One of the requirements of RFG specified by CAAA90 is a 2-percent oxygen requirement, which is met by blending with “oxygenates” including MTBE and ethanol. MTBE is the oxygenate used in almost all RFG used outside of the Midwest. Ethanol is currently used in the Midwest as an oxygenate in RFG and as an octane booster and volume extender in conventional gasoline.
Several years ago, MTBE was detected in water supplies scattered throughout the country, but predominantly in areas using RFG. MTBE from RFG was apparently making its way through leaking pipelines and storage tanks into ground water. The discovery of MTBE in ground water touched off a debate about the use of MTBE in gasoline, and subsequently the oxygen requirement itself. Discussions of removing the oxygen requirement on RFG have often been linked to the concept of a renewable fuels standard that would assure a certain level of ethanol blending.
Legislation that would ban or restrict the use of MTBE in gasoline, between 2003 and 2004, has already been passed in 13 States: Arizona, California, Colorado, Connecticut, Iowa, Illinois, Kansas, Michigan, Minnesota, Nebraska, New York, South Dakota, and Washington. In addition, Maine has passed legislation that contains a goal of phasing-out MTBE. Of these States, only California, Connecticut, and New York currently rely on MTBE as an oxygenate for RFG. California petitioned the U.S. Environmental Protection Agency (EPA) to waive the Federal oxygen requirement for areas of the State required by CAAA90 to use RFG, but the waiver request was denied by EPA. California has its own formulation of gasoline outside of the Federally mandated areas that does not have an oxygen requirement. Since the EPA denied the waiver request, California officials have been considering postponement of the MTBE ban due to concerns about the availability and price of gasoline without MTBE. A recent report commissioned by the California Energy Commission (CEC) highlights the possibility of short-term supply shortfalls and associated price spikes if MTBE is banned without adequate lead-time.5
MTBE is an important blending component for RFG because it adds oxygen, extends the volume of the gasoline and boosts octane, all at the same time. In order to meet the 2 percent (by weight) oxygen requirement for Federal RFG, MTBE is blended into RFG at approximately 11 percent by volume, thus extending the volume of the gasoline. When MTBE is added to a gasoline blend stock, it has an important dilution effect, replacing undesirable compounds such as benzene, aromatics, and sulfur. The dilution effect is even more valuable in light of a ruling by the EPA that will require the sulfur content of gasoline to be reduced substantially by 2004, and by EPA’s Mobile Source Air Toxics (MSAT) regulatory program, which will maintain benzene at 1998-2000 levels on an individual refinery basis. In addition, MTBE is a valuable octane enhancer. Its high octane helps offset the Federal limitations on other high-octane components such as aromatics and benzene. If the use of MTBE is reduced or banned, refiners must find other measures to maintain the octane level of gasoline and still meet all Federal requirements.
Ethanol currently receives a Federal excise tax exemption of 53 cents per gallon, which is scheduled to decline to 52 cents in 2003, and 51 cents in 2005. Legal authority for the Federal tax exemption expires in 2007, but because this exemption has been renewed several times since it was initiated in 1978, the AEO2002 Reference Case assumes that the exemption will be extended at the 51-cent (nominal) level through 2020 and it is included in the cases presented in this report. Blending with ethanol, which is primarily produced from corn, is also encouraged by tax incentives in 17 States to help bolster agricultural markets. Some of the characteristics of ethanol have made it less attractive to refiners than MTBE as an oxygenate. Ethanol results in higher emissions of smog-forming volatile organic compounds (VOCs) than MTBE. Its higher volatility makes it more difficult to meet emissions standards, especially in the summertime when RFG must meet VOC emissions standards. To accommodate the use of ethanol, other gasoline components, such as pentane, which are highly volatile, must be removed from gasoline to balance the addition of ethanol.
In addition to being more volatile than MTBE, ethanol contains more oxygen. As a result, only about half as much ethanol is needed to produce the same oxygen level in RFG that is provided by MTBE. The volatility of ethanol discourages refiners from blending ethanol into RFG beyond the volume that is required to fulfill the oxygen requirement. The result is that the other half of the displaced MTBE volume must generally come from other petroleum-based gasoline components. Ethanol is slightly higher in octane than MTBE is, but because only one-half as much ethanol is blended, a net loss in octane occurs when ethanol is used to replace MTBE. Blending with ethanol also results in a slight increase in emissions of toxics, which must be compensated by other blending changes in order to comply with “antibacksliding” regulations under MSAT.
Summary of Results
All analysis in this report is compared to a Reference Case that reflects no State-level restrictions on MTBE. Legislation in 13 States that would restrict the use of MTBE in gasoline between 2003 and 2004, included in the AEO2002 Reference Case, was excluded from this analysis to evaluate the impact of the requested cases in relation to the current market. In the S. 1766 Case, all changes from the Reference Case can be attributed to provisions of S. 1766, and in the RFS/No MTBE Ban Case, changes can be solely attributed to the RFS.
 Figure Data |
Both the S. 1766 and the RFS/No MTBE Ban Cases reflect the RFS requirement specified in Section 818 of S. 1766, after an adjustment for a 1.5 gallon credit for every gallon of cellulose (biomass) ethanol. The RFS schedule requires 2.0 billion gallons of renewable fuels by 2003, increasing to 5.0 billion gallons by 2012. S. 1766 does not specify RFS targets after 2012, but requires renewable fuels to maintain the same percentage of transportation fuels that was achieved in 2012. Given the volume of cellulose-based ethanol that could be produced, the credit for cellulose ethanol would reduce the amount of renewable fuels required in the RFS schedule by about 10 million gallons in 2003 growing to 130 million gallons by 2012, and about 370 million gallons by 2020 (Figure 2). S. 1766 includes a provision that would ban MTBE nationally within four years of passage and is assumed to occur in 2006. Ethanol blending is projected to increase significantly as a result of the MTBE ban, exceeding the 2006 RFS target by more than 1 billion gallons. The gap between ethanol blending and the RFS targets specified in S. 1766 disappears by 2010 due to increasing RFS targets. Beginning in 2010, the level of ethanol blending is effectively determined predominantly by the RFS schedule (adjusted for the cellulose credit) rather than the assumed MTBE ban. In the RFS/No MTBE Ban Case, the level of ethanol blending is effectively set by the adjusted RFS in all years because no Federal MTBE ban, requiring increased ethanol blending requirements, is assumed.
The S. 1766 Case is projected to result in U.S. annual average gasoline prices that are about 4 cents per gallon (real 2000 dollars) higher, and average RFG prices that are between 9.0 and 10.5 cents per gallon higher than the Reference Case, after the MTBE ban in 2006. The higher prices reflect the loss of volume, oxygen, and octane associated with the MTBE ban. Ethanol can only partially compensate for these blending qualities and is more expensive to use than MTBE. There is a greater price impact in areas of the country required to use RFG than for areas that can use conventional gasoline. The RFS/No MTBE Ban Case is projected to result in average national prices that are up to one-half cent per gallon higher for all gasoline, and up to one cent per gallon higher for RFG, compared to the Reference Case. The price impact of the RFS/No MTBE Ban Case is mitigated by the shift of ethanol blending into conventional gasoline and away from RFG blending. The S. 1766 price differentials are higher than those in the RFS/No MTBE Ban Case because the MTBE ban requires more ethanol blending into RFG to partially offset the loss of MTBE which is relatively less expensive. In the RFS/No MTBE Case additional ethanol for RFG blending is not required, and the RFS standard can be met by blending ethanol into conventional gasoline.
These cases only assess changes in the average annual prices of gasoline at the national level and do not analyze any localized or seasonal price changes that could result from such policy changes, which would likely result in some higher price differentials. In addition, investment decisions are assume perfect foresight and adequate lead times for implementing policy changes. Also, any further legislation that would change gasoline requirements on a State-by-State basis would serve to further fragment the gasoline market and could increase the likelihood of localized price volatility.
The higher gasoline prices projected in the S. 1766 Case translate into a higher annual cost to consumers of $6.37 billion on average between 2006 and 2020, compared to the Reference Case. By comparison, the RFS/No MTBE Ban Case is associated with a higher annual consumer cost of $281 million for the same time period. In addition to the impact on consumers, the additional ethanol consumption would impact tax revenues collected by the Federal government due to the tax exemption provided to ethanol-blended gasoline. Due to the increased use of ethanol, EIA estimates that S. 1766 would result in lower annual excise tax collections of $892 million on average between 2006 and 2020 for the S. 1766 Case, and $814 million for the RFS/No MTBE Ban Case, compared to Reference Case tax collections.
Methodology
This analysis was performed using the Petroleum Market Module (PMM) of the National Energy Modeling System (NEMS). 6 The PMM represents domestic refinery operations and the marketing of petroleum products to consumption regions. PMM solves for petroleum product prices, crude oil and product import activity (in conjunction with the international energy module and the oil and gas supply module), and domestic refinery capacity expansion and fuel consumption. PMM is a regional, linear programming representation of the U.S. petroleum market. Refining operations are represented by a three-region linear programming formulation of the five Petroleum Administration for Defense Districts (PADDs). PADDs I (East Coast) and V (West Coast) are each treated as single regions, while PADDs II (Midwest), III (Gulf Coast), and IV (Rocky Mountains) are aggregated into one region. Each region is considered as a single firm for which more than 80 distinct refinery processes are modeled. Refining capacity is allowed to expand in each region over each non-overlapping 3-year period. That is, in 2002 the model looks ahead to 2005 to determine how much new capacity is required and then allows additions of new capacity in 2003, 2004, and 2005. The capacity planning decisions begin anew for 2008 at the end of 2005. As a result, cumulative investment for any given year includes investment to meet future expectations of market demand. Investment decisions are based on an assumed return on investment (ROI) of 10 percent with a 10 percent hurdle rate.7
In the model, products are produced to annual average specifications and demands with calibrations to account for non-linear blending qualities such as Reid Vapor Pressure (RVP) in motor gasoline. The PMM models EPA’s complex model requirements for Phase II RFG through specification constraints on aromatics, benzene, sulfur, RVP, E200, E300, olefins, and oxygen content. The specification constraints conform to EPA’s complex model requirements for emissions reductions of VOCs, NOx, and toxics but do not determine these specifications as a model solution.
The “Tier 2” regulation that requires the nationwide phase-in of gasoline with a 30 parts per million (ppm) annual average sulfur content (less than 10 percent of the 1999 pool average) between 2004 and 2007, and the regulation requiring ultra-low-sulfur diesel for on-road use beginning in 2006, are both explicitly modeled.8
Revisions to the Petroleum Market Module for this Analysis
Revised AEO2002 Reference Case
The AEO2002 Reference Case reflects legislation in 13 States that would limit the use of MTBE between 2003 and 2004. The actual timing and implementation of these State restrictions are highly uncertain (see Background) and their inclusion in the Reference Case effectively obscures the impact of the requested scenarios relative to the current market. In order to analyze the impact of the S. 1766 Case and the RFS/No MTBE Ban Case more clearly, a revised Reference Case excluding State-level MTBE restrictions was developed for the purpose of this report. The Reference Case in this study is consistent with H.R. 4, which has no RFS or MTBE ban provisions.
Conversion of MTBE Production
Refineries and petrochemical plants in the United States have at least 242,000 barrels per day of MTBE production capacity that would become inoperable if MTBE is banned. 9 The loss of these assets may be minimized if they can be economically converted to other applications such as ethyl tertiary butyl ether (ETBE), iso-octane, or alkylate production. Conversion to ETBE production is assumed to be infeasible because, like MTBE, it is an ether and because it shares many of the same properties as MTBE, may be subject to similar bans.10 Along with ethanol, iso-octane and alkylate may serve to offset some of the lost volume and fuel properties associated with the loss of MTBE in the gasoline pool.
The economics of MTBE unit conversion is highly uncertain and would vary from plan-to-plant depending on many market and regulatory conditions, including, the passage of an RFS, and the extent and location of MTBE bans in the United States. Issues related to MTBE conversion are discussed in greater detail below.
MTBE is typically produced by reacting isobutylene with methanol. It has relatively low vapor pressure compared to ethanol, which helps minimize hydrocarbon vapor losses into the atmosphere. Atmospheric hydrocarbons in the presence of nitrogen oxides and sunlight are believed to form ozone through a sequence of complex chemical reactions.
MTBE is produced in three kinds of plants: refineries, petrochemical plants, and on-purpose plants. The latter two are typically called “merchant plants.” On-purpose merchant plants purchase their feedstocks and then react them to produce a saleable commodity. If MTBE is banned, it is unlikely that these plants will find it economical to convert to iso-octane production, because the cost of the inputs (isobutylene and isobutene) is higher than the value of the output (iso-octane). Discussions with producers indicate that even a direct subsidy would probably not induce on-purpose MTBE producers to convert.
Petrochemical plants produce MTBE as a byproduct of another process, such as production of styrene monomer. In this case, conversion of an MTBE plant to iso-octane will depend on the relative economics of the companion process. It might be worthwhile for a petrochemical plant to accept a grant to convert to iso-octane, in order to support its other line of business.
If MTBE is banned, refineries would be more likely to convert an MTBE unit to an isooctane unit or send the butane now being used to produce MTBE to an existing or expanded alkylation.
If MTBE is banned, MTBE producers would also have the option of exporting their product, since it will continue to be used abroad. But U.S. producers have a competitive disadvantage. They tend to have higher feedstock costs, and risk creating a world surplus and driving down prices. The on-purpose plants and petrochemical plants would likely be squeezed out of the export market before refiners with excess MTBE capacity.
The decision to convert to either iso-octane or alkylate production would depend on individual plant economics. This analysis reflects the ability of MTBE producers to convert to iso-octane, and to divert butane to existing alkylation units. In addition to the capital and operating cost of MTBE unit conversion to iso-octane, an allowance of $250 million for merchant plant conversion was included, reflecting the provisions of Section 828 of S. 1766. However, this analysis results in conversion of only the refinery MTBE units because the projected feedstock costs of the on-purpose units makes conversion uneconomic. The PMM includes no representation of petrochemical MTBE plants, and therefore can give no indication of the behavior of this type of merchant plant. The ability to convert MTBE production to iso-octane is expected to slightly reduce the cost of gasoline production.
Credit for Cellulose Ethanol
Ethanol from corn is currently the most established renewable fuel. It is blended into gasoline to add oxygenate, octane, and volume. The problem is that it is fairly costly to produce. The technology for producing ethanol from corn is mature, so it is unlikely that production cost can be reduced significantly. Attempts to drastically expand corn ethanol output would require more corn to be grown, placing further pressure on costs.
Because of these limitations to the use of corn for ethanol production, there are ongoing experiments to find other feedstocks for ethanol production. Ethanol is the product of fermentation of sugars by yeast. Corn grain contains sugars and starches which may be converted into sugars by enzymes. Wood products, grasses, and agricultural wastes (biomass) contain little starch or sugar but much cellulose. The cellulose can be converted to sugars by treatment with acid or with enzymes. Reduction in the cost of converting cellulose to sugars has been a major focus of various research efforts. Cellulose ethanol production is modeled in NEMS.
To encourage further cellulose ethanol production, Section 818 of S. 1766 credits every gallon of ethanol produced from cellulose (biomass) as 1.5 gallons of renewable fuel. In order to reflect this provision, an adjustment was made to the accounting of biomass ethanol in the PMM. The result of this biomass ethanol credit is a projected renewable fuels level that is somewhat lower than the RFS schedule specified in Section 818 of the Bill. The split between biomass and corn-based ethanol is determined based on the relative economics of the two feedstocks.
Biodiesel as Part of the RFS
Biodiesel is a fuel for compression-ignition, or diesel, engines that is produced from vegetable oil or animal fat. Because the RFS specified in S. 1766 includes biodiesel in addition to ethanol, a representation of biodiesel was added to the PMM for this analysis. As a result, the amount of ethanol required to fulfill the RFS is reduced by the amount of biodiesel that penetrates the market.
In addition to its status as a renewable fuel, the incentives for biodiesel consumption are the credits it generates under the Energy Policy Act of 1992 (EPAct) for State and Federal Governments,11 its value as a lubricity additive, and its lower particulate emissions. If only the consumption likely to be spurred by EPAct were considered, biodiesel consumption would probably reach 7.3 million gallons in 2020. If biodiesel is able to capture a large share of the market because of its value as a blending additive for improved lubricity, consumption may reach about 630 million gallons in 2020.12
EIA estimated the total cost of soybean diesel based on information from other sources.
The National Renewable Energy Laboratory (NREL) provided estimates of biodiesel production costs assuming a plant of 10 million gallons of output per year fed by soybean oil.13The NREL estimates are based on the technology of methyl alcohol and oil reaction catalyzed by sodium hydroxide. The plant was estimated to cost $1 per annual gallon of capacity, or $10 million total capital costs (in current dollars), with operating expenses of $0.20 per gallon, excluding the cost of the soybean oil. Biodiesel production yields coproduct fatty acids and glycerol. The sale of the fatty acids yields a credit of $0.002 per gallon of biodiesel, and the sale of the glycerol yields a credit of $0.15 per gallon of biodiesel. Using Urbanchuk’s projection of a soybean oil feedstock cost of $1.49 per gallon of biodiesel,14the average variable cost of soybean biodiesel today is thus $0.20+$1.49-$0.002-$0.15=$1.538 per gallon. The plant is assumed to be financed by equity with an annualized return of 15 percent, and a 20-year plant life. Treating the hypothetical income stream as an annuity over the 20 years, the estimated capital cost is $1.6 million per year, or $0.16 per gallon at full output. Total cost of soybean biodiesel is therefore $1.538+$0.16=$1.698 per gallon at plant output of 10 million gallons per year. This is the plant gate price of biodiesel that pays investors their desired return. If the expected price is at least $1.698 then biodiesel capacity can be expected to expand.
Soybean oil is not the only possible feedstock. According to NREL, “ Biodiesel can be produced from recycled restaurant greases called yellow grease. Approximately 13 million gallons of domestic production capacity, or a little more than 50 percent of U.S. biodiesel capacity, can use yellow grease. The average variable cost of producing biodiesel from yellow grease, assuming approximately 1.5 cents per gallon higher operating costs, is equal to $0.613 per gallon. Yellow grease currently sells for 7 cents per pound or $0.54 per gallon of feedstock. The total cost of producing yellow grease biodiesel, including capital, would be $0.773 per gallon. Since more than half of the U.S. biodiesel capacity is capable of producing yellow grease biodiesel, long term reductions in biodiesel costs appear to be promising .”15 The drawback is that yellow grease biodiesel has poorer cold flow properties than soybean biodiesel.16
An adjusted Reference Case was produced for this analysis because AEO2002 did not include projections for biodiesel. The adjusted Reference Case and the scenarios provided in this analysis reflect EIA’s estimate of a lower bound for biodiesel demand based on an assessment of potential fleet demand for biodiesel to comply with EPAct. The Act requires that a fraction of new light vehicle purchases for qualified fleets be alternatively fueled vehicles (AFV’s). Light vehicles for EPAct purposes have Gross Vehicle Weight Rating (GVWR) less than or equal to 8500 lbs. Federal, State, and alternative fuel providers' vehicles that are capable of being fueled at central locations are qualified fleets. Law enforcement, emergency, and military vehicles are excluded from qualification. The Federal and State Government AFV requirement is 75 percent; alternative fuel providers' AFV requirement is 90 percent. In lieu of an AFV purchase, a fleet operator may purchase 450 gallons of pure biodiesel for use in a vehicle with GVWR over 8,500 lbs. The fleet operator may offset up to half the number of required AFV purchases with biodiesel purchases. Approximately 32,000 new fleet vehicle purchases were covered under EPAct in 2001.17 Since alternative fuel provider purchases are aggregated with Government purchases, the 75 percent requirement was applied uniformly. The number of vehicle purchases covered under EPAct was assumed to grow at the same rate as that projected for the light vehicle stock in AEO2002. Every qualified fleet is assumed to use biodiesel purchases to offset half the AFV requirement. Thus, biodiesel demand under EPAct would reach 6.5 million gallons in 2010 and 7.3 million gallons in 2020.
Although not reflected in the scenarios presented in this report, EIA also developed upper bound estimates of the demand for biodiesel as a lubricity additive. As mentioned in Appendix B, low sulfur diesel fuel marketed in the United States has lubricity problems. The move to ultra-low-sulfur diesel is expected to make the problem worse. The upper bound estimates assume that biodiesel is blended into ultra-low-sulfur diesel at one percent by volume to improve lubricity. This yields 470 million gallons of biodiesel in 2010 and 630 million gallons in 2020. Sensitivity analysis of the higher biodiesel penetration rate indicated no significant impact on gasoline prices, but served to reduce ethanol requirements to meet RFS by the higher amount.