Biofuels and Greenhouse Gas Emissions on a Collision Course
AgMRC Renewable Energy Newsletter
Dr. Robert Wisner
Ag Marketing Resource Center
Iowa state University
The Energy Independence and Security Act (EISA) of 2007 (1) requires a gradual increase in the volume of various kinds of biofuels to be blended with U.S. motor fuels in the next several years. The gradual increase was designed to provide time for technology development and industry growth. At the same time, the EISA – unless modified – requires a one-step adjustment in greenhouse gas (GHG) reductions, rather than a gradual phase-in to reflect less than instantaneous technological progress. The EISA also implicitly assumes that greenhouse gas (GHG) emissions from the baseline that is used to evaluate biofuels will be unchanged in the future. It is debatable whether that assumption is valid.
These two different sets of mandates are now on a collision course. If changes are not made, their different paths could slow or halt the growth of some parts of the biofuels industry. The sectors of the industry to be most immediately affected are Midwest corn-starch ethanol and biodiesel from vegetable oils. As regulatory activity on the GHG issues has progressed, two different government agencies have become involved. One is the U.S. Environmental Protection Agency (EPA), which has recently announced proposed national assessments on GHG emissions. The other is the Air Resources Board of the California Environmental Protection Agency. California has decided to move ahead more quickly than at the national level in establishing regulations to reduce GHG emissions and has developed assessments of GHG emissions for several different kinds of biofuels.
The proposed California regulations take on added significance when the biofuels industry considers that (1) California is the largest potential market in the U.S. for biofuels and (2) at least 13 other states are considering adoption of its standards. President Obama has expressed a desire for a uniform national standard relating to GHG emissions. That raises the possibility that California’s standards could become the U.S. standards. A key issue in both the California and EPA GHG assessments of biofuels is the impact of “indirect land use emissions impacts”.
Indirect land use stems from the presumption that when an acre of land is diverted from production for feed and food to biofuels, that at least a portion of that acre will to be added to food and feed production somewhere else, either in the U.S. or abroad. It is assumed that additional cropland will be needed and that it is most likely to come from diversion of rainforest or pasture in tropical areas to food and feed production. In some cases, if there is an indirect land use impact, it could come from conversion of pasture, forage, or conservation reserve land in the U.S. to cropland. Thus, the indirect land use measurement represents the estimated net change in GHG emissions or CO2 sequestering done by the change in land use somewhere else in the world.
The amount of indirect land use change needed for biofuels and ways of measuring resulting emissions impacts from land-use changes are being intensely debated. Longer-term technological changes that bring increased crop yields per acre, changes in livestock and poultry feed conversion efficiency that reduce feed needs per animal, the amount of crop residue left on soils, and other factors will affect indirect land use emissions. Much more research is needed on these issues to accurately measure indirect land use impacts. Also, direct emissions from biofuels refineries are being reduced over time through technological advances.
California GHG Emissions Regulations (2)
The California Air Resources Board (CARB) of the California Environmental Protection Agency is the agency responsible for implementing GHG emission standards required by the state government. As shown in Table 1, California’s low carbon fuel standard (LCFS) reduces the allowable amount of CO2 emissions each year from 2011 through 2020, until average emissions from gasoline and diesel fuel are reduced by 10% from the current baseline level. Emissions are measured per unit of energy of each fuel so that variations in energy content per gallon of various fuels are taken into account. Petroleum-based gasoline and diesel fuel are used for the baselines from which other fuels will be compared. Reductions are not required for individual shipments of fuel. However, individual regulated firms are to be required to reduce GHG emissions from their total annual volumes by these percentages.
Required percentage reductions decline quite gradually for the first two years, but the rate of decrease accelerates starting in 2013. The initial gradual decline provides a limited time for the petroleum-based and renewable fuels industries to adjust before more extreme reductions are required.
Table 2 shows CARB’s estimated carbon emissions intensity of various biofuels by direct and indirect land use impacts, as well as the gasoline baseline emissions. Note that each type of ethanol has a rating for indirect land use while the baseline and some other fuel alternatives do not. This category is the controversial indirect land use impact rating, which has a large negative impact on the ability of ethanol to meet proposed future California GHG standards. Without this category, the ethanol fuels would be in a much stronger position relative to gasoline than current assessments indicate. Also note that ethanol from cellulose feedstocks is not included because commercially applicable technology for its production is not yet available.
The California Air Resources Board (CARB) identifies several types of ethanol, with CO2 emissions varying depending on where the fuel was produced, whether its co-product, distillers grain and solubles, (DGS) is dried or shipped wet from the plant, and what fuel type or types were used for the plant’s energy source. The location of production is assumed to impact emissions because of its relationship to transport needs and emissions. Alternative fuel types include coal, natural gas (NG), biomass, or some combination of these. Note that coal-fired plants are at the greatest disadvantage relative to other biofuels.
Table 2 shows total CO2 emissions for various types of fuels as a percent of the baseline, with and without the indirect land use effect. We have included a number of alternatives to ethanol and gasoline, some of which are not from renewable sources. We show them in Tables 1 and 2 because they will be strong future competitors with ethanol in the effort to control GHGs. Some of these alternatives -- for example compressed natural gas -- are already being used here and in other countries. They may or may not be competitive with ethanol in price, depending on future costs of natural gas and electricity.
(Click to enlarge.)
Midwest Ethanol Indicated to be at a Disadvantage
Table 3 shows CARB’s estimated carbon emissions intensity of various biofuels as percentages of the gasoline baseline. Note that each type of ethanol has a rating for indirect land use. This category is the controversial indirect land use impact rating. Without this category, the ethanol fuels would be in a much stronger position relative to gasoline than current assessments indicate. For every ethanol alternative, California ethanol is given a more favorable GHG rating than that from the Midwest. Also note that ethanol from cellulose feedstocks is not included because commercially applicable technology for its production is not yet available.
(Click to enlarge.)
Figure 1 shows how selected alternative fuels compare with the baseline (gasoline) from 2011 through 2020, as allowable emissions of GHG decline in future years. Note that for each year including 2011, Midwest ethanol produced from plants using either 100% natural gas, or coal for 40% and natural gas for 60% of their energy requirements, with dry distillers grain would fail to meet the proposed California standards. From 2015 onward, E-10 made entirely from typical Midwest ethanol or from 80% Midwest ethanol and 20% typical California ethanol would fail to meet the proposed standards. Midwest ethanol produced with natural gas fired plants and producing only wet distillers grain would meet the standards from 2011 through 2017 but would fail to meet them in later years. In contrast, California ethanol plants producing only wet distillers grain and using natural gas for energy would meet the standards throughout the period, as would Brazilian sugar cane ethanol. Thus, application of the proposed standards would place Midwest corn-starch ethanol plants at a distinct disadvantage relative to California plants and Brazil. Both of these sources of ethanol would be at a large disadvantage to compressed gas from landfill sources.
Figure 2 shows ratings for additional types of biofuels, including ethanol from Midwestern and California plants that use biomass for a portion of their energy source. Midwestern plants using biomass for 20% of their energy source, natural gas for 80%, and producing only dry distillers grain would meet the California standards through 2014 but not in later years. If these same plants produced only wet distillers grain, they would meet the proposed California GHG emissions standards only until 2019. Equivalent California plants producing either wet or dry DGS would continue to meet the standards through 2020. Even so, California ethanol plants would face intense GHG emissions competition from vehicle fuel produced by compressed natural gas and electricity – especially electricity produced from natural gas and renewable energy sources. Market share of these various fuels would depend not only on traditional cost competitiveness but GHG emissions as well.
If these proposed regulations are implemented in their present form, the ethanol industry will face a critically important new dimension in its competitiveness in addition to traditional price and cost issues. This analysis indicates that even if Midwest ethanol plants have cost advantages over California plants, the proposed regulations would be expected to keep them from marketing their ethanol in California in future years. How soon their California markets would be affected would depend on whether they produce only wet DGS or dry a portion of the co-product. Midwest plants using biomass for a portion of their energy source could delay loss of the California market for a few years. At the same time, extensive use of biomass such as corn stover as an ethanol plant energy source could divert supplies from their planned future use as feedstock for the cellulose ethanol industry.
|The proposed California regulations hint that in California, ethanol may be viewed as a temporary transitional fuel, to be replaced by electric-powered vehicles and those using various forms of compressed gas for fuel in the future. Extensive analysis of potential supplies and cost of these alternative fuels is needed before a determination can be made of how much motor fuel can be generated from these sources.|
A key determinant of ethanol’s disadvantage in the California motor fuel market is the estimated indirect land use impact. There is considerable disagreement in the scientific community on how to accurately assess this impact and to what extent this factor is needed. The U.S. historically has had large grain surplus production capacity as productivity increases from new technology have outpaced food and feed demand growth. Along with a number of other considerations, future prospects for productivity in grain production needs to be included in the assessment, along with probable future technological improvements in energy efficiency of ethanol production.
California’s policies that are designed to reduce greenhouse gas (GHG) emissions are of vital interest to the U.S. biofuels industries. There is a strong chance that California’s proposed regulations for reducing carbon dioxide (CO2) emissions from motor fuels will be applied nation-wide.(3) The current version of California regulations as well as GHG reduction mandates from the Energy Independence and Security Act of 2007 and emerging regulations from the U.S. Environmental Protection Agency are on a collision course with the ethanol blending mandates. The current direction of GHG emissions reductions policy will make it difficult to attain the sharply increased biofuels use levels that are mandated by 2007 energy legislation.
The California proposed regulations also put Midwest corn-starch ethanol at a substantial disadvantage relative to ethanol produced in California or Brazil in the nation’s potentially largest ethanol market. Midwest ethanol is at an even greater disadvantage relative to compressed natural gas, compressed landfill gas, electric vehicles, and possible future hydrogen-powered vehicles – from a GHG emissions standpoint. Ethanol could conceivably be more cost competitive than some of these alternatives (unless penalized by emissions taxes) but unable to compete because of estimated GHG emissions.
California’s initial version of proposed regulations does not include GHG emissions evaluations from biodiesel. However, preliminary reports from the U.S. EPA hint that soy-based biodiesel may not fare well in the GHG evaluations because of indirect land use impacts.(4) Indirect land use impacts are triggered if some portion of each acre of land shifted from feed and food use to fuel production needs to be replaced by other land brought into production elsewhere in the world. Changing use of that other land may result in increased GHG emissions or reduced GHG sequestering by that land.
Indirect land use impact is an important component of the California estimated emissions disadvantage from corn-starch ethanol. Scientists and economists are not in universal agreement on ways of measuring this impact. Much more research is needed before universally acceptable indirect land use impact assessments are available. With the rapid rate at which GHG emissions policy is moving forward, there is an urgent need for more research on indirect land use impacts.
1 Energy Independence and Security Act of 2007
2 California Environmental Protection Agency, Air Resources Board, Proposed regulation to Implement the Low Carbon Fuel Standard, Volume I, March 5, 2009 with release date April 23, 2009.
3 David Shepardson, “White House to unveil new auto emissions standards” Detroit News Washington Bureau, Monday, May 18, 2009 indicates a universal U.S. automobile tailpipe emissions policy is expected. This raises the possibility of a universal GHG emissions policy as well.
4 Jeanne Bernick, “EPA Rule Could Wreck Biofuel Competition”, Top Producer Crops & Issue, 5/19/2009