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Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel Standard Program
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PDF Version (50 pp, 618K, About PDF) [Federal Register: May 26, 2009 (Volume 74, Number 99)] [Proposed Rules] [Page 24903-24952] From the Federal Register Online via GPO Access [wais.access.gpo.gov] [DOCID:fr26my09-21] [[Page 24904]] ----------------------------------------------------------------------- ENVIRONMENTAL PROTECTION AGENCY 40 CFR Part 80 [EPA-HQ-OAR-2005-0161; FRL-8903-1] RIN 2060-A081 Regulation of Fuels and Fuel Additives: Changes to Renewable Fuel Standard Program AGENCY: Environmental Protection Agency (EPA). ACTION: Notice of proposed rulemaking. ----------------------------------------------------------------------- SUMMARY: Under the Clean Air Act, as amended by Sections 201, 202, and 210 of the Energy Independence and Security Act of 2007, the Environmental Protection Agency is required to promulgate regulations implementing changes to the Renewable Fuel Standard program. The revised statutory requirements specify the volumes of cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel that must be used in transportation fuel each year, with the volumes increasing over time. The revised statutory requirements also include new definitions and criteria for both renewable fuels and the feedstocks used to produce them, including new greenhouse gas emission thresholds for renewable fuels. For the first time in a regulatory program, an assessment of greenhouse gas emission performance is being utilized to establish those fuels that qualify for the four different renewable fuel standards. As mandated by the revised statutory requirements, the greenhouse gas emission assessments must evaluate the full lifecycle emission impacts of fuel production including both direct and indirect emissions, including significant emissions from land use changes. The proposed program is expected to reduce U.S. dependence on foreign sources of petroleum by increasing domestic sources of energy. Based on our lifecycle analysis, we believe that the expanded use of renewable fuels would provide significant reductions in greenhouse gas emissions such as carbon dioxide that affect climate change. We recognize the significance of using lifecycle greenhouse gas emission assessments that include indirect impacts such as emission impacts of indirect land use changes. Therefore, in this preamble we have been transparent in breaking out the various sources of greenhouse gas emissions included in the analysis and are seeking comments on our methodology as well as various options for determining the lifecycle greenhouse gas emissions (GHG) for each fuel. In addition to seeking comments on the information in this document and its supporting materials, the Agency is conducting peer reviews of critical aspects of the lifecycle methodology. The increased use of renewable fuels would also impact criteria pollutant emissions, with some pollutants such as volatile organic compounds (VOC) and nitrogen oxides (NOX) expected to increase and other pollutants such as carbon monoxide (CO) and benzene expected to decrease. The production of feedstocks used to produce renewable fuels is also expected to impact water quality. This action proposes regulations designed to ensure that refiners, blenders, and importers of gasoline and diesel would use enough renewable fuel each year so that the four volume requirements of the Energy Independence and Security Act would be met with renewable fuels that also meet the required lifecycle greenhouse gas emissions performance standards. Our proposed rule describes the standards that would apply to these parties and the renewable fuels that would qualify for compliance. The proposed regulations make a number of changes to the current Renewable Fuel Standard program while retaining many elements of the compliance and trading system already in place. DATES: Comments must be received on or before July 27, 2009, 60 days after publication in the Federal Register. Under the Paperwork Reduction Act, comments on the information collection provisions are best assured of having full effect if the Office of Management and Budget (OMB) receives a copy of your comments on or before June 25, 2009, 30 days after date of publication in the Federal Register. Hearing: We will hold a public hearing on June 9, 2009 at the Dupont Hotel in Washington, DC. The hearing will start at 10 a.m. local time and continue until everyone has had a chance to speak. If you want to testify at the hearing, notify the contact person listed under FOR FURTHER INFORMATION CONTACT by June 1, 2009. Workshop: We will hold a workshop on June 10-11, 2009 at the Dupont Hotel in Washington, DC to present details of our lifecycle GHG analysis. During this workshop, we intend to go through the lifecycle GHG analysis included in this proposal. The intent of this workshop is to help ensure a full understanding of our lifecycle analysis, the major issues identified and the options discussed. We expect that this workshop will help ensure that we receive submission of the most thoughtful and useful comments to this proposal and that the best methodology and assumptions are used for calculating GHG emissions impacts of fuels for the final rule. While this workshop will be held during the comment period, it is not intended to replace either the formal public hearing or the need to submit comments to the docket. ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ- OAR-2005-0161, by one of the following methods: • www.regulations.gov: Follow the on-line instructions for submitting comments. • E-mail: asdinfo@epa.gov. • Mail: Air and Radiation Docket and Information Center, Environmental Protection Agency, Mailcode: 2822T, 1200 Pennsylvania Ave., NW., Washington, DC 20460. In addition, please mail a copy of your comments on the information collection provisions to the Office of Information and Regulatory Affairs, Office of Management and Budget (OMB), Attn: Desk Officer for EPA, 725 17th St., NW., Washington, DC 20503. • Hand Delivery: EPA Docket Center, EPA West Building, Room 3334, 1301 Constitution Ave., NW., Washington, DC 20004. Such deliveries are only accepted during the Docket's normal hours of operation, and special arrangements should be made for deliveries of boxed information. Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR- 2005-0161. EPA's policy is that all comments received will be included in the public docket without change and may be made available online at www.regulations.gov, including any personal information provided, unless the comment includes information claimed to be Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Do not submit information that you consider to be CBI or otherwise protected through www.regulations.gov or e-mail. The www.regulations.gov Web site is an ``anonymous access'' system, which means EPA will not know your identity or contact information unless you provide it in the body of your comment. If you send an e- mail comment directly to EPA without going through www.regulations.gov your e-mail address will be automatically captured and included as part of the comment that is placed in the public docket and made available on the Internet. If you submit an electronic comment, EPA recommends that you include your name and other contact information in the body of your [[Page 24905]] comment and with any disk or CD-ROM you submit. If EPA cannot read your comment due to technical difficulties and cannot contact you for clarification, EPA may not be able to consider your comment. Electronic files should avoid the use of special characters, any form of encryption, and be free of any defects or viruses. For additional information about EPA's public docket visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm. For additional instructions on submitting comments, go to Section XI, Public Participation, of the SUPPLEMENTARY INFORMATION section of this document. Docket: All documents in the docket are listed in the www.regulations.gov index. Although listed in the index, some information is not publicly available, e.g., CBI or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, will be publicly available only in hard copy. Publicly available docket materials are available either electronically in www.regulations.gov or in hard copy at the Air and Radiation Docket and Information Center, EPA/DC, EPA West, Room 3334, 1301 Constitution Ave., NW., Washington, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is (202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742. Hearing: The public hearing will be held on June 9, 2009 at the Dupont Hotel, 1500 New Hampshire Avenue, NW., Washington, DC 20036. See Section XI, Public Participation, for more information about the public hearing. FOR FURTHER INFORMATION CONTACT: Julia MacAllister, Office of Transportation and Air Quality, Assessment and Standards Division, Environmental Protection Agency, 2000 Traverwood Drive, Ann Arbor, MI 48105; Telephone number: 734-214-4131; Fax number: 734-214-4816; E-mail address: macallister.julia@epa.gov, or Assessment and Standards Division Hotline; telephone number (734) 214-4636; E-mail address asdinfo@epa.gov. SUPPLEMENTARY INFORMATION: General Information A. Does This Proposal Apply to Me? Entities potentially affected by this proposal are those involved with the production, distribution, and sale of transportation fuels, including gasoline and diesel fuel or renewable fuels such as ethanol and biodiesel. Regulated categories include: -------------------------------------------------------------------------------------------------------------------------------------------------------- NAICS \1\ SIC \2\ Category codes codes Examples of potentially regulated entities -------------------------------------------------------------------------------------------------------------------------------------------------------- Industry..................................... 324110 2911 Petroleum Refineries. Industry..................................... 325193 2869 Ethyl alcohol manufacturing. Industry..................................... 325199 2869 Other basic organic chemical manufacturing. Industry..................................... 424690 5169 Chemical and allied products merchant wholesalers. Industry..................................... 424710 5171 Petroleum bulk stations and terminals. Industry..................................... 424720 5172 Petroleum and petroleum products merchant wholesalers. Industry..................................... 454319 5989 Other fuel dealers. -------------------------------------------------------------------------------------------------------------------------------------------------------- \1\ North American Industry Classification System (NAICS). \2\ Standard Industrial Classification (SIC) system code. This table is not intended to be exhaustive, but rather provides a guide for readers regarding entities likely to be regulated by this proposed action. This table lists the types of entities that EPA is now aware could potentially be regulated by this proposed action. Other types of entities not listed in the table could also be regulated. To determine whether your activities would be regulated by this proposed action, you should carefully examine the applicability criteria in 40 CFR part 80. If you have any questions regarding the applicability of this proposed action to a particular entity, consult the person listed in the preceding FOR FURTHER INFORMATION CONTACT section. B. What Should I Consider as I Prepare My Comments for EPA? 1. Submitting CBI Do not submit this information to EPA through www.regulations.gov or e-mail. Clearly mark the part or all of the information that you claim to be confidential business information (CBI). For CBI information in a disk or CD-ROM that you mail to EPA, mark the outside of the disk or CD-ROM as CBI and then identify electronically within the disk or CD-ROM the specific information that is claimed as CBI. In addition to one complete version of the comment that includes information claimed as CBI, a copy of the comment that does not contain the information claimed as CBI must be submitted for inclusion in the public docket. Information so marked will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. 2. Tips for Preparing Your Comments When submitting comments, remember to: • Explain your views as clearly as possible. • Describe any assumptions that you used. • Provide any technical information and/or data you used that support your views. • If you estimate potential burden or costs, explain how you arrived at your estimate. • Provide specific examples to illustrate your concerns. • Offer alternatives. • Make sure to submit your comments by the comment period deadline identified. • To ensure proper receipt by EPA, identify the appropriate docket identification number in the subject line on the first page of your response. It would also be helpful if you provided the name, date, and Federal Register citation related to your comments. We are primarily seeking comment on the proposed 40 CFR Part 80 Subpart M regulatory language that is not directly included in 40 CFR Part 80 Subpart K. For the proposed subpart M regulatory language that is unchanged from subpart K, we are only soliciting comment as it relates to its use for the RFS2 rule. Outline of This Preamble I. Introduction A. Renewable Fuels and the Transportation Sector [[Page 24906]] B. Renewable Fuels and Greenhouse Gas Emissions C. Building on the RFS1 Program II. Overview of the Proposed Program A. Summary of New Provisions of the RFS Program 1. Required Volumes of Renewable Fuel 2. Changes in How Renewable Fuel Is Defined 3. Analysis of Lifecycle Greenhouse Gas Emissions and Thresholds for Renewable Fuels 4. Coverage Expanded to Transportation Fuel, Including Diesel and Nonroad Fuels 5. Effective Date for New Requirements 6. Treatment of Required Volumes Preceding the RFS2 Effective Date 7. Waivers and Credits for Cellulosic Biofuel 8. Proposed Standards for 2010 B. Impacts of Increasing Volume Requirements in the RFS2 Program 1. Greenhouse Gases and Fossil Fuel Consumption 2. Economic Impacts and Energy Security 3. Emissions, Air Quality, and Health Impacts 4. Water 5. Agricultural Commodity Prices III. What Are the Major Elements of the Program Required Under EISA? A. Changes to Renewable Identification Numbers (RINs) B. New Eligibility Requirements for Renewable Fuels 1. Changes in Renewable Fuel Definitions a. Renewable Fuel and Renewable Biomass b. Advanced Biofuel c. Cellulosic Biofuel d. Biomass-Based Diesel e. Additional Renewable Fuel 2. Lifecycle GHG Thresholds 3. Renewable Fuel Exempt From 20 Percent GHG Threshold a. Definition of Commence Construction b. Definition and Boundaries of a Facility c. Options Proposed in Today's Rulemaking i. Basic Approach: Grandfathering Limited to Baseline Volumes (1) Increases in volume of renewable fuel produced at grandfathered facilities due to expansion (2) Replacements of equipment (3) Registration, Recordkeeping and Reporting (4) Sub-option of treatment of future modifications ii. Alternative Options for Which We Seek Comment (1) Facilities that meet the definition of ``reconstruction'' are considered new (2) Expiration date of 15 years for exempted facilities (3) Expiration date of 15 years for grandfathered facilities and limitation on volume (4) ``Significant production units'' are defined as facilities (5) Indefinite grandfathering and no limitations placed on volume 4. Renewable Biomass with Land Restrictions a. Definitions of Terms i. Planted Crops and Crop Residue ii. Planted Trees and Tree Residue iii. Slash and Pre-Commercial Thinnings iv. Biomass Obtained From Certain Areas at Risk From Wildfire b. Issues Related to Implementation and Enforceability i. Ensuring That RINs Are Generated Only for Fuels Made From Renewable Biomass ii. Ensuring That RINs Are Generated for All Qualifying Renewable Fuel c. Review of Existing Programs i. USDA Programs ii. Third-Party Programs d. Approaches for Domestic Renewable Fuel e. Approaches for Foreign Renewable Fuel C. Expanded Registration Process for Producers and Importers 1. Domestic Renewable Fuel Producers 2. Foreign Renewable Fuel Producers 3. Renewable Fuel Importers 4. Process and Timing D. Generation of RINs 1. Equivalence Values 2. Fuel Pathways and Assignment of D Codes a. Domestic Producers b. Foreign Producers c. Importers 3. Facilities With Multiple Applicable Pathways 4. Facilities That Co-Process Renewable Biomass and Fossil Fuels 5 Treatment of Fuels Without an Applicable D Code 6. Carbon Capture and Storage (CCS) E. Applicable Standards 1. Calculation of Standards a. How Would the Standards Be Calculated? b. Proposed Standards for 2010 c. Projected Standards for Other Years d. Alternative Effective Date 2. Treatment of Biomass-Based Diesel in 2009 and 2010 a. Proposed Shift in Biomass-Based Diesel Requirement from 2009 to 2010 i. First Option for Treatment of 2009 Biodiesel and Renewable Diesel RINs ii. Second Option for Treatment of 2009 Biodiesel and Renewable Diesel RINs b. Proposed Treatment of Deficit Carryovers and Valid RIN Life for Adjusted 2010 Biomass-Based Diesel Requirement c. Alternative Approach to Treatment of Biomass-Based Diesel in 2009 and 2010 F. Fuels That Are Subject to the Standards 1. Gasoline 2. Diesel 3. Other Transportation Fuels G. Renewable Volume Obligations (RVOs) 1. Determination of RVOs Corresponding to the Four Standards 2. RINs Eligible to Meet Each RVO 3. Treatment of RFS1 RINs under RFS2 a. Use of 2009 RINs in 2010 b. Deficit Carryovers from the RFS1 Program to RFS2 4. Alternative Approach to Designation of Obligated Parties H. Separation of RINs 1. Nonroad 2. Heating Oil and Jet Fuel 3. Exporters 4. Alternative Approaches to RIN Transfers 5. Neat Renewable Fuel and Renewable Fuel Blends Designated as Transportation Fuel, Home Heating Oil, or Jet Fuel I. Treatment of Cellulosic Biofuel 1. Cellulosic Biofuel Standard 2. EPA Cellulosic Allowances for Cellulosic Biofuel 3. Potential Adverse Impacts of Allowances J. Changes to Recordkeeping and Reporting Requirements 1. Recordkeeping 2. Reporting 3. Additional Requirements for Producers of Renewable Natural Gas, Electricity, and Propane K. Production Outlook Reports L. What Acts Are Prohibited and Who Is Liable for Violations? IV. What Other Program Changes Have We Considered? A. Attest Engagements B. Small Refinery and Small Refiner Flexibilities 1. Small Refinery Temporary Exemption 2. Small Refiner Flexibilities a. Extension of Existing RFS1 Temporary Exemption b. Program Review c. Extensions of the Temporary Exemption Based on Disproportionate Economic Hardship d. Phase-in e. RIN-Related Flexibilities C. Other Flexibilities 1. Upward Delegation of RIN-Separating Responsibilities 2. Small Producer Exemption D. 20% Rollover Cap E. Concept for EPA Moderated Transaction System 2. How EMTS Would Work 3. Implementation of EMTS F. Retail Dispenser Labelling for Gasoline with Greater than 10 Percent Ethanol V. Assessment of Renewable Fuel Production Capacity and Use A. Summary of Projected Volumes 1. Reference Case 2. Control Case for Analyses a. Cellulosic Biofuel b. Biomass-Based Diesel c. Other Advanced Biofuel d. Other Renewable Fuel B. Renewable Fuel Production 1. Corn/Starch Ethanol a. Historic/Current Production b. Forecasted Production Under RFS2 2. Cellulosic Ethanol a. Current Production/Plans b. Federal/State Production Incentives c. Feedstock Availability i Urban Waste ii. Agricultural and Forestry Residues iii Dedicated Energy Crops iv. Summary of Cellulosic Feedstocks for 2022 v. Cellulosic Plant Siting 3. Imported Ethanol a. Historic World Ethanol Production and Consumption b. Historic/Current Domestic Imports c. Projected Domestic Imports 4. Biodiesel & Renewable Diesel a. Historic and Projected Production i. Biodiesel [[Page 24907]] ii. Renewable Diesel b. Feedstock Availability C. Renewable Fuel Distribution 1. Overview of Ethanol Distribution 2. Overview of Biodiesel Distribution 3. Overview of Renewable Diesel Distribution 4. Changes in Freight Tonnage Movements 5. Necessary Rail System Accommodations 6. Necessary Marine System Accommodations 7. Necessary Accommodations to the Road Transportation System 8. Necessary Terminal Accommodations 9. Need for Additional E85 Retail Facilities D. Ethanol Consumption 1. Historic/Current Ethanol Consumption 2. Increased Ethanol Use under RFS2 a. Projected Gasoline Energy Demand b. Projected Growth in Flexible Fuel Vehicles c. Projected Growth in E85 Access d. Required Increase in E85 Refueling Rates e. Market Pricing of E85 Versus Gasoline 3. Other Mechanisms for Getting Beyond the E10 Blend Wall a. Mandate for FFV Production b. Waiver of Mid-Level Ethanol Blends (E15/E20) c. Partial Waiver for Mid-Level Blends d. Non-Ethanol Cellulosic Biofuel Production e. Measurement Tolerance for E10 f. Redefining ``Substantially Similar'' to Allow Mid-Level Ethanol Blends VI. Impacts of the Program on Greenhouse Gas Emissions A. Introduction 1. Definition of Lifecycle GHG Emissions 2. History and Evolution of GHG Lifecycle Analysis B. Methodology 1. Scenario Description 2. Scope of the Analysis a. Legal Interpretation of Lifecycle Greenhouse Gas Emissions b. System Boundaries 3. Modeling Framework 4. Treatment of Uncertainty 5. Components of the Lifecycle GHG Emissions Analysis a. Feedstock Production i. Domestic Agricultural Sector Impacts ii. International Agricultural Sector GHG Impacts b. Land Use Change i. Amount of Land Converted ii. Where Land Is Converted iii. What Type of Land Is Converted iv. What Are the GHG Emissions Associated with Different Types of Land Conversion v. Assessing GHG Emissions Impacts Over Time and Potential Application of a GHG Discount Rate c. Feedstock Transport d. Processing e. Fuel Transport f. Tailpipe Combustion 6. Petroleum Baseline 7. Energy Sector Indirect Impacts C. Fuel Specific GHG Emissions Estimates 1. Greenhouse Gas Emissions Reductions Relative to the 2005 Petroleum Baseline a. Corn Ethanol b. Imported Ethanol c. Cellulosic Ethanol d. Biodiesel 2. Treatment of GHG Emissions Over Time D. Thresholds E. Assignment of Pathways to Renewable Fuel Categories 1. Statutory Requirements 2. Assignments for Pathways Subjected to Lifecycle Analyses 3. Assignments for Additional Pathways a. Ethanol From Starch b. Renewable Fuels from Cellulosic Biomass c. Biodiesel d. Renewable Diesel Through Hydrotreating 4. Summary F. Total GHG Emission Reductions G. Effects of GHG Emission Reductions and Changes in Global Temperature and Sea Level 1. Introduction 2. Estimated Projected Reductions in Global Mean Surface Temperatures VII. How Would the Proposal Impact Criteria and Toxic Pollutant Emissions and Their Associated Effects? A. Overview of Impacts B. Fuel Production & Distribution Impacts of the Proposed Program C. Vehicle and Equipment Emission Impacts of Fuel Program D. Air Quality Impacts 1. Current Levels of PM2.5, Ozone and Air Toxics 2. Impacts of Proposed Standards on Future Ambient Concentrations of PM2.5, Ozone and Air Toxics E. Health Effects of Criteria and Air Toxic Pollutants 1. Particulate Matter a. Background b. Health Effects of PM 2. Ozone a. Background b. Health Effects of Ozone 3. Carbon Monoxide 4. Air Toxics a. Acetaldehyde b. Acrolein c. Benzene d. 1,3-Butadiene; e. Ethanol f. Formaldehyde g. Naphthalene h. Peroxyacetyl nitrate (PAN) i. Other Air Toxics F. Environmental Effects of Criteria and Air Toxic Pollutants 1. Visibility 2. Atmospheric Deposition 3. Plant and Ecosystem Effects of Ozone 4. Welfare Effects of Air Toxics VIII. Impacts on Cost of Renewable Fuels, Gasoline, and Diesel A. Renewable Fuel Production Costs 1. Ethanol Production Costs a. Corn Ethanol b. Cellulosic Ethanol i. Feedstock Costs ii. Production Costs c. Imported Sugarcane Ethanol 2. Biodiesel and Renewable Diesel Production Costs a. Biodiesel b. Renewable Diesel 3. BTL Diesel Production Costs B. Distribution Costs 1. Ethanol Distribution Costs a. Capital Costs to Upgrade the Distribution System for Increased Ethanol Volume b. Ethanol Freight Costs 2. Biodiesel and Renewable Diesel Distribution Costs a. Capital Costs to Upgrade the Distribution System for Increased FAME Biodiesel Volume b. Biodiesel Freight Costs c. Renewable Diesel Distribution System Capital and Freight Costs C. Reduced Refining Industry Costs D. Total Estimated Cost Impacts 1. Refinery Modeling Methodology 2. Overall Impact on Fuel Cost a. Costs Without Federal Tax Subsidies b. Gasoline and Diesel Costs Reflecting the Tax Subsidies IX. Economic Impacts and Benefits of the Proposal A. Agricultural Impacts 1. Commodity Price Changes 2. Impacts on U.S. Farm Income 3. Commodity Use Changes 4. U.S. Land Use Changes 5. Impact on U.S. Food Prices 6. International Impacts B. Energy Security Impacts 1. Implications of Reduced Petroleum Use on U.S. Imports 2. Energy Security Implications a. Effect of Oil Use on Long-Run Oil Price, U.S. Import Costs, and Economic Output b. Short-Run Disruption Premium from Expected Costs of Sudden Supply Disruptions c. Costs of Existing U.S. Energy Security Policies d. Anticipated Future Effort e. Total Energy Security Benefits C. Benefits of Reducing GHG Emissions 1. Introduction 2. Marginal GHG Benefits Estimates 3. Discussion of Marginal GHG Benefits Estimates 4. Total Monetized GHG Benefits Estimates D. Co-pollutant Health and Environmental Impacts 1. Human Health and Environmental Impacts 2. Monetized Impacts 3. Other Unquantified Health and Environmental Impacts E. Economy-Wide Impacts X. Impacts on Water A. Background 1. Ecological Impacts 2. Gulf of Mexico B. Upper Mississippi River Basin Analysis 1. SWAT Model 2. Baseline Model Scenario 3. Alternative Scenarios C. Additional Water Issues 1. Chesapeake Bay Watershed 2. Ethanol Production a. Distillers Grain with Solubles b. Ethanol Leaks and Spills 3. Biodiesel Plants 4. Water Quantity 5. Drinking Water D. Request for Comment on Options for Reducing Water Quality Impacts XI. Public Participation [[Page 24908]] A. How Do I Submit Comments? B. How Should I Submit CBI to the Agency? C. Will There Be a Public Hearing? D. Comment Period E. What Should I Consider as I Prepare My Comments for EPA? XII. Statutory and Executive Order Reviews A. Executive Order 12866: Regulatory Planning and Review B. Paperwork Reduction Act C. Regulatory Flexibility Act 1. Overview 2. Background 3. Summary of Potentially Affected Small Entities 4. Potential Reporting, Record Keeping, and Compliance 5. Related Federal Rules 6. Summary of SBREFA Panel Process and Panel Outreach a. Significant Panel Findings b. Panel Process c. Panel Recommendations i. Delay in Standards ii. Phase-in iii. RIN-Related Flexibilities iv. Program Review v. Extensions of the Temporary Exemption Based on a Study of Small Refinery Impacts vi. Extensions of the Temporary Exemption Based on Disproportionate Economic Hardship D. Unfunded Mandates Reform Act E. Executive Order 13132: Federalism F. Executive Order 13175: Consultation and Coordination With Indian Tribal Governments G. Executive Order 13045: Protection of Children From Environmental Health Risks and Safety Risks H. Executive Order 13211: Actions Concerning Regulations That Significantly Affect Energy Supply, Distribution, or Use I. National Technology Transfer Advancement Act J. Executive Order 12898: Federal Actions to Address Environmental Justice in Minority Populations and Low-Income Populations XIII. Statutory Authority I. Introduction The current Renewable Fuel Standard program (RFS1) was originally adopted by EPA to implement the provisions of the Energy Policy Act of 2005 (EPAct), which added section 211(o) to the Clean Air Act (CAA). With the passage of the Energy Independence and Security Act of 2007 (EISA), Congress recently made several important revisions to these renewable fuel requirements. This Notice proposes to revise the RFS program regulations to implement these EISA provisions. The proposed changes would apply starting January 1, 2010. For the remainder of 2009, the current RFS1 regulations would apply. However, in anticipation of the biomass-based diesel standard proposed for 2010, obligated parties may find it in their best interest to plan accordingly in 2009. A. Renewable Fuels and the Transportation Sector For the past several years, U.S. renewable fuel use has been rapidly increasing for a number of reasons. In the early 1990's, certain oxygenated gasoline fuel programs required by the CAA amendments of 1990 established new market opportunities for renewable fuels, primarily ethanol. At the same time, growing concern over U.S. dependence on foreign sources of crude placed increasing focus on renewable fuels as a replacement for petroleum-based fuels. More recently, several state bans on the use of methyl tertiary butyl ether (MTBE) in gasoline resulted in a large, sudden increase in demand for ethanol. Perhaps the largest impact on renewable fuel demand, however, has been the dramatic increase in the cost of crude oil. In the last few years, both crude oil prices and crude oil price forecasts have increased dramatically, which have resulted in a large economic incentive for the increased development and use of renewable fuels. In 2005, Congress introduced a new approach to supporting renewable fuels. EPAct established a major new federal renewable fuel volume mandate. EPAct required a ramp up to 7.5 billion gallons of renewable fuel as motor vehicle fuel by 2012 and set annual volume targets for each year leading up to 2012. For 2013 and beyond, EPA was directed to establish the annual required renewable fuel volumes, but at a percentage level no less than that required for 2012. While the market forces described above ultimately caused renewable fuel use to far exceed the EPAct mandates, this program provided certainty that at least a minimum amount of renewable fuel would be used in the U.S. transportation market, which in turn provided assurance for investment in production capacity. The subsequent passage of EISA made significant changes to both the structure and the magnitude of the renewable fuel program. The renewable fuel program established by EISA, hereafter referred to as RFS2, mandates the use of 36 billion gallons of renewable fuel by 2022. This is nearly a five-fold increase over the highest volume specified by EPAct and constitutes a 10-year extension of the scheduled production ramp-up period provided for in that legislation. It is clear that the volumes required by EISA will push the market to new levels-- far beyond what current market conditions would achieve alone. In addition, EISA specifies four separate categories of renewable fuels, each with a separate volume mandate. The categories are renewable fuel, advanced biofuel, biomass-based diesel, and cellulosic biofuel. There is a notable increase in the mandate for cellulosic biofuels in particular. EISA increased the cellulosic biofuel mandate from 250 million in EPAct to 1.0 billion gallons by 2013, with additional yearly increases to 16 billion gallons by 2022. These requirements will provide a strong foundation for investment in cellulosic production and position cellulosic fuel to become a major portion of the renewable fuel pool over the next decade. The implications of the volume expansion of the program are not trivial. Development of infrastructure capable of delivering, storing and blending these volumes in new markets and expanding existing market capabilities will be needed. For example, the market's absorption of increased volumes of ethanol may ultimately require new ``outlets'' beyond E10 blends (i.e., gasoline containing 10% ethanol by volume), such as an expansion of the number of flexible-fuel E85 vehicles and the number of retail outlets selling E85. B. Renewable Fuels and Greenhouse Gas Emissions Another significant aspect of the RFS2 program is the focus on the greenhouse gas impact of renewable fuels, from a lifecycle perspective. The lifecycle GHG emissions means the aggregate quantity of GHGs related to the full fuel cycle, including all stages of fuel and feedstock production and distribution, from feedstock generation and extraction through distribution and delivery and use of the finished fuel. EISA established specific greenhouse gas emission thresholds for each of four types of renewable fuels, requiring a percentage improvement compared to a baseline of the gasoline and diesel used in 2005. EPA must conduct a lifecycle analysis to determine whether or not renewable fuels produced under varying conditions will meet the greenhouse gas (GHG) thresholds for the different fuel types for which EISA establishes mandates. While these thresholds do not constitute a control on greenhouse gases for transportation fuels (such as a low carbon fuel standard),\1\ they do require that the volume mandates be met through the use of renewable fuels that meet certain lifecycle GHG reduction thresholds when compared to [[Page 24909]] the baseline lifecycle emissions of petroleum fuel they replace. Compliance with the thresholds requires a comprehensive evaluation of renewable fuels, as well as of gasoline and diesel, on the basis of their lifecycle emissions. As mandated by EISA, the greenhouse gas emission assessments must evaluate the full lifecycle emission impacts of fuel production including both direct and indirect emissions, including significant emissions from land use changes. We recognize the significance of using lifecycle greenhouse gas emission assessments that include indirect impacts such as emission impacts of indirect land use changes. Therefore, in this preamble, we have been transparent in breaking out the various sources of greenhouse gas emissions included in the analysis. As described in detail in Section VI, EPA has analyzed the lifecycle GHG impacts of the range of biofuels currently expected to contribute significantly to meeting the volume mandates of EISA through 2022. In these analyses we have used the best science available. Our analysis relies on peer reviewed models and the best estimate of important trends in agricultural practices and fuel production technologies as these may impact our prediction of individual biofuel GHG performance through 2022. We have identified and highlighted assumptions and model inputs that particularly influence our assessment and seek comment on these assumptions, the models we have used and our overall methodology so as to assure the most robust assessment of lifecycle GHG performance for the final rule. --------------------------------------------------------------------------- \1\ See Section IV.D of EPA's advanced notice of proposed rulemaking, Regulating Greenhouse Gas Emissions under the Clean Air Act, for a discussion of EPA's possible authority under section 211(c) of the CAA to establish GHG standards for renewable and alternative fuels. 73 FR 44354, July 30, 2008. --------------------------------------------------------------------------- Because lifecycle analysis is a new part of the RFS program, in addition to the formal comment period on the proposed rule, EPA is making multiple efforts to solicit public and expert feedback on our proposed approach. EPA plans to hold a public workshop focused specifically on lifecycle analysis during the comment period to assure full understanding of the analyses conducted, the issues addressed and the options that are discussed. We expect that this workshop will help ensure that we receive submission of the most thoughtful and useful comments to this proposal and that the best methodology and assumptions are used for calculating GHG emissions impacts of fuels for the final rule. Additionally, between this proposal and the final rule, we will conduct peer-reviews of key components of our analysis. As explained in more detail in the Section VI, EPA is specifically seeking peer review of: Our use of satellite data to project future the type of land use changes; the land conversion GHG emissions factors estimates we have used for different types of land use; our estimates of GHG emissions from foreign crop production; methods to account for the variable timing of GHG emissions; and how the several models we have relied upon are used together to provide overall lifecycle GHG estimates. In addition to the GHG thresholds, EISA included several provisions for the RFS2 program designed to address the long-term environmental sustainability of expanded biofuels production. The new law limits the crops and crop residues used to produce renewable fuel to those grown on land cleared or cultivated at any time prior to enactment of EISA, that is either actively managed or fallow, and non-forested. EISA also generally requires that forest-related slash and tree thinnings used for renewable fuel production pursuant to the Act be harvested from non-federal forest lands. To address potential air quality concerns, EPA is required by section 209 of EISA to determine whether the RFS2 volumes will adversely impact air quality as a result of changes in vehicle and engine emissions and then to issue fuel regulations that mitigate--to the extent achievable--these impacts. The Agency is also required by section 204 of EISA to conduct a broad study of environmental and resource conservation impacts of EISA, including impacts on water quality and availability, soil conservation, and biodiversity. Congress set specific deadlines for both of these provisions, which are separate from this rulemaking and will be carried out as part of a future effort. However, this NPRM does include EPA's initial assessment of the air and water quality impacts of the EISA volumes. While the above described changes are significant, it is important to note that Congress left other structural elements of the RFS program basically intact. The various modifications are discussed throughout this preamble. C. Building on the RFS1 Program In designing this proposed RFS2 program, the Agency is utilizing and building on the same programmatic structure created to implement the current renewable fuel program (hereafter referred to as RFS1). For example, we propose to continue to use the Renewable Identification Number (RIN) system currently in place to track compliance with the RFS1 program, with modifications to implement the EISA provisions. This approach is in keeping with the Agency's overall intent for RFS1--to design a flexible and enforceable system that could continue to operate effectively regardless of the level of renewable fuel use or market conditions in the transportation fuel sector. A key component of the Agency's work to build a successful RFS1 program was early and sustained engagement with our stakeholders. In developing this proposed rulemaking, we have again worked closely with a wide variety of stakeholders. Because EISA created new obligated parties and established new, complex provisions such as the lifecycle GHG thresholds and previous cropland requirements, EPA has extended its stakeholder engagement to include dozens of meetings with stakeholders from a broad spectrum of perspectives. For example, the Agency has had multiple meetings and discussions with renewable fuel producers, technology companies, petroleum refiners and importers, agricultural associations, lifecycle experts, environmental groups, vehicle manufacturers, states, gasoline and petroleum marketers, pipeline owners and fuel terminal operators. II. Overview of the Proposed Program This section provides an overview of the RFS2 program requirements that EPA proposes to implement as a result of EISA. The RFS2 program would replace the RFS1 program promulgated on May 1, 2007 (72 FR 23900).\2\ We are also proposing a number of changes to make the program more flexible based on what we learned from the operation of the RFS1 program since it began on September 1, 2007. Details of the proposed requirements can be found in Sections III and IV. We request comment on our proposed regulatory requirements and the alternatives that we have considered. --------------------------------------------------------------------------- \2\ To meet the requirements of EPAct, EPA had previously adopted a limited program that applied only to calendar year 2006. The RFS1 program refers to the general program adopted in the May 2007 rulemaking. --------------------------------------------------------------------------- This section also provides a summary of EPA's impacts assessment of the use of higher renewable fuel volumes. Impacts that we assessed include: emissions of pollutants such as greenhouse gases (GHG), oxides of nitrogen (NOX), hydrocarbons, particulate matter (PM), and toxics; reductions in petroleum use and related impacts on national energy security; impacts on the agriculture sector; impacts on costs of transportation fuels; economic costs and benefits; and impacts on water. Details of these [[Page 24910]] analyses can be found in Sections V through X and in the Draft Regulatory Impact Analysis (DRIA). A. Summary of New Provisions of the RFS Program Today's notice proposes new regulatory requirements for the RFS program that would be implemented through a new Subpart M to 40 CFR Part 80. EPA is generally proposing to maintain many elements of the RFS1 program such as regulations governing the generation, transfer, and use of Renewable Identification Numbers (RINs). At the same time, we seek comment on a number of RFS1 provisions that may require adjustment under an expanded RFS2 program, including whether or not to require that all qualifying renewable fuels have RINs generated for it (discussed in Section III.B.4.b.ii), and whether a rollover cap on RINs other than 20 percent might be appropriate (discussed in Section IV.D). Furthermore, EPA is proposing several new provisions and seeking comment on alternatives on aspects of the program for which EISA grants EPA discretion and flexibility, such as the grandfathering of existing renewable fuel production facilities (discussed in Section III.B.3), the potential inclusion of electricity for credit (discussed in Section III.B.1.a), and how renewable fuels are categorized based on the results of lifecycle analyses (discussed in Section VI.B). We believe these and other aspects of the program are important because they will affect available volumes of qualifying renewable fuel, regulated parties' ability to comply with the program and, ultimately, the program's environmental and societal impacts. A full description of all the changes we are proposing to the RFS program to implement the requirements in EISA is provided in Section III, while Section IV includes extensive discussion of other changes to the RFS program under consideration. 1. Required Volumes of Renewable Fuel The primary purpose of the RFS program is to require a minimum volume of renewable fuel to be used each year in the transportation sector. Under RFS1, the required volume was 4.0 billion gallons in 2006, ramping up to 7.5 billion gallons by 2012. Starting in 2013, EPAct required that the total volume of renewable fuel represent at minimum the same volume fraction of the gasoline fuel pool as it did in 2012, and that the total volume of renewable fuel contains at least 250 million gallons of fuel derived from cellulosic biomass. EISA makes three primary changes to the volume requirements of the RFS program. First, it substantially increases the required volumes and extends the timeframe over which the volumes ramp up through at least 2022. Second, it divides the total renewable fuel requirement into four separate categories, each with its own volume requirement. Third, it requires that each of these mandated volumes of renewable fuels achieve certain minimum thresholds of GHG emission performance. The volume requirements in EISA are shown in Table II.A.1-1. Table II.A.1-1--Renewable Fuel Volume Requirements for RFS2 [Billion gallons] ---------------------------------------------------------------------------------------------------------------- Cellulosic Biomass- based Advanced Total biofuel diesel biofuel renewable fuel requirement requirement requirement requirement ---------------------------------------------------------------------------------------------------------------- 2009............................................ n/a 0.5 0.6 11.1 2010............................................ 0.1 0.65 0.95 12.95 2011............................................ 0.25 0.80 1.35 13.95 2012............................................ 0.5 1.0 2.0 15.2 2013............................................ 1.0 \a\ 2.75 16.55 2014............................................ 1.75 \a\ 3.75 18.15 2015............................................ 3.0 \a\ 5.5 20.5 2016............................................ 4.25 \a\ 7.25 22.25 2017............................................ 5.5 \a\ 9.0 24.0 2018............................................ 7.0 \a\ 11.0 26.0 2019............................................ 8.5 \a\ 13.0 28.0 2020............................................ 10.5 \a\ 15.0 30.0 2021............................................ 13.5 \a\ 18.0 33.0 2022............................................ 16.0 \a\ 21.0 36.0 2023+........................................... \b\ \b\ \b\ \b\ ---------------------------------------------------------------------------------------------------------------- \a\ To be determined by EPA through a future rulemaking, but no less than 1.0 billion gallons. \b\ To be determined by EPA through a future rulemaking. As shown in the table, the volume requirements are not exclusive, and generally result in nested requirements. Any renewable fuel that meets the requirement for cellulosic biofuel or biomass-based diesel is also valid for meeting the advanced biofuel requirement. Likewise, any renewable fuel that meets the requirement for advanced biofuel is also valid for meeting the total renewable fuel requirement. See Section VI.E for further discussion of which specific types of fuel meet the requirements for one of the four categories shown in Table II.A.1-1. We are co-proposing and taking comment on two options for how to treat the volumes of different renewable fuels for purposes of complying with the volume mandates of RFS2: As either ethanol- equivalent gallons, based on energy content, as finalized in the RFS1 program, or as actual volume in gallons. Consideration of the actual volume option would recognize that EISA now guarantees a market for specific categories of renewable fuel and assigns a GHG requirement to each category in the form of minimum GHG thresholds that each must meet. The approach taken in RFS1 would continue to assign value, in terms of gallons, to all renewable fuels based on their energy value in comparison with ethanol. Further discussion of the rationale and implications of these two approaches can be found in Section III.D.1. The statutorily-prescribed phase-in period ends in 2012 for biomass-based diesel and in 2022 for cellulosic biofuel, advanced biofuel, and total renewable fuel. Beyond these years, EISA requires EPA to determine the applicable [[Page 24911]] volumes based on a review of the implementation of the program up to that time, and an analysis of a wide variety of factors such as the impact of the production of renewable fuels on the environment, energy security, infrastructure, costs, and other factors. For these future standards, EPA must promulgate rules establishing the applicable volumes no later than 14 months before the first year for which such applicable volumes would apply. For biomass-based diesel, this would mean that final rules would need to be issued by October 31, 2011 for application starting on January 1, 2013. In today's proposed rulemaking, we are not suggesting any specific volume requirements for biomass-based diesel for 2013 and beyond that would be appropriate under the statutory criteria that we must consider. Likewise, we are not suggesting any specific volume requirements for the other three renewable fuel categories for 2023 and beyond. However, the statute requires that the biomass-based diesel volume in 2013 and beyond must be no less than 1.0 billion gallons, and that advanced biofuels in 2023 and beyond must represent at a minimum the same percentage of total renewable fuel as it does in 2022. 2. Changes in How Renewable Fuel Is Defined Under the existing Renewable Fuel Standard, (RFS1) renewable fuel is defined generally as ``any motor vehicle fuel that is used to replace or reduce the quantity of fossil fuel present in a fuel mixture used to fuel a motor vehicle''. The RFS1 definition includes motor vehicle fuels produced from biomass material such as grain, starch, fats, greases, oils and biogas. The definitions of renewable fuels under today's proposed rule (RFS2) are based on the new statutory definitions in EISA. Like the existing rules, the definitions in RFS2 include a general definition of renewable fuel, but unlike RFS1, we are including a separate definition of ``Renewable Biomass'' which identifies the feedstocks from which renewable fuels may be made. Another difference in the definitions of renewable fuel is that RFS2 contains three subcategories of renewable fuels: (1) Advanced Biofuel, (2) Cellulosic Biofuel and (3) Biomass-Based Diesel. ``Advanced Biofuel'' is a renewable fuel other than ethanol derived from corn starch and which must achieve a lifecycle GHG emission displacement of 50%, compared to the gasoline or diesel fuel it displaces. Cellulosic biofuel is any renewable fuel, not necessarily ethanol, derived from any cellulose, hemicellulose, or lignin each of which must originate from renewable biomass. It must achieve a lifecycle GHG emission displacement of 60%, compared to the gasoline or diesel fuel it displaces for it to qualify as cellulosic biofuel. The RFS1 definition provided that ethanol made at any facility-- regardless of whether cellulosic feedstock is used or not--may be defined as cellulosic if at such facility ``animal wastes or other waste materials are digested or otherwise used to displace 90% or more of the fossil fuel normally used in the production of ethanol.'' This provision was not included in EISA, and therefore does not appear in the definitions pertaining to cellulosic biofuel in today's proposed rule. The statutory definition of ``renewable biomass'' in EISA does not include a reference to municipal solid waste (MSW) as did the definition of ``cellulosic biomass ethanol'' in EPAct, but instead includes ``separated yard waste and food waste. EPA's proposed definition of renewable biomass in today's proposed rule includes the language present in EISA. As discussed in Section III.B.1.a, we invite comment on whether this definition should be interpreted as including or excluding MSW containing yard and/or food waste from the definition of renewable biomass. EPA intends to resolve this matter in the final rule, and EPA solicits comment on the approach that it should take. Under today's proposed rule ``Biomass-based diesel'' includes biodiesel (mono-alkyl esters), non-ester renewable diesel and any other diesel fuel made from renewable biomass, as long as they are not ``co- processed'' with petroleum. EISA requires that such fuel achieve a lifecycle GHG emission displacement of 50%, compared to the gasoline or diesel fuel it displaces. As discussed in Section III.B.1.d, we are proposing that co-processing is considered to occur only if both petroleum and biomass feedstock are processed in the same unit simultaneously. Thus, if serial batch processing in which 100% vegetable oil is processed one day/week/month and 100% petroleum the next day/week/month occurs, the fuel derived from renewable biomass would be assigned RINs with a D code identifying it as biomass-based diesel. The resulting products could be blended together, but only the volume produced from renewable biomass would count as biomass-based diesel. For other renewable fuels, EISA makes a distinction between fuel from new and existing facilities. Only renewable fuel from new facilities is required to achieve a lifecycle GHG emission displacement of 20%. As discussed in Section III.B.3, this requirement applies only to renewable fuel that is produced from certain facilities which commenced construction after December 19, 2007. EISA defines ``additional renewable fuel'' as fuel produced from renewable biomass that is used to replace or reduce fossil fuels used in home heating oil or jet fuel. The Act provides that EPA may allow for the generation of RFS credits for such fuel. This represents a change from RFS1, where renewable fuel qualifying for credits was limited to fuel used in motor vehicles. We propose to modify the regulatory requirements to allow RINs assigned to renewable fuel blended into heating oil or jet fuel to be valid for compliance purposes. The fuel would still have to meet all the other criteria to qualify as a renewable fuel, including being made from renewable biomass. For example, RINs generated for advanced biofuel or biomass- based diesel that could be used in automobiles would still be valid, and would not need to be retired, if the fuel producer instead sells the fuels for use in heating oil or jet fuel. ``Renewable biomass'' is defined in EISA to include a number of feedstock types, such as planted crops and crop residue, planted trees and tree residue, animal waste, algae, and yard and food waste. However, the EISA definition limits many of these feedstocks according to the management practices for the land from which they are derived. For example, planted crops and crop residue must be harvested from agricultural land cleared or cultivated at any time prior to December 19, 2007, that is actively managed or fallow, and non-forested. Therefore, planted crops and crop residue derived from land that does not meet this definition cannot be used to produce renewable fuel for credit under RFS2. Under today's proposed rule, we describe several options for ensuring that feedstocks used to produce renewable fuel for which credits are generated under RFS2 meet the definition of renewable biomass. Our proposed approach places overall responsibility for verifying a feedstock's source on the party who generates a RIN for the renewable fuel produced from the feedstock. We also present options for how a party could or should verify his or her feedstock, and we seek comment on these options. A full discussion of the definition and implementation options for ``renewable biomass'' is presented in Section III.B.4. [[Page 24912]] 3. Analysis of Lifecycle Greenhouse Gas Emissions and Thresholds for Renewable Fuels As shown in Table II.A.3-1, EISA requires that a renewable fuel must meet minimum thresholds for their reduction in lifecycle greenhouse gas emissions: A 20% reduction in lifecycle GHG emissions for any renewable fuel produced at new facilities; a 50% reduction in order to be classified as biomass-based diesel or advanced biofuel; and a 60% reduction in order to be classified as cellulosic biofuel. The lifecycle GHG emissions means the aggregate quantity of GHG emissions related to the full fuel cycle, including all stages of fuel and feedstock production and distribution, from feedstock generation or extraction through distribution and delivery and use of the finished fuel. As mandated by EISA, it includes direct emissions and significant indirect emissions such as significant emissions from land use changes. EPA believes that compliance with the EISA mandate--determining the aggregate GHG emissions related to the full fuel lifecycle, including both direct emissions and significant indirect emissions such as land use changes--make it necessary to assess those direct and indirect impacts that occur not just within the United States but also those that occur in other countries. This applies to determining the lifecycle emissions for petroleum-based fuels to determine the baseline, as well as the lifecycle emissions for biofuels. For biofuels, this includes evaluating significant emissions from indirect land use changes that occur in other countries as a result of the increased domestic production or importation of biofuels into the U.S. As detailed in Section VI, we have included the GHG emission impacts of international land use changes including the indirect land use changes that result from domestic production of biofuel feedstocks. We recognize the significance of including international land use emission impacts and, in our analysis presentation in Section VI, have been transparent in breaking out the various sources of GHG emissions so that the reader can readily see the impact of including international land use impacts. Table II.A.3-1--Lifecycle GHG Thresholds Specified in EISA [Percent reduction from baseline] ------------------------------------------------------------------------ ------------------------------------------------------------------------ Renewable fuel \a\............................................. 20 Advanced biofuel............................................... 50 Biomass-based diesel........................................... 50 Cellulosic biofuel............................................. 60 ------------------------------------------------------------------------ \a\ The 20% criterion generally applies to renewable fuel from new facilities that commenced construction after December 19, 2007. The lifecycle GHG emissions of the renewable fuel are compared to the lifecycle GHG emissions for gasoline or diesel (whichever is being replaced by the renewable fuel) sold or distributed as transportation fuel in 2005. EISA provides some limited flexibility for EPA to adjust these GHG percentage thresholds downward by up to 10 percent under certain circumstances. As discussed in Section VI.D, we are proposing that the GHG threshold for advanced biofuels be adjusted to 44% or potentially as low as 40% depending on the results from the analyses that will be conducted for the final rule. This adjustment would allow ethanol produced from sugarcane to count as advanced biofuel and would help ensure that the volume mandate for advanced biofuel could be met. The regulatory purpose of the lifecycle greenhouse gas emissions analysis is to determine whether renewable fuels meet the GHG thresholds for the different categories of renewable fuel. As described in detail in Section VI, EPA has analyzed the lifecycle GHG impacts of the range of biofuels currently expected to contribute significantly to meeting the volume mandates of EISA through 2022. In these analyses we have used the best science available. Our analysis relies on peer reviewed models and the best estimate of important trends in agricultural practices and fuel production technologies as these may impact our prediction of individual biofuel GHG performance through 2022. We have identified and highlighted assumptions and model inputs that particularly influence our assessment and seek comment on these assumptions, the models we have used and our overall methodology so as to assure the most robust assessment of lifecycle GHG performance for the final rule. In addition to the many technical issues addressed in this proposal, Section VI discusses the emissions decreases and increases associated with the different parts of the lifecycle emissions of various biofuels and the timeframes in which these emissions changes occur. The need to determine a single lifecycle value that best represents this combination of emissions increases and decreases occurring over time led EPA to consider various alternative ways to analyze the timeframe of emissions changes related to biofuel production and use as well as options for adjusting or discounting these emissions to determine their net present value. Section VI highlights two options. One option assumes a 30 year time period for assessing future GHG emissions impacts of the anticipated increase in biofuel production to meet the mandates of EISA, both emissions increases and decreases, and values all these emission impacts the same regardless of when they occur during that time period (i.e., no discounting). The second option assesses emissions impacts over a 100 year time period but then discounts future emissions 2% annually to arrive at an estimate of a net present value of those emissions. Several other variations of time period and discount rate are also discussed. The analytical time horizon and the choice whether to discount GHG emissions and, if so, at what appropriate rate can have a significant impact on the final assessment of the lifecycle GHG emissions impacts of individual biofuels as well as the overall GHG impacts of these EISA provisions and this rule. We believe that our lifecycle analysis is based on the best available science and recognize that in some aspects it represents a cutting edge approach to addressing lifecycle GHG emissions. Because of the varying degrees of uncertainty in the different aspects of our analysis, we conducted a number of sensitivity analyses which focus on key parameters and demonstrate how our assessments might change under alternative assumptions. By focusing attention on these key parameters, the comments we receive as well as additional investigation and analysis by EPA will allow narrowing of uncertainty concerns for the final rule. In addition to this sensitivity analysis approach, we will also explore options for more formal uncertainty analyses for the final rule to the extent possible. Because lifecycle analysis is a new part of the RFS program, in addition to the formal comment period on the proposed rule, EPA is making multiple efforts to solicit public and expert feedback on our proposed approach. EPA plans to hold a public workshop focused specifically on lifecycle analysis during the comment period to assure full understanding of the analyses conducted, the issues addressed and the options that are discussed. We expect that this workshop will help ensure that we receive submission of the most [[Page 24913]] thoughtful and useful comments to this proposal and that the best methodology and assumptions are used for calculating GHG emissions impacts of fuels for the final rule. Additionally, between this proposal and the final rule, we will conduct peer reviews of key components of our analysis. As explained in more detail in Section VI, EPA is specifically seeking peer review of: Our use of satellite data to project future types of land use changes; the land conversion GHG emissions factors estimates we have used for different types of land use; our estimates of GHG emissions from foreign crop production; methods to account for the variable timing of GHG emissions; and how the several models we have relied upon are used together to provide overall lifecycle GHG estimates. Some renewable fuel is not required to meet the 20% GHG threshold. Section 211(o)(2)(A) provides that only renewable fuel produced from new facilities which commenced construction after December 19, 2007 must meet the 20% threshold. Facilities that commenced construction on or before December 19, 2007 are exempt or ``grandfathered'' from the 20% threshold requirement. In addition, section 210(a) of EISA provides a further exemption from the 20% threshold requirement for ethanol plants that commenced construction in 2008 or 2009 and are fired with natural gas, biomass, or any combination thereof. The renewable fuel from such facilities is deemed to be in compliance with the 20% threshold, and would thus also be ``grandfathered.'' We are proposing and taking comment on one approach to the grandfathering provisions in today's rule, and seeking comment on five additional options. The proposed approach would provide an indefinite time period for grandfathering status but with restrictions to the baseline volume of renewable fuel that is grandfathered. The alternative options are (1) Expiration of exemption for grandfathered status when facilities undergo sufficient changes to be considered ``reconstructed''; (2) Expiration of exemption 15 years after EISA enactment, industry-wide; (3) Expiration of exemption 15 years after EISA enactment with limitation of exemption to baseline volume; (4) ``Significant'' production components are treated as facilities and grandfathered or deemed compliant status ends when they are replaced; and (5) Indefinite exemption and no limitations placed on baseline volumes. Our proposal and the alternative options are discussed in further detail in Section III.B.3.c. While renewable fuels would be required to meet the GHG thresholds shown in Table II.A.3-1 in order to be valid for compliance purposes under the RFS2 program, we are not proposing that an individual facility-specific lifecycle GHG emissions value would have to be determined in order to show that the biofuel produced or imported at an individual facility complies with the threshold. Instead, EPA has determined lifecycle GHG values for specific combinations of fuel type, feedstock, and production process, using average values for various lifecycle model inputs. As a result of these assessments, we propose to assign each combination of fuel type, feedstock, and production process to one of the four renewable fuel categories specified in EISA or, alternatively, make a determination that the biofuel combination has been disqualified from generating RINs (except as may be allowed for grandfathered renewable fuel) due to a failure to meet the minimum 20% GHG threshold. Section VI.E discusses our proposed assignments. We are also proposing a mechanism to allow biofuels whose lifecycle GHG emissions have not been assessed to participate in the RFS program under certain limited conditions. These conditions are described in Section III.D.5. 4. Coverage Expanded to Transportation Fuel, Including Diesel and Nonroad Fuels EPAct only mandated the blending of renewable fuels into gasoline, though it gave credit for renewable fuels blended into diesel fuel. EISA expanded the program to generally cover transportation fuel, which is defined as fuel for use in motor vehicles, motor vehicle engines, nonroad vehicles, or nonroad engines. This includes diesel fuel intended for use in highway vehicles and engines, and nonroad, locomotive, and marine engines and vessels, as well as gaseous or other fuels used in these vehicles, engines, or vessels. EISA also specifies that ``transportation fuels'' do not include fuels for use in ocean- going vessels. EPA is required to ensure that transportation fuel contains at least the specified volumes of renewable fuel. Under EISA, renewable fuel now includes fuel that is used to displace fossil fuel present in transportation fuel, and as in RFS1, EPA is required to determine the refiners, blenders, and importers of transportation fuel that are subject to the renewable volume obligation. As discussed in Section III.F, while we are seeking comment on alternatives, EPA is proposing consistent with RFS1 that these provisions could best be met by requiring that the renewable volume obligation apply to refiners, blenders, and importers of motor vehicle or nonroad gasoline or diesel (with limited flexibilities for small refineries and small refiners), and that their percentage obligation would apply to the amount of gasoline or diesel they produce for such use. We propose to use the current definition of motor vehicle, nonroad, locomotive, and marine diesel fuel (MVNRLM)--as defined at Sec. 80.2(qqq)--to determine the obligated volumes of non-gasoline transportation fuel for this rule. We request comment on these aspects of our proposed program. 5. Effective Date for New Requirements Under CAA section 211(o) as modified by EISA, EPA is required to revise the RFS1 regulations within one year of enactment, or December 19, 2008. Promulgation by this date would have been consistent with the revised volume requirements shown in Table II.A.1-1 that begin in 2009 for certain categories of renewable fuel. However, due to the addition of complex lifecycle assessments to the determination of eligibility of renewable fuels, the extensive analysis of impacts that we are conducting for the higher renewable fuel volumes, the various complex changes to the regulatory program that require close collaboration with stakeholders, and various statutory limitations such as the Small Business Regulatory Enforcement Flexibility Act (SBREFA) and a 60 day Congressional review period for all significant actions, we were not able to promulgate final RFS2 program requirements by December 19, 2008. As a result, we are proposing that the RFS2 regulatory program go into effect on January 1, 2010. In order to successfully implement the RFS2 program, parties that generate RINs, own and/or transfer them, or use them for compliance purposes will need to re-register under the RFS2 provisions and modify their information technology (IT) systems to accommodate the changes we are proposing today. As described more fully in Section III, these changes would include redefining the D code within the RIN, adding a process for verifying that feedstocks meet the renewable biomass definition, and calculating compliance with four standards instead of one. Regulated parties will need to establish new contractual relationships to cover the different types of renewable fuel required under RFS2. Parties that [[Page 24914]] produce MVNRLM diesel but not gasoline will be newly obligated parties and may be establishing IT systems for the RFS program for the first time. For RFS1, regulated parties had four months between promulgation of the final rulemaking on May 1, 2007 and the start of the program on September 1, 2007. However, this was for a new program that had not existed before. For the RFS2 program, most regulated parties will already be familiar with the general requirements for RIN generation, transfer, and use, and the attendant recordkeeping and reporting requirements. We believe that with proper attention to the implementation requirements by regulated parties, the RFS2 program can be implemented on January 1, 2010 following release of the final rule. Although we are proposing that the RFS2 regulatory program begin on January 1, 2010, we seek comment on whether a start date later than January 1, 2010 would be necessary. Alternative effective dates for the RFS2 program include January 1, 2011 and a date after January 1, 2010 but before January 1, 2011. We are requesting comment on all issues related to such an alternative effective date, including the need for such a delayed start, treatment of diesel producers and importers, whether the standards for advanced biofuel, cellulosic biofuel and biomass-based diesel should apply to the entire 2010 production or just the production that would occur after the RFS2 effective date, and the extent to which RFS1 RINs should be valid to show compliance with RFS2 standards. Further discussion of alternative effective dates for RFS2 can be found in Section III.E.1.d. 6. Treatment of Required Volumes Preceding the RFS2 Effective Date We are proposing that the RFS2 regulatory program begin on January 1, 2010. Under CAA section 211(o), the requirements for refiners, blenders, and importers (called ``obligated parties'') as well as the requirements for producers of renewable fuel and others, stem from the regulatory provisions adopted by EPA. In effect while EPAct and EISA both call for EPA to issue regulations that achieve certain results, the various regulated parties are not subject to these requirements until EPA issues the regulations establishing their obligations. The changes brought about by EISA, such as the 4 separate standards, the lifecycle GHG thresholds, changes to obligated parties, and the revised definition of renewable biomass do not become effective until today's proposal is finalized. Rather, the current RFS1 regulations continue to apply until EPA amends them to implement EISA, and any delay in issuance of the RFS2 regulations means that parties would continue to be subject to the RFS1 regulations until the RFS2 regulations were in effect. Therefore, regulated parties would continue to be subject to the existing regulations at 40 CFR Part 80 Subpart K through December 31, 2009, or later if the effective date of the RFS2 program were later than January 1, 2010. Under the RFS1 regulations the annual percentage standards that are applicable to obligated parties are determined by a formula set forth in the regulations. The formula uses gasoline volume projections from the Energy Information Administration (EIA) and the required volume of renewable fuel provided in Clean Air Act section 211(o)(2)(B). Since EISA modified the required volumes in this section of the Clean Air Act, EPA believes that the new statutory volumes can be used under the RFS1 regulations in generating the standards for 2009. Therefore, in November 2008 we used the new total renewable fuel volume of 11.1 billion gallons as the basis for the 2009 standard, and not the 6.1 billion gallons that was required by EPAct.\3\ --------------------------------------------------------------------------- \3\ 73 FR 70643, November 21, 2008. --------------------------------------------------------------------------- While this approach will ensure that the total renewable fuel volume of 11.1 billion gallons required by EISA for 2009 will be used, the RFS1 regulatory structure does not provide a mechanism for implementing the 0.5 billion gallon requirement for biomass-based diesel nor the 0.6 billion gallon requirement for advanced biofuel. As described in more detail in Section III.E.2, we are proposing to address this issue by increasing the 2010 biomass-based diesel requirement by 0.5 billion gallons and allowing 2009 biodiesel and renewable diesel RINs to be used to meet this combined 2009/2010 requirement. Doing so would also allow most of the 2009 advanced biofuel requirement to be met. We believe this would provide a similar incentive for biomass-based diesel use in 2009 as would have occurred had we been able to implement this standard for 2009. We propose that this requirement would apply to all obligated parties under RFS2, including producers and importers of diesel fuel. As noted above, EPA is proposing a start date for the RFS2 program of January 1, 2010, and is also seeking comment on alternative start dates of sometime during 2010 or January 1, 2011. If the start date is other than January 1, 2010, EPA would need to determine what renewable fuel volumes to require in the interim between January 1, 2010 and the start of the RFS2 program. While we could apply the same approach, described above, that we have used for 2009, doing so could mean that 2009 biodiesel RINs would be valid for compliance purposes in 2011, which would run counter to the statutory valid life of two years. Nevertheless, we request comment on whether this potential approach or another approach is warranted based on the differing volumes and types of renewable fuel specified for use in EISA for 2010. 7. Waivers and Credits for Cellulosic Biofuel Section 202(e) of EISA provides that for any calendar year in which the projected volume of cellulosic biofuel production is less than the minimum applicable volume required by the statute, EPA will waive a portion of the cellulosic biofuel standard by using the projected volume as the basis for setting the applicable standard. In this event, EISA also allows but does not require EPA to reduce the required volume of advanced biofuel and total renewable fuel. The process of projecting the volume of cellulosic biofuel that may be produced in the next year, and the associated process of determining whether and to what degree the advanced biofuel and total renewable fuel requirements should be lowered, will involve considerations that extend beyond the simple calculation based on gasoline demand that was used to set the annual standards under RFS1. As a result, we believe that this process should be subject to a notice-and-comment rulemaking process. Moreover, since we must make these determinations every year for application to the following year, we expect to conduct these rulemakings every year. In determining whether the advanced biofuel and/or total renewable fuel volume requirements should also be adjusted downward in the event that projected volumes of cellulosic biofuel fall short of the statutorily required volumes, we believe it would be appropriate to allow excess advanced biofuels to make up some or all of the shortfall in cellulosic biofuel. For instance, if we determined that sufficient biomass-based diesel was available, we could decide that the required volume of advanced biofuel need not be lowered, or that it should be lowered to a smaller degree than the required cellulosic biofuel volume. We would then lower the total renewable fuel volume to the same degree that we [[Page 24915]] would lower the advanced biofuel volume. We do not believe it would be appropriate to lower the advanced biofuel standard but not the total renewable standard, as this would allow conventional biofuels to effectively be used to meet the standards Congress specifically set for cellulosic and advanced biofuels. If EPA reduces the required volume of cellulosic biofuel, EPA must offer a number of credits no greater than the reduced cellulosic biofuel standard. EISA dictates the cost of these credits and ties them to inflation. The Act also dictates that we must promulgate regulations on the use of these credits and offers guidance on how these credits may be offered and used. We propose that their uses will be very limited. The credits would not be allowed to be traded or banked for future use, but would be allowed to meet the cellulosic biofuel standard, advanced biofuel standard and total renewable fuel standard. Further discussion of the implementation of these provisions can be found in Section III.I. 8. Proposed Standards for 2010 Once the RFS2 program is implemented, we expect to conduct a notice-and-comment rulemaking process each year in order to determine the appropriate standards applicable in the following year. We therefore intend to issue an NPRM in the spring and a final rule by November 30 of each year as required by statute. However, for the 2010 compliance year, today's action provides a means for seeking comment on the applicable standards. Therefore, rather than issuing a separate NPRM for the 2010 standard, we are proposing the 2010 standards in today's notice. We will consider comments received during the comment period associated with today's NPRM, and we expect to issue a Federal Register notice by November 30, 2009 setting the applicable standards for 2010. We propose that the RFS2 program be effective on January 1, 2010. Therefore, all EISA volume mandates for 2010 would be implemented in that year, unless EPA exercised its authority to waive one or more of the standards. Based on information from the industry, we believe that there are sufficient plans underway to build plants capable of producing 0.1 billion gallons of cellulosic biofuel in 2010, the minimum volume of cellulosic biofuel required by EISA for 2010. However, we recognize that cellulosic biofuel is at the very earliest stages of commercialization and current economic concerns could have significant impacts on these near term plans. Therefore, while based on industry plans available to EPA, we are not proposing that any portion of the cellulosic biofuel requirement for 2010 be waived, we are seeking additional and updated information that would be available prior to November 30, 2009 which could result in a change in this conclusion. Similarly, we are not aware of the need to waive any other volume mandates for 2010. Therefore, we are proposing that the volumes shown in Table II.A.1-1 for all four renewable fuel categories be used as the basis for the applicable standards for 2010. The proposed standards are shown in Table II.A.8-1, each representing the fraction of a refiner's or importer's gasoline and diesel volume which must be renewable fuel. Table II.A.8-1--Proposed Standards for 2010 [Percent] ------------------------------------------------------------------------ ------------------------------------------------------------------------ Cellulosic biofuel............................................. 0.06 Biomass-based diesel........................................... 0.71 Advanced biofuel............................................... 0.59 Renewable fuel................................................. 8.01 ------------------------------------------------------------------------ Note that the proposed 2010 standards shown in Table II.A.8-1 were based on currently available projections of 2010 gasoline and diesel volumes. The final standards will be calculated on the basis of gasoline and diesel volume projections from the Energy Information Administration's (EIA) Short-Term Energy Outlook and published by November 30, 2009. Additional discussion of our proposed 2010 standards can be found in Section III.E.1.b. Note also that the proposed standards assume an effective date of January 1, 2010 for RFS2. We are taking comment on alternative effective dates for RFS2, including January 1, 2011 and a date after January 1, 2010 but before January 1, 2011. Such alternative effective dates would raise issues with regard to the calculation and application of the standards for total renewable fuel and the other standards required under EISA, as well as the generation and application of RINs under RFS1 and RFS2. As described more fully in Section III.E.1.d, we request comment on the issues associated with alternative effective dates for RFS2. B. Impacts of Increasing Volume Requirements in the RFS2 Program The displacement of gasoline and diesel with renewable fuels has a wide range of environmental and economic impacts. As we describe below, we have assessed many of these impacts for the RFS2 proposal and we will have more complete assessments, including a cost-benefit comparison, for the final rule. These assessments provide important information to the wider public policy considerations of renewable fuels, climate change, and national energy security. They are also an important component of all significant rulemakings. However, because the volumes of renewable fuel were specified by statute, they would not be based on or revised by our analysis of impacts. In addition, because we have very limited discretion to pursue regulatory alternatives, the proposal does not include a systematic alternatives analysis. We have investigated regulatory alternatives in some areas to the degree that EISA provides discretion. As one point of reference to assess the impacts of the volume requirements for the RFS2 program, we used projections for renewable fuel use in 2022 that EIA issued through their 2007 Annual Energy Outlook (AEO), and for transportation fuel consumption through their 2008 AEO. This reference case, referred to as the ``AEO Reference Case,'' represents a projection of the demand for renewable fuels prior to enactment of EISA while still reflecting the new Corporate Average Fuel Economy (CAFE) requirements in EISA, and the 2008 AEO projections for the future price of crude oil ($53 to $92 per barrel). Further discussion of the Reference Case can be found in Section V.A.1. Other points of reference include the renewable fuel volumes mandated by EPAct for the RFS1 program, renewable fuel use prior to implementation of the RFS1 program, and the full impacts of renewable fuel use compared to a petroleum-only economy. Given the short time provided by Congress to conduct a rulemaking, many of our analyses were done in parallel for this proposal. As a result, some analyses were conducted without the benefit of waiting for the conclusion of another analysis that could prove influential. Thus, for example, impacts on food prices assume that soy-based biodiesel and sugarcane ethanol will qualify as advanced fuels under the proposed RFS2 program, even though the analyses conducted for this proposal might preclude such eligibility. We have highlighted such inconsistencies in results and assumptions throughout the proposal. Additionally, since we have identified many issues and analytical options in our assessment of which biofuel pathways would comply with the GHG thresholds, the assessment we [[Page 24916]] conducted for this proposal may not reflect the final rule in all cases. We will be addressing these issues of analytical consistency between analyses more fully in the final rule. In a similar fashion, while we recognize uncertainty in our assessment of impacts of the proposed RFS2 program, we do not present a formal, comprehensive analysis of uncertainty. For this proposal, many of the analyses are without precedent, and as a result we have identified the more uncertain aspects of these analyses and have worked to assess their potential impact on the results through sensitivity analyses. We intend to continue these assessments for the final rule, and expect that comments on this proposal will allow us to reduce our uncertainty in a number of areas. In addition to this sensitivity analysis approach, we will also explore options for more formal uncertainty analyses for the final rule to the extent possible. 1. Greenhouse Gases and Fossil Fuel Consumption Our analyses of GHG impacts consider the full useful life assessment of the production of biofuels compared to the petroleum- based fuels they would replace. The analysis compared the AEO reference case transportation fuel pool in 2022 without the EISA mandates with the same fuel pool in 2022, but assuming the greater volumes of biofuel as mandated by EISA replace an energy equivalent amount of petroleum- based fuel. The incremental volumes of each biofuel type were then evaluated to determine their average impact on GHG emissions compared to the 2005 baseline petroleum fuel they would be displacing. These average GHG emission reduction results can then be compared to the threshold performance levels for each fuel type. As a result of the transition to greater renewable fuel use, some petroleum-based gasoline and diesel will be directly replaced by renewable fuels. Therefore, consumption of petroleum-based fuels will be lower than it would be if no renewable fuels were used in transportation vehicles. However, a true measure of the impact of greater use of renewable fuels on petroleum use, and indeed on the use of all fossil fuels, accounts not only for the direct use and combustion of the finished fuel in a vehicle or engine, but also includes the petroleum use associated with production and transportation of that fuel. For instance, fossil fuels are used in producing and transporting renewable feedstocks such as plants or animal byproducts, in converting the renewable feedstocks into renewable fuel, and in transporting and blending the renewable fuels for consumption as motor vehicle fuel. Likewise, fossil fuels are used in the production and transportation of petroleum and its finished products. In order to estimate the true impacts of increases in renewable fuel use on fossil fuel use, we must take these steps into account. Such analyses are termed lifecycle analyses. The definition of lifecycle greenhouse gas emissions in EISA requires the Agency to look broadly at lifecycle analyses and to develop a methodology that accounts for the significant secondary or indirect impacts of expanded biofuels use. These indirect effects include both the domestic and international impact of land use change from increased biofuel feedstock production and the secondary agricultural sector GHG impacts from increased biofuel feedstock production (e.g., changes in livestock emissions due to changes in agricultural commodity prices). Today no single model can capture all of the complex interactions required to conduct a complete lifecycle assessment as required by Congress. As a result, the methodology EPA has currently evaluated uses a number of models and tools to provide a comprehensive estimate of GHG emissions. We have used a combination of peer reviewed models including Argonne National Laboratory's GREET model, Texas A&M's Forestry and Agricultural Sector Optimization Model (FASOM) and Iowa State University's Food and Agricultural Policy Research Institute's (FAPRI) international agricultural models as well as the Winrock International database to estimate lifecycle GHG emissions estimates. These models are described in more detail in Section VI and have been used in combination to provide the lifecycle GHG estimates presented in this proposal. However, we recognize other models and sources of information can also be used and these are also discussed in Section VI. Based on the combined use of these models we have estimated the lifecycle GHG emissions for a number of pathways for producing the increased volumes of renewable fuels as mandated by EISA. Section VI of this proposal outlines the approach taken and describes the key assumptions and parameters used in this analysis. In addition, this section highlights the impacts of varying these key inputs on the overall results. We estimate the greater volumes of biofuel mandated by RFS2 will reduce lifecycle GHG emissions from transportation by approximately 6.8 billion tons of CO2 equivalent emissions when accounting for all the emissions changes over 100 years and then discounting this emission stream by 2% per year. This is equivalent to an average annualized emission rate of 160 million metric tons of CO2- eq. emissions per year over the entire 100 year modeling time frame if that average annualized emission rate is also discounted at 2% per year. Determining lifecycle GHG emissions values for renewable fuels using a 0% discount rate over 30 years would result in an estimated total reduction of 4.5 billion tons of CO2-eq. over the 30 year period or an average annualized emission rate reduction of 150 million metric tons of CO2-eq. GHG emissions per year. (See Section VI.F of this preamble for additional information on how these emission reductions were calculated). Our analysis of the petroleum consumption impacts took a similar lifecycle approach. For the year 2022, we estimate that the 36 billion gallons of renewable fuel mandated by these rules will increase renewable fuel usage by approximately 22 billion gallons which will displace about 15 billion gallons of petroleum-based gasoline and diesel fuel. This represents about 8% of annual oil consumed by the transportation sector in 2022. 2. Economic Impacts and Energy Security The substantially increased volumes of renewable fuel that would be required under RFS2 would produce a variety of different economic impacts. These would include changes in the cost of gasoline and diesel, a reduction in nationwide expenditures on petroleum imports and the associated increase in energy security, and increases in the prices of agricultural commodities such as corn and soybeans. The RFS program is projected to significantly impact the cost of gasoline and diesel, though the estimated costs vary based on the price of crude oil that is assumed. In our analysis we used both $92 and $53 per barrel crude oil based on price projections made by EIA. At these two crude oil price points, we estimate that gasoline costs would increase by about 2.7 and 10.9 cents per gallon, respectively, by 2022. Likewise, diesel fuel costs could experience a small cost reduction of 0.1 cents per gallon, or increase by about 1.2 cent per gallon, respectively. For the nation as a whole, these costs are equivalent to $4 and $18 billion in 2022, respectively (in 2006 dollars, and amortizing capital costs using a 7% before-tax rate of return). These costs represent the nationwide average impacts including the costs of producing and distributing [[Page 24917]] both renewable fuels and gasoline and diesel, as well as blending costs, but without consideration of either the tax subsidies and import tariff for ethanol or tax subsidies for biodiesel and renewable diesel fuel. EPA's estimates of economic impacts of fuels do not consider other societal benefits. For example, the displacement of petroleum-based fuel (largely imported) by renewable fuel (largely produced in the United States), should reduce our consumption of imported oil and fuel. We estimate that 91% of the lifecycle petroleum reductions resulting from the use of renewable fuel will be met through reductions in net petroleum imports. In Section IX of this preamble we estimate the value of the decrease in imported petroleum at about $12.4 billion in 2022 due to increased volumes of renewable fuels mandated by RFS2 in comparison to the AEO reference case. Net U.S. expenditures on petroleum imports in 2022 are projected to be about $208 billion. Furthermore, the above estimate of reduced U.S. petroleum import expenditures only partly assesses the economic impacts of this proposal. One of the effects of increased use of renewable fuel is that it diversifies the energy sources used in making transportation fuel. To the extent that diverse sources of fuel energy reduce the U.S. dependence on any one source, the risks, both financial as well as strategic, of a potential disruption in supply of a particular energy source are reduced. EPA has worked with researchers at Oak Ridge National Laboratory (ORNL) to update a study they previously published that has been used or cited in several government actions impacting U.S. oil consumption. This updated study went through an independent, third-party peer review process and a final draft report of this updated study was developed. This peer-reviewed report is being made available in the docket at this time for further consideration. Using the updated ORNL estimate, the total energy security benefits associated with a reduction of U.S. imported oil is $12.38 per barrel of imported oil that is reduced. Based on these values, we estimate that the total annual energy security benefits would be $3.7 billion in 2022 (in 2006 dollars). We recognize that our current energy security analysis does not take into account risk-shifting that might occur as the U.S. reduces its dependency on petroleum by increasing its use of biofuels. For example, our analysis did not take into account other energy security implications associated with biofuels, such as possible supply disruptions of corn-based ethanol. We will attempt to broaden our energy security analysis to incorporate estimates of overall motor fuel supply and demand flexibility and reliability for the final rule, along with impacts of possible agricultural sector market disruptions. A complete discussion of the Agency's plans for this analysis can be found in Section IX.B.2. of this preamble. While increased use of renewable fuel will reduce expenditures on imported oil, it will also increase expenditures on renewable fuels and in turn on the sources of those renewable fuels. The RFS program is likely to spur the increased use of renewable transportation fuels made principally from agricultural crops and it is expected that most of these crops will be produced in the U.S. As a result, it is important to analyze the consequences of the transition to greater renewable fuel use in the U.S. agricultural sector. To analyze the domestic agricultural sector impacts, EPA selected the Forest and Agricultural Sector Optimization Model (FASOM) developed by Professor Bruce McCarl of Texas A&M University and others over the past thirty years. FASOM is a dynamic, nonlinear programming model of the agriculture and forestry sectors of the U.S. In Section IX of this preamble, we estimate the change in the price of various agricultural products as a result of this rulemaking. By 2022, we estimate the price of corn would increase by $0.15 per bushel (4.6%) above the Reference Case price of $3.19 per bushel. By 2022, U.S. soybean prices would increase by $0.29 per bushel (2.9%) above the Reference Case price of $9.97 per bushel. Due to higher commodity prices, FASOM estimates that U.S. food costs would increase by $10 per person per year by 2022, relative to the Reference Case. Total farm gate food costs would increase by $3.3 billion (0.2%) in 2022. As a result of increased renewable fuel requirements, FASOM predicts that net U.S. farm income would increase by $7.1 billion dollars in 2022 (10.6%), relative to the Reference Case. Due to higher commodity prices, FASOM estimates that U.S. corn exports would drop from 2.7 billion bushels under the Reference Case to 2.4 billion bushels (a 10% decrease) by 2022. In value terms, U.S. exports of corn would fall by $487 million in 2022. FASOM estimates that U.S. exports of soybeans would decrease from 1.03 billion bushels to 943 million bushels (an 8% decrease) in 2022. In value terms, U.S. exports of soybeans would decrease by $691 million in 2022. Assuming current subsidies remain in place, the Renewable Fuels Standard, by encouraging the use of biofuels, will result in an expansion of subsidy payments by the U.S. government. If this resulting loss of tax revenue were offset by an increase in taxes, this could have a distortionary impact on the economy. We intend to consider the impact of the expansion of biofuel subsidies associated with the RFS2 in the context of the economy-wide modeling to be conducted for the final rule. We note that the economic analyses that support this proposal do not reflect all of the potentially quantifiable economic impacts. There are several key impacts that remain incomplete as a result of time and resource constraints, including the economic impact analysis (see Section IX) and the air quality and health impacts analysis (see Section II.B.3). As a result, this proposal does not combine economic impacts in an attempt to compare costs and benefits, in order to avoid presenting an incomplete and potentially misleading characterization. For the final rule, when the planned analyses are complete and current analyses updated, we will provide a consistent cost-benefit comparison. 3. Emissions, Air Quality, and Health Impacts Analysis of criteria and toxic emission impacts was performed relative to three different reference case ethanol volumes, ranging from 3.64 to 13.2 billion gallons per year. To assess the total impact of the RFS program, emissions were analyzed relative to the RFS1 rule base case of 3.64 billion gallons in 2004. To assess the impact of today's RFS2 proposal relative to the current mandated volumes, we analyzed impacts relative to RFS1 mandate of 7.5 billion gallons of renewable fuel use by 2012, which was estimated to include 6.7 billion gallons of ethanol.\4\ In order to assess the impact of today's proposal relative to the level of ethanol projected to be used in 2022 without RFS2, the AEO2007 projection of 13.2 billion gallons of ethanol in 2022 was analyzed. --------------------------------------------------------------------------- \4\ RFS1 base and mandated ethanol levels were projected to remain essentially unchanged in 2022 due to the flat energy demands projected by EIA. --------------------------------------------------------------------------- We are also presenting a range of impacts meant to bracket the impacts of ethanol blends on light-duty vehicle emissions. Similar to the approach presented in the RFS1 rule, we present a ``less sensitive'' and ``more sensitive'' case to present a range of the possible [[Page 24918]] emission impacts of E10 on recent model year light duty gasoline vehicles. As detailed in Section VII.C, ``less sensitive'' does not apply any E10 effects to NOX or HC emissions for later model year vehicles, or E85 effects for any pollutant, while ``more sensitive'' does. Our projected emission impacts for the ``less sensitive'' and ``more sensitive'' cases are shown in Table II.B.3-1 and II.B.3-2, showing the expected emission changes for the U.S. in 2022, and the percent contribution of this impact relative to the total U.S. inventory across all sectors. Overall we project the proposed program will result in significant increases in ethanol and acetaldehyde emissions--increasing the total U.S inventories of these pollutants by up to 30-40% in 2022 relative to the RFS1 mandate case. We project more modest but still significant increases in acrolein, NOX, formaldehyde and PM. We project today's action will result in decreased ammonia emissions (due to reductions in livestock agricultural activity), decreased CO emissions (driven primarily by the impacts of ethanol on exhaust emissions from vehicles and nonroad equipment), and decreased benzene emissions (due to displacement of gasoline with ethanol in the fuel pool). Discussion and a breakdown of these results by the fuel production/distribution and vehicle and equipment emissions are presented in Section VII. Table II.B.3-1--RFS2 ``Less Sensitive'' Case Emission Impacts in 2022 Relative to Each Reference Case -------------------------------------------------------------------------------------------------------------------------------------------------------- RFS1 base RFS1 mandate AEO2007 ----------------------------------------------------------------------------------------------- Pollutant Annual short % of total Annual short % of total Annual short % of total tons U.S. inventory tons U.S. inventory tons U.S. inventory -------------------------------------------------------------------------------------------------------------------------------------------------------- NOX..................................................... 312,400 2.8 274,982 2.5 195,735 1.7 HC...................................................... 112,401 1.0 72,362 0.6 -8,193 -0.07 PM10.................................................... 50,305 1.4 37,147 1.0 9,276 0.3 PM2.5................................................... 14,321 0.4 11,452 0.3 5,376 0.16 CO...................................................... -2,344,646 -4.4 -1,669,872 -3.1 -240,943 -0.4 Benzene................................................. -2,791 -1.7 -2,507 -1.5 -1,894 -1.1 Ethanol................................................. 210,680 36.5 169,929 29.4 83,761 14.5 1,3-Butadiene........................................... 344 2.9 255 2.1 65 0.5 Acetaldehyde............................................ 12,516 33.7 10,369 27.9 5,822 15.7 Formaldehyde............................................ 1,647 2.3 1,348 1.9 714 1.0 Naphthalene............................................. 5 0.03 3 0.02 -1 -0.01 Acrolein................................................ 290 5.0 252 4.4 174 3.0 SO2..................................................... 28,770 0.3 4,461 0.05 -47,030 -0.5 NH3..................................................... -27,161 -0.6 -27,161 -0.6 -27,161 -0.6 -------------------------------------------------------------------------------------------------------------------------------------------------------- Table II.B.3-2--RFS2 ``More Sensitive'' Case Emission Impacts in 2022 Relative to Each Reference Case -------------------------------------------------------------------------------------------------------------------------------------------------------- RFS1 base RFS1 mandate AEO2007 ----------------------------------------------------------------------------------------------- Pollutant Annual short % of total Annual short % of total Annual short % of total tons U.S. inventory tons U.S. inventory tons U.S. inventory -------------------------------------------------------------------------------------------------------------------------------------------------------- NOX..................................................... 402,795 3.6 341,028 3.0 210,217 1.9 HC...................................................... 100,313 0.9 63,530 0.6 -15,948 -0.14 PM10.................................................... 46,193 1.3 33,035 0.9 5,164 0.15 PM2.5................................................... 10,535 0.3 7,666 0.2 1,589 0.05 CO...................................................... -3,779,572 -7.0 -3,104,798 -5.8 -1,675,869 -3.1 Benzene................................................. -5,962 -3.5 -5,494 -3.3 -4,489 -2.7 Ethanol................................................. 228,563 39.6 187,926 32.5 105,264 18.2 1,3-Butadiene........................................... -212 -1.8 -282 -2.4 -430 -3.6 Acetaldehyde............................................ 16,375 44.0 14,278 38.4 9,839 26.5 Formaldehyde............................................ 3,373 4.7 3,124 4.3 2,596 3.6 Naphthalene............................................. -175 -1.2 -178 -1.3 -187 -1.3 Acrolein................................................ 253 4.4 218 3.8 143 2.5 SO2..................................................... 28,770 0.3 4,461 0.05 -47,030 -0.5 NH3..................................................... -27,161 -0.6 -27,161 -0.6 -27,161 -0.6 -------------------------------------------------------------------------------------------------------------------------------------------------------- We note that the aggregate nationwide emission inventory impacts presented here will likely lead to health impacts throughout the U.S. due to changes in future-year ambient air quality. However, emissions changes alone are not a good indication of local or regional air quality and health impacts, as there may be highly localized impacts such as increased emissions from ethanol plants and evaporative emissions from cars, and decreased emissions from gasoline refineries. In addition, the atmospheric chemistry related to ambient concentrations of PM2.5, ozone and air toxics is very complex, and making predictions based solely on emissions changes is extremely difficult. Full-scale photochemical modeling is necessary to provide the needed spatial and temporal detail to more completely and accurately estimate the changes in ambient levels of these pollutants. As discussed in Section VII.D, timing and resource constraints precluded EPA from conducting a full-scale photochemical air quality modeling analysis in time for the NPRM. For the final rule, however, a national-scale air quality modeling analysis will be performed to analyze the impacts of the proposed standards on PM2.5, ozone, and selected air toxics (i.e., benzene, formaldehyde, acetaldehyde, ethanol, acrolein and 1,3-butadiene). As described in Section VII.D.2, EPA intends to use a 2005-based Community Multi-scale Air Quality (CMAQ) modeling platform as the tool for the air [[Page 24919]] quality modeling. The CMAQ modeling system is a comprehensive three- dimensional grid-based Eulerian air quality model designed to estimate the formation and fate of oxidant precursors, primary and secondary PM concentrations and deposition, and air toxics, over regional and urban spatial scales (e.g., over the contiguous U.S.). The lack of air quality modeling data also precluded EPA from conducting its standard analysis of human health impacts, where CMAQ output data are used as inputs to the Environmental Benefits Mapping and Analysis Program (BenMAP). Section IX.D of this preamble describes the human health impacts that will be quantified and monetized for the final rule, as well as the unquantified impacts that will be qualitatively described. 4. Water As the production of biofuels increases to meet the requirements of this proposed rule, there may be adverse impacts on both water quality and quantity. Increased production of biofuels may lead to increased application of fertilizer and pesticides and increased soil erosion, which could impact water quality. Since ethanol production uses large quantities of water, the supply of water could also be significantly impacted in some locations. EPA focused the water quality analysis for this proposal on the impacts of corn produced for ethanol for several reasons. Corn has the highest fertilizer and pesticide use per acre and accounts for the largest share of nitrogen fertilizer use among all crops. Furthermore, corn-based ethanol is expected to be a large component of the biofuels mix. Fertilizer nutrients that are not used by the crops are available to runoff to surface water or leach into groundwater. Nutrient enrichment due to human activities is one of the leading problems facing our nation's lakes, reservoirs, and estuaries, and also has negative impacts on aquatic life in streams; adverse health effects on humans and domestic animals; and impairs aesthetic and recreational use. Excess nutrients can lead to excessive growth of algae in rivers and streams, and aquatic plants in all waters. Nutrient pollution is widespread. The most widely known examples of significant nutrient impacts include the Gulf of Mexico and the Chesapeake Bay, however waterbodies in virtually every state and territory are impacted by nutrient-related degradation. A more detailed discussion of nutrient pollution can be found in Section X of this preamble and in Chapter 6 of the DRIA. To provide a quantitative estimate of the impact of this proposal and production of corn ethanol generally on water quality, EPA conducted an analysis that modeled the changes in loadings of nitrogen, phosphorus, and sediment from agricultural production in the Upper Mississippi River Basin (UMRB). The UMRB is representative of the many potential issues associated with ethanol production, including its connection to major water quality concerns such as Gulf of Mexico hypoxia, large corn acreage, and numerous ethanol production plants. The UMRB contributes 39% of nitrogen loads and 26% of phosphorus loads to the Gulf of Mexico. EPA selected the SWAT (Soil and Water Assessment Tool) model to assess nutrient loads from changes in agricultural production in the UMRB. SWAT is a physical process model developed to quantify the impact of land management practices in large, complex watersheds. In conducting its analysis EPA quantified the impacts from a baseline that preceded the current high production of ethanol from corn to four future years--2010, 2015, 2020 and 2022. Table II.B.4-1 summarizes the model outputs at the outlet of the UMRB in the Mississippi River at Grafton, Illinois for each of the four scenario years. The local impact in smaller watersheds within the UMRB may be significantly different. The decreasing nitrogen load over time is likely attributed to the increased corn yield production, resulting in greater plant uptake of nitrogen. The relatively stable sediment loadings are likely due to the fact that corn was modeled assuming that corn stover is left on the fields following harvest. Table II.B.4-1--Changes From the 2005 Baseline to the Mississippi River at Grafton, Illinois From the Upper Mississippi River Basin ---------------------------------------------------------------------------------------------------------------- 2005 Baseline 2010 2015 2020 2022 ---------------------------------------------------------------------------------------------------------------- Average corn yield (bushels/acre)......... 141......................... 150 158 168 171 Nitrogen.................................. 1433.5 million lbs.......... +5.5% +4.7% +2.5% +1.8% Phosphorus................................ 132.4 million lbs........... +2.8% +1.7% +0.98% +0.8% Sediment.................................. 6.4 million tons............ +0.5% +0.3% +0.2% +0.1% ---------------------------------------------------------------------------------------------------------------- After evaluating comments on this proposal, if time and resources permit, EPA may conduct additional water quality analyses using the SWAT model in the UMRB. Potential future analyses could include: (1) Determination of the most sensitive assumptions in the model, (2) water quality impacts from the changes in ethanol volumes between the reference case and this proposal, (3) removing corn stover for cellulosic ethanol, and (4) a case study of a smaller watershed to evaluate local water quality impacts that are impossible to ascertain at the scale of the UMRB. EPA also qualitatively examined other water issues, which are also discussed in detail in Section X of this Preamble, and Chapter 6 of the DRIA. 5. Agricultural Commodity Prices The recent increase in food prices, both domestically and internationally, has raised the issue of whether diverting grains and oilseeds for fuel production is having a large impact on commodity markets. While we share the concern that food prices have increased significantly over the same time period in which renewable fuel production has increased, many factors have contributed to recent increases in food prices. As described by the U.S. Department of Agriculture (USDA), the Department of Energy (DOE), the Council of Economic Advisors (CEA), and others, the recent increase in commodity prices has been influenced by factors as diverse as world economic growth, droughts in Australia, China and Eastern Europe, increasing oil prices, changes in investment strategies, and the declining value of the U.S. dollar. While the increase in renewable fuel production has contributed to the increase in commodity prices, the magnitude of the contribution of the RFS has most likely been minor, as market conditions have continued to push renewable fuel use beyond the mandated levels. As the mandated levels of renewable fuels continue to rise in the future, our [[Page 24920]] economic modeling suggests that the impact of the RFS2 program on food prices will continue to be modest, particularly with the expansion of cellulosic biofuels. Table II.B.5-1 summarizes the changes in prices for some commodities we have estimated for this proposal. Further discussion can be found in Section IX.A. Table II.B.5-1--Change in U.S. Commodity Prices for 2022 in Comparison to the Reference Case [2006$] ------------------------------------------------------------------------ ------------------------------------------------------------------------ Corn............................... $0.15/bushel. Soybeans........................... $0.29/bushel. Sugarcane.......................... $13.34/ton. Beef............................... $0.93/hundred pounds. ------------------------------------------------------------------------ II. What Are the Major Elements of the Program Required Under EISA? While EISA made a number of changes to CAA section 211(o) that must be reflected in the RFS program regulations, it left many of the basic program elements intact, including the mechanism for translating national renewable fuel volume requirements into applicable standards for individual obligated parties, requirements for a credit trading program, geographic applicability, treatment of small refineries, and general waiver provisions. As a result, we propose that many of the regulatory requirements of the RFS1 program would remain largely or, in some cases, entirely unchanged. These provisions would include the distribution of RINs, separation of RINs, use of RINs to demonstrate compliance, provisions for exporters, recordkeeping and reporting, deficit carryovers, and the valid life of RINs. The primary elements of the RFS program that we propose changing to implement the requirements in EISA fall primarily into the following five areas: (1) Expansion of the applicable volumes of renewable fuel (2) Separation of the volume requirements into four separate categories of renewable fuel, with corresponding changes to the RIN and to the applicable standards (3) Changes to the definition of renewable fuels and criteria for determining which if any of the four renewable fuel categories a given renewable fuel is eligible to meet (4) Expansion of the fuels subject to the standards (and applicable to refiners, blenders, and importers of those fuels) to include diesel and certain nonroad fuels (5) Inclusion of specific types of waivers and EPA-generated credits for cellulosic biofuel. EISA does not change the basic requirement under CAA 211(o) that the RFS program include a credit trading program. In the May 1, 2007 final rulemaking implementing the RFS1 program, we described how we reviewed a variety of approaches to program design in collaboration with various stakeholders. We finally settled on a RIN-based system for compliance and credit purposes as the one which met our goals of being straightforward, maximizing flexibility, ensuring that volumes are verifiable, and maintaining the existing system of fuel distribution and blending. RINs represent the basic framework for ensuring that the statutorily required volumes of renewable fuel are produced and used as transportation fuel in the U.S. The use of RINs is predicated on the fact that once renewable fuels are produced or imported, there is very high confidence that, setting aside exports, all but de minimus quantities will in fact be used as transportation fuel in the U.S. Focusing on production of renewable fuel as a surrogate for the later actual blending and use of such fuel has many benefits as far as streamlining the RFS program and minimizing the impact that the program has on the business operations of the regulated industries. Since the RIN-based system generally has been successful in meeting EPA's goals, we propose to maintain much of its structure under RFS2. This section describes the regulatory changes we propose to implement the new EISA provisions. Section IV describes other changes to the RFS program that we have considered or are proposing, including a concept for an EPA-moderated RIN trading system that would provide a context within which all RIN transfers could occur. A. Changes to Renewable Identification Numbers (RINs) Under RFS2, we propose that each RIN would continue to represent one gallon of renewable fuel for compliance purposes consistent with our approach under RFS1, and the RIN would continue to have 38 digits. In general the codes within the RIN would have the same meaning under RFS2 as they do under RFS1, with the exception of the D code which would be expanded to cover the four categories of renewable fuel defined in EISA. The proposed change to the D code is described in Table III.A-1. Table III.A-1--Proposed Change to D Code ---------------------------------------------------------------------------------------------------------------- D value Meaning under RFS1 Meaning under RFS2 ---------------------------------------------------------------------------------------------------------------- 1...................................... Cellulosic biomass ethanol..... Cellulosic biofuel. 2...................................... Any renewable fuel that is not Biomass-based diesel. cellulosic biomass ethanol. 3...................................... Not applicable................. Advanced biofuel. 4...................................... Not applicable................. Renewable fuel. ---------------------------------------------------------------------------------------------------------------- The determination of which D code would be assigned to a given batch of renewable fuel is described in more detail in Section III.D.2 below. As described in Section II.A.5, we are proposing that the RFS2 program go into effect on January 1, 2010. However, we are also taking comment on other potential start dates including January 1, 2011 and dates between January 1, 2010 and January 1, 2011. If we were to start the RFS2 program during 2010 but after January 1, some 2010 RINs would be generated under the RFS1 requirements and others would be generated under the RFS2 requirements, but all RINs generated in 2010 would need to be valid for meeting the appropriate 2010 annual standards. Since RFS1 RINs and RFS2 RINs would differ in the meaning of the D codes, we would need a mechanism for distinguishing between these two categories of RINs in order to appropriately apply them to the standards. One straightforward way of accomplishing this would be to use values for the D code under RFS2 that do not overlap the values for the D code under RFS1. Table III.A-2 describes the D code definitions under such an alternative approach. [[Page 24921]] Table III.A-2--Alternative D Code Definitions ---------------------------------------------------------------------------------------------------------------- D value Meaning under RFS1 Meaning under RFS2 ---------------------------------------------------------------------------------------------------------------- 1...................................... Cellulosic biomass ethanol..... Not applicable. 2...................................... Any renewable fuel that is not Not applicable. cellulosic biomass ethanol. 3...................................... Not applicable................. Cellulosic biofuel. 4...................................... Not applicable................. Biomass-based diesel. 5...................................... Not applicable................. Advanced biofuel. 6...................................... Not applicable................. Renewable fuel. ---------------------------------------------------------------------------------------------------------------- In this alternative approach, D code values of 1 and 2 would only be relevant for RINs generated under RFS1, and D code values of 3, 4, 5, and 6 would only be relevant for RINs generated under RFS2. As a result, 2010 RINs generated under RFS1 would be subject to our proposed RFS1/RFS2 transition provisions wherein they would be assigned to one of the four annual standards that would apply in 2010 using their RR and/or D codes. See Section III.G.3 for further description of how we propose using RFS1 RINs to meet standards under RFS2. Under RFS2, each batch-RIN generated would continue to uniquely identify not only a specific batch of renewable fuel, but also every gallon-RIN assigned to that batch. Thus the RIN would continue to be defined as follows: RIN: KYYYYCCCCFFFFFBBBBBRRDSSSSSSSSEEEEEEEE Where: K = Code distinguishing assigned RINs from separated RINs YYYY = Calendar year of production or import CCCC = Company ID FFFFF = Facility ID BBBBB = Batch number RR = Code identifying the Equivalence Value D = Code identifying the renewable fuel category SSSSSSSS = Start of RIN block EEEEEEEE = End of RIN block B. New Eligibility Requirements for Renewable Fuels Aside from the higher volume requirements, most of the substantive changes that EISA makes to the RFS program affect the eligibility of renewable fuels in meeting one of the four volume requirements. Eligibility would be determined based on the types of feedstocks that can be used, the land that can be used to grow feedstocks for renewable fuel production, the processes that can be used to convert those feedstocks into fuel, and the lifecycle greenhouse gas (GHG) emissions that can be emitted in comparison to the gasoline or diesel that the renewable fuel displaces. This section describes these eligibility criteria and how we propose to include them in the RFS2 program. 1. Changes in Renewable Fuel Definitions Under the existing Renewable Fuel Standard (RFS1), renewable fuel is defined generally as ``any motor vehicle fuel that is used to replace or reduce the quantity of fossil fuel present in a fuel mixture used to fuel a motor vehicle''. The RFS1 definition includes motor vehicle fuels produced from biomass material such as grain, starch, fats, greases, oils, and biogas. The definition specifically includes cellulosic biomass ethanol, waste derived ethanol, and biodiesel, all of which are defined separately. (See 72 FR 23915.) The definitions of renewable fuels under today's proposed rule (RFS2) are based on the new statutory definition in EISA. Like the existing rules, the definitions in RFS2 include a general definition of renewable fuel, but unlike RFS1, we are including a separate definition of ``Renewable Biomass'' which identifies the feedstocks from which renewable fuels may be made. Another difference in the definitions of renewable fuel is that RFS2 contains three subcategories of renewable fuels: (1) Advanced Biofuel, (2) Cellulosic Biofuel and (3) Biomass-Based Diesel. Each must meet threshold levels of reduction of greenhouse gas emissions as discussed in Section III.B.2. The specific definitions and how they differ from RFS1 follow below. a. Renewable Fuel and Renewable Biomass ``Renewable Fuel'' is defined as fuel produced from renewable biomass and that is used to replace or reduce the quantity of fossil fuel present in a transportation fuel. The definition of ``Renewable Fuel'' now refers to ``transportation fuel'' rather than referring to motor vehicle fuel. ``Transportation fuel'' is also defined, and means fuel used in motor vehicles, motor vehicle engines, nonroad vehicles or nonroad engines (except for ocean going vessels). We propose to allow fuel producers and importers to include electricity, natural gas, and propane (i.e., compressed natural gas (CNG) and liquefied petroleum gas (LPG)) as a RIN-generating renewable fuel in today's program only if they can identify the specific quantities of their product which are actually used as a transportation fuel, and if the fuel is produced from renewable biomass. This may be possible for some portion of electricity, natural gas, and propane since many of the affected vehicles and equipment are in centrally- fueled fleets supplied under contract by a particular producer or importer of natural gas or propane. A producer or importer of electricity, natural gas, or propane who could document the use of his product in a vehicle or engine would be allowed to generate RINs to represent that product, if it met the definition of renewable fuel. Given that the primary use of electricity, natural gas, and propane is not for fueling vehicles and engines, and the producer generally does not know how it will be used, we cannot require that producers or importers of these fuels generate RINs for all the volumes they produce as we do with other renewable fuels. Our proposal to allow electricity, natural gas, and propane to generate RINs under certain conditions is consistent with our treatment of neat renewable fuels under RFS1 and EISA's requirement that all transportation fuels be included in RFS2. With specific regard to renewable electricity, Section 206 of EISA requires the EPA to conduct a study of the feasibility of issuing credits under the RFS2 program for renewable electricity used by electric vehicles. Once completed, this study will provide additional information regarding the means by which renewable electricity is able to generate RINs under the RFS2 program. As an alternative to allowing producers and importers of electricity, natural gas, and propane to generate RINs if they can demonstrate that their product is a renewable fuel and it is used as transportation fuel, we could allow or require parties who supply these fuels to centrally fueled fleets to generate the RINs even if they are not the producer of the fuel. This approach [[Page 24922]] would treat the supplier of the fuel to the fleet as the producer or importer who then generates RINs, as they are the party who in effect changes the fuel from a fuel that can be used in a variety of ways and ensures that it is in fact used as transportation fuel. This alternative approach might enable a larger volume of electricity, natural gas, and propane that is made from renewable biomass and which is actually used in vehicles or engines to be included in our proposed fuels program as RIN-generating, since in many cases a supplier could document the use of these fuels in vehicles or engines, while a producer could not. In addition, in this case the supplier is the party who causes the fuel to transition from general fuel supply to fuel designated for use in motor vehicles or nonroad applications--in that sense, the supplier is more like a producer or importer than the upstream producer or importer. However, if we were to allow the supplier of renewable electricity, natural gas, or propane to generate RINs in such cases, it may also be appropriate to require suppliers of fossil-based electricity, natural gas, or propane to determine a Renewable Volume Obligation (RVO) that includes these fuels used as transportation fuel. See Section III.F.3 for further discussion. We request comment on this alternative approach for generating RINs for renewable electricity, natural gas and propane. The term ``Renewable Biomass'' as defined in EISA, means: 1. Planted crops and crop residue, 2. Planted trees and tree residues, 3. Animal waste material and byproducts, 4. Slash and pre-commercial thinnings (from non-federal forestlands), 5. Biomass cleared from the vicinity of buildings and other areas to reduce the risk of wildfire, 6. Algae, and 7. Separated yard waste or food waste. Section III.B.4 of this preamble outlines our proposed interpretations for most of the key terms contained in the EISA definition of ``renewable biomass'' and possible approaches for implementing the land restrictions on renewable biomass that are included in EISA. It is worth noting here, however, that the statutory definition of ``renewable biomass'' does not include a reference to municipal solid waste (MSW) as did the definition of ``cellulosic biomass ethanol'' in the Energy Policy Act of 2005 (EPAct), but instead includes ``separated yard waste and food waste. EPA's proposed definition of renewable biomass in today's regulation includes the language present in EISA, and we propose to clarify in the regulations that ``yard waste'' is leaves, sticks, pine needles, grass and hedge clippings, and similar waste from residential, commercial, or industrial areas. Nevertheless, EPA invites comment on whether the definition of ``renewable biomass'' should be interpreted as including or excluding MSW from the definition of renewable biomass. While the lack of a reference to MSW and the new listing of separated yard waste and food waste could be readily interpreted to exclude MSW as a qualifying feedstock under RFS2, EPA believes there are indications of ambiguity on this issue and solicits comment on whether EPA can and should interpret EISA as including MSW that contains yard and/or food waste within the definition of renewable biomass. On the one hand, the reference in the statutory definition to ``separated yard waste and food waste,'' and the lack of reference to other components of MSW (such as waste paper and wood waste) suggests that only yard and food wastes physically separated from other waste materials satisfy the definition of renewable biomass as opposed to the yard and food waste present in MSW. This view would exclude unprocessed MSW from any role in the development of renewable fuel under EISA, and would also likely severely limit the amount of yard and food waste available as feedstock for EISA-qualifying fuel, since large quantities of these materials are disposed of as unprocessed MSW. On the other hand, there are some indications that Congress may not have specifically intended to exclude MSW from playing a role in the development of renewable fuels under EISA. For example, ethanol ``derived from waste material'' and biogas ``including landfill gas'' are specifically identified as ``eligible for consideration'' in the definition of advanced biofuel. While landfill gas is generated primarily by the yard waste and food waste in a landfill, these wastes typically are not separated from each other in a landfill. In addition, Congress did not define the term ``separated'' and did not otherwise specify the degree of ``separation'' required of yard and food waste in the definition of renewable biomass. Thus, it might be reasonable to consider these items sufficiently ``separated'' from other materials, including non-waste materials, when food and yard waste is present in MSW. In addition, the processing of MSW to fuel will effectively separate out the materials in MSW that cannot be made into fuel, such as glass and metal, and non-biomass portions of MSW (for example, pastics) could be excluded from getting credit under the RFS program as described in Section III.D.4. EPA invites comment on whether there is enough separation of food and yard waste in MSW used in renewable fuel production for MSW containing yard and food waste to meet the definition of renewable biomass. Approximately 35% by weight of MSW is paper wastes, and another 6% by weight from wood wastes. Combined with food and yard wastes, more than 60% by weight of MSW is biomass that could be used to make ethanol and other renewable fuels.\5\ The volume of ethanol associated with MSW as a feedstock is described in more detail in Section 1.1 of the Draft Regulatory Impact Analysis (DRIA). --------------------------------------------------------------------------- \5\ Construction and demolition (C&D) wastes are not typically considered as elements of MSW. Because they are significant feedstocks for the production of ethanol, we include such wastes in our economic analysis (Section V). Therefore, for all practical purposes, the discussion here as it pertains to whether MSW should be included in the definition of ``renewable biomass'' also applies to C&D wastes. --------------------------------------------------------------------------- Our discussions with stakeholders indicate that a potential concern with interpreting the definition of renewable biomass to include MSW containing yard and/or food waste is that this approach may cause some decrease in the amount of paper that is separated from the MSW waste stream and recycled into paper products. We believe, however, that current waste handling practices and current and anticipated market conditions would continue to provide a strong incentive for paper separation and recycling. A narrow reading of the statute to exclude MSW-derived renewable fuel would directionally reduce the options available for meeting the goal of EISA to reduce our dependence on foreign sources of energy. By including MSW containing yard and/or food waste in the definition of renewable biomass, we could also allow renewable fuel to be produced in part from certain plastics in the MSW waste stream. We believe this could be appropriate given that plastics that would otherwise be destined for landfills can be used for fuel and energy production. We recognize that the definition of renewable biomass generally includes only materials of a non fossil-fuel origin, and ask that commenters consider this issue in their comments on whether: (1) MSW containing yard and food waste should qualify as renewable biomass, (2) if non-fossil portions of MSW should be included in the definition of renewable biomass, and (3) if non-fossil portions of [[Page 24923]] MSW should not be included, whether the approach discussed in Section III.D.4 can provide an appropriate means for excluding the non-fossil portions. Although we are proposing to exclude MSW from the definition of ``renewable biomass'' for the proposed rule, our analysis of renewable fuel volume (discussed in Section V) assumes that MSW is included for purposes of quantifying the potential future volume of renewable fuel. EPA intends to resolve this matter in the final rule, and we solicit comment on the approach that we should take. b. Advanced Biofuel ``Advanced Biofuel'' is a renewable fuel other than ethanol derived from corn starch and which must also achieve a lifecycle GHG emission displacement of 50%, compared to the gasoline or diesel fuel it displaces. As such, advanced biofuel would be assigned a D code of 3 as shown in Table III.A-1. ``Advanced biofuel'' also may be biomass-based diesel, biogas (including landfill gas and sewage waste treatment gas), butanol or other alcohols produced through conversion of organic matter from renewable biomass, and other fuels derived from cellulosic biomass, as long as it meets the proposed 40-44% GHG emission reduction threshold. ``Advanced Biofuel'' is a renewable fuel other than ethanol derived from corn starch and for which lifecycle GHG emissions are at least 40- 44% less than the gasoline or diesel fuel it displaces. Advanced biofuel would be assigned a D code of 3 as shown in Table III.A-1. While ``Advanced Biofuel'' specifically excludes ethanol derived from corn starch, it includes other types of ethanol derived from renewable biomass, including ethanol made from cellulose, hemicellulose, lignin, sugar or any starch other than corn starch, as long as it meets the proposed 40-44% GHG emission reduction threshold. Thus, even if corn starch-derived ethanol were made so that it met the proposed 40-44% GHG reduction threshold, it would still be excluded from being defined as an advanced biofuel. Such ethanol, while not an advanced biofuel, would still qualify as a renewable fuel for purposes of meeting the standards. ``Advanced biofuel'' also may be biomass-based diesel, biogas (including landfill gas and sewage waste treatment gas), butanol or other alcohols produced through conversion of organic matter from renewable biomass, and other fuels derived from cellulosic biomass, as long as it is derived from renewable biomass and meets the proposed 40- 44% GHG emission reduction threshold. c. Cellulosic Biofuel Cellulosic biofuel is renewable fuel, not necessarily ethanol, derived from any cellulose, hemicellulose, or lignin each of which must originate from renewable biomass. It must also achieve a lifecycle GHG emission reduction of at least 60%, compared to the gasoline or diesel fuel it displaces. Cellulosic biofuel is assigned a D code of 1 as shown in Table III.A-1. Cellulosic biofuel in general also qualifies as both ``advanced biofuel'' and ``renewable fuel''. The proposed definition of cellulosic biofuel for RFS2 is broader in some respects than the RFS1 definition of ``cellulosic biomass ethanol''. That definition included only ethanol, whereas the RFS2 definition of cellulosic biofuels includes any biomass-to-liquid fuel in addition to ethanol. The definition of ``cellulosic biofuel'' in RFS2 differs from RFS1 in another significant way. The RFS1 definition provided that ethanol made at any facility--regardless of whether cellulosic feedstock is used or not--may be defined as cellulosic if at such facility ``animal wastes or other waste materials are digested or otherwise used to displace 90% or more of the fossil fuel normally used in the production of ethanol.'' This provision was not included in EISA, and therefore does not appear in the definitions pertaining to cellulosic biofuel in today's proposed rule. d. Biomass-Based Diesel Under today's proposed rule ``Biomass-based diesel'' includes both biodiesel (mono-alkyl esters) and non-ester renewable diesel (including cellulosic diesel). The definition is the same very broad definition of ``biodiesel'' that was in EPAct and in RFS1, with three exceptions. First, EISA requires that such fuel be made from renewable biomass. Second, its lifecycle GHG emissions must be at least 50% less than the gasoline or diesel fuel it displaces. Third, the statutory definition of ``Biomass-based diesel'' excludes renewable fuel derived from co- processing biomass with a petroleum feedstock. In drafting the proposed definition, we considered two options for how co-processing could be treated. The first option would consider co-processing to occur only if both petroleum and biomass feedstock are processed in the same unit simultaneously. The second option would consider co-processing to occur if renewable biomass and petroleum feedstock are processed in the same unit at any time; i.e., either simultaneously or sequentially. Under the second option, if petroleum feedstock was processed in the unit, then no fuel produced from such unit, even from a biomass feedstock, would be deemed to be biomass-based diesel. We are proposing the first option to be used in the definition in today's rule. Under this approach, a batch of fuel qualifying for the D code of 2 that is produced in a processing unit in which only renewable biomass is the feedstock for such batch, would meet the definition of ``Biomass-Based Diesel. Thus, serial batch processing in which 100% vegetable oil is processed one day/week/month and 100% petroleum the next day/week/month could occur without the activity being considered ``co-processing.'' The resulting products could be blended together, but only the volume produced from vegetable oil would count as biomass- based diesel. We believe this is the most straightforward approach and an appropriate one, given that it would allow RINs to be generated for volumes of fuel meeting the 50% GHG reduction threshold that is derived from renewable biomass, while not providing any credit for fuel derived from petroleum sources. In addition, this approach avoids the need for potentially complex provisions addressing how fuel should be treated when existing or even mothballed petroleum hydrotreating equipment is retrofitted and placed into new service for renewable fuel production or vice versa. Under today's proposal, any fuel that does not satisfy the definition of biomass-based diesel only because it is co-processed with petroleum would still meet the definition of ``Advanced Biofuel'' provided it meets the 50% GHG threshold and other criteria for the D code of 3. Similarly it would meet the definition of renewable fuel if it meets a GHG emission reduction threshold of 20%. In neither case, however, would it meet the definition of biomass-based diesel. This restriction is only really an issue for renewable diesel and biodiesel produced via the fatty acid methyl ester (FAME) process. For other forms of biodiesel, it is never made through any sort of co- processing with petroleum.\6\ [[Page 24924]] Producers of renewable diesel must therefore specify whether or not they use ``co-processing'' to produce the fuel in order to determine the correct D code for the RIN. --------------------------------------------------------------------------- \6\ The production of biodiesel (mono alkyl esters) does require the addition of methanol which is usually derived from natural gas, but which contributes a very small amount to the resulting product. We do not believe that this was intended by the statute's reference to ``co-processing'' which we believe was intended to address only renewable fats or oils co-processed with petroleum in a hydrotreater to produce renewable diesel. --------------------------------------------------------------------------- e. Additional Renewable Fuel The statutory definition of ``additional renewable fuel'' specifies fuel produced from renewable biomass that is used to replace or reduce fossil fuels used in home heating oil or jet fuel. EISA indicates that EPA may allow for the generation of credits for such additional renewable fuel that will be valid for compliance purposes. Under the RFS program, RINs operate in the role of credits, and RINs are generated when renewable fuel is produced rather than when it is blended. In most cases, however, renewable fuel producers do not know at the time of fuel production (and RIN generation) how their fuel will ultimately be used. Under RFS1, only RINs assigned to renewable fuel that was blended into motor vehicle fuel are valid for compliance purposes. As a result, we created special provisions requiring that RINs be retired if they were assigned to renewable fuel that was ultimately blended into nonroad fuel. The new EISA provisions regarding additional renewable fuel make the RFS1 requirement for retiring RINs unnecessary if renewable fuel is blended into heating oil or jet fuel. As a result, we propose modifying the regulatory requirements to allow RINs assigned to renewable fuel blended into heating oil or jet fuel to continue to be valid for compliance purposes. 2. Lifecycle GHG Thresholds As part of the new definitions that EISA creates for cellulosic biofuel, biomass-based diesel, advanced biofuel, and renewable fuel, EISA also sets minimum performance measures or ``thresholds'' for lifecycle GHG emissions. These thresholds represent the percent reduction in lifecycle GHGs that is estimated to occur when a renewable fuel displaces gasoline or diesel fuel. Table III.B.2-1 lists the thresholds required by EISA. Table III.B.2-1--Required Lifecycle GHG Thresholds [Percent reduction from a 2005 gasoline or diesel baseline] ------------------------------------------------------------------------ ------------------------------------------------------------------------ Renewable fuel................................................. 20 Advanced biofuel............................................... 50 Biomass-based diesel........................................... 50 Cellulosic biofuel............................................. 60 ------------------------------------------------------------------------ There are also special provisions for each of these thresholds: Renewable fuel: The 20% threshold only applies to renewable fuel from new facilities that commenced construction after December 19, 2007, with an additional exemption from the 20% threshold for ethanol plants that commenced construction in 2008 or 2009 and are fired with natural gas, biomass, or any combination thereof. Facilities not subject to the 20% threshold would be ``grandfathered.'' See Section III.B.3 below for a complete discussion of grandfathering. Also, EPA can adjust the 20% threshold to as low as 10%, but the adjustment must be the minimum possible, and the resulting threshold must be established at the maximum achievable level based on natural gas fired corn-based ethanol plants. Advanced biofuel and biomass-based diesel: The 50% threshold can be adjusted to as low as 40%, but the adjustment must be the minimum possible and result in the maximum achievable threshold taking cost into consideration. Also, such adjustments could be made only if it was determined that the 50% threshold was not commercially feasible for fuels made using a variety of feedstocks, technologies, and processes. As described more fully in Section VI.D, we are proposing that the GHG threshold for advanced biofuels be adjusted to 44% or potentially as low as 40% depending on the results from the analyses that will be conducted for the final rule. Cellulosic biofuel: Similarly to advanced biofuel and biomass-based diesel, the 60% threshold applicable to cellulosic biofuel can be adjusted to as low as 50%, but the adjustment must be the minimum possible and result in the maximum achievable threshold taking cost into consideration. Also, such adjustments could be made only if it was determined that the 60% threshold was not commercially feasible for fuels made using a variety of feedstocks, technologies, and processes. Our analyses of lifecycle GHG emissions, discussed in detail in Section VI, included all GHGs related to the full fuel cycle, including all stages of fuel and feedstock production and distribution, from feedstock generation and extraction through distribution, delivery, and use of the finished fuel. They included direct emissions and any significant indirect emissions such as significant emissions from land use changes. These lifecycle analyses were used to determine whether the thresholds shown in Table III.B.2-1 should be adjusted downwards and which specific combinations of feedstock, fuel type, and production process met those thresholds under the assumption of a 100-year timeframe and 2% discount rate for GHG emission impacts. We are not proposing to adjust any of these thresholds. However, we may adjust the GHG threshold for biomass-based diesel and/or advanced biofuel downward for the final rule based on additional lifecycle GHG analyses and further assessments of the market potential for volumes that can meet the requirements for these categories of renewable fuel. As explained in more detail in Section VI.D, ethanol produced from sugarcane sugar has been estimated to have a lifecycle GHG performance of 44% (under the assumption of a 100 year timeframe and 2% discount rate), short of the 50% threshold specified in EISA. Ethanol from sugarcane is one of the few currently commercial pathways that have the potential to meet the requirements for advanced biofuel in the near term (in addition to cellulosic biofuel and biomass-based diesel which are a subset of advanced biofuel, and any other new fuels that may arise), and the only such pathway that was subjected to lifecycle analysis to date. If ethanol from sugarcane does not qualify as advanced biofuel, it is likely that it would not be commercially feasible for the advanced biofuel volume requirements to be met in the near term. We request comment on whether it would be necessary to adjust the GHG threshold for advanced biofuel. For similar reasons, as discussed in more detail in Section VI.D, we are also seeking comment on the need to adjust the GHG threshold for biomass-based diesel. 3. Renewable Fuel Exempt From 20 Percent GHG Threshold EISA amends section 211(o) of the Clean Air Act to provide that renewable fuel produced from new facilities which commenced construction after December 19, 2007 must achieve at least a 20% reduction in lifecycle greenhouse gas emissions compared to baseline lifecycle greenhouse gas emissions.\7\ Facilities that commenced construction before December 19, 2007 are ``grandfathered'' and thereby exempt from the 20% GHG reduction requirement. --------------------------------------------------------------------------- \7\ Section 211(o)(2)(A)(i) of the Clean Air Act as amended by EISA. Note that this is not a prohibition--facilities that make ethanol can continue to do so. It is a minimum requirement for facilities to generate RINs under today's proposed rule; failure to meet such requirements means that the ethanol produced from such facilities cannot generate RINs. --------------------------------------------------------------------------- [[Page 24925]] For facilities that produce ethanol and for which construction commenced after December 19, 2007, section 210 of EISA states that ``for calendar years 2008 and 2009, any ethanol plant that is fired with natural gas, biomass, or any combination thereof is deemed to be in compliance with the 20% threshold.'' We refer to these facilities as ``deemed compliant.'' This provision does not specify whether such facilities are deemed to be in compliance only for the period of 2008 and 2009, or indefinitely. Nor does EISA specify a date by which such qualifying facilities must have started operation. Although the Act is unclear as to whether their special treatment is only for 2008/2009, or for a longer time period, we believe that it would be a harsh result for investors in these new facilities, and generally inconsistent with the energy independence goals of EISA, for these new facilities to only be guaranteed two years of participation in the RFS2 program. We propose that the statute be interpreted to mean that fuel from such qualifying facilities, regardless of date of startup of operations, would be exempt from the 20% GHG threshold requirement for the same time period as facilities that commence construction prior to December 19, 2007, provided that such plants commence construction prior to December 31, 2009, complete such construction in a reasonable amount of time, and continue to burn only natural gas, biomass, or a combination thereof. Therefore, we believe that they should be treated like grandfathered facilities. We seek comment, however, on the alternative in which after 2009, such plants must meet the 20% threshold in order to generate RINs for renewable fuel produced. Based on our survey of ethanol plants in operation, as well as those not yet in operation but which commenced construction prior to December 19, 2007, it is likely that production capacity of ethanol from all such facilities will reach 15 billion gallons. (See Section 1.5.1.4 of the DRIA.) This volume of ethanol will be excluded from having to meet the 20% GHG threshold by the grandfathering and deemed compliant provisions of EISA.\8\ For ease of reference, we will refer to both these provisions as the ``exemption provisions'' of EISA. --------------------------------------------------------------------------- \8\ The grandfathering and deemed compliant provisions in EISA sections 202 and 210 do not apply to the advanced biofuels, biomass- based diesel or cellulosic biofuel standards for which the Act requires a 50 or 60% GHG reduction threshold to be met regardless of when the facilities producing such fuels are constructed. --------------------------------------------------------------------------- EISA does not define the term ``new facility'' and, as mentioned above, does not clarify whether ``deemed compliant'' facilities have that status for only 2008 and 2009, or for a longer time period. EPA seeks, in interpreting these terms, to avoid long-term backsliding with respect to environmental performance and to also provide a level playing field for future investments. Thus, we want to avoid incentives that would allow overall GHG performance to worsen via expansion at older plants with poorer GHG performance or by modifications such as switches to more polluting process heat sources, such as coal. At the same time, we also want to offer protection for historical business investments that were made prior to enactment of EISA, and we want future significant investments to meet the GHG reduction standards of the Act. Finally we want to avoid excessive case-by-case decision making where possible, and seek instead a rule that offers ease of implementation while providing certainty to EPA and the regulated industry. We are proposing one basic approach to the exemption provisions and seeking comment on five additional options. In fashioning the basic proposal and alternative options for exempted facilities, we considered aspects of exemption approaches elsewhere in the CAA and EPA regulations to evaluate whether they would foster the above-described objectives. We are only looking to these other provisions for guidance and are not bound to follow any already-established approach for a different statutory provision (especially as those other provisions may contain definitions that Congress did not incorporate here). a. Definition of Commence Construction In defining ``commence'' and ``construction'', we wanted a clear designation that would be broad enough to avoid facility-specific issues, but narrow enough to prevent new facilities (i.e., post- December 19, 2007) from being grandfathered. We believe that the definitions of ``commence'' and ``Begin actual construction'' in the Prevention of Significant Deterioration (PSD) regulations, which draws upon definitions in the Clean Air Act, served this purpose. (40 CFR 52.21(b)(9) and (11)). Specifically, under the PSD regulations, ``commence'' means that the owner or operator has all necessary preconstruction approvals or permits and either has begun a continuous program of actual on-site construction to be completed in a reasonable time, or entered into binding agreements which cannot be cancelled or modified without substantial loss.'' Such activities include, but are not limited to, ``installation of building supports and foundations, laying underground pipe work and construction of permanent storage structures.'' We have added language to the definition that is currently not in the PSD definition with respect to multi-phased projects. We are proposing that for multi-phased projects, commencement of construction of one phase does not constitute commencement of construction of any later phase, unless each phase is ``mutually dependent'' on the other on a physical and chemical basis, rather than economic. The PSD regulations provide additional conditions beyond what constitutes commencement. Specifically, the regulations require that the owner or operator ``did not discontinue construction for a period of 18 months or more and completed construction within a reasonable time.'' (40 CFR 52.21(i)(4)(ii)(c). While ``reasonable time'' may vary depending on the type of project, we believe that with respect to renewable fuel facilities, a reasonable time to complete construction is no greater than 3 years from initial commencement of construction. We seek comment on the use of these definitions. b. Definition and Boundaries of a Facility We propose that the grandfathering and deemed compliant exemptions apply to ``facilities.'' Our proposed definition of this term is similar in some respects to the definition of ``building, structure, facility, or installation'' contained in the PSD regulations in 40 CFR 52.21. We have modified the definition, however, to focus on the typical renewable fuel plant. We therefore propose to describe the exempt ``facilities'' as including all of the activities and equipment associated with the manufacture of renewable fuel which are located on one property and under the control of the same person or persons. c. Options Proposed in Today's Rulemaking We are proposing one basic approach to the grandfathering provisions and seeking comment on five additional options. The basic approach would provide an indefinite extension of grandfathering and deemed compliant status but with a limitation of the exemption from the 20% GHG threshold to a baseline volume of renewable fuel. The five additional options for which we seek comment are: (1) Expiration of exemption for grandfathered and ``deemed compliant'' status when facilities undergo sufficient changes to [[Page 24926]] be considered ``reconstructed''; (2) Expiration of exemption 15 years after EISA enactment, industry-wide; (3) Expiration of exemption 15 years after EISA enactment with limitation of exemption to baseline volume; (4) ``Significant'' production components are treated as facilities and grandfathered or deemed compliant status ends when they are replaced; and (5) Indefinite exemption and no limitations placed on baseline volumes. i. Basic Approach: Grandfathering Limited to Baseline Volumes We are proposing and seeking comments on an option which generally limits the volume of any renewable fuel for which a grandfathered and deemed compliant facility can generate RINs without complying with the 20% GHG reduction threshold to the capacity volume specified in a state or Federal air permit or the greater of nameplate capacity or actual production. This approach is similar to how we have treated small refiner flexibilities under our other fuel rules. As a sub-option to this approach, we also seek comment on a provision whereby facilities would lose their status if they switch to a process fuel or feedstock which results in an increase of GHG emissions. (1) Increases in Volume of Renewable Fuel Produced at Grandfathered Facilities due to Expansion For facilities that commenced construction prior to December 19, 2007, we are proposing to define the baseline volume of renewable fuel exempt from the 20% GHG threshold requirement to be the maximum volumetric capacity of the facility as allowed in any applicable state air permit or Federal Title V operating permit. If the capacity of a facility is not stipulated in such air permits, then the grandfathered volume is the greater of the nameplate capacity of the facility or historical annual peak production prior to enactment of EISA. Volumes greater than this amount which may typically be due to expansions of the facility which occur after December 19, 2007, would be subject to the 20% GHG reduction requirement in order for the facility to generate RINs for the incremental expanded volume. The increased volume would be considered as if produced from a ``new facility'' which commenced construction after December 19, 2007. Changes that might occur to the mix of renewable fuels produced within the facility would remain grandfathered as long as the overall volume fell within the baseline volume. The baseline volume would be defined as above for deemed compliant facilities with the exception that if the maximum capacity is not stipulated in air permits, then the exempt volume would be the maximum annual peak production during the plant's first three years of operation. In addition, any production volume increase that is attributable to construction which commenced prior to December 31, 2009 would be exempt from the 20% GHG threshold, provided that the facility continued to use natural gas, biomass or a combination thereof for process energy. Because deemed compliant facilities owe their status to the fact that they use natural gas, biomass or a combination thereof for process heat, we propose that their status would be lost, and they would be subject to the 20% GHG threshold requirement, at any time that they change to a process energy source other than natural gas and/or biomass. Finally, because EISA limits deemed compliant facilities to ethanol facilities, we propose that if there are any changes in the mix of renewable fuels produced by the facility that only the ethanol volume remain grandfathered. We solicit comment, however, on whether the statute could be read to allow deemed compliant facilities to be treated the same as grandfathered facilities by allowing a mix of renewable fuels. Volume limitations contained in air permits may be defined in terms of peak hourly production rates or a maximum annual capacity. If they are defined only as maximum hourly production rates, they would need to be converted to an annual rate. We believe that assuming 24-hour per day production over 365 days per year (8,760 production hours) may overstate nameplate capacity. In other regulations that pertain to refinery operations, we have assumed a conversion rate of 90% of the total hours in a year (7884 production hours). We seek comment on what would be an appropriate conversion rate for renewable fuel facilities. The facility registration process (see Section III.C) would be used to define the baseline volume for individual facilities. Owners and operators would submit information substantiating the nameplate capacity of the plant, as well as historical annual peak capacity if such is greater than nameplate capacity. Subsequent expansions at a grandfathered that result in an increase in volume would subject the increase in volume to the 20% GHG emission reduction threshold (but not the original baseline volume). Thus, any new expansions would need to be designed to achieve the 20% GHG reduction threshold if the facility wants to generate RINs for that volume. Such determinations would be made on the basis of EPA-defined corn ethanol fuel pathway categories that are deemed to represent such 20% reduction. As an alternative approach to the greater of nameplate capacity or historical annual peak capacity, we seek comment on an approach in which the baseline volume is the actual volume of renewable fuel produced during the 2006 calendar year, where adequate data is available. Since there has been a particularly high demand for ethanol in recent years, the use of 2006 data may be a fair representation of the real production capacity for most plants. For plants that have not operated for an adequate shake down period, the information in the state or Federal air permit could be used and if this is not available, the nameplate capacity could be used. As mentioned above, deemed compliant facilities would be exempt from the 20% GHG threshold for baseline volumes and any additional volumes regarding which construction commenced prior to December 31, 2009. We recognize, however, that some debottlenecking type changes may cause increases in volume that are within a plant's inherent capacity. To account for this in past regulations (e.g., 40 CFR 80.552 and 554) we allowed for an increase of 5% above the baseline volume. Based on conversations with builders of ethanol plants, however, such plants have often been debottlenecked to exceed nameplate capacity by 20% and sometimes much higher. We seek comment on whether we should allow a 10% tolerance on the baseline volume for which RINs can be generated without complying with the 20% GHG reduction threshold. Once that 10% increase in volume is exceeded, the total increase above baseline volume would then be subject to the 20% GHG reduction requirement in order to generate RINs. We also seek comment on tolerance values in the 5 to 20% range. Our guiding philosophy of protecting historical business investments that were made to comply with the provisions of RFS1 is realized by allowing production increases within a plant's inherent capacity. At the same time, the alternative of requiring compliance with the 20% GHG reduction requirement for increases in volume above 10% over the baseline volume, would place new volumes from grandfathered facilities on a level playing field with product from new grass roots facilities. We believe that a level playing field for new investments [[Page 24927]] is fair and consistent with the provisions of EISA. (2) Replacements of Equipment If production equipment such as boilers, conveyors, hoppers, storage tanks and other equipment are replaced, it would not be considered construction of a ``new facility'' under this option of today's proposal--the baseline volume of fuel would continue to be exempt from the 20% GHG threshold. We discuss in a sub-option in III.B.3.c.i(4) below in which if the replacement unit uses a higher polluting fuel in terms of GHG emissions such replacement would render the facility a new facility, and it would no longer be exempt from the 20% GHG threshold. We also solicit comment on an approach that would require that if coal-fired units are replaced, that the replacement units must be fired with natural gas or biofuel for the product to be eligible for RINs that do not satisfy the 20% GHG threshold. (3) Registration, Recordkeeping and Reporting Facility owner/operators would be required to provide evidence and certification of commencement of construction. Owner/operators must provide annual records of process fuels used on a BTU basis, feedstocks used and product volumes. For facilities that are located outside the United States (including outside the Commonwealth of Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, and the Commonwealth of the Northern Mariana Islands) owners would be required to provide certification as well. Since the definition of commencement of construction includes having all necessary air permits, we would require that facilities outside the United States to certify that such facilities have obtained all necessary permits for construction and operation required by the appropriate national and local environmental agencies. (4) Sub-Option of Treatment of Future Modifications We seek comment on a sub-option to the basic approach whereby facilities would lose their grandfathered status if they switch to a process fuel or feedstock which results in an increase of GHG emissions. Some facilities may keep production volumes the same, but change some or all of their feedstocks and energy sources, thus causing a facility's product to fall further below the GHG performance for the fuel pathway it produced at the time of enactment. We are therefore seeking comment on an approach to limit the initial grandfathering only for the fuel pathways that applied during 2007, when establishing the volume baseline. Table III.B.3.c.i-1 below presents a ranking of fuels and feedstock by fuel pathway in order of life cycle GHG emissions (as discussed further in Section VI.E). (Table III.B.3.c.i-1 is based on the table of fuel pathways contained in proposed regulations 40 CFR 80.1426.) Since the majority of facilities under consideration in this portion of the rulemaking consists of ethanol plants, the table below is limited to those types. Any changes to a facility that shift it to a feedstock or use of a process energy source that results in higher GHG emissions on the basis of the ranking categories in Table III.B.3.c.i-1 below would terminate the facility's grandfathered status. For example, an ethanol dry mill plant using natural gas for process heat, as well as combined heat and power (CHP), is ranked as ``2'' in the table below. If the plant (or any portion of the plant) switches to coal, it is ranked as ``4''. The higher number indicates an increase in GHG emissions. Therefore in this example, the plant is considered to have undertaken a modification that increases GHG emissions, would render the facility as ``new'' and its grandfathered status would end. Similarly, replacements of equipment that worsen GHG emissions would also terminate grandfathered status. (For replacements of equipment that do not change the fuel, nor result in an increase in volume of renewable fuel, the grandfathered status of the plant would remain, as discussed in Section III.B.3.c.i(2) above.) Table III.B.3.c.i-1--Groups of Renewable Fuel Facilities by Fuel Feedstock and Process Energy ------------------------------------------------------------------------ Production process Feedstock requirements Ranking ------------------------------------------------------------------------ Starch from corn, wheat, barley, --Process heat derived 1 oats, rice, or sorghum. from biomass. Starch from corn, wheat, barley, --Dry mill plant........ 2 oats, rice, or sorghum. --All process heat derived from natural gas. --Combined heat and power (CHP). --Fractionation of feedstocks. --Dried distillers grains. Starch from corn, wheat, barley, --Dry mill plant........ 3 oats, rice, or sorghum. --All process heat derived from natural gas. --Wet distillers grains. Starch from corn, wheat, barley, --Dry mill plant........ 4 oats, rice, or sorghum. --All or part of process heat derived from coal. --Combined heat and power (CHP). --Fractionation of feedstocks. --Membrane separation of ethanol. --Raw starch hydrolysis. --Dried distillers grains. Starch from corn, wheat, barley, --Dry mill plant........ 5 oats, rice, or sorghum. --All or part of process heat derived from coal. --Combined heat and power (CHP). --Fractionation of feedstocks. --Membrane separation of ethanol. --Wet distillers grains. Sugarcane sugar.................. --Process heat derived 1 from sugarcane bagasse. Sugarcane sugar.................. --Process heat derived 2 from natural gas. Sugarcane sugar.................. --Process heat derived 3 from coal. ------------------------------------------------------------------------ [[Page 24928]] We considered whether improvements at a facility (i.e., a fuel switch from coal to natural gas) that still result in GHG performance less than 20% should be credited to allow the facility to increase its baseline volume. We decided not to propose such an approach because it would take away an incentive for new plants that achieve greater than 20% GHG reduction to be constructed. As such, this would go against our guiding principle of providing equal opportunities for future investments in new plants. We recognize that there may be combinations of changes made at a plant, some of which may worsen GHG emissions and others which may cause an improvement and that not all such combinations can be taken into account in a single table of fuel pathways. We seek comment on ways to address such combinations. ii. Alternative Options for Which We Seek Comment (1) Facilities That Meet the Definition of ``Reconstruction'' Are Considered New An alternative approach on which we are seeking comment would consider whether a facility is effectively a ``new'' facility with respect to the costs incurred in maintaining the plant over time. Starting in 2010, we would require facility owners to report annually (specifically by January 31) to EPA the expenses for replacements, additions, and repairs undertaken at facilities since start up of the facility through the year prior to reporting. The Agency would then determine whether the degree of such activities warrants considering the facility as effectively ``new''. That substantial rebuilding or modernization may render an existing facility a new facility for regulatory purposes finds analogies in other Clean Air Act regulatory programs. For example, under the New Source Performance Standards (NSPS) equipment that has been ``reconstructed'' as defined in 40 CFR 60.15 is considered new. Specifically, ``reconstruction'' is defined in 40 CFR 60.15 as ``the replacement of components of an existing facility to such an extent that the fixed capital cost of the new components exceeds 50% of the fixed capital cost that would be required to construct a comparable entirely new facility. In addition to the NSPS program, regulations such as the recently promulgated standards for locomotive and marine engines (73 FR 25160; May 6, 2008) use a more encompassing concept of reconstruction and consider a vessel to be new if it is modified such that the value of the modifications exceeds 50% of the value of the modified vessel. We are seeking comment on an approach wherein upon the Agency's determination that costs of replacements, repairs and upgrades conducted since the start-up of the facility meet the test of ``reconstruction'' (i.e., the costs equal or exceed 50% of what it would cost to rebuild), that the facility would be considered effectively new, and would be subject to the 20% GHG reduction requirements. The application of the definition of reconstruction in the NSPS program occurs on an equipment-wide rather than on a plant-wide basis. Under this option, we would apply the concept of a ``new'' facility on a plant-wide basis similar to the approach we have taken in the recently promulgated locomotive and marine standards. We believe that a plant-wide approach is appropriate under RFS2 because it is not the emissions from individual pieces of equipment that are being regulated. Rather, the 20% GHG reduction standard applies to the renewable fuel produced by the facility, and it is logical to consider all of the equipment and structures at the facility involved in producing the product in evaluating when a grandfathered facility has been reconstructed. For these reasons, we believe that it would be reasonable to apply the definition of ``new'' on a plant-wide basis. Also, since upgrades, replacements and repairs will occur on an ongoing basis we would consider rebuilding or reconstruction to occur over time as the accumulation of all individual upgrades, replacements and repairs. The NSPS definition also requires that it be ``technologically and economically feasible for the reconstructed facility to meet applicable standards that apply to new facilities.'' We do not think that EISA requires this additional consideration, and also do not believe that there is any compelling public policy justification for allowing a reconstructed facility to continue to make renewable fuel that does not meet the 20% GHG reduction standard based upon a claim that it is technologically or economically infeasible. EPA's experience in the New Source Review (NSR) program has demonstrated that it is extremely difficult to clearly define what the terms ``technologically and economically feasible'' mean. Aside from such definitional difficulties, however, and as discussed in Section III.B.3.c.ii(2) below, we believe that it is technologically feasible to meet the 20% GHG reduction and with proper planning would be economically so, as well. Therefore, this alternative option would not require such a showing. Our assessment of whether a facility has been reconstructed would be based on application of an appropriate cost model such as U.S. Department of Agriculture's cost estimation model for construction of new ethanol plants described by Kwiatkowski, J. et al. (2006) \9\. Costs associated with the costs of repair and replacement of all parts (including the labor associated with replacement and repair), would be included in such calculation, regardless of the parts' intended useful life. We seek comment on whether to also include costs associated with employee labor related to routine maintenance, and also whether the costs of repairs and replacements at the facility should be limited only to the property directly related to the production of biofuels.\10\ --------------------------------------------------------------------------- \9\ Kwiatkowski, J.R., McAloon, A., Taylor, F. Johnson, D. 2006. ``Modeling the process and costs of fuel ethanol production by the corn dry-grind process.'' Industrial Crops and Products 23 (2006) 288-296. \10\ We note that under NSPS the costs considered in determining whether the definition of reconstruction has been met are restricted to the capital costs of equipment and materials. The RFS2 program is authorized from EISA which does not rely on the definitions of ``modification'' and ``routine maintenance and repair'' that are in NSPS and other new source programs (e.g., New Source Review, National Emission Standards for Hazardous Pollutants). Since our application of the term ``reconstruction'' assumes that over time, renewable fuel facilities may become substantially rebuilt it is therefore appropriate to consider not only equipment replacements but some of the labor costs associated with such replacements. --------------------------------------------------------------------------- Under this alternative option, the volume of renewable fuel that qualifies for an exemption from the 20% GHG threshold would remain fixed at the baseline volume as in the basic option described in III.B.3(c)(i). However, we also seek comment on whether the volume of renewable fuel at a grandfathered facility should be allowed to increase above baseline volumes under this option. Specifically, increases in volume could be exempt until such time as the entire plant is deemed to have been reconstructed. In making such assessment and applying the 50% test, the basis for the cost of a ``comparable entirely new facility'' would be a facility with the original baseline volume. For example, if an existing plant has a 100 million gallon per year capacity and expands its volume to 120 million gallons per year, reconstruction would occur if the costs incurred over time equal or exceed 50% of the cost of a comparable 100 million gallon per year facility. Under this alternative option, owner/operators or other responsible parties would be required to provide records of costs incurred for additions, replacements, and repairs that have [[Page 24929]] occurred since start-up. Such records would be provided on an annual basis to EPA by May 31, and would include cumulative cost information up to the prior year. We recognize that implementation of a facility-wide definition of ``reconstruction'' would be complex. Records of costs since start-up may not be available for older facilities. Also, this alternative option requires EPA enforcement staff to have sufficient financial knowledge and experience to be able to evaluate the veracity of claims regarding various types of expenditures. Calculating the costs of repairs and replacements also poses challenges. Specifically, as discussed above, we seek comment on whether the costs of routine maintenance and repair should be included in such assessments. Were such costs to be included, the determination of whether a replacement or a repair is routine may not always be straightforward. In addition to the recordkeeping and implementation issues, however, there is an important policy consideration that is also significant. As in the case of the NSR program, where many industry representatives have argued that the program has a chilling effect on projects that could provide environmental benefits, the reconstruction approach in this alternative option could also provide a disincentive to implementation of safety and environmental projects. Thus, this option could have the unintended consequence of causing facilities to refrain from investing in projects that will increase safety and efficiency and reduce emissions in order to avoid triggering the 50% cost threshold. We seek comment on this issue. (2) Expiration Date of 15 Years for Exempted Facilities The above discussion highlights potential complexities in implementing the option of considering reconstruction of exempted facilities on a case-by-case basis. These include potential disputes over how to calculate costs, as well as verifying records of expenditures. In addition, that option has as a potential unintended consequence, a disincentive for investment in projects that could improve safety, efficiency and environmental performance. As an alternative to the case-by case approach described above, this option offers a practical way of implementing the reconstruction concept by establishing an expiration date for all grandfathered and deemed compliant facilities after a period of 15 years from enactment of EISA (i.e., after December 31, 2022), regardless of when such facilities commenced construction or began operation. Under such option, the grandfathered and deemed compliant facilities would be subject to the 20% GHG threshold starting on January 1, 2023. Renewable fuel produced from these facilities after this date would be required to comply with the 20% threshold requirement in order to generate RINs. Based on our discussions with companies that construct ethanol plants, we believe that facility owners will make decisions about equipment replacements and technology upgrades that will continue to improve the overall operating costs and energy efficiency of the plant which ultimately lead to improvements in GHG emission performance as well. In particular, energy-intensive processes in the plant are likely to be replaced or upgraded to increase fuel and operating efficiency, thus reducing operating costs of the plant, and increasing output. Nilles (2006) reports that the first line of next-generation dry-grind ethanol plants was built with mild steel components and that in 10 or 15 years, those components will need to be replaced entirely--most likely with stainless steel. Of particular importance is that durable materials as well as weaker materials all require maintenance and replacement. As such, the components and equipment in ethanol facilities are designed to be easily replaced and to allow simple maintenance.\11\ --------------------------------------------------------------------------- \11\ Nilles, D. 2006. ``Time Testing''; Ethanol Producer Magazine, May, Vol. 12, No. 5. --------------------------------------------------------------------------- Using cost data contained in the U.S. Department of Agriculture's cost estimation model for construction of new ethanol plants described by Kwiatkowski, J. et al (2006), we calculated the cost of a replacement of specific components in a hypothetical 100 million gallon ethanol facility.12 13 We assumed that all steel tanks are replaced with stainless steel tanks, and that specific combustion equipment is replaced. Combining replacement costs with maintenance, repairs, upgrades and supply costs (at 2% of the capital cost of the facility per year), we calculated that over 15 years, the accumulated costs range from 50% to 75% of the capital cost of an equivalent facility.\14\ --------------------------------------------------------------------------- \12\ Op Cit., Kwiatkowski, et al. (2006). \13\ Note to Docket (EPA-HQ-OAR-2005-0161), ``Analysis of Costs of Replacements and Repairs at a Hypothetical 100 MM GPY Ethanol Facility''; from Barry Garelick, Environmental Protection Specialist, Assessment and Standards Division, Office of Transportation and Air Quality; October 16, 2008. \14\ The USDA model gives the installed capitol cost of a 40 million GPY facility at approximately $60 million (2006 dollars). The model also gives replacement costs of individual components (steel tanks and the ring dryer) at about $13 million. Ongoing maintenance costs are estimated at about $6 million per year. --------------------------------------------------------------------------- As discussed in Section 1.5.1.3 of the DRIA, per our conversations with builders of ethanol plants, the changes and upgrades would be made to improve competitiveness which will also improve operating and fuel efficiency, thus tending to improve overall GHG performance of the plant. The high price of natural gas has many ethanol plants considering alternative fuel sources. Greater biofuel availability and potential low life cycle green house gas emissions incentives may further encourage ethanol producers to switch from fossil fuels for process heat to biomass based fuels. In addition, ethanol producers may consider energy saving changes to the ethanol production process. Several process changes, including raw starch hydrolysis, corn fractionation, corn oil extraction, and membrane separation, are likely to be adopted to varying degrees. Since such changes would be consistent with ultimately achieving the 20% GHG reduction required of new facilities, we believe it is reasonable to expect that the newly rebuilt facilities could meet the 20% GHG reduction threshold, based on the results of a life cycle analysis.\15\ --------------------------------------------------------------------------- \15\ Unless and until EPA conducts facility specific life cycle analyses, however, compliance with the 20% GHG reduction threshold would be made on the basis of fuel pathways as described in Section III.D.2. --------------------------------------------------------------------------- We solicit further information and data, particularly evidence of the types of replacements and ongoing maintenance that has occurred at existing plants and what is projected to occur in the future. We will evaluate such information along with other comments received during the public comment period. We also solicit comment on whether a period other than 15 years may be more appropriate. Under this approach, facilities that are exempted could expand their volume of renewable fuel production, or could switch fuels or feedstocks within the 15 year exemption period without fear of losing their temporary exemption. While some of these activities have the potential to worsen GHG emissions further below the 20% threshold requirement, we believe that the imposition of an expiration date will result in modifications to facilities that tend to increase the efficiency and GHG performance of the plant rather than worsen them. The need for compliance with the 20% threshold requirement by a date certain would provide an incentive for owners and operators of [[Page 24930]] such plants to ensure the changes they make over time would bring them into compliance with the 20% requirement at the end of the 15 year period. While the facilities built in 2008 and 2009 would be in operation for less than 15 years, the majority of ethanol plants will have been in operation for 15 years or longer. As discussed in Section V.B.1, approximately 15 billion gallons of corn ethanol production capacity is currently online, idled or under construction. While some of these plants/projects are currently on hold due to the economy, we anticipate that this corn ethanol capacity will come online in the future under the proposed RFS2 program. And the majority of these plants commenced construction prior to 2008. We solicit comment, however, on whether there should be a plant-specific expiration date of 15 years after commencement of operations for deemed compliant facilities that commenced construction in 2008 or 2009. Under this sub-option, the expiration date for such plants would be 15 years from the time the facility began operation, per registration made by the owner of the facility. The option of limiting the exemption period to 15 years or other specific time period offers certainty to industry for a 15 year period, and also certainty that at the end of that time period they will be subject to the 20% GHG reduction threshold. This time period could be used by facility owners to ensure the facility will ultimately meet the requirement. Finally, the option ensures that investments made in equipment to comply with RFS1 requirements are protected with respect to being fully depreciated for tax purposes.\16\ Furthermore, this approach is easy to implement, and avoids case-by-case determinations that can extremely be time-consuming, contentious, and costly for both industry and EPA. In addition, because the exemption expiration date would apply to all facilities, this option would provide no incentive to delay modifications that increase energy efficiency, safety, or improve environmental performance unlike the option described above involving case-by-case consideration of reconstruction. --------------------------------------------------------------------------- \16\ Specifically, Table B-2 of IRS Publication 946, ``How To Depreciate Property'' provides class lives and recovery periods for use in computing depreciation for asset classes categorized by SIC codes. Ethanol facilities (which are in SIC 28, Manufacture of Chemical and Allied Products) is given a class life of 10 years. For facilities that qualify for Modified Accelerated Cost Recovery System (MACRS), the period is 7 years. --------------------------------------------------------------------------- (3) Expiration Date of 15 Years for Grandfathered Facilities and Limitation on Volume We also seek comment on a hybrid approach in which an expiration date of 15 years is established for grandfathered and deemed compliant facilities, but prior to then, the facilities' exemption from the 20% GHG threshold would be limited to their baseline volumes, as in the option described in Section III.B.3.c. (4) ``Significant Production Units'' Are Defined as Facilities We seek comment on an approach in which ``facility'' would be defined on the basis of ``significant production units''. For example, the regulations regarding air toxic emissions for the miscellaneous organic chemical manufacturing industry (which includes ethanol manufacturing plants) under NESHAPS (40 CFR 2440(c)) apply to miscellaneous chemical process units and heat exchangers within a single facility. This option, therefore, would follow a similar approach, and treat as new facilities subject to the 20% GHG reduction requirement any new significant production units. Defining ``facility'' as a significant production unit would raise the question of when an increase in volume due to the addition of specific pieces of equipment should be considered augmenting current production lines as opposed to being a new production line. We solicit comment on this approach as well as how the term ``significant production unit'' would need to be defined in the regulations to avoid ambiguity. Any incidental increases in volume due to the addition of pieces of equipment that would not constitute a new ``significant production unit'' line would continue to be grandfathered, as would increases in volume associated with changes made to debottleneck the facility. (5) Indefinite Grandfathering and No Limitations Placed on Volume Under our basic option, described in Section III.B.3.c.i, we would interpret the statutory language to mean that expansions of grandfathered facilities after enactment of EISA and which expand volume beyond a plant's inherent capacity are not among those that qualify for an exemption from the 20% GHG reduction requirement. Otherwise, a facility that qualifies for grandfathering could be expanded by any amount, and the additional volume would also receive protection. We do not believe that this was the intent of the language in EISA. Nevertheless, we recognize that there are alternative interpretations of the statute and therefore seek comment on an alternative that places no limitations on the volume of renewable fuel from grandfathered or deemed compliant facilities. Under such option, ``new facility'' would be defined solely as a new ``greenfield'' plant. 4. Renewable Biomass With Land Restrictions As explained in Section III.B.1.a, EISA lists seven types of feedstock that qualify as ``renewable biomass'': 1. Planted crops and crop residue. 2. Planted trees and tree residue. 3. Animal waste material and animal byproducts. 4. Slash and pre-commercial thinnings. 5. Biomass obtained from the vicinity of buildings at risk from wildfire. 6. Algae. 7. Separated yard or food waste. EISA limits not only the types of feedstocks that can be used to make renewable fuel, but also the land that several of these renewable fuel feedstocks may come from. Specifically, EISA's definition of renewable biomass incorporates land restrictions for planted crops and crop residue, planted trees and tree residue, slash and pre-commercial thinnings, and biomass from wildfire areas. EISA does not prohibit the production of renewable fuel feedstock that does not meet the definition of renewable biomass, nor does it prohibit the production of renewable fuel from feedstock that does not meet the definition of renewable biomass. It does, however, prohibit the generation of RINs for renewable fuel made from feedstock that does not meet the definition of renewable biomass, which includes not meeting the associated land restrictions. The following sections discuss the challenges of implementing the land restrictions contained in the definition of renewable biomass and propose approaches for establishing a workable implementation scheme. a. Definitions of Terms EISA's descriptions of four feedstock types noted above--planted crops and crop residue, planted trees and tree residue, slash and pre- commercial thinnings, and biomass from wildfire areas--contain terms that can be interpreted in multiple ways. The following sections discuss our proposed interpretations for many of the terms contained in EISA's definition of renewable biomass. In developing this proposal, we consulted many sources, including the USDA, as well as stakeholder groups, in order to [[Page 24931]] determine the range of possible interpretations for these different terms. We have made every attempt to define these terms as consistently with USDA and industry standards as possible, while keeping them workable for purposes of program implementation. We seek comment on our proposed definitions of important terms in the following sections. i. Planted Crops and Crop Residue The first type of renewable biomass described in EISA is planted crops and crop residue harvested from agricultural land cleared or cultivated at any time prior to December 19, 2007, that is either actively managed or fallow, and nonforested. We propose to interpret the term ``planted crops'' to include all annual or perennial agricultural crops that may be used as feedstock for renewable fuel, such as grains, oilseeds, and sugarcane, as well as energy crops, such as switchgrass, prairie grass, and other species, providing that they were intentionally applied to the ground by humans either by direct application as seed or nursery stock, or through intentional natural seeding by mature plants left undisturbed for that purpose. Many energy crops that could be used for cellulosic biofuel production, especially perennial cover plants, are currently grown in the U.S. without significant agronomic inputs such as fertilizer, pesticides, or other chemical treatment. These crops may be introduced or indigenous to the area in which they grow, and may have been originally planted decades ago. We propose to include this type of vegetation as a planted crop with the recognition that it may include some plants that were intentionally naturally generated, i.e., resulted from natural seeding from existing plants, and not planted through direct human intervention. We believe that given the increasing importance under RFS2 of biofuels produced from cellulosic feedstocks, such as switchgrass and other grasses, such a definition is appropriate. We note that because EISA contains specific provisions for planted trees and tree residue from tree plantations, we propose that the definition of planted crops in EISA exclude planted trees, even if they may be considered planted crops under some circumstances. We further propose that ``crop residue'' be limited to the residue left over from the harvesting of planted crops, such as corn stover and sugarcane bagasse. However, we seek comment on an alternative interpretation that would include as crop residue biomass from agricultural land removed for purposes of invasive species control or fire management. In that context ``crop residue'' would include any biomass removed from agricultural land that facilitates crop management, whether or not the crop itself is part of the residue. Our proposed regulations would restrict planted crops and crop residue to that harvested from existing agricultural land. With respect to what land would qualify as agricultural land, we first turned to the mutually exclusive categories of land defined by USDA's Natural Resources Conservation Service (NRCS) in its annual Natural Resources Inventory (NRI), a statistical survey designed to estimate natural resource conditions and trends on non-federal U.S. lands.\17\ The categories used in the NRI are cropland, pastureland, rangeland, forest land, Conservation Reserve Program (CRP) land, federal land, developed land, and ``other rural land.'' We have chosen to include in our proposed definition of agricultural land three of these land categories--cropland, pastureland, and CRP land. Using the NRI descriptions of these land types as models, we developed definitions for these land types for this proposal. --------------------------------------------------------------------------- \17\ Natural Resource Conservation Service, USDA, ``Natural Resources Inventory 2003 Annual NRI,'' February 2007. Available at http://www.nrcs.usda.gov/technical/NRI/2003/Landuse-mrb.pdf. --------------------------------------------------------------------------- We propose to define cropland as land used for the production of crops for harvest, including cultivated cropland for row crops or close-grown crops and non-cultivated cropland for horticultural crops. Corn, wheat, barley, and soybeans are renewable fuel feedstocks that would be grown on cropland. We propose to define pastureland as land managed primarily for the production of indigenous or introduced forage plants for livestock grazing or hay production, and to prevent succession to other plant types. Under this proposed definition, land would qualify as pastureland if it is maintained for grazing or hay production and not allowed to develop greater ecological diversity. Switchgrass is one example of a renewable fuel feedstock that could be grown on pastureland. We also propose that CRP land be counted as ``agricultural land'' under RFS2. The CRP is administered by USDA's Farm Service Agency and is designed to promote restoration of environmentally sensitive lands by offering annual rental payments in return for removing land from cultivation over a period of several years. To qualify for the CRP, land had to have been used for agricultural production for at least three years prior to entering the program. For this reason, we believe it is appropriate to propose that CRP land be included under the rubric of agricultural land. In addition, we seek comment on whether rangeland should be included as agricultural land under RFS2. Rangeland is land on which the indigenous or introduced vegetation is predominantly grasses, grass-like plants, forbs or shrubs and which--unlike cropland or pastureland--is predominantly managed as a natural ecosystem. Given the relative lower degree of management of such lands, it is questionable whether any rangeland should qualify as ``actively managed'' under EISA (a general discussion on our proposed interpretation of the term ``actively managed'' is presented later in this section). On the other hand, we understand that there is frequently some degree of management on such lands, such as controlling invasive species, managing grazing rates, fencing, etc. Therefore, we believe that there may be merit in allowing planted crops and crop residue from rangeland to qualify as renewable biomass under this program. This would allow, for example, existing switchgrass or native grasses on rangeland to be used for renewable fuel production that qualifies for RIN generation under this program. However, we are not proposing to include rangeland as agricultural land due to our own implementation concerns as well as issues raised by stakeholders over the potential for providing any incentive for increased crop production in rangeland areas. We seek comment on the issue and on the points raised in the following discussion. Allowing rangeland to qualify as agricultural land under RFS2 would make millions of acres of additional non-cropland, non-forested land qualify for renewable fuel feedstock production in the U.S. This additional land could be important to support future expansion of dedicated energy crops, such as switchgrass and tall prairie grass, which currently grow or could grow on such lands. The availability of rangeland could alleviate some of the competition on cropland and pastureland for space to grow crops for biofuel feedstocks, thereby allowing continued growth of food crops on land best suited for that specific purpose. It would also provide rangeland owners with the potential for increased revenues from their lands by producing feedstocks for renewable fuel, and decrease the pressure for such lands to be converted to cropland for food crop production. [[Page 24932]] However, we recognize that rangeland is a term that can be used to describe a wide variety of ecosystems, including certain grasslands, savannas, wetlands, deserts, and even tundra. These types of ecosystems represent land that at best could serve only marginally well for producing renewable fuel feedstocks, and at worst could suffer significantly if intensive agricultural practices were imposed upon them for purposes of producing crops. We also recognize that if we were to include rangeland as agricultural land under RFS2, there is a risk that some rangeland, including native grasslands and shrublands, could be converted to produce monoculture crops. We raise these concerns for two reasons. First, certain rangeland cannot be used sustainably for agricultural crop production, and any such short-term use could seriously diminish the long-term potential of these lands to be used for less-intensive forage production or even to return to their previous ecological state. Second, conversion of relatively undisturbed rangeland to the production of annual crops could in some cases result in large releases of GHGs that have been stored in the soil. EPA believes that Congress enacted the renewable biomass definition in part to minimize GHG releases from land conversion, a goal that could be undermined by conversion of rangeland to intensive crop production under RFS2. On the other hand, it may be argued that while GHGs would be emitted initially, planting dedicated energy crops rather than food crops on such land could yield more positive than negative results over time. Such could be the case if the alternative were to grow energy crops on cropland, consequently displacing food crops to other lands, either in the U.S. or abroad. This displacement could lead to overall higher direct and indirect GHG emissions. EPA solicits comment on the potential GHG effects if rangeland were included as eligible agricultural land under RFS2. We are especially interested in data that could help us to quantify such impacts. While enforcement of the overall renewable biomass provisions under the final RFS2 program is expected to be challenging, it is possible that including rangeland as qualifying agricultural land under the RFS2 program would increase enforcement complexity. As discussed later in this section, in order to qualify as renewable biomass under RFS2, agricultural products must come from agricultural land that was cleared or cultivated at any time prior to enactment of EISA, and either actively managed or fallow, and nonforested. We believe that evidence of past intensive use and management of rangeland may be considerably more rare, and considerably less definitive, than for other types of agricultural land. In addition, given the continuous, open nature of some rangeland, there would likely be difficulty in identifying the precise boundaries of a parcel of qualifying rangeland. EPA seeks comment on these issues. We thus seek comment on whether or not we should include rangeland in the definition of ``existing agricultural land'' in the final RFS2 program, as well as comment on whether or not the benefits of including rangeland exceed the disadvantages. We also seek comment on how best to define rangeland, and whether we can define rangeland in a meaningful way such that sensitive ecosystems that may generally be described as rangeland can be protected from cultivation for renewable fuel feedstock production. Furthermore, EPA solicits comment on an alternative option that would include rangeland as agricultural land, but that would interpret the EISA ``actively managed'' criterion in the renewable biomass definition (again, discussed later in this section) to limit the types of planted crops or crop residues from specific parcels of land that can qualify as renewable biomass by reference to the type of management (cropland, pastureland, or rangeland) being practiced on the date EISA was enacted. For example, if at some point in the future corn or other row crops are grown on land that was pastureland or rangeland when EISA was enacted, such row crops would not qualify as renewable biomass under RFS2. This approach could thus reduce the incentives for pastureland and rangeland owners to convert their land to cropland. We believe that this approach could have less environmental harm than allowing unrestricted use of qualifying rangeland for the production of crops for renewable fuel production. While our proposed implementation approach and alternatives are presented later in this section, it is important to note here that the principal drawback to this alternative option involves its implementation and enforcement. This approach would require that land types (again, cropland, pastureland, or rangeland) be identified as of the date of EISA enactment in order to determine which feedstocks grown on such land would qualify as renewable biomass. In practical terms, such an approach may mean, for example, that a renewable fuel producer would need to be able to identify not only whether a given shipment of corn was grown on agricultural land cleared or cultivated prior to enactment of EISA, but also that the land was not previously pastureland or rangeland that had been converted to cropland after enactment of EISA. If it was, it would not qualify as renewable biomass. We are concerned that adding this additional feedstock verification criterion to those already contained in this proposal could render the program unworkable and unenforceable. However, we invite comment on this option, and specifically request comment on how this option could be implemented in a workable and enforceable manner. In keeping with the statutory definition for renewable biomass, we propose to include in our definition of existing agricultural land the requirement that the land was cleared or cultivated prior to December 19, 2007, and that, since December 19, 2007, it has been continuously actively managed (as agricultural land) or fallow, and nonforested. We believe the language ``cleared or cultivated at any time'' prior to December 19, 2007, describes most cultivable land in the U.S., since so much of the country's native forests and grasslands were cleared in the 17th, 18th, and 19th centuries, if not before, for agriculture. We further believe that land that was cropland, pastureland, or CRP land on December 19, 2007, would automatically satisfy this particular criterion, and that therefore it is not of significant concern from an implementation or enforcement perspective. In the event that we were to include rangeland as agricultural land under the final RFS2 program, satisfying the ``cleared or cultivated'' criterion could pose significant challenges. Some rangeland has never been cleared or cultivated, or may have been cleared or cultivated prior to December 19, 2007, but no evidence exists to confirm this. Therefore, we could not assume that it would necessarily meet the ``cleared or cultivated'' criterion. For instance, grasslands in the Midwest and West that during the Dust Bowl of the 1930s had been used for cultivation could meet this criterion, but other western grasslands and prairies used for cattle grazing may not. We seek comment on how best to verify that rangeland to be used for renewable fuel feedstock production was cleared or cultivated at some point prior to December 2007. We also seek comment on whether the challenge associated with applying this criterion to rangeland is sufficient (alone or combined with the concerns raised earlier about the inclusion of rangeland in the definition of agricultural land) to exclude rangeland [[Page 24933]] from the final definition of agricultural land. We believe that the more restrictive, and therefore more important, criteria is whether agricultural land is actively managed or fallow, and nonforested, per the statutory language. We propose to interpret the phrase ``that is actively managed or fallow, and nonforested'' as meaning that land must have been actively managed or fallow, and nonforested, on December 19, 2007, and continuously thereafter in order to qualify for renewable biomass production. We believe this interpretation of the legislative language is reasonable and appropriate for the following reason. The EISA language uses the present tense (``is actively managed * * *'') rather than the past tense to describe qualifying agricultural land. We interpret this language to mean that at the time the planted crops or crop residue are harvested (i.e., now or at some time in the future), the land from which they come must be actively managed or fallow, and nonforested. However, assuming that the land was cleared or cultivated at some point in time, then any land converted to agricultural land after December 19, 2007, and used to produce crops or crop residue would inherently meet the definition of ``is actively managed or fallow, and nonforested,'' and the EISA land restriction for planted crops and crop residue would have little meaning (except in cases where it could be established that the land in question had never been cleared or cultivated). We believe that in order for this provision to have meaning, we must require that agricultural land remain ``continuously'' either actively managed or fallow, and nonforested, since December 19, 2007. In this way, the upper bound on acreage that qualifies for planted crop and crop residue production under RFS2 would be limited to existing agricultural land--cropland, pastureland, or CRP land--as of December 19, 2007, and the phrase ``is actively managed or fallow, and nonforested'' would be interpreted in a meaningful way. We propose that ``actively managed'' would mean managed for a predetermined outcome as evidenced by any of the following: sales records for planted crops, crop residue, or livestock; purchasing records for land treatments such as fertilizer, weed control, or reseeding; a written management plan for agricultural purposes; documentation of participation in an agricultural program sponsored by a Federal, state or local government agency; or documentation of land management in accordance with an agricultural certification program. Examples of government programs or product certification programs that would indicate active agricultural land management include USDA's certified organic program or the Federal Crop Insurance program. We realize that it may be difficult to conclude that certain land has been actively managed continuously since December 2007 based solely on the existence of receipts for fertilizer or seed. However, we have included sales and purchasing records in the list of written documentation that could be used to indicate active management due to the fact that there may be qualifying land that is not registered with any formal agricultural program, for which the owner does not receive government benefits, and for which no written management plan exists (or existed as of December 2007). We believe this may be the case especially for pastureland from which no crops are harvested or sold. Other evidence that could be used regarding the consistent management of pastureland since December 2007 are records associated with the sale of livestock that grazed on the land. We seek comment on our proposal to include relevant records of sales and purchasing as adequate documentation to prove that land was actively managed since December 2007 and whether there may be other records, such as tax or insurance records, which could satisfy this requirement more effectively. The term ``fallow'' is generally used to describe cultivated land taken out of production for a finite period of time. We believe it may be argued that fallow land is actively managed land because there is a clear purpose or goal for taking the land out of production for a period of time (e.g., to conserve soil moisture). Nonetheless, because the EISA language clearly identifies a difference between actively managed agricultural land and fallow agricultural land, we propose to define fallow to mean agricultural land that is intentionally left idle to regenerate for future agricultural purposes, with no seeding or planting, harvesting, mowing, or treatment during the fallow period. While fallow agricultural land is characterized by a lack of activity on the land, we believe that the decision to let land lie fallow is made deliberately and intentionally by a land owner or farmer such that there should be documentation of such intent. We seek comment on this assumption and on whether there are other means of verifying whether land was fallow, particularly as of December 2007. We also seek comment on whether we should specify in the regulations a time period after which land that is not actively managed for agricultural purposes should be considered to have been abandoned for agriculture (and not eligible for renewable biomass production under RFS2), as opposed to being left fallow. If specifying such a time limit is appropriate, we seek comment on what the time period should be, and if there should be a distinction between allowable fallow periods for different types of agricultural land. Finally, in order to define the term ``nonforested,'' we first propose to define the term ``forestland'' as generally undeveloped land covering a minimum area of 1 acre upon which the predominant vegetative cover is trees, including land that formerly had such tree cover and that will be regenerated. We are also proposing that forestland would not include tree plantations. Under this proposal, ``nonforested'' land would be land that is not forestland. We believe this definition is sufficient to make distinctions between forestland and land that is considered nonforested in the field. However, we seek comment on whether we should incorporate into our definition of forestland more quantitative descriptors, such as a minimum percentage of canopy cover or minimum or maximum tree height, to help clarify what would be considered forestland. For example, the NRI definition of forestland includes a minimum of twenty-five percent canopy cover. We also seek comment on whether the one-acre minimum size designation is appropriate. ii. Planted Trees and Tree Residue The definition of renewable biomass in EISA includes planted trees and tree residue from actively managed tree plantations on non-federal land cleared at any time prior to December 19, 2007, including land belonging to an Indian tribe or an Indian individual, that is held in trust by the United States or subject to a restriction against alienation imposed by the United States. We propose to define the term ``planted trees'' to include not only trees that were established by human intervention such as planting saplings and artificial seeding, but also trees established from natural seeding by mature trees left undisturbed for such a purpose. We understand that, depending on the particular conditions at a plantation, certain trees in a stand may be harvested, while others are maintained, for the express purpose of naturally regenerating new trees. We believe that trees established in such a fashion, and which meet the conditions for planted trees in every other way, should not be [[Page 24934]] excluded from qualifying as renewable biomass under RFS2. Rather than using the term ``tree residue,'' we propose to use the term ``slash'' in our regulations as a more descriptive, but otherwise synonymous, term. According to the Dictionary of Forestry (1998, p. 168), slash is ``the residue, e.g., treetops and branches, left on the ground after logging or accumulating as a result of a storm, fire, girdling, or delimbing.'' We believe that this substitution will simplify our regulations, since paragraph (iv) of the EISA definition of renewable biomass also uses the term ``slash.'' Furthermore, the term ``slash'' is a common term that has a specific meaning to industry. As noted earlier, we have attempted to define terms in RFS2 using existing and commonly understood definitions to the extent possible. The term ``slash'' is more descriptive than ``tree residue,'' and yet in practice means the same thing, so we are proposing to use it rather than ``tree residue.'' We also propose to clarify that slash can include tree bark and can be the result of any natural disaster, including flooding. In concert with our proposed definition for ``planted trees,'' we propose to define a ``tree plantation'' as a stand of no fewer than 100 planted trees of similar age and comprising one or two tree species, or an area managed for growth of such trees covering a minimum of 1 acre. Given that only trees from a tree plantation may be used as renewable biomass under RFS2, we believe that the definition should be clear and easily applied in the field. We recognize that this proposed definition is more specific than the Dictionary of Forestry's definition of ``tree plantation,'' which is ``a stand composed primarily of trees established by planting or artificial seeding.'' We seek comment on all aspects of our proposed definition of tree plantation. We also propose to apply the same management restrictions on tree plantations as on agricultural land and to interpret the EISA language as requiring that to qualify for renewable biomass production under RFS2, a tree plantation must have been cleared at any time prior to December 19, 2007, and continuously actively managed since December 19, 2007. Similar to our proposal for actively managed agricultural land, we propose to define the term ``actively managed'' in the context of tree plantations as managed for a predetermined outcome as evidenced by any of the following: Sales records for planted trees or slash; purchasing records for seeds, seedlings, or other nursery stock; a written management plan for silvicultural purposes; documentation of participation in a silvicultural program sponsored by a Federal, state or local government agency; or documentation of land management in accordance with an agricultural or silvicultural product certification program. Silvicultural programs such as those of the Forest Stewardship Council, the Sustainable Forestry Initiative, the American Tree Farm System, or USDA are examples of the types of programs that could indicate actively managed tree plantations. iii. Slash and Pre-Commercial Thinnings The EISA definition of renewable biomass includes slash and pre- commercial thinnings from non-federal forestlands, including forestlands belonging to an Indian tribe or an Indian individual, that are held in trust by the United States or subject to a restriction against alienation imposed by the United States. It excludes slash and pre-commercial thinnings from forests or forestlands that are ecological communities with a global or State ranking of critically imperiled, imperiled, or rare pursuant to a State Natural Heritage Program, old growth forest, or late successional forest. As described in Sec. III.B.4.a.i of this preamble, our proposed definition of ``forestland'' is generally undeveloped land covering a minimum area of 1 acre upon which the primary vegetative species are trees, including land that formerly had such tree cover and that will be regenerated. Also as noted in Sec. III.B.4.a.ii of this preamble, we propose to adopt the definition of slash listed in the Dictionary of Forestry. As for ``pre-commercial thinnings,'' the Dictionary of Forestry defines the act of such thinning as ``the removal of trees not for immediate financial return but to reduce stocking to concentrate growth on the more desirable trees.'' \18\ Because what may now be considered pre-commercial may eventually be saleable as renewable fuel feedstock, we propose not to include any reference to ``financial return'' in our definition, but rather to define pre-commercial thinnings as those trees removed from a stand of trees in order to reduce stocking to concentrate growth on more desirable trees. We propose to include diseased trees in the definition of pre-commercial thinnings due to the fact that they can threaten the integrity of an otherwise healthy stand of trees, and their removal can be viewed as reducing stocking to promote the growth of more desirable trees. We seek comment on whether our definition of pre-commercial thinnings should include a maximum diameter and, if so, what the appropriate maximum diameter should be. --------------------------------------------------------------------------- \18\ Helms, John, ed. ``The Dictionary of Forestry.'' Bethesda, MD: Society of American Foresters, 2003. --------------------------------------------------------------------------- We understand that the State Natural Heritage Programs referred to in EISA are those comprising a network associated with NatureServe, a non-profit conservation and research organization. The network includes local programs in each of the 50 United States, other U.S. territories and regions including the Navajo Nation and Tennessee Valley Authority, eleven Canadian provinces and territories, and eleven Latin American countries. Individual Natural Heritage Programs collect, analyze, and distribute scientific information about the biological diversity found within their jurisdictions. As part of their activities, these programs survey and apply NatureServe's rankings, such as critically imperiled (S1), imperiled (S2), and rare (S3) to species and ecological communities within their respective borders. NatureServe meanwhile uses data gathered by these Natural Heritage Programs to apply its global rankings, such as critically imperiled (G1), imperiled (G2), or vulnerable (the equivalent of the term ``rare,'' or G3), to species and ecological communities found in multiple States or territories. We propose to prohibit slash and pre-commercial thinnings from all forest ecological communities with global or State rankings of critically imperiled, imperiled, or vulnerable (``rare'' in the case of State rankings) from being used for renewable fuel for which RINs may be generated under RFS2. We seek comment on our interpretation that the statutory language implies including global rankings determined by NatureServe, including the ranking of vulnerable (G3), in the land restrictions under RFS2 since State Natural Heritage Programs, which were explicitly referenced in EISA, do not establish global rankings. The various state-level Natural Heritage Programs in the U.S. and abroad differ in organizational affiliation, with some operated as agencies of state or provincial government and others residing within universities or non-profit organizations. According to the NatureServe Web site, ``consistent standards for collecting and managing data allow information from different programs to be shared and combined regionally, nationally, and internationally. The nearly 800 staff from across the network are experts in their fields, and include some of the most knowledgeable field biologists and [[Page 24935]] conservation planners in their regions.'' Different Natural Heritage Programs have different processes for initiating and performing surveys of ecological communities. In many cases, the programs respond to requests for environmental reviews or surveys from parties interested in specific locations, oftentimes for a fee. They do not make available for public consumption detailed information on the location of a ranked ecological community in some cases to protect the communities themselves and in other cases to protect private property interests. Additionally, the datasets maintained by different Natural Heritage Programs may not completely represent all of the vulnerable ecological communities in their respective States or territories simply due to the fact that surveys have not been performed for all areas. NatureServe, however, interacts with each of the State Natural Heritage Programs to update their central database to include each State program's ecological community rankings. We propose to use data compiled by NatureServe and published in a special report to identify ``ecologically sensitive forestland.'' The report would list all forest ecological communities in the U.S. with a global ranking of G1, G2, or G3, or with a State ranking of S1, S2, or S3, and would include descriptions of the key geographic and biologic attributes of the referenced ecological community. The document would be incorporated by reference into the definition of renewable biomass in the final RFS2 regulations, and the effect would be to identify specific ecological communities from which slash and pre-commercial thinnings could not be used as feedstock for the production of renewable fuel that would qualify for RINs under RFS2. In the future, it may be necessary to update this list as appropriate through notice and comment rulemaking. We will place a draft version of this document in the docket for the proposed rule as soon as it is available. EPA solicits comment both on this general incorporation-by-reference approach and on each individual listing in the document. We also seek comment on whether EPA should include in the document forest ecological communities outside of the 50 United States (such as in Canada or Latin American countries) that have natural heritage rankings of G1, G2, or G3 or S1, S2, or S3. In addition, we request comment on other ways that EPA may be able to provide the protections that Congress intended for important ecological communities with state-level rankings pursuant to a State Natural Heritage Program. To complete the definition of ``ecologically sensitive forestland,'' we propose to include old growth and late successional forestland which is characterized by trees at least 200 years old.\19\ We seek comment on this definition, including the proposed 200-year tree age, on whether we should specify a process for determining when a forest is ``characterized by'' trees of this or another age, and on other ways to identify old growth or late successional forestland. --------------------------------------------------------------------------- \19\ Old-growth forest is defined in the Dictionary of Forestry as ``the (usually) late successional stage of forest development. Note: Old-growth forests are defined in many ways; generally, structural characteristics used to describe old-growth forests include (a) live trees: Number and minimum size of both seral and climax dominants, (b) canopy conditions: Commonly including multilayering, (c) snags: Minimum number of specific size, and (d) down logs and coarse woody debris: Minimum tonnage and numbers of pieces of specific size. Note: Old-growth forests generally contain trees that are large for their species and site and sometimes decadent (overmature) with broken tops, often a variety of trees sizes, large snags and logs, and a developed and often patchy understory * * *.'' --------------------------------------------------------------------------- iv. Biomass Obtained From Certain Areas at Risk From Wildfire The EISA definition of renewable biomass includes biomass obtained from the immediate vicinity of buildings and other areas regularly occupied by people, or of public infrastructure, at risk from wildfire. We propose to clarify in the regulations that ``biomass'' is organic matter that is available on a renewable or recurring basis, and that it must be obtained from within 200 feet of buildings, campgrounds, and other areas regularly occupied by people, or of public infrastructure, such as utility corridors, bridges, and roadways, in areas at risk of wildfire. We propose to define ``areas at risk of wildfire'' as areas located within--or within one mile of--forestland, tree plantations, or any other generally undeveloped tract of land that is at least one acre in size with substantial vegetative cover. It is our understanding that 100 to 200 feet is the minimum distance recommended for clearing trees and brush away from homes and other property in certain wildfire-prone areas, depending on slope and vegetation.\20\ We propose that under RFS2, the term ``immediate vicinity'' would mean within 200 feet of a given structure or area, but we seek comment on the appropriateness of limiting the distance to within 100 feet. --------------------------------------------------------------------------- \20\ See Cohen, Jack. ``Reducing the Wildland Fire Threat to Homes: Where and How Much?'' USDA Forest Service Gen.Tech.Rep. PSW- GTR-173. 1999. See also U.S. Federal Emergency Management Agency (FEMA) Web site http://www.fema.gov/hazard/wildfire/index.shtm. --------------------------------------------------------------------------- A great deal of work has been done to identify communities and areas on the landscape in the vicinity of public lands that are at risk of wildfire by States in cooperation and consultation with the U.S. Forest Service, Bureau of Land Management, and other federal, State, and local agencies and tribes. In order to take advantage of this work, we seek comment on two possible implementation alternatives. The first alternative would incorporate into our definition of ``areas at risk of wildfire'' any communities identified as ``communities at risk'' through a process defined within the ``Field Guidance--Identifying and Prioritizing Communities at Risk'' (National Association of State Foresters, June 2003) and covered by a community wildfire protection plan (CWPP) developed in accordance with ``Preparing a Community Wildfire Protection Plan--A Handbook for Wildland-Urban Interface Communities'' (Society of American Foresters, March 2004) and certified by a State Forester or equivalent. We believe that it may make sense to include communities with CWPPs in the definition of ``areas at risk of wildfire'' since they represent specific areas around the U.S. that are identified and agreed upon through a public process that includes local and state representatives, federal agencies, and stakeholders. Additionally, CWPP guidelines indicate that normally three entities must mutually agree to the contents of the CWPPs: The applicable local government, the local fire department or departments, and the state entity responsible for forest management (State Forester or equivalent). As of June 2008, there were roughly 52,000 total ``communities at risk'' and 5,000 ``communities at risk'' covered by a CWPP. We seek comment on incorporating by reference into the final RFS2 regulations a list of ``communities at risk'' with an approved CWPP. Similar to the document proposed for Natural Heritage Rankings, this document would be incorporated by reference into the definition of ``areas at risk of wildfire'' in the final RFS2 regulations. Because this list does not currently exist, EPA would be required to seek data from each State in order to assemble the document. The effect of this incorporation by reference would be to identify specific areas in the U.S. at risk of wildfire and from which biomass obtained from the immediate vicinity of buildings and other areas regularly occupied by people, or of public infrastructure, could be easily identified [[Page 24936]] and documented as renewable biomass. In the future, it may be necessary to update this list as appropriate through notice and comment rulemaking. The second implementation approach on which we seek comment would incorporate into our definition of ``areas at risk of wildfire'' any areas identified as wildland urban interface (WUI) land, or land in which houses meet wildland vegetation or are mixed with vegetation. The concept of the WUI was established as part of the Healthy Forests Restoration Act (Pub. L. 108-148) which provided a means for prioritizing, planning, and executing hazardous fuels reduction projects on federal lands. SILVIS Lab, in the Department of Forest Ecology and Management and the University of Wisconsin, Madison, has, with funding provided by the U.S. Forest Service, mapped WUI lands based on data from the 2000 U.S. Census and U.S. Geological Survey National Land Cover Data.\21\ We seek comment on whether and how best to make use of this WUI map and data to help implement the land restrictions for biomass obtained from areas at risk of wildfire under RFS2. --------------------------------------------------------------------------- \21\ See http://silvis.forest.wisc.edu/projects/US_WUI_ 2000.asp.--------------------------------------------------------------------------- b. Issues Related to Implementation and Enforceability Incorporating the new definition of renewable biomass into the RFS2 program raises issues that we did not have to consider when designing the RFS1 program. Under RFS1, the source of a renewable fuel feedstock was not a central concern, and it was a relatively straightforward matter to require all fuel made from specified renewable feedstocks to be assigned RINs. However, with the terms ``renewable fuel'' and ``renewable biomass'' being defined differently under EISA, we must consider potential issues related to implementation and enforcement to ensure that renewable fuel for which RINs are generated is produced from qualifying renewable biomass. Our proposed approach to the treatment of renewable biomass under RFS2 is intended to define the conditions under which RINs can be generated as well as the conditions under which renewable fuel can be produced or imported without RINs. Both of these areas are described in more detail below. i. Ensuring That RINs Are Generated Only for Fuels Made From Renewable Biomass The effect of adding EISA's definition of renewable biomass to the RFS program is to ensure that renewable fuels are only allowed to participate in the program if the feedstocks from which they were made come from certain types of land. In the context of our regulatory program, this means that RINs could only be generated if it can be established that the feedstock from which the fuel was made came from these types of lands. Otherwise, no RINs could be generated to represent the renewable fuel produced or imported. We have considered the possibility that land restrictions contained within the definition of renewable biomass may not, in practice, result in a significant change in agricultural practices. For example, a farmer wishing to expand his production by cutting forested land could grow feedstock for renewable fuel on his existing agricultural land and move production for food, animal feed, and fiber production to newly cultivated land. While the EISA language is fairly clear about what lands may be used for harvesting renewable fuel feedstocks, it does not specifically address the potential for switching non-feedstock crops to new lands. Our proposed options recognize the potential for this behavior but do not attempt to prohibit it as we believe doing so would be beyond our mandate under EISA. EPA believes that Congress would have specifically directed EPA to regulate this practice if they intended EPA to do so. Another major issue we have considered is the treatment of domestically produced renewable fuel feedstocks versus imported feedstocks and imported renewable fuel, since the new EISA language does not distinguish between domestic renewable fuel feedstocks and renewable fuel and feedstocks that come from abroad. Under RFS1, RINs must be generated for imported renewable fuel by the renewable fuel importer. Foreign renewable fuel producers may not participate as producers in the program (i.e., may not generate RINs for their fuel) unless they produce cellulosic biomass or waste-derived ethanol and register with EPA. Because RFS1 does not define renewable fuel by its source, assigning RINs to imported renewable fuel under RFS1 is a straightforward responsibility of the importer. However, under RFS2, ensuring that the feedstock used to produce imported renewable fuel meets the definition of renewable biomass presents additional challenges to designing a program that can apply to both domestic and imported renewable fuel. The options contained in today's proposal attempt to address this additional constraint, as discussed in Section III.B.4.d of this preamble. ii. Ensuring That RINs Are Generated for All Qualifying Renewable Fuel Under RFS1, virtually all renewable fuel is required to be assigned a RIN by the producer or importer. This requirement was developed and finalized in the RFS1 rulemaking in order to address stakeholder concerns, particularly from obligated parties, that the number of available RINs should reflect the total volume of renewable fuel used in the transportation sector in the U.S. and facilitate program compliance. The only circumstances under which a batch of fuel is not assigned a RIN in RFS1 is if the feedstock used to produce the fuel is not among those listed in the regulatory definition of renewable fuel at Sec. 80.1101(d), the producer or importer of the fuel produces or imports less than 10,000 gallons per year, or the fuel is produced and used for off-road or other non-motor vehicle purposes. As a result, we believe that almost all renewable fuel produced or imported into the U.S. is assigned RINs under the RFS1 program, and thus the number of RINs available to obligated parties represents as accurately as possible the volume of renewable fuel being used in the U.S. transportation sector. EISA has dramatically increased the mandated volumes of renewable fuel that obligated parties must ensure are produced and used in the U.S. At the same time, EISA makes it more difficult for renewable fuel producers to demonstrate that they have fuel that qualifies for RIN generation by restricting qualifying renewable fuel to that made from ``renewable biomass,'' defined to include restrictions on the types of land from which feedstocks may be harvested, as discussed in this section. The inclusion of such land restrictions under RFS2 may mean that, in some situations, a renewable fuel producer would prefer to forgo the benefits of RIN generation to avoid the cost and difficulty of ensuring that its feedstocks qualify for RIN generation. If a sufficient number of renewable fuel producers acted in this way, it could lead to a situation in which not all qualifying fuel is assigned RINs, thus resulting in a short RIN market that could force obligated parties into non-compliance. Another possible outcome would be that the demand for and price of RINs would increase significantly, making compliance by obligated parties more costly and difficult than necessary and raising prices for consumers. In order to avoid situations in which obligated parties cannot comply with [[Page 24937]] their annual RVOs and the volume mandates in EISA are not met, or instances where the requirements are met but at an inflated price, we believe that our proposal should ensure that RINs are generated for all fuel made from feedstock that meets the definition of renewable biomass and which meets the GHG emissions reduction thresholds set out in EISA. This would require eliminating any incentive for renewable fuel producers to avoid ascertaining where their feedstocks come from. As described in Section III.B.4.d below, we propose to require a demonstration of the type of land used to produce any feedstock used in the production of renewable fuel, regardless of whether RINs are generated or not, and to require that RINs be generated for all qualifying fuel. However, we also seek comment on an alternative approach wherein a renewable fuel producer would not be required to make any demonstration with regard to the origin of feedstocks used in fuel production if the fuel producer were not generating RINs. In this situation, we would rely on the price of RINs in the market to encourage renewable fuel producers to generate RINs where possible. This approach would have the advantage of lessening the regulatory burden for renewable fuel producers using feedstock that is not renewable biomass, and would generally simplify the regulations relating to implementation of the renewable biomass definition. The disadvantage to this approach, as discussed above, would be the increased potential for a RIN shortage caused by renewable fuel producers choosing not to generate RINs for qualifying renewable fuel and a concurrent increase in the price of RINs that do exist. Under such circumstances, it is likely that some obligated parties could not acquire sufficient RINs for compliance purposes, while others could comply but at an inflated cost. A further step that we could take to streamline not just the implementation of the renewable biomass definition, but also the tracking and trading of RINs, would be to remove the restriction established under the RFS1 rule requiring that RINs be assigned to batches of renewable fuel and transferred with those batches. Instead, renewable fuel producers could sell RINs (with a K code of 2 rather than 1) separately from volumes of renewable fuel. While this alternative approach could potentially place obligated parties at greater risk of market manipulation by renewable fuel producers, it could also provide a greater incentive for producers to demonstrate that the renewable biomass definition has been met for their feedstocks. That is, by having the flexibility to sell RINs independent from volume, producers could potentially command higher prices for those RINs. This would make RINS more valuable to them, and provide an incentive to generate as many RINs as possible. As a result, producers would be motivated to demonstrate that their feedstocks meet the renewable biomass definition. However, this approach could also increase compliance costs for obligated parties. For further discussion of this approach, see Section III.H.4. c. Review of Existing Programs i. USDA Programs To inform our approach for designing an implementation scheme for the renewable biomass land restrictions under RFS2, we reviewed a number of programs and models that track, certify, or verify agricultural and silvicultural products or land use in the U.S. and abroad. First we looked at several existing programs administered by USDA that involve data collection from agricultural land owners, farmers, and forest owners. However, while USDA obtains and maintains valuable data from agricultural land owners, producers, and forest owners for assessing the status of agricultural land, forest land, and other types of land that could be used for renewable fuel feedstock production, Section 1619 of the Food, Conservation, and Energy Act of 2008 (the 2008 Farm Bill) and policies of certain USDA agencies significantly limit EPA's ability to access such data in a timely and meaningful way. Given that agricultural land owners, producers, and forest owners already report a great deal of information to USDA, having access to such information could enable EPA to avoid having to require duplicative reporting or recordkeeping and thereby minimize any burden that RFS2 may place on parties in the renewable fuel feedstock supply chain, from feedstock producer to renewable fuel producer, while still allowing us to ensure that the land restrictions on renewable biomass production are adhered to. We request comment on how EPA could acquire the type of information submitted by parties such as agricultural land owners, producers, and forest owners to USDA agencies in order to aid in administering RFS2. Having access to such information could be valuable to EPA in informing our enforcement actions. ii. Third-Party Programs To inform our options for how we might verify and track renewable biomass, we also explored non-governmental, third-party verification programs used for certifying and tracking agricultural and forest products from point of origin to point of use both within the U.S. and outside the U.S. The United Kingdom and the EU are looking to such third-party verification programs to implement the sustainability provisions of their biofuels programs. There is no third-party organization that certifies agricultural land, managed tree plantations, and forests; rather, each generally focuses on one area. Due to this constraint, we examined third party organizations that certify specific types of biomass from croplands and organizations that certify forest lands. We examined third-party organizations that focus on a particular type of feedstock used for renewable fuel production, including the Roundtable on Sustainable Palm Oil and the Basel Criteria for Responsible Soy Production. These initiatives have outlined traceable certification programs for industry to follow. Two other cooperative organizations whose primary concern is renewable fuel production from biomass are the Roundtable on Sustainable Biofuels (RSB) and the Better Sugarcane Initiative (BSI). At present, the RSB and BSI are still in their developmental stages and do not have fully developed certification processes. We also examined the work of the international Soy Working Group, comprised of representatives from industry, the Brazilian government, and international non-governmental organizations (NGOs), which recently announced a one-year extension of a moratorium on the use of soy harvested from recently deforested lands in the Brazilian Amazon. This moratorium is the result of a negotiated voluntary agreement through which companies that purchase Brazilian soy work with their suppliers to ensure that they source their soy from farms cultivated prior to August 2006. The Brazilian Association of Vegetable Oil Industries (ABIOVE) and Brazil's National Association of Grain Exporters (ANEC) have used aerial photography to identify whether any newly deforested areas were used to grow soy, and Greenpeace, one of the NGOs involved in the agreement, uses satellite imagery and aerial photography to perform spot checks for enforcement purposes. Another new example of a renewable fuel feedstock verification system is the [[Page 24938]] Verified Sustainable Ethanol initiative, which established a series of criteria for ethanol produced in Brazil and sold to Swedish ethanol importer SEKAB. The Brazilian sugarcane ethanol industry trade association, UNICA, its member companies, and SEKAB established the criteria to promote environmental and social sustainability of sugarcane ethanol exported to Sweden. The agreement is between companies, and it relies on a third-party auditor to inspect Brazilian feedstock and ethanol production facilities to verify compliance with the criteria. We also examined third-party organizations that specialize in certifying sustainable forest lands. The Sustainable Agriculture Network (SAN), through the Rainforest Alliance, provides comprehensive certification of wooded areas used for commercial development through sustainable processes in the United States and Latin American countries. The SAN certifies approximately 10 million acres of land worldwide, with minimal agricultural land certified in the U.S.\22\ --------------------------------------------------------------------------- \22\ Forest acreage taken from USDA Economic Research Service, Major uses of Land in the United States, 2002, Economic Information Bulletin No. (EIB-14), May 2006. --------------------------------------------------------------------------- We examined the certification process of the Forest Stewardship Council (FSC) because of their international recognition for certifying sustainable forests and their recordkeeping requirement for ``chain of supply'' certification for products. The FSC certifies 22 million acres of land in the U.S. according to certification standards designed for nine separate regions within the U.S., and it provides an example for chain-of-custody and product segregation requirements.\23\ Finally, we examined the American Tree Farm program and Sustainable Forestry Initiative (SFI). --------------------------------------------------------------------------- \23\ FSC certified acreage taken from FSC-US, Prospectus, 2005. --------------------------------------------------------------------------- The criteria used to certify participants through third-party verification systems are overall more comprehensive and generally more stringent than the land restrictions contained within the definition of renewable biomass. However, three issues emerged through our investigation of these existing third-party verification systems that would make it difficult to adopt or incorporate any one of them into our regulations for the land restriction provisions under EISA. First, as previously noted, many of these third-party certifiers are limited in the scope of products that they certify. Second, the acreage of agricultural land or actively managed tree plantations certified through third parties in the U.S. covers only a small portion of the total available land and forests estimated to qualify for renewable biomass production under the EISA definition. Third, none of the existing third-party systems had definitions or criteria that perfectly matched the land use definitions and restrictions contained in the EISA definition of renewable biomass. Thus, we have determined that at this time we cannot rely on any existing third-party verification program solely to implement the land restrictions on renewable biomass under RFS2. We believe there is potential benefit in utilizing third-party verification programs if these issues can be addressed, and in the following section we offer one possible scenario as an implementation alternative. Nonetheless, we seek comment on our conclusion that there are currently no appropriate third-party verification systems for renewable biomass that could be adopted under RFS2. We further seek comment on whether any existing program or combination of programs would be able to meet the definitions and adopt the land restriction criteria proposed for RFS2 to assist industry in meeting their obligations under this proposed program. d. Approaches for Domestic Renewable Fuel Consistent with RFS1, renewable fuel producers would be responsible for generating RINs under RFS2. In order to make a determination whether or not their fuel is eligible for RINs, renewable fuel producers would need to have at least basic information about the origin of their feedstock. The following approaches for implementing the land restrictions on renewable biomass contained in EISA illustrate the variety of ways that renewable fuel feedstocks could be handled under RFS2. These options are presented singly, but we seek comment on how they might be combined to create the most appropriate, practical, and enforceable implementation scheme for renewable biomass under RFS2. One approach for ensuring that producers generate RINs properly would be for EPA to require that renewable fuel producers obtain documentation about their feedstocks from their feedstock supplier(s) and take the measures necessary to ensure that they know the source of their feedstocks and can demonstrate to EPA that they have complied with the EISA definition of renewable biomass. Under this approach, EPA would require renewable fuel producers who generate RINs to certify on their renewable fuel production reports that the feedstock used for each renewable fuel batch meets the definition of renewable biomass. We would require renewable fuel producers to maintain sufficient records to support these claims. Specifically, renewable fuel producers who use planted crops or crop residue from existing agricultural land, or who use planted trees or slash from actively managed tree plantations, would be required to have copies of their feedstock producers' written records that serve as evidence of land being actively managed (or fallow, in the case of agricultural land) since December 2007, such as sales records for planted crops or trees, livestock, crop residue, or slash; a written management plan for agricultural or silvicultural purposes; or, documentation of participation in an agricultural or silvicultural program sponsored by a Federal, state or local government agency. In the case of all other biomass, we would require renewable fuel producers to have, at a minimum, written certification from their feedstock supplier that the feedstock qualifies as renewable biomass. We seek comment on whether we should also require renewable fuel producers that use slash and pre-commercial thinnings from non-federal forestland and biomass from areas at risk of wildfire to maintain additional records to support the claim that these feedstocks meet the definition of renewable biomass. These records could include sworn statements from licensed or registered foresters, contracts for tree or slash removal or documentation of participation in a fire mitigation program. We seek comment on other methods of verifying renewable fuel producers' claims that feedstocks qualify for these categories of renewable biomass. A review of such records would become part of the producer's annual attest engagement, the annual audit of their records by an independent third party (see Section IV.A for a full discussion of attest engagement requirements). A renewable fuel producer would only be permitted to produce and sell renewable fuel without RINs if he demonstrates that the feedstocks used to produce his fuel do not meet the definition of renewable biomass. This approach would ensure that renewable fuel producers could not avoid the generation of RINs simply by failing to make a demonstration regarding the land used to produce their feedstocks. Thus, renewable fuel producers would be required to keep records of their feedstock source(s), regardless of [[Page 24939]] whether RINs were generated or not. At a minimum, renewable fuel producers who do not generate RINs would need to have certification from their feedstock supplier that their feedstock does not meet the definition of renewable biomass. In the event that some portion of a load of feedstock does meet the definition of renewable biomass and some portion does not, the renewable fuel producer would need to maintain documentation from their supplier that states the percentage of each portion. All of these records would be included as part of the renewable fuel producer's annual attest engagement. The renewable fuel producer would also indicate on his renewable fuel production report that he did not generate RINs for fuel made from feedstock that did not meet the definition of renewable biomass. Some stakeholders have expressed concern about EPA specifying the records that a renewable fuel producer must obtain from their feedstock supplier. We therefore seek comment on an approach that would require renewable fuel producers to certify on their renewable fuel production reports that their feedstock either met or did not meet the definition of renewable biomass and would require producers to maintain sufficient records to support their claims, but would stop short of specifying what those records would have to include. We anticipate that a large portion of feedstocks that qualify as renewable biomass will be obtained from existing agricultural land or actively managed tree plantations, for which, by definition, documentation already exists. We believe that, in most other cases, feedstock producers will have or will be able to create other forms of documentation that could be provided to renewable fuel producers in order to provide adequate assurance that the feedstock in question meets the definition of renewable biomass. As described above, there are many existing programs, such as those administered by USDA and independent third- party certifiers, that could be useful to verify that feedstock from certain land qualifies as renewable biomass. We anticipate that these self-certification approaches would result in renewable fuel producers amending their contracts and altering their supply chain interactions to satisfy their need for documented assurance and proof about their feedstock's origins. Enforcement under either of these approaches would rely in part on EPA's review of renewable fuel production reports and attest engagements of renewable fuel producers' records. EPA would also consult other data sources, including any data made available by USDA, and could conduct site visits or inspections of feedstock producers' and suppliers' facilities. We seek comment on the feasibility and practical limitations of EPA working with publicly available USDA data to keep track of significant land use changes in the U.S. and around the world and to note general increases in feedstock supplier productivity that might signal cultivation of new agricultural land for renewable fuel feedstock production. Either of these approaches would easily fold into existing and newly proposed registration, recordkeeping, reporting, and attest engagement procedures. They would also place the burden of implementation and enforcement on renewable fuel producers rather than bringing feedstock producers and suppliers directly under EPA regulation. In this way, they would minimize the number of regulated parties under RFS2. They would also allow, to varying degree, the renewable fuel industry to determine the most efficient means of verifying and tracking feedstocks from the point of production to the point of consumption, thereby minimizing any additional cost and administrative burden created by the EISA definition of renewable biomass. Another alternative would be for EPA to establish a chain-of- custody tracking system from feedstock producer to renewable fuel producer through which renewable fuel producers would obtain information regarding the lands where their feedstocks were produced. This information would accompany each transfer of custody of the feedstock until the feedstock reaches the renewable fuel producer. Renewable fuel feedstock producers, suppliers and handlers would not have any reporting obligations. EPA would, however, require all feedstock producers, suppliers, and handlers to maintain as records these chain-of-custody documents for all biomass intended to be used as a renewable fuel feedstock. Renewable fuel producers would also be required to maintain these chain-of-custody tracking documents in their records and would have to include them as part of their records presented during their annual attest engagement. An additional alternative would be for EPA to require renewable fuel producers to set up and administer a quality assurance program that would create an additional level of rigor in the implementation scheme for the EISA land restrictions on renewable biomass. The quality assurance program could include (1) an unannounced independent third party inspection of the renewable feedstock producer's facility at least once per quarter or once every 15 deliveries, whichever is more frequent, (2) an unannounced independent third party inspection of each intermediary facility that stores renewable fuel feedstock received by the renewable fuel producer at least once per quarter, and (3) on each occasion when the independent third party inspection reveals noncompliance, the renewable fuel producer must (a) conduct an investigation to determine the proper number of RINs that should have been generated for a volume of fuel and either generate or retire an equal number of RINs, depending on whether the fuel's feedstock did or did not meet the definition of renewable biomass, (b) conduct a root cause analysis of the violation, and (c) refuse to accept or process feedstock from the renewable fuel feedstock producer unless or until the feedstock producer takes appropriate corrective action to prevent future violations. This alternative could provide a partial affirmative defense either for renewable producers that illegally generate RINs for fuel made from feedstocks that do not qualify as renewable biomass or for renewable fuel producers who do not generate enough RINs for fuel made from feedstocks that do qualify as renewable biomass. In either case, the producers must demonstrate that the violation was caused by a feedstock producer or supplier and not themselves; that the commercial documents (e.g., bills of lading) received with the feedstock indicated that the feedstock either met (in the case that RINs were generated illegally) or did not meet (in the case that an inadequate number of RINs were generated) the land restrictions for renewable biomass, and that they met EPA's quality assurance program requirements. A renewable fuel producer that generates RINs for fuel made from a feedstock that does not meet the definition of renewable biomass, but that qualifies for the partial affirmative defense, would still have to retire a number of RINs equal to the illegally generated RINs. Likewise, a renewable fuel producer that does not generate sufficient RINs for fuel made from a feedstock that does meet the definition of renewable biomass, but that qualifies for the partial affirmative defense, would have to generate enough RINs to make up the difference. However, in neither case would they be subject to civil penalties. As yet another alternative approach, EPA could bring together renewable fuel producers and renewable fuel feedstock producers and suppliers to develop an industry-wide quality assurance [[Page 24940]] program for the renewable fuel production supply chain, following the model of the successful Reformulated Gasoline Survey Association. We believe that this alternative could be less costly than if each individual renewable fuel producer were to create their own quality assurance program, and it would add a quality assurance element to RFS2 while creating the possibility for a partial affirmative defense for renewable fuel producers and feedstock producers and suppliers. The program would be carried out by an independent surveyor funded by industry and consist of a nationwide verification program for renewable fuel producers and renewable feedstock producers and handlers designed to provide independent oversight of the feedstock designations and handling processes that are required to determine if a feedstock meets the definition of renewable biomass. Under this alternative, a renewable fuel producer and its renewable feedstock suppliers and handlers would have to participate in the funding of an organization which arranges to have an independent surveyor conduct a program of compliance surveys. Compliance surveys would be carried out by an independent surveyor pursuant to a detailed survey plan submitted to EPA for approval by November 1 of the year preceding the year in which the alternative quality assurance sampling and testing program would be implemented. The survey plan would include a methodology for determining when the survey samples would be collected, the locations of the surveys, the number of inspections to be included in the survey, and any other elements that EPA determines are necessary to achieve the same level of quality assurance as the requirement included in the RFS2 regulations at the time. Under this alternative, the independent surveyor would be required to visit renewable feedstock producers and suppliers to determine if they are properly designating their product and adhering to adequate chain of custody requirements. This nationwide sampling program would be designed to ensure even coverage of renewable feedstock producers and suppliers. The surveyor would generate and report the results of the surveys to EPA each calendar quarter. In addition, where the survey finds improper designations or handling, the liable parties would be responsible for identifying and addressing the root cause of the violation to prevent future violations. When a violation is detected, the renewable fuel producer that participates in the consortium would be deemed to have met the quality assurance criteria for a partial affirmative defense. If the renewable fuel producer met the other applicable criteria, he would have to take corrective action to retire or generate the appropriate number of RINs depending on the violation, but he would not be subject to civil penalties. Some stakeholders have suggested that EPA take advantage of existing satellite and aerial imagery and mapping software and tools to implement the renewable biomass provisions of EISA. One way to do so would be for EPA to develop a renewable fuel mapping Web site to assist regulated parties in meeting their obligation to identify the location of land where renewable fuel feedstocks are produced. Such a Web site could include an interactive map that would allow renewable feedstock producers to trace the boundaries of their property and create an electronic file with information regarding the land where their renewable fuel feedstocks were produced, such as a code that identifies the plot of land. This would allow the feedstock producer to provide information, such as a standard land ID code, on all bills of lading or other commercial documents that identify the type and quantity of feedstock being delivered to the renewable fuel producer. Renewable fuel producers could then make a determination regarding whether or not the renewable fuel feedstock that they use meets the definition of renewable biomass, and is therefore eligible or not for RIN generation. Feedstock producers would not necessarily be required to use this Internet-based tool to identify the location where renewable fuel feedstocks are produced, since many feedstock producers already participate in various government or insurance programs that have required them to map the location of their fields. But the map would enable renewable fuel producers to verify the accuracy of these descriptions and report these locations to EPA using the interactive mapping tool on EPA's Web site. EPA specifically solicits comment on the practicability of constructing an accurate map from existing data sources. As noted above, EPA recognizes that land restrictions contained within the definition of renewable biomass may not, in practice, result in a significant change in agricultural practices. EPA also recognizes that the implementation options described in this proposal could impose costs and constraints on existing storage, transportation, and delivery systems for feedstocks, in particular for corn and soybeans in the U.S. We therefore seek comment on a stakeholder suggestion to establish a baseline level of production of biomass feedstocks such that reporting and recordkeeping requirements would be triggered only when the baseline production levels of feedstocks used for biofuels were exceeded. Such an approach would avoid imposing a new recordkeeping burden on the industry as long as biofuels demand is met with existing feedstock production. We seek comment on this alternative, including how to set the baseline production levels and information on appropriate data sources in the U.S. and in other countries that produce feedstocks that could be used for renewable fuel production, and on how to track whether the feedstock use for biofuels production has exceeded baseline production levels. We also solicit comment on whether this approach could be applied to all types of feedstocks on which EISA places land restrictions, or if it would only be appropriate for traditional agricultural crops such as corn, soybeans, and sugarcane for which historical acreage data exists both domestically and internationally. EPA acknowledges that under this alternative, while there could be a net increase in lands being cultivated for a particular crop, we would presume that increases in cultivation would be used to meet non- biofuels related feedstock demand. We also acknowledge that such an approach would be difficult to enforce because data that could indicate that baseline production levels were exceeded in a given year would likely be delayed by many months, such that the recordkeeping requirements for renewable fuel producers would also be delayed. During the interim period, renewable fuel producers would have generated RINs for fuel that did not qualify for credit under the program, and any remedial steps to invalidate such RINs after the fact could be costly and burdensome to all parties in the supply chain. Nonetheless, we seek comment on the approach as described above. We seek comment on all of these approaches and what combination of these approaches would be the most appropriate, enforceable, and practical for ensuring that the land restrictions on renewable biomass contained in EISA are implemented under RFS2. We also seek comment on whether there are other possible approaches that would be superior to those we have described above. We also note that we intend to monitor RIN generation and the trends [[Page 24941]] in renewable fuel feedstock sources as RFS2 implementation gets underway, and that we may make changes to the approach we adopt in the final RFS2 regulations if renewable fuel feedstock production conditions change or if new, better renewable biomass verification tools become available. e. Approaches for Foreign Renewable Fuel EISA creates unique challenges related to the implementation and enforcement of the definition of renewable biomass for foreign-produced renewable fuel. In order to address these issues, we propose to require foreign producers of renewable fuel who export to the U.S. to meet the same compliance obligations as domestic renewable fuel producers. These obligations would include facility registration and submittal of independent engineering reviews (described in Section III.C below), and reporting, recordkeeping, and attest engagement requirements. They would also include the same obligations that domestic producers have for verifying that their feedstock meets the definition of renewable biomass as described above, such as certifying on each renewable fuel production report that their renewable fuel feedstock meets the definition of renewable biomass and working with their feedstock supplier(s) to ensure that they receive and maintain accurate and sufficient documentation in their records to support their claims. As under the RFS1 program for producers of cellulosic fuel, the foreign producer would be required to comply with additional requirements designed to ensure that enforcement of the regulations at the foreign production facility would not be compromised. For instance, foreign producers would be required to designate renewable fuel intended for export to the U.S. as such and segregate the volume until it reaches the U.S. and post a bond to ensure that penalties can be assessed in the event of a violation. Moreover, as a regulated party under the RFS2 program, foreign producers would have to allow for potential visits by EPA enforcement personnel to review the completeness and accuracy of records and registration information. We propose that a foreign renewable fuel producer, like a domestic renewable fuel producer, could only produce and sell renewable fuel for export to the U.S. without RINs if he demonstrated that the land used to produce his feedstocks did not meet the definition of renewable biomass. This approach would ensure that foreign renewable fuel producers could not avoid the generation of RINs for fuel shipped to the U.S. simply by failing to make any demonstration regarding the land used to produce their feedstocks. Thus, foreign renewable fuel producers that export their product to the U.S. would be required to keep records of the type of land used to produce their feedstock regardless of whether RINs are generated or not. Section III.D.2.b outlines more specifically our proposed requirements for foreign renewable fuel producers. Importers will likely have less knowledge than a foreign renewable fuel producer would about the point of origin of their fuel's feedstock and whether it meets the definition of renewable biomass. Therefore, we are proposing that in the event that a batch of foreign-produced renewable fuel does not have RINs accompanying it, an importer must obtain documentation from its producer that states whether or not the definition of renewable biomass was met by the fuel's feedstock. With such documentation, the importer would be required to generate RINs (if the definition of renewable biomass is met) or would be prohibited from doing so (if the definition is not met) prior to introducing the fuel into commerce in the U.S. Without such documentation, the fuel would not be permitted for importation. Section III.D.2.c outlines our proposed requirements for importers more fully. We seek comment on whether and to what extent the approaches for ensuring compliance with the EISA's land restrictions by foreign renewable fuel producers could or should differ from the proposed approach for domestic renewable fuel producers. In light of the challenges associated with enforcing the EISA's land restrictions in foreign countries, we believe that it may be appropriate to require foreign renewable fuel producers to use an alternative method of demonstrating compliance with these requirements. We seek comment on whether foreign renewable producers exporting product to the U.S. should have to comply with any of the alternatives described for domestic renewable fuel producers under this section. For example, we seek comment on whether a foreign renewable fuel producer should have to demonstrate that it had a contract in place with its renewable feedstock producer that required designation and chain of custody and handling methods similar to one of the alternatives for domestic renewable fuel producers discussed above. We also seek comment on whether foreign renewable fuel producers that export product to the U.S. should have to provide EPA with the location of land from which they will or have acquired feedstocks, along with historical satellite or aerial imagery demonstrating that feedstocks from these lands meet the definition of renewable biomass. We seek comment on whether foreign renewable fuel producers should also be subject to the same quality assurance requirements relating to their feedstock sources as domestic renewable fuel producers, and whether they should have the same option to use an approved survey consortium in lieu of implementing their own individual quality assurance programs. We also seek comment on an alternative that would provide foreign renewable fuel producers an option of participating in RFS2 (in a manner consistent with our main proposal), or not participating at all. If they elected not to participate in RFS2, they could export renewable fuel to the United States without RINs, and without providing any documentation as to whether or not the fuel was made with renewable biomass. However, they would also have to meet requirements for segregating their fuel from renewable fuel for which RINs were generated, and the importer of their fuel would be required to track it to ensure that the fuel remains segregated in the U.S. and is not used by a domestic company for illegal RIN generation. This alternative would provide foreign renewable fuel producers an option not available to domestic renewable fuel producers, who in all cases would be required to document whether or not their feedstock met the definition of renewable biomass, and who would be required to generate RINs for their product if it was. As discussed in Section III.B.4.b.ii of this preamble, EPA believes that in order for obligated parties to meet the increasing annual volume requirements under RFS2, all qualifying renewable fuel will need to have RINs generated for it. Nonetheless, this alternative recognizes the potential difficulty of applying renewable biomass verification procedures in the international context, and provides an exemption process that EPA expects would only be used by relatively small producers for whom the burden of participating in the RFS2 program would outweigh the benefits, and whose total production volume would be negligible. C. Expanded Registration Process for Producers and Importers In order to implement and enforce the new restrictions on qualifying renewable fuel under RFS2, we are proposing that the registration process [[Page 24942]] for renewable fuel producers and importers be revised. Under the existing RFS1 program, all producers and importers of renewable fuel who produce or import more than 10,000 gallons of fuel annually must register with EPA's fuels program prior to generating RINs. Renewable fuel producer and importer registration under the existing RFS program consists of filling out two forms: 3520-20A (Fuels Programs Company/ Entity Registration), which requires basic contact information for the company and basic business activity information (e.g., for an ethanol producer, they need to indicate that they are a RIN generator), and 3520-20B (Gasoline Programs Facility Registration) or 3520-20B1 (Diesel Programs Facility Registration), which requires basic contact information for each facility owned by the producer or importer. More detailed information on the renewable fuel production facility, such as production capacity and process, feedstocks, and products is not required for most producers or importers to generate RINs under RFS1 (producers of cellulosic biomass ethanol and waste-derived ethanol are the exception to this). Due to the revised definitions of renewable fuel under EISA, as well as other changes, we believe it necessary to expand the registration process for renewable fuel producers and importers in order to implement the new program effectively. Specifically, generating and assigning a certain category of RIN to a volume of fuel is dependent on whether the feedstock used to produce the fuel meets the definition of renewable biomass, whether the lifecycle greenhouse gas emissions of the fuel meets a certain GHG reduction threshold and, in some cases, whether the renewable fuel production facility is considered to be grandfathered into the program. Unless we require producers, including foreign producers, and importers to provide us with information on their feedstocks, facilities, and products, we cannot adequately implement or enforce the program or have confidence that producers and importers are properly categorizing their fuel and generating RINs. In particular, our proposed approach for ensuring that the GHG emission reduction thresholds for each category of renewable fuel are met will require producers and importers to determine the proper category assignment for their fuel based on a combination of their feedstock, production processes, and products (see Section III.D.2 for the proposed list). Such information, therefore, is central to program implementation. Therefore, we are proposing new registration requirements for all domestic renewable fuel producers, importers, and foreign renewable fuel producers. We also plan on integrating registration procedures with the new EPA Moderated Transaction System, discussed in detail in Section IV.E of this preamble. We encourage those affected by the proposed registration requirements to review the document entitled ``Proposed Information Collection Request (ICR) for the Renewable Fuels Standard (RFS2) Program--EPA ICR 2333.01,'' and an Addendum to the proposed ICR, which have been placed in the public docket and to provide comments to us regarding the burdens associated with the proposed registration requirements. 1. Domestic Renewable Fuel Producers The most significant proposed changes to the current registration system pertain to the information that a producer will need to provide EPA prior to generating RINs. As noted above, we are proposing that producers provide information about their products, feedstocks, and facilities in order to be registered for the RFS2 program. Information contained in a producer's registration would be used to verify the validity of RINs generated and their proper categorization as either cellulosic biofuel, biomass-based diesel, advanced biofuel, or other renewable fuel. With respect to products, we are interested in the types of renewable fuel and co-products that a facility is capable of producing. With respect to feedstocks, we believe it is necessary to have on file a list of all the different feedstocks that a renewable fuel producer's facility is capable of converting into renewable fuel. For example, if a renewable fuel producer produces fuel from both cellulosic material, such as corn stover, and non-cellulosic material, such as corn starch, the producer may be eligible to generate RINs in two different categories (cellulosic biofuel and renewable fuel). This producer's registration information would be required to list both of these feedstocks before we would allow two different categories of RINs to be generated. With respect to the producer's facilities, we are proposing two types of information that would need to be reported to the Agency. First, we believe it is important to have information on file that describes each facility's fuel production processes (e.g., wet mill, dry mill, thermochemical, etc.), and thermal/process energy source(s). Second, in order to determine what production volumes would be grandfathered and thus deemed to be in compliance with the 20% GHG threshold, we would require evidence and certification of the facility's qualification under the definition of ``commence construction'' as well as information necessary to establish it's renewable fuel baseline volume per the proposal outlined in Section III.B.3 of this preamble. Under the existing RFS1 program, producers of cellulosic biomass and waste-derived ethanol are required to have an annual engineering review of their production records performed by an independent third party who is licensed Professional Engineer (P.E.) who works in the chemical engineering field. This independent third party need not be based in the United States, but must hold a P.E. Each review must be kept on file by both the producer and the engineer for five years. The independent third party must include documentation of its qualifications as part of the engineering review. Foreign producers of cellulosic biomass and waste-derived ethanol are also required to have an engineering review of their facilities, with a report submitted to EPA that describes in detail the physical plant and its operation. These requirements helps ensure that producers who claim to be producing such fuel, which earns 2.5 RINs per gallon rather than 1.0 RIN per gallon for corn-based ethanol under RFS1, are in fact doing so. We believe that the requirement for an on-site engineering review is an effective implementation tool and propose to adopt the requirement under RFS2, with the following changes. First, we propose expanding the applicability of the requirement to all renewable fuel producers due to the variability of production facilities, the increase in the number of categories of renewable fuels, and the importance of generating RINs in the correct category. Second, we propose that every renewable fuel producer must have the on-site engineering review of their facility performed in conjunction with his or her initial registration for the new RFS program in order to establish the proper basis for RIN generation, and every three years thereafter to verify that the fuel pathways established in their initial registration are still applicable. These requirements would apply unless the renewable fuel producer updates its facility registration information to qualify for a new RIN category (i.e., D code), in which case the review would need to be performed within 60 days of the registration update. Finally, we propose that producers be required to [[Page 24943]] submit a copy of their independent engineering review to EPA rather than simply maintaining it in their records. We believe that this extra step is necessary for verification and enforcement purposes. In addition to the new registration requirements for all renewable fuel producers who produce greater than 10,000 gallons of product each year, we seek comment on whether to require renewable fuel producers and importers in the U.S. who produce or import less than 10,000 gallons per year to register basic information about their company and facility (or facilities) with EPA, similar to information currently required of renewable fuel producers under RFS1. This information would complement information submitted to EPA under the Fuels and Fuel Additives Registration System (FFARS) program to help ensure that EPA has a complete record of renewable fuel production and importation in the U.S. 2. Foreign Renewable Fuel Producers Under the current RFS program, foreign renewable fuel producers of cellulosic biomass ethanol and waste-derived ethanol may apply to EPA to generate RINs for their own fuel. This allows a foreign producer of this renewable fuel to obtain the same benefits of higher credit value as domestic producers of this category of renewable fuel. Under the RFS1 regulations, the foreign fuel producer must meet a variety of requirements established to make the program effective and enforceable with respect to a foreign producer. These requirements mirror a number of similar fuel provisions that apply to foreign refiners in other fuels programs. For RFS2, we propose that foreign producers of renewable fuel must meet the same requirements as domestic producers, including registering information about their feedstocks, facilities, and products, as well as submitting an on-site independent engineering review of their facilities at the time of registration for the program and every three years thereafter. These requirements would apply to all foreign renewable fuel producers who export their products to the U.S., whether or not they qualify to generate RINs for their fuel. They would also be subject to the variety of enforcement related provisions that apply under RFS1 to foreign producers of cellulosic biomass or waste derived ethanol. As discussed in Section III.C.1, the existing RFS1 program requires that the independent engineering review be conducted by an independent third party who is a licensed P.E. who works in the chemical engineering field. This P.E. need not be based in the United States. The independent third party must include documentation of its qualifications as part of the engineering review. Since implementation of RFS1 we have received questions about engineers who are licensed by other countries that may have equivalent licensing requirements to those associated with the P.E. designation in the United States. The existing RFS1 program does not permit independent third party review by a party who is not a licensed P.E. We invite comment on whether or not we should permit independent third parties who are based in--and licensed by--foreign countries and who work in the chemical engineering field to demonstrate the foreign equivalency of a P.E. license. We also seek comment on requiring foreign renewable fuel producers to provide EPA with the location of land from which they will acquire feedstocks, along with historical satellite or aerial imagery demonstrating that the lands from which they acquire feedstock are eligible under the definition of renewable biomass (see Section III.B.4 for a full discussion of our proposed and alternative approaches for foreign renewable fuel producers to verify their feedstocks meet the definition of ``renewable biomass''). 3. Renewable Fuel Importers A renewable fuel importer is required under RFS1 to register basic information about their company with EPA prior to generating RINs. Under the proposed new RFS2 program, we are proposing that only in limited cases can importers generate RINs for imported fuel that they receive without RINs. In any case, whether they receive fuel with or without RINs, an importer must rely on his supplier, a foreign renewable fuel producer, to provide documentation to support any claims for their decision to generate or not to generate RINs. An importer may have an agreement with a foreign renewable fuel producer for the importer to generate RINs if the foreign producer has not done so already. However, the foreign renewable fuel producer must be registered with EPA as noted above. Section III.D.2.c describes our proposed RIN generating restrictions and requirements for importers under RFS2. 4. Process and Timing We intend to make forms for expanded registration for renewable fuel producers and importers available electronically, with paper registration only in exceptional cases. We propose that registration forms will have to be submitted by January 1, 2010 (the proposed effective date of the final RFS2 regulations), or 60 days prior to a producer producing or importer importing any renewable fuel, whichever dates comes later. If a producer changes to a feedstock that is not listed in his registration information on file with EPA but the feedstock will not incur a change of RIN category for the fuel (i.e., a change in the appropriate D code), then we propose that the producer must update his registration information within seven (7) days of the change. However, if a producer's feedstock, facility (including industrial processes or thermal energy source), or products undergo changes that would qualify his renewable fuel for a new RIN category (and thus a new D code), then we propose that such an update would need to be submitted at least 60 days prior to the change, followed by submittal of a complete on-site independent engineering review of the producer's facility also within 60 days of the change. D. Generation of RINs Under RFS2, each RIN would continue to be generated by the producer or importer of the renewable fuel, as in the RFS1 program. In order to determine the number of RINs that must be generated and assigned to a batch of renewable fuel, the actual volume of the batch of renewable fuel must be multiplied by the appropriate Equivalence Value. The producer or importer must also determine the appropriate D code to assign to the RIN to identify which of the four standards the RIN can be used to meet. This section describes these two aspects of the generation of RINs. We propose that other aspects of the generation of RINs, such as the definition of a batch and temperature standardization, as well as the assignment of RINs to batches, should remain unchanged from the RFS1 requirements. 1. Equivalence Values For RFS1, we interpreted CAA section 211(o) as allowing us to develop Equivalence Values representing the number of gallons that can be claimed for compliance purposes for every physical gallon of renewable fuel. We described how the use of Equivalence Values adjusted for renewable content and based on energy content in comparison to the energy content of ethanol was consistent with Congressional intent to treat different renewable fuels differently in different circumstances, and to provide [[Page 24944]] incentives for use of renewable fuels in certain circumstances, as evidenced by the specific circumstances addressed by Congress. This included the direction that EPA establish ``appropriate'' credit values in certain circumstances, as well as provisions in the statute providing for different credit values to be assigned to the same volume of different types of renewable fuels (e.g., cellulosic and waste- derived fuels). We also noted that the use of Equivalence Values based on energy content was an appropriate measure of the extent to which a renewable fuel would replace or reduce the quantity of petroleum or other fossil fuel present in a fuel mixture. The result was an Equivalence Value for ethanol of 1.0, for butanol of 1.3, for biodiesel (mono alkyl ester) of 1.5, and for non-ester renewable diesel of 1.7. EPA stated that these provisions indicated that Congress did not intend to limit the RFS program solely to a straight volume measurement of gallons. EPA also noted that the use of Equivalence Values would not interfere with meeting the overall volume goals specified by Congress, given the various provisions that make achievement of the specified volumes imprecise. See 72 FR 23918-23920, and 71 FR 55570-55571. EISA has not changed certain of the statutory provisions we looked to for support under RFS1 in establishing Equivalence Values based on relative volumetric energy content in comparison to ethanol. For instance, CAA 211(o) continues to give EPA the authority to determine an ``appropriate'' credit for biodiesel, and also directs EPA to determine the ``appropriate'' amount of credit for renewable fuel use in excess of the required volumes. However, EISA made a number of other changes to CAA section 211(o) that impact our consideration of Equivalence Values in the context of the RFS2 program. For instance, EISA eliminated the 2.5-to-1 credit for cellulosic biomass ethanol and waste-derived ethanol and replaced this provision with large mandated volumes of cellulosic biofuel and advanced biofuels. Under the RFS1 program, an Equivalence Value of 2.5 applies to these types of ethanol through the end of 2012. Under the new RFS2 program, these types of ethanol would have an Equivalence Value of 1.0, consistent with all other forms of ethanol. EISA also expanded the program to include four separate categories of renewable fuel (cellulosic biofuel, biomass-based diesel, advanced biofuel, and total renewable fuel) and included GHG thresholds in the definitions of each category. Each of these categories of renewable fuel has its own volume requirement, and thus there will exist a guaranteed market for each. As a result there may no longer be a need for additional incentives for certain fuels in the form of Equivalence Values greater than 1.0. In addition, the use of an energy-based approach to Equivalence Values raises some questions, discussed below, concerning the impact of such Equivalence Values on the biomass-based diesel volume requirement and in the initial years on the advanced biofuel volume requirement. Overall EPA believes that the statute continues to be ambiguous on this issue, and we are therefore co- proposing and seeking comment on two options for Equivalence Values: 1. Equivalence Values would be based on the energy content and renewable content of each renewable fuel in comparison to denatured ethanol, consistent with the approach under RFS1. 2. All liquid renewable fuels would be counted strictly on the basis of their measured volumes, and the Equivalence Values for all renewable fuels would be 1.0 (essentially, Equivalence Values would no longer apply). While these two different approaches to volume would have an impact on the market values of renewable fuels with different energy contents as explained more fully below, the overall impact on the program would likely be small since we are projecting that the overwhelming majority of renewable fuels will be ethanol (see further discussion in Section V.A.2). Under either option, non-liquid renewable fuels such as biogas and renewable electricity would continue to be valued based on the energy contained in one gallon of denatured ethanol. In the RFS1 final rulemaking, we specified that 77,550 Btu of biogas be counted as the equivalent of 1 gallon of renewable fuel with an assigned Equivalence Value of 1.0. We propose to maintain this approach to non-liquid renewable fuels under the RFS2 program under either approach to Equivalence Values, but with a small modification to make the ethanol energy content more accurate. The energy content of denatured ethanol was specified as 77,550 Btu/gal under RFS1, but a more accurate value would be 77,930 Btu/gal. Thus we propose to use 77,930 Btu to convert biogas and renewable electricity into volumes of renewable fuel under RFS2. Under the second option in which all liquid renewable fuels would be counted strictly on the basis of their measured volumes, we would need to determine how to treat the small amount of denaturant in ethanol and the nonrenewable portion of biodiesel. Under RFS1, Equivalence Values were determined from a formula that included measures of both volumetric energy content and renewable content. The renewable content was intended to take into account the portion, if any, of a renewable fuel that originated from a fossil fuel feedstock. EISA eliminated the statutory language on which the inclusion of renewable content was based, and instead restricts renewable fuels that are valid under the RFS2 program to those produced from renewable biomass. In the case of fuels produced from both renewable and nonrenewable feedstocks, we have interpreted this to mean only that portion of the volume attributable to the renewable feedstocks (see further discussion in Section III.D.4 below). However, we do not believe that this approach is appropriate for the denaturant in ethanol and the small amount of non-renewable methanol used in the production of biodiesel, since Congress clearly intended that ethanol and biodiesel be included as a renewable fuel, and they are only used as a fuel under these circumstances. We therefore propose to treat the denaturant in ethanol and the nonrenewable portion of biodiesel as de minimus and thus count them as part of the renewable fuel volume under an approach to Equivalence Values in which all liquid renewable fuels would be counted strictly on the basis of their measured volumes. As a result, under this co-proposed approach we are proposing that the full formula used to calculate Equivalence Values under RFS1 be eliminated from the regulations and that the Equivalence Value for all renewable fuels be specified as 1.0. Nevertheless, we seek comment on this approach. Although there are several reasons for a straight volume approach as discussed above, there are also several reasons to maintain the ethanol-equivalent energy content approach to Equivalence Values of RFS1. For instance, in our discussions with stakeholders, some have argued that the existence of four standards is not a sufficient reason to eliminate the use of energy-based Equivalence Values for RFS2. The four categories are defined in such a way that a variety of different types of renewable fuel could qualify for each category, such that no single specific type of renewable fuel will have a guaranteed market. For example, the cellulosic biofuel requirement could be met with both cellulosic ethanol or cellulosic diesel. As a result, the existence of four standards under RFS2 may not obviate the value of standardizing for energy [[Page 24945]] content, which provides a level playing field under RFS1 for various types of renewable fuels based on energy content. More importantly, they argue that a straight volume approach would be likely to create a disincentive for the development of new renewable fuels that have a higher energy content than ethanol in the same way as the current ethanol tax credit structure. For a given mass of feedstock, the volume of renewable fuel that can be produced is roughly inversely proportional to its energy content. For instance, one ton of biomass could be gasified and converted to syngas, which could then be catalytically reformed into either 90 gallons of ethanol (and other alcohols) or 50 gallons of diesel fuel (and naphtha).\24\ If RINs were assigned on a straight volume basis, the producer could maximize the number of RINs he is able to generate and sell by producing ethanol instead of diesel. Thus, even if the market would otherwise lean towards demanding greater volumes of diesel, the greater RIN value for producing ethanol may favor its production instead. However, if the energy-based Equivalence Values were maintained, the producer could assign 1.7 RINs to each gallon of diesel made from biomass in comparison to 1.0 RIN to each gallon of ethanol from biomass, and the total number of RINs generated would be essentially the same for the diesel as it would be for the ethanol. The use of energy-based Equivalence Values could thus provide a level playing field in terms of the RFS program's incentives to produce different types of renewable fuel from the available feedstocks. The market would then be free to choose the most appropriate renewable fuels without any bias imposed by the RFS regulations, and the costs imposed on different types of renewable fuel through the assignment of RINs would be more evenly aligned with the ability of those fuels to power vehicles and engines, and displace fossil fuel-based gasoline or diesel. --------------------------------------------------------------------------- \24\ Another example would be a fermentation process in which one ton of cellulose could be used to produce either 70 gallons of ethanol or 55 gallons of butanol. --------------------------------------------------------------------------- Moreover, the technologies for producing more energy-dense fuels such as cellulosic diesel are still in the early stages of development and may benefit from not having to overcome the disincentive in the form of the same Equivalence Value based on straight volume. Given the projected tightness in the distillate market and relative excess supply in the gasoline market in the coming years, allowing the market to choose freely may be important to overall fuel supply. In the extreme, the cellulosic biofuel standard could then be met by roughly 10 billion gallons of a cellulosic diesel fuel instead of the 16 billion gallons of cellulosic ethanol assumed for the impacts analysis of this proposal. The same amount of petroleum energy would be displaced, but by different physical volumes. As discussed above, there are no provisions in EISA that explicitly instruct the Agency to change from the approach to Equivalence Values adopted in RFS1. However, there is a question of how to address the biomass-based diesel requirement under such an approach. In that context, it does appear that Congress intended the required volumes of biomass-based diesel to be treated as diesel volumes rather than ethanol-equivalent volumes. Therefore EPA proposes that, for the biomass-based diesel volume mandate under an ethanol-equivalent energy content approach to Equivalence Values, the compliance calculations would be structured such that this requirement is treated in effect as a straight volume-based requirement.\25\ --------------------------------------------------------------------------- \25\ The proposed regulations and the ensuing discussion in Sections III and IV of this proposal reflect straight volume approach, however, the impacts analysis of the program are calculated using volumes based on ethanol-equivalent energy content. Were we to maintain the energy content approach to Equivalence Values, then we believe the biomass-based diesel standard should be treated in effect as a biodiesel volume, reflecting the nature of this standard, while the other three standards would be treated as ethanol-equivalent volumes. In order to effectuate this, we are considering two approaches. Under either approach all RINs would be generated based on ethanol-equivalent volume, including biomass- based diesel RINs. Under one approach, we would propose that the biomass-based diesel standard also be expressed as an ethanol- equivalent volume (e.g., 1.5 billion ethanol-equivalent gallons in 2012). Another approach would be to have the standard expressed as a volume of biomass-based diesel, and to require the biomass-based diesel RINs be adjusted back to a volume basis, with this adjustment just for purposes of the biomass-based diesel standard but not for purposes of the other fuels mandates. Either approach would have the same result. --------------------------------------------------------------------------- In addition, it is also clear that Congress established the advanced biofuel standard in EISA to begin to take affect in 2009. However, if we maintain the ethanol-equivalent energy content approach for RFS2, and biodiesel continues to have an Equivalence Value of 1.5, then from 2009-2012 the combination of the biomass-based diesel standard and the cellulosic biofuel standard will meet or exceed the advanced biofuel standard. Unless we were to waive a portion of either the biomass-based diesel standard or the cellulosic biofuel standard, the advanced biofuel standard would not have an independent effect until 2013. While EPA recognizes this, EPA believes that the long term benefits of an energy based Equivalence Value may be significantly greater than any temporary diminishment in the real world impact of the advanced biofuel mandate. In recognition of the competing perspectives, we request comment on both co-proposed approaches to the Equivalence Values: (1) Retaining the energy-based approach of the RFS1 program, and (2) a straight volume approach measured in liquid gallons of renewable fuel. 2. Fuel Pathways and Assignment of D Codes As described in Section III.A, we propose that RINs under RFS2 would continue to have the same number of digits and code definitions as under RFS1. The one change would be that, while the D code would continue to identify the standard to which the RIN could be applied, it would be modified to have four values corresponding to the four different renewable fuel categories defined in EISA. These four D code values and the corresponding categories are shown in Table III.A-1. In order to generate RINs for renewable fuel that meets the various eligibility requirements (see Section III.B), a producer or importer must know which D code to assign to those RINs. We propose that a producer or importer would determine the appropriate D code using a lookup table in the regulations. The lookup table would list various combinations of fuel type, production process, and feedstock, and the producer or importer would choose the appropriate combination representing the fuel he is producing and for which he is generating RINs. Parties generating RINs would be required to use the D code specified in the lookup table and would not be permitted to use a D code representing a broader renewable fuel category. For example, a party whose fuel qualified as biomass-based diesel could not choose to categorize that fuel as advanced biofuel or general renewable fuel. This section describes our proposed approach to the assignment of D codes to RINs for domestic producers, foreign producers, and importers of renewable fuel. Subsequent sections address the generation of RINs in special circumstances, such as when a production facility has multiple applicable combinations of feedstock, fuel type, and production process within a calendar year, production facilities that co-process renewable biomass and fossil fuels, and production [[Page 24946]] facilities for which the lookup table does not provide an applicable D code. a. Domestic Producers For domestic producers, the lookup table would identify individual fuel ``pathways'' comprised of unique combinations of the type of renewable fuel being produced, the feedstock used to produce the renewable fuel, and a description of the production process. Each pathway would be assigned to one of the four specific D codes on the basis of the revised renewable fuel definitions provided in EISA and our assessment of the GHG lifecycle performance for that pathway. A description of the lifecycle assessment of each fuel pathway and the process we used for determining the associated D code can be found in Section VI. Note that the subsequent generation of RINs would also require as a prerequisite that the feedstocks used to make the renewable fuel meet the definition of ``renewable biomass'' as described in Section III.B.4, including applicable land use restrictions. Moreover, a domestic producer could not introduce renewable fuel into commerce without generating RINs unless he had records demonstrating that the feedstocks used to produce the fuel did not meet the definition of renewable biomass. See Section III.B.4.b.ii for further discussion of this issue. Through our assessment of the lifecycle GHG impacts of different pathways and the application of the EISA definitions for each of the four categories of renewable fuel, including the GHG thresholds, we have determined that all four categories would have pathways that could be used to meet the Act's volume requirements. For example, ethanol made from corn stover or switchgrass in an enzymatic hydrolysis process would count as cellulosic biofuel. Biodiesel made from waste grease could count as biomass-based diesel. Ethanol made from sugarcane sugar may count as advanced biofuel depending on the results of the lifecycle assessment conducted for the final rule and a determination about whether the GHG threshold for advanced biofuel should be adjusted downward. Finally, under an assumed 100-year timeframe and 2% discount rate for GHG emissions impacts, a variety of pathways would count as generic renewable fuel under the RFS2 program, including ethanol made from corn starch in a facility powered by biomass combustion and biodiesel made from soybean oil. The complete list of pathways that would be valid under our proposed RFS program is provided in the regulations at Sec. 80.1426(d), based upon an assumed 100-year timeframe and 2% discount rate for GHG emission impacts. Domestic producers would choose the appropriate D code from the lookup table in the regulations based on the fuel pathway that describes their facility. The fuel pathway must be specified by the producer in the registration process as described in Section III.C. If there were changes to a domestic producer's facility or feedstock such that their fuel would require a D code that was different from any D code(s) which their existing registration information already allowed, the producer would be required to revise its registration information with EPA 30 days prior to changing the applicable D code it uses to generate RINs. Situations in which multiple fuel pathways could apply to a single facility are addressed in Section III.D.3 below. For producers for whom none of the defined fuel pathways in the lookup table would apply, we propose two possible treatments. First, such producers may be able to generate RINs through our proposed system of default D codes as described in Section III.D.5 below. Second, if a producer meets the criteria for grandfathered status as described in Section III.B.3 and his fuel meets the definition of renewable fuel as described in Section III.B.1, he could continue to generate RINs for his fuel but would use a D code of 4 for those RINs generated under the grandfathering provisions. If a producer was not covered by either of these two treatments, we propose that he would not be permitted to generate RINs for his product until the lookup table in the regulations was modified to include a pathway applicable to his operations. A diesel fuel product produced from cellulosic feedstocks that meets the 60% GHG threshold could qualify as either cellulosic biofuel or biomass-based diesel. As a result, we are proposing that the producer of such ``cellulosic diesel'' be given the choice of whether to categorize his product as either cellulosic biofuel or biomass-based diesel. This would allow the producer to market his product and the associated RINs on the basis of market demand. However, we request comment on an alternative approach as shown in Table III.D.2.a-1 in which an additional D code would be defined to represent cellulosic diesel and an obligated party would be given the choice of using cellulosic diesel RINs either to meet his or her RVO for cellulosic biofuel or for biomass-based diesel. Table III.D.2.a-1--Alternative D Code Definitions To Accommodate Cellulosic Diesel ------------------------------------------------------------------------ D value Meaning under RFS1 Meaning under RFS2 ------------------------------------------------------------------------ 1............................... Cellulosic biomass Cellulosic ethanol. biofuel. 2............................... Any renewable fuel Biomass-based that is not diesel. cellulosic biomass ethanol. 3............................... Not applicable.... Cellulosic biofuel or biomass-based diesel. 4............................... Not applicable.... Advanced biofuel. 5............................... Not applicable.... Renewable fuel. ------------------------------------------------------------------------ Under this alternative, producers of cellulosic diesel would assign a D code of 3 to their product rather than being given a choice of whether to assign a D code of 1 or 2. Any obligated party that acquired a RIN with a D code of 3 could apply that RIN to either its cellulosic biofuel or biomass-based diesel obligation, but not both. The advantage of this alternative approach is that it reflects the full compliance value for the product, and hence its potential value to an obligated party. The obligated party is then given the ability to make a choice about how to treat cellulosic diesel based on the market price and availability of RINs with D codes of 1 and 2. We request comment on this alternative approach to the designation of D codes for cellulosic diesel. b. Foreign Producers Under RFS1, foreign producers have the option of generating RINs for the renewable fuel that they export to the U.S. if they want to designate their fuel as cellulosic biomass ethanol or waste-derived ethanol, and thereby take advantage of the additional 1.5 credit value afforded by the 2.5 Equivalence Value for such products. In order to [[Page 24947]] ensure that EPA has the ability to enforce the regulations relating to the generation of RINs from such foreign ethanol producers, the RFS1 regulations require them to post a bond and submit to third-party engineering reviews of their production process. If a foreign producer does not generate RINs for the renewable fuel that it exports to the U.S., the U.S. importer is responsible for generating the RINs associated with the imported renewable fuel. EISA creates unique challenges in the implementation and enforcement of the renewable fuel standards for imported renewable fuel. Unlike our other fuels programs, EPA cannot determine whether a particular shipment of renewable fuel is eligible to generate RINs under the new program by testing the fuel itself. Instead, information regarding the feedstock that was used to produce renewable fuel and the process by which it was produced is vital to determining the proper renewable fuel category and RIN type for the imported fuel. It is for these reasons that we required foreign producers of cellulosic biomass ethanol or waste-derived ethanol under RFS1 to take additional steps to ensure the validity of the RINs they generate. For RFS2 we are proposing a similar approach to that taken under RFS1, but with a number of modifications to account for the changes that EISA makes to the definition of renewable fuel. Thus, we propose that foreign producers would have the option of generating RINs for any renewable fuel (not just the cellulosic biofuel category) that they export to the U.S. If the foreign producer did not generate RINs, the importer would be required to generate RINs for the imported renewable fuel. Our proposed importer provisions are covered in more detail in Section III.D.2.c below. In general, we propose that foreign producers of renewable fuel who intend to export their fuel to the U.S. would use the same process as domestic producers to generate RINs, namely the lookup table to identify the appropriate D code as a function of fuel type, production process, and feedstock. They would be required to be registered with the EPA as a producer under the RFS2 program and would be subject to the same recordkeeping, reporting, and attest engagement requirements as domestic producers, including those provisions associated with ensuring that the feedstocks they use meet the definition of renewable biomass. They would also be required to submit to third-party engineering reviews of their production process and use of feedstocks, just as domestic producers are. As under the RFS1 program, the foreign producer would also be required to comply with additional requirements designed to ensure that enforcement of the regulations at the foreign production facility would not be compromised. For instance, foreign producers would be required to designate renewable fuel intended for export to the U.S. as such and segregate the volume until it reaches the U.S. in order to ensure that RINs are only generated for volumes imported into the U.S. Foreign producers would also be required to post a bond to ensure that penalties can be assessed in the event of a violation. Moreover, as a regulated party under the RFS2 program, foreign producers must allow for potential visits by EPA enforcement personnel to review the completeness and accuracy of records and registration information. Non-compliance with any of these requirements could be grounds for refusing to allow renewable fuel from such a foreign producer to be imported into the U.S. For RFS2, we are proposing a number of additional provisions to address foreign companies that produce renewable fuel for export to the United States, but that do not generate their own RINs for that renewable fuel. These provisions are intended to account for the greater difficulties in verifying the validity of RINs for imported renewable fuel when the importer is generating the RINs, given that the importer would generally not have direct knowledge of the feedstocks used to produce the renewable fuel, the land used to grow those feedstocks, or the fuel production process. We believe that these additional provisions would be necessary to ensure that RINs representing imported renewable fuel and used by obligated parties have been generated appropriately. As described more fully in Section III.D.2.c below, importers would only be allowed to import renewable fuel from registered foreign producers and would be required to generate RINs for all imported renewable fuel that has not been assigned RINs by the foreign producer. Like domestic and foreign producers who generate RINs, the importer must be able to determine if the renewable biomass definition has been met before generating RINs. The importer must also have enough information about the production process and feedstock to be able to use the lookup table to identify the appropriate D code to include in the RINs he generates. Since the foreign producer is the only party who can provide this information, we believe that it would be appropriate to require the foreign producer of any renewable fuel exported to the U.S. to provide this information to the U.S. importer before the renewable fuel enters U.S. commerce even if the foreign producer is not generating RINs himself. Moreover, the foreign producer should be liable for the accuracy of this information just as if he were the party generating RINs. Therefore, in order to ensure that RINs are valid regardless of who generates them, we propose that all the provisions described above that would be applicable to a foreign producer who generates RINs would also apply to a foreign producer who does not generate RINs but still exports renewable fuel to the U.S. This would include registration with the EPA under the RFS2 program, being subject to all the recordkeeping, reporting, and attest engagement requirements, and posting a bond. The only exception would be that the foreign producer would not be required to segregate a specific volume between the foreign producer's facility and the import facility if the foreign producer is not generating RINs, since the importer would be the primary party responsible for measuring the volume before generating RINs. Although we are proposing that RINs for imported renewable fuel could be generated by either the importer or the foreign producer, it is possible that this could result in difficulty in verifying that only one set of RINs has been generated for a given volume of renewable fuel. One possible solution would be to require a foreign producer to make a decision regarding RIN generation that would apply for an entire calendar year. Under this approach, a foreign producer would be required to either generate RINs for all the renewable fuel that he exports to the U.S within a calendar year, or to generate no RINs for the renewable fuel that he exports to the U.S within a calendar year. While we are not proposing this approach it today's action, we request comment on it. As described in Section III.B.4.b.ii, we are proposing that domestic producers could only introduce renewable fuel into commerce without generating RINs if they demonstrate that feedstocks used to produce the fuel did not meet the definition of renewable biomass. Thus it would not be sufficient for a domestic producer to simply fail to make a demonstration that the renewable biomass definition had been met, and thereby avoid generation of RINs. We propose that a similar approach would be applied to imported renewable fuel. As a result, all renewable fuel that would be imported into the U.S. would be required to come with [[Page 24948]] documentation regarding the status of the feedstock's compliance with the renewable biomass definition. In the case of documentation indicating that the renewable biomass definition had been met, the importer would be required to generate RINs. In the case of documentation indicating that the renewable biomass definition had not been met, the importer would be prohibited from generating RINs but could still import the renewable fuel into the U.S. Renewable fuel that was not accompanied by any documentation regarding the status of the feedstock's compliance with the renewable biomass definition could not be imported into the U.S. Our proposed approach to foreign producers is consistent with the approach we propose taking for domestic producers, in that the producer is responsible for ensuring that RINs generated for renewable fuel used in the U.S. are valid and categorized appropriately. While our proposed approach to foreign producers of renewable fuel under RFS2 would require additional actions in comparison to their general requirements under RFS1, we believe these provisions would be necessary to ensure that the volume mandates shown in Table II.A.1-1 are met, given the new definitions for renewable fuel and renewable biomass in EISA. We request comment on our proposed approach to foreign producers. c. Importers Under RFS1, importers who import more than 10,000 gallons in a calendar year must generate RINs for all imported renewable fuel based on its type, except for cases in which the foreign producer generated RINs for cellulosic biomass ethanol or waste-derived ethanol. Due to the new definitions of renewable fuel and renewable biomass in EISA, importers could no longer generate RINs under RFS2 on the basis of fuel type alone. Instead, they must be able to determine whether or not the renewable biomass definition has been met for the renewable fuel they intend to import, and they must also have sufficient information about the feedstock and process used to make the renewable fuel to allow them to identify the appropriate D code from the lookup table for use in the RINs they generate. As described in Section III.D.2.b above, we are proposing that in order for an importer to import renewable fuel into the U.S., the foreign producer would have to provide this information to the importer. Under today's proposal, importers would be able to import renewable fuels only under one of the following scenarios: 1. The importer receives RINs generated by the registered foreign producer when he imports a volume of renewable fuel. 2. The imported renewable fuel is not accompanied by RINs generated by the registered foreign producer, and the foreign producer provides the importer with: --A demonstration that the renewable biomass definition has been met for the volume of renewable fuel being imported. --Information about the feedstock and production process used to produce the renewable fuel. In this case, the importer would be required to generate RINs for the imported renewable fuel before introducing it into commerce in the contiguous 48 states or Hawaii. 3. The imported renewable fuel is not accompanied by RINs generated by the registered foreign producer, and the foreign producer provides the importer with a demonstration that the renewable biomass definition has not been met for the volume of renewable fuel being imported. See further discussion of this issue in Section III.B.4.b.ii. The importer would be prohibited from generating RINs for the imported volume, but could still introduce the renewable fuel into commerce. If none of these scenarios applied, the importer would be prohibited from importing renewable fuel. Our proposed approach to imported fuels would apply to both neat renewable fuel and renewable fuels blended into gasoline or diesel. As described in Section III.B.4.e, we also seek comment on an alternative approach to imported renewable fuel in which foreign renewable fuel producers would have the option of not participating in RFS2 but still export renewable fuel to the U.S. Under this alternative approach, foreign producers would have to meet requirements for segregating their fuel from renewable fuel for which RINs were generated, and the importer of their fuel would be required to track it to ensure that the fuel remains segregated in the U.S. and is not used by a domestic company for illegal RIN generation. While it is important that all RINs be based on accurate information about the feedstocks and production process used to produce the renewable fuel, it may not be necessary to place the burden upon importers for acquiring this information before they generate RINs. Instead, an alternative approach would prohibit importers from generating any RINs, and instead require foreign producers to generate RINs for all renewable fuel that they export to the U.S. We recognize that this would be a significant change from RFS1, and thus we are not proposing it. However, since it would place the same responsibilities on foreign producers as domestic producers, we request comment on it. 3. Facilities With Multiple Applicable Pathways If a given facility's operations can be fully represented by a single pathway, then a single D code taken from the lookup table will be applicable to all RINs generated at or imported into that facility. However, we recognize that this will not always be the case. Some facilities use multiple feedstocks at the same time, or switch between different feedstocks over the course of a year. A facility may be modified to produce the same fuel but with a different process, or may be modified to produce a different type of fuel. Any of these situations could result in multiple pathways being applicable to a facility, and thus there may be more than one D code used for various RINs generated at the facility. If more than one pathway applies to a facility within a compliance period, no special steps would need to be taken if the D codes were the same for all the applicable pathways. In this case, all RINs generated at the facility would have the same D code. As for all other producers, the producer with multiple applicable pathways would describe its feedstock(s), fuel type(s), and production process(es) in its annual report to the Agency so that we could verify that the D code used was appropriate. However, if more than one pathway applies to a facility within a compliance period and these pathways have been assigned different D codes, then the producer must determine which D codes to use when generating RINs. There are a number of different ways that this could occur, and our proposed approach to designating D codes for RINs in these cases is described in Table III.D.3-1. [[Page 24949]] Table III.D.3-1--Proposed Approach To Assigning Multiple D Codes for Multiple Applicable Pathways ------------------------------------------------------------------------ Case Description Proposed approach ------------------------------------------------------------------------ 1............................... The pathway The applicable D applicable to a code used in facility changes generating RINs on a specific must change on date, such that the date that the one single fuel produced pathway applies changes pathways. before the date and another single pathway applies on and after the date. 2............................... One facility The volumes of the produces two or different types more different of renewable fuel types of should be renewable fuel at measured the same time. separately, with different D codes applied to the separate volumes. 3............................... One facility uses For any given two or more batch of different renewable fuel, feedstocks at the the producer same time to should assign the produce a single applicable D type of renewable codes using a fuel. ratio (explained below) defined by the amount of each type of feedstock used. ------------------------------------------------------------------------ In general, we are not aware of a scenario in which a facility uses two different processes in parallel to convert a single type of feedstock into a single type of renewable fuel. Therefore, we have not created a case in Table III.D.3-1 to address it. However, we know that some corn-ethanol facilities may dry only a portion of their distiller's grains and leave the remainder wet. Using the lifecycle with an assumed 100 year timeframe and 2% discount rate for GHG emission impacts, the treatment of the distiller's grains could impact the determination of whether the 20% GHG threshold for renewable fuel has been met, a corn-ethanol facility that dries some portion of its distiller's grains would need to implement additional technologies in order to qualify to generate RINs for all the ethanol it produces (if the facility has not been grandfathered). The lifecycle analyses conducted for this proposal only examined cases in which a corn-ethanol facility dried 100% of its distiller's grains or left 100% of its distiller's grains wet. As a result, a corn-ethanol facility that dried only a portion of its distiller's grain would be treated as if it dried 100% of its grains, and would thus need to implement additional GHG- reducing technologies as described in the lookup table in order to qualify to generate RINs. This is reflected in the list of required production technologies in the lookup table at Sec. 80.1426(d) for facilities that dry any portion of their distiller's grains. In practice, depending on the selection of other technologies, it may be possible for a facility using some combination of dry and wet distiller's grains to meet the 20% GHG threshold. Therefore we request comment on whether a selection of pathways should be included in the lookup table that represent corn-ethanol facilities that dry only a portion of their distiller's grains. We also request comment on whether RINs could be assigned to only a portion of the facility's ethanol in cases wherein only a portion of the distiller's grains are dried. We propose that the cases listed in Table III.D.3-1 be treated as hierarchical, with Case 2 only being used to address a facility's circumstances if Case 1 is not applicable, and Case 3 only being used to address a facility's circumstances if Case 2 is not applicable. We believe that this approach covers all likely cases in which multiple applicable pathways may apply to a renewable fuel producer. Some examples in which Case 2 or 3 would apply are provided in Table III.D.3-2. Table III.D.3-2--Examples of Facilities With Multiple Pathways ------------------------------------------------------------------------ Applicable Example case Reasoning ------------------------------------------------------------------------ Facility makes both diesel and 2 The production of two naphtha (a gasoline blendstock) types of renewable from gasified biomass in a Fischer- fuel from the same Tropsch process. feedstock and process makes it highly likely that the two pathways would be assigned the same D code. If LCA determined that this was not the case, the volumes of diesel and naphtha can be measured separately and assigned separate batch-RINs with different D codes. Facility produces ethanol from corn 3 There is only one fuel starch and corn cobs/husks. produced, so Case 2 cannot apply. Facility makes both ethanol and 2 Case 2 is the default butanol through two different since there are two processes using corn starch. separate fuels produced. However, Case 3 would not apply regardless because there is only one feedstock. Facility makes ethanol through an 3 There is only one fuel enzymatic hydrolysis process using produced, so Case 2 both switchgrass and corn stover. cannot apply. ------------------------------------------------------------------------ A facility where two or more different types of feedstock were used to produce a single fuel (such as Case 3 in Table III.D.3-1) would be required to generate two or more separate batch-RINs \26\ for a single volume of renewable fuel, and these separate batch-RINs would have different D codes. The D codes would be chosen on the basis of the different pathways as defined in the lookup table in Sec. 80.1426(d). The number of gallon-RINs that would be included in each of the batch- RINs would depend on the relative amount of the different types of feedstocks used by the facility. We propose to use the useable energy content of the feedstocks to determine how many gallon-RINs should be assigned to each D code. Our proposed calculations are given in the regulations at Sec. 80.1126(d)(5). --------------------------------------------------------------------------- \26\ Batch-RINs and gallon-RINs are defined in the RFS1 regulations at 40 CFR 80.1101(o). --------------------------------------------------------------------------- In determining the useable energy content of the feedstocks, we propose to take into account several elements to ensure that the number of gallon-RINs associated with each D code is appropriate. For instance, we propose [[Page 24950]] that only that portion of a feedstock which is expected to be converted into renewable fuel by the facility should be counted in the calculation. For example, a biochemical cellulosic ethanol conversion process that could not convert the lignin into ethanol would not include the lignin portion of the biomass in the calculation. This approach would also take into account the conversion efficiency of the facility. We propose that the producer of the renewable fuel would be required to designate this fraction for the feedstocks processed by his facility and to include this information as part of its reporting requirements. We are also proposing to use the energy content of the feedstocks instead of their mass since we believe that their relative energy contents are more closely related than their mass to the energy in the renewable fuel. Producers would be required to designate the energy content (in Btu/lb) of the portion of each of their feedstocks which is converted into fuel. We request comment on whether producers would determine these values independently for their own feedstocks, or whether a standard set of such values should be developed and incorporated into the regulations for use by all renewable fuel producers. If we did specify a standard set of energy content values, we request comment on what those values should be and/or the most appropriate sources for determining those values. Some components in the calculation of the useable energy content of feedstocks are unlikely to vary significantly for a particular type of feedstock. This would include that portion of a feedstock which is expected to be converted into renewable fuel by the facility, and the relative amount of energy in the two feedstocks. For these factors, we propose that one set of values be determined by the producer and applied to all renewable fuel production within a calendar year. The values could be reassessed annually and adjusted as necessary. Although we are proposing annual determinations of the portion of a feedstock which is expected to be converted into renewable fuel by the facility and the relative amount of energy in the two feedstocks, we are proposing daily determinations of the total mass of each type of feedstocks used by the facility. This approach would take into account the fact that the relative amount of the different feedstocks used could vary frequently, and thus the determination of the total useable energy content of the feedstocks would be unique to the renewable fuel produced each day. We believe that renewable fuel producers would have ready access to information about total feedstock mass used each day, such that the timely generation of RINs should not be unduly affected. We request comment on the effort and time involved in collecting information on feedstock mass and translating this information on a daily basis into RINs assigned to volumes of renewable fuel. In order to generate RINs when the processing of two or more different feedstocks in the same facility results in two or more different applicable D codes but a single renewable fuel, the producer would continue to determine the total number of gallon-RINs that must be generated for and assigned to a given volume of renewable fuel using the process established under RFS1. In short, the total volume of the renewable fuel would be multiplied by its Equivalence Value. However, the feedstock's useable energy content would be used to divide the resulting number of gallon-RINs into two or more groups, each corresponding to a different D code. Two, three, or more separate batch-RINs could then be generated and assigned to the single volume of renewable fuel. The sum of all gallon-RINs from the different batch- RINs would be equal to the total number of gallon-RINs that must be generated to represent the volume of renewable fuel. As described in Section III.J, we propose that in their reports, producers of renewable fuel be required to submit information on the feedstocks they used, their production processes, and the type of fuel(s) they produced during the compliance period. This would apply to both domestic producers and foreign producers who export any renewable fuel to the U.S. We would use this information to verify that the D codes used in generating RINs were appropriate. 4. Facilities That Co-Process Renewable Biomass and Fossil Fuels We expect situations to arise in which a producer uses a renewable feedstock simultaneously with a fossil fuel feedstock, producing a single fuel that is only partially renewable. For instance, biomass might be cofired with coal in a coal-to-liquids (CTL) process that uses Fischer-Tropsch chemistry to make diesel fuel, biomass and waste plastics might be fed simultaneously into a catalytic or gasification process to make diesel fuel, or vegetable oils could be fed to a hydrotreater along with petroleum to produce a diesel fuel. In these cases, the diesel fuel would be only partially renewable. We propose that RINs must be generated in such cases, but in such a way that the number of gallon-RINs corresponds only to the renewable portion of the fuel. Under RFS1, we created a provision to address the co-processing of ``renewable crudes'' along with petroleum feedstocks to produce a gasoline or diesel fuel that is partially renewable. See 40 CFR 80.1126(d)(6). However, this provision would not apply in cases where either the renewable feedstock or the fossil fuel feedstock is a gas (e.g., biogas, natural gas) or a solid (e.g. biomass, coal). Therefore, we propose to eliminate the existing provision applicable only to liquid feedstocks and replace it with a more comprehensive approach that could apply to liquid, solid, or gaseous feedstocks and any type of conversion process. Our proposed approach would be similar to the treatment of renewable fuels with multiple D codes as described in Section III.D.3 above. Thus, the producer would determine the renewable fuel volume that would be assigned RINs based on the amount of energy in the renewable feedstock relative to the amount of energy in the fossil feedstock. Just as two different batch-RINs would be generated for a single volume of renewable fuel produced from two different renewable feedstocks, only one batch-RIN would be generated for a single volume of renewable fuel produced from both a renewable feedstock and a fossil feedstock, and this one batch-RIN would be based on the contribution that the renewable feedstock makes to the volume of renewable fuel. See Sec. 80.1426(d)(6) for our proposed calculations under these circumstances. For facilities that co-process renewable biomass and fossil fuels to produce a single fuel that is partially renewable, we propose to use the relative energy in the feedstocks to determine the number of gallon-RINs that should be generated. As shown in the regulations at Sec. 80.1426(d)(6), the calculation of the relative energy contents would include factors that take into account the conversion efficiency of the plant, and as a result, potentially different reaction rates and byproduct formation for the various feedstocks would be accounted for. The relative energy content of the feedstocks would be used to adjust the basic calculation of the number of gallon-RINs downward from that calculated on the basis of fuel volume alone. The D code that would be assigned to the RINs would be drawn from the lookup table in the regulations as if the feedstock was entirely renewable biomass. Thus, for instance, a coal-to-liquids plant that co-processes some cellulosic biomass to make diesel fuel would be treated as a plant that [[Page 24951]] produces only cellulosic diesel for purposes of identifying the appropriate D code. One drawback of our proposed approach is that it does nothing to address lifecycle GHG emissions associated with the portion of the fuel that comes from the fossil fuel feedstock. While the lifecycle GHG thresholds under RFS2 are specific to fuels made from renewable biomass, allowing a fuel producer to generate RINs for the co- processing of renewable biomass with fossil fuels might provide a greater incentive for production of transportation fuels from processes that have high lifecycle GHGs. In such cases, the GHG benefits of the renewable fuel may be overwhelmed by the GHG increases of the fossil fuel. This is of particular concern for CTL processes which generally produce higher lifecycle GHG emissions per unit of transportation fuel produced than traditional refinery processes that use petroleum. Under our proposed approach to the treatment of co-processing of renewable biomass and fossil fuels, incentives would be provided for renewable fuels with lower lifecycle GHG emissions, but there will be little disincentive for production of high GHG-emitting fuels made from fossil fuels. As an alternative to our proposed approach, we could treat fuels produced through co-processing of renewable biomass and fossil fuel feedstocks in an aggregate fashion rather than focusing only on the renewable portion of those fuels. In this approach, we would require the whole fuel produced at co-processing facilities to meet the lifecycle GHG thresholds under RFS2. If, for instance, a diesel fuel produced from co-processing renewable biomass and coal in a Fischer- Tropsch process were determined to not meet the 20% GHG threshold, no RINs could be generated even though the renewable portion of the diesel fuel might meet the 20% GHG threshold. However, this alternative approach would require a lifecycle analysis that is specific to the relative amounts of renewable biomass and fossil fuel feedstock being used at a particular facility, which would in turn require a facility- specific lifecycle GHG model. As described in Section II.A.3, this is beyond the capabilities of our current modeling tools. Moreover, this alternative approach could have undesirable effects on facilities that produce renewable fuel from multiple renewable feedstocks. For instance, if a facility produced ethanol from both corn starch and corn stover and the lifecycle GHG assessment was conducted for this specific facility as a whole, it might not meet the 60% GHG threshold for cellulosic biofuel. As a result, the portion of the ethanol produced from corn stover could not be counted as cellulosic biofuel but would instead count only as renewable fuel, even though our lifecycle analyses have determined that ethanol from corn stover does meet the 60% GHG threshold. Nevertheless, we seek comment on this alternative approach. As another alternative to using the relative energy in the feedstocks to determine the number of gallon-RINs that should be generated, we could allow renewable fuel producers to use an accepted test method to directly measure the fraction of the fuel which originates with biomass rather than a fossil fuel feedstock. For instance, ASTM test method D-6866 can be used to determine the renewable content of gasoline. However, such a test method could not distinguish between fuel made from feedstocks that meet the definition of renewable biomass, and other biomass feedstocks which do not meet the definition of renewable biomass. We request comment on the use of ASTM D-6866 or equivalent test methods to determine the number of RINs generated when multiple feedstocks are used simultaneously to make a fuel. 5. Treatment of Fuels Without an Applicable D Code Among all fuels covered by our proposed RFS2 program, we have identified a number of specific ``pathways'' of fuels, defined by fuel type, feedstock, and various production process characteristics. This list includes fuels that either already exist in the marketplace or are expected to exist sometime during the next decade, and for which we had sufficient information to conduct a lifecycle analysis of the GHG emissions. As described in III.D.2, we have assigned each pathway a D code corresponding to the four categories of renewable fuel defined in EISA. Despite our efforts to explicitly address the existing or possible pathways in our proposed program, it is expected that a fuel, process, or feedstock will arise that is a renewable fuel meeting the RFS definitions, and yet is not among the fuels we explicitly identified in the regulations as a RIN-generating fuel. This could occur for an entirely new fuel type, a known fuel produced from a new feedstock, or a known fuel produced through a unique production process. In such cases, the fuel may meet our definition of renewable fuel covered under our program, but would not have been assigned the appropriate D code in the regulations. To address some of these fuel pathways, we are proposing the use of default D codes.\27\ --------------------------------------------------------------------------- \27\ Additional default requirements applicable to importers of renewable fuels are discussed in Section III.D.2.c. --------------------------------------------------------------------------- Under our proposed approach, the producer would be required to register under the RFS program and provide information about their facility as described in Section III.C. The producer will also be required to provide any information necessary for EPA to perform a proper lifecycle analysis. Additionally, the company would need to register their renewable fuel under title 40 CFR part 79 as a motor vehicle fuel. If EPA determines, based on the company's registration, that they are not producing renewable fuel, the company will not be able to generate RINs. In order to generate RINs, the producer of renewable fuel would apply through our registration system to use the D code that best represents his combination of fuel type, feedstock, and production process. If the producer's combination of fuel type and feedstock, but not production process, is represented in an already defined pathway combination of fuels, processes, or feedstocks, the producer would use the highest numerical D code applicable to the fuel and feedstock combination. For example, if a fuel and feedstock spans the D Codes 3 and 4 then the producer would use 4 until the regulations were updated. The producer then would generate RINs using the D code 4, until EPA could perform a lifecycle analysis and issue a change to the regulations to reflect the new pathway. If the producer is making a new fuel or using a new feedstock that producer will still need to apply, but would be unable to generate RINs until the regulations were updated with the new pathway. Since certain combinations of fuel, production process, and feedstock have been determined through our lifecycle analysis to not meet the minimum 20% GHG threshold, they would be ineligible to generate RINs and EPA would not allow producers using those processes to generate RINs using a default D code. To effectuate this, we propose to provide a statement in the regulations of pathways that are prohibited from using a default D code. For example, if a producer is producing ethanol from cornstarch in a process that uses coal or natural gas for process heat, then regardless of other elements of the production process the producer may not use a default D code, but must register and provide information [[Page 24952]] necessary to conduct a lifecycle analysis. EPA will not conduct a rulemaking every year to adjust the regulations for new fuels, processes, or feedstocks. EPA will periodically update the regulations as necessary under CAA section 211(o)(4) and may take the opportunity to update the list of fuel pathways. Companies are encouraged to work with EPA early to provide information about fuels, processes, or feedstocks not in the regulations so that we can do a proper lifecycle analysis before these fuels, processes, or feedstocks are commercially viable. EPA is proposing that if the regulations are not updated with in 5 years of receipt of the application and the application is not rejected in that time then the producer will no longer be able to generate RINs using a default D code until the regulations are updated. 6. Carbon Capture and Storage (CCS) One element of the production process that may enable renewable fuel producers to greatly improve their GHG emissions is carbon capture and storage (CCS). CCS involves the process of capturing CO2 from an industrial or energy-related source, transporting it to a suitable storage site, and isolating it from the atmosphere for long periods of time. While we are not proposing a specific pathway in today's NPRM that would allow a renewable fuel producer to use CCS to demonstrate compliance with the GHG thresholds, we believe that CCS could be an effective method for significantly reducing the GHG emissions associated with renewable fuel production. Although there are several possible approaches for long-term storage of CO2, this section will only address geologic storage as a means to reduce CO2 emissions from renewable fuel production facilities. This method entails injecting CO2 deep underground and monitoring to ensure long-term isolation from the atmosphere. The remainder of this section describes the efforts to establish regulatory requirements for CCS, and the further work that needs to be done before allowing the use of CCS as an element in pathways eligible for generating RINs under the RFS2 program. Although there is limited experience with integrated CCS systems in the US, where CO2 is captured, transported and injected for long-term storage, there are commercial CCS projects operating today and several DOE pilot projects underway to further demonstrate CCS in a variety of industrial sectors and geological settings. The EPA has been working closely with DOE to collectively ensure that governmental research programs address the range of potential environmental risks associated with CCS and that appropriate regulatory frameworks are in place to manage risks.\28\ --------------------------------------------------------------------------- \28\ More information on the EPA's UIC Program and ongoing research into CCS issues is available at: http://www.epa.gov/ safewater/uic/wells_sequestration.html. --------------------------------------------------------------------------- The EPA has experience regulating underground injection of various fluids and believes that well selected, designed, and managed sites can sequester CO2 for long periods of time. The Safe Drinking Water Act's (SDWA) Underground Injection Control (UIC) Program has been successfully regulating tens of thousands of injection wells for over 35 years. The UIC program's siting, well construction, and monitoring and testing requirements are keys to ensuring that injected fluids remain in the geologic rock formations specifically targeted for injection. In March 2007, the EPA issued UIC permitting guidelines for pilot geologic sequestration projects in order to ensure that these projects could move forward under an appropriate regulatory framework. Subsequently, on July 25, 2008, EPA issued a proposed rulemaking that would address commercial-scale projects and establish the regulatory requirements for underground injection of CO2 for the purpose of geologic storage (73 FR 43492). These proposed regulations include permitting requirements, criteria for establishing and maintaining the mechanical integrity of wells, minimum criteria for siting, injection well construction and operating requirements, recordkeeping and reporting requirements, etc. While these regulations cover many operational aspects of underground injection and monitoring geologic sequestration sites, their purpose is to protect underground sources of drinking water. The SDWA does not provide authority to develop regulations for all areas related to CCS, including capture and transport of CO2 and accounting or certification for GHG emissions reductions. The UIC requirements will not replace or supersede other statutory or regulatory requirements for protection of human health and the environment. Thus, parties that implemented CCS would still need to obtain all necessary permits from appropriate State and Federal authorities under the Clean Air Act or any other applicable statutes and regulations. Specific areas that would need to be addressed before allowing the renewable fuel producers to benefit from CCS in meeting GHG thresholds include: the means through which the CO2 would be captured from the renewable fuel production facility, the minimum fraction that must be captured, appropriate means for transporting to the injection site, and appropriate monitoring procedures to ensure long-term storage of CO2. We believe the CO2 that would be most readily available for capture in an ethanol production facility would be that which is produced during the fermentation process, not CO2 that is generated during the combustion of fossil fuels for process energy, since CO2 from the fermentation process provides a more concentrated stream that is more amenable to capture. However, we request comment on the efficacy of capturing CO2 from the combustion of fossil fuels for process heat. A mechanism for accounting for potential leakage of captured CO2 during transport to the storage site or after injection has occurred would also be required. The renewable fuel producer would be responsible for tracking any leaks that occur after CO2 capture. We request comment on the type and level of surface and/or subsurface monitoring that would be required to demonstrate long-term storage of CO2. We also request comment on whether additional monitoring and reporting requirements would be appropriate. For example, whether there should be a requirement for the monitoring and reporting of CO2 volumes captured, transported, injected and stored, as well as any fugitive emissions released. We seek comment on the appropriateness of establishing a performance standard for CO2 leakage during transport, injection, and/or geologic storage, and any data that might be available to help develop such a performance standard. Finally, in order to generate RINs, the renewable fuel producer would have to, at minimum, demonstrate that a sufficient amount of CO2 was sequestered to reach the appropriate lifecycle GHG threshold. We expect that the regulations would need to specify the minimum fraction of CO2 emitted that must be captured and stored in order for a renewable fuel producer to qualify for generating RINs. We request comment on whether this approach is appropriate. E. Applicable Standards CAA section 211(o)(3) describes how the applicable standards are to be calculated. The only changes made to this provision by EISA are substituting ``transportation fuel'' for gasoline, and reflecting the expanded number of years [[Continued on page 24953]]