## California Environmental Protection Agency


# Air Resources Board

Proposed Regulation to Implement the
Low Carbon Fuel Standard

Volume I

Staff Report: Initial Statement of Reasons

Release Date: March 5, 2009i 

### State of California

California Environmental Protection Agency

AIR RESOURCES BOARD Stationary Source Division

STAFF REPORT: INITIAL STATEMENT OF REASONS

PROPOSED REGULATION TO IMPLEMENT

THE LOW CARBON FUEL STANDARD



## Volume I

Public Hearing to Consider the Proposed Regulation to Implement the Low Ca rbon Fuel Standard

Date of Release: March 5, 2009
Scheduled for Considerat ion: April 23, 2009

Location:



## California Air Resources Board
Byron Sher Auditorium

1001 I Street Sacramento, California 95814

This report has been reviewed by the staff of the Air Resources Board and approved for publication. Approval does not signify that the contents necessarily reflect the views and polici es of the Air Resources Board, nor does mention of trade names or commercial products constitute

endorsement or recommendation for use

.ii This Page Left Intentionally Blankiii Acknowledgments

This report was prepared with the assistance and support from many individuals within the Air Resources Board; only the principal c ontributors. In addition , staff would like to acknowledge the assistance and cooperation that we have received from many individuals and organizations, t oo numerous to list, whose contributions throughout the development process have been in valuable. Finally, staff would like to acknowledge the significant contributions from the numer ous State, federal, and international governmental agencies that have provided assistance throughout the rulemaking

process.

Special thanks goes to the late Professor Al exander Farrell, whose tireless efforts to promote the development of a low carbon fuel policy was an inspiration to us all. Thank you Alex.

Air Resources Board Stationary Source Division Principal Contributors

Kevin Cleary Jim Peterson, M.S James Duffy, Ph.D Chan Pham Chris Gallenstein Anil Prabhu, Ph.D. Alan Glabe, Ph.D. Manisha Singh, Ph.D. Wes Ingram, Ph.D. Susan Solarz

Jill Locke Marcelle Surovik Reza Lorestany, M.S., M.B.A Christina Zhang-Tillman, M.S. Carolyn Lozo Michelle Werner, Ph.D. Ron Oineza Jing Yuan, Ph.D. Eric Patton, P.E

Special Thanks To: Office of Legal Affairs Office of Climate Change Tom Jennings Jeannie Blakeslee Claudia Nagy Sam Wade

Research Division Enforcement Division Alvaro Alvarado, Ph.D Steve Brisby, M.S. Reza Mahdavi, Ph.D Dickman Lum

Planning and Technical Suppo rt Division Mobile So urce Control Division

Martin Johnson Crai g Childers, P.E. Beth Schwehr Ben Deal, P.E. Jonathon Tayloriv Acknowledgments (Continued)

State Water Resources Control Board Robert Hodam, M.S. Division of Water Quality

California Integrated Waste Management Board Brian Helmowski, M.S. Climat e Change and Technology Section

California Energy Commission McKinley Addy Jim Page
Mike McCormack

University of Californi a, Berkeley University of California, Davis Andrew Jones Bryan Jenkins, Ph.D. Dan Kammen, Ph.D. Chris Knittel, Ph.D. Michael O’Hare, Ph.D. Nathan Parker Richard Plevin Dan Sumner, Ph.D. Sabrina Spatari Sonia Yeh, Ph.D.

Purdue University Alla Golub, Ph.D. Tom Hertel, Ph.D. Wally Tyner, Ph.D.

Energy Foundation Jason Mark, Director of Transportation Programs

Life Cycle Associates – Stephan Unasch Tiax LLC – Jenny Pont

Reviewed by :

Michael H. Scheible, Deputy Executive Officer Robert D. Fletcher, Chief, Stationary Source Division Dean C. Simeroth, Chief, Cr iteria Pollutants Branch John Courtis, Manager, Alte rnative Fuels Section Hardip Judge, Manager, Pr ogram Review Section Renee Littaua, Manager, Fuels Section Floyd Vergara, Manager , Industrial Section Michael Waugh, Manager, Progr am Assistance Sectionv TABLE OF CONTENTS

Page

Number

EXECUTIVE SUMMARY........................................................................................

I. INTRODUC TION................................................................................................ I-1

A. Greenhouse Gases A nd Climate C hange................................................ I-1
B. Public Process For LC FS Regulation De velopment ................................ I-3 C. Report Org anization ................................................................................. I-4

II. GOVERNMENT PROGRAMS AFFECTIN G TRANSPORTATION FUELS ....... II-1 A. California Programs to R educe Transportation-Related GHG

Emissi ons ............................................................................................... II-1
B. California F uels Program s ...................................................................... II-7 C. California Incentive Program s For Transportati on Fuels ....................... II-12

D. Federal Renewable Fuels Standar d ..................................................... II-14
E. Other LCFS In itiatives ........................................................................... II-18

III. TECHNOLOGY ASSESSMENT ....................................................................... III-1
A. Overview Of Current Califo rnia Transportati on Fuels ............................ III-1
B. Current Tec hnologies ............................................................................. III-1 C. Mid-Term Technologies Projected By 2015......................................... III-14 D. Long-Term Technologies Pr ojected After 2020 ................................... III-18

IV. DETERMINATION OF CARBON INTENSITY VAL UES...................................IV-1 A. Summary ...............................................................................................IV-1

B. Direct Effect s Analysis ...........................................................................IV-4
C. Indirect Effe cts Analys is.......................................................................IV -16

D. Uncertainties in the Analysi s................................................................IV-45 E. Proposed Look up Tables .....................................................................IV-49

V. SUMMARY OF THE PROP OSED REGULA TION.............................................V-1

A. Overview of the Proposed Regu lation .....................................................V-1 B. Applicability of the St andard ................................................................... V-2
C. Defi nitions ...............................................................................................V-4 D. Average Carbon Int ensity Require ments ................................................V-5 E. Applicable Standards fo r Alternative Fuels .............................................V-8 F. Requirements for Regulated Part ies.......................................................V-9
G. LCFS Credits and Deficits .....................................................................V-19 H. Retaining, Trading, and Borrowing of LCFS Credits .............................V-22
I. Determination of Car bon Intensity Va lues............................................. V-24 J. Requirements for Mu ltimedia Evaluat ion ..............................................V-26 K. Cap and Trade Under the LCFS Regulation (Res erved) ......................V-34 L. Regulation Review................................................................................V-36vi Page

Number

VI. COMPLIANCE SCENARIOS ............................................................................VI-1 A. Summary ...............................................................................................VI-1 B. Primary Sc enarios ................................................................................. VI-1 C. Supplemental Scenarios ......................................................................VI-16
D. Fuel Carbon Reductions In The Post-2020 Period .............................. VI-21

VII. ENVIRONMENTA L IMPACTS .........................................................................VII-1 A. Summary of the Envi ronmental Anal ysis ..............................................VII-1
B. Greenhouse Gas Emi ssion Benefit s .....................................................VII-3
C. Air Qualit y Impacts ................................................................................VII-7
D. Other Environment al Impacts .............................................................VII-24
E. Sustainabi lity.......................................................................................VII-31

F. Multimedia Ev aluation......................................................................... VII-33
G. Environmental Justice......................................................................... VII-35

VIII. ECONOMIC IMPACTS...................................................................................VIII-1 A. Summary of the Economic Impac ts .....................................................VIII-1 B. Legal Requir ements.............................................................................VIII-2 C. Methodology for Es timating Cost s .......................................................VIII-3
D. Cost-Effect iveness............................................................................. VIII-33 E. Sensitivity Analys is ............................................................................VIII-34 F. Impacts of RF S2 on LCFS .................................................................VIII-36 G. Potential Costs and Savings to California Consumers, Including

Businesses ........................................................................................VIII-39 H. Other Potential Impacts to California Busi nesses ..............................VIII-45 I. Potential Costs to Local, Stat e, and Federal Ag encies ......................VIII-47
J. Consideration of Alternatives .............................................................VIII-49

IX. COMPLIANCE AND ENFORCEMEN T.............................................................IX-1 A. LCFS Report ing Tool .............................................................................IX-1 B. Credit Tracking S ystem (CTS) ...............................................................IX-4 C. Description Of En forcement Appr oaches............................................... IX-5
D. Penalties And Other Remedies For Violations Of The LCFS .................IX-5

X. ANALYSIS OF AL TERNATIVE S .......................................................................X-1 A. Alternative Approache s to the Regul ation...............................................X-1 B. Specific Proposed Modifica tions to the R egulation .................................X-4

REFERENCES ......................................................................................................R1

Appendix A: Regul ation Or der......................................................................................A1vii OTHER APPENDICES

Appendices B through G Are Avai lable Under Separate Cover

Appendix B: Supporting Documentati on For The Technology Assessment

Appendix C: Supporting Do cumentation for Determination of Carbon Intensity

Values

Appendix D: LCFS Credit Calculations

Appendix E: Supporting Documentat ion for the Compliance Scenarios

Appendix F: Supporting Documentat ion for Environmental Analysis

Appendix G: Supporting Document ation for Economic Analysisviii This Page Left Intentionally BlankES-1 

### Executive Summary

Overview

In this rulemaking, the Air Resources Boar d (ARB/ Board) staff is proposing to reduce emissions of greenhouse gases (GHG) by lowe ring the carbon content of transportation

fuels used in California. The regulation is referred to as the California Low Carbon Fuel Standard (LCFS). The LCFS will reduce GHG emissions from the transportation sector in California by about 16 million metric tons (MMT) in 2020. These reductions account for almost 10 percent of the total GHG emission reductions needed to achieve the State’s mandate of reducing GHG emissions to 1990 levels by 2020. In addition, the LCFS is designed to reduce California’s dependence on petroleum, create a lasting market for clean transportation technology, and stimulate the production and use of alternative, low-carbon fuels in California. Governor Schwarzenegger has identified all of these outcomes as import ant goals for California.

The LCFS is designed to provide a durable fr amework that uses market mechanisms to spur the steady introduction of lower ca rbon fuels. The fr amework establishes performance standards that f uel producers and importers must meet each year beginning in 2011. One standard is establis hed for gasoline and the alternative fuels that can replace it. A second similar standard is set for diesel fuel and its replacements. Each standard is set to achieve an average 10 reduction in the carbon intensity of the statewide mix transportation fuels by 2020.

The standards are “back-loaded”; t hat is, there are more reduc tions required in the last five years, than the first five years. This schedule allows for the development of

advanced fuels that are lower in carbon than today’s fuels and the penetration of plug-in hybrid electric vehicles, battery electric v ehicles, fuel cell vehicles, and flexible fuel vehicles. The staff anticipates that compliance with the LCFS will be based on a combination of strategies involving lower carbon fuels and more efficient, advanced-technology vehicles.

Reformulated gasoline mixed with corn-deriv ed ethanol at 10 percent by volume and low sulfur diesel fuel represent the base line fuels. Lower ca rbon fuels may be ethanol, biodiesel, renewable diesel, or blends of these fuels with gasoline or diesel as appropriate. Compressed natural gas and liquefied natural gas also may be low carbon fuels. Hydrogen and electricity are also lo w carbon fuels and result in significant

reductions of GHGs when used in fuel cell or el ectric vehicles due to significant vehicle power train efficiency improvements over co nventionally-fueled vehicles. As such,

these fuels are included in the LCFS as lo w carbon options. Other fuels may be used to

meet the standards and are s ubject to meeting existing r equirements for transportation

fuels.ES-2 The LCFS framework is based on the premis e that each fuel has a “lifecycle” GHG emission value that is then compared to a standard. 1 This lifecycle analysis represents the GHG emissions associated with the pr oduction, transportation, and use of low

carbon fuels in motor vehicles. The life cycle analysis includes the direct emissions associated with producing, trans porting, and using the fuels. In addition, the lifecycle analysis considers any other effects, both di rect and indirect, that are caused by the change in land use or other effects. Fo r some crop-based biofuels, the staff has identified land use changes as a significant source of additional GHG emissions. Therefore, the staff is pr oposing that emissions associated with land use changes be included in the carbon intensity values assign ed to those fuels in the regulation. No other significant indirect effe cts that result in large GH G emissions have been identified that would substantially affect the LCFS fr amework for reducing the carbon intensity of transportation fuels.

The standards are expressed as the carbon in tensity of gasoline an d diesel fuel and their alternatives. Measured on a lifecycle basis, the carbon intensity represents the equivalent amount of carbon dioxide (CO 2 e) emitted from eac h stage of producing, transporting, and using the fuel in a motor vehicle. Depending on the circumstances, GHG emissions from each step c an include carbon dioxide (CO 2 ), methane, nitrous oxide (N 2 O), and other GHG contributors. Moreov er, the overall GHG contribution from each particular step is a function of the energy that the fuel contains. Thus, carbon intensity is expressed in terms of grams of CO 2 equivalent per megajoule (g CO 2 e/MJ).

Providers of transportation fuels (referred to as regulated part ies) must demonstrate that the mix of fuels they supply meet the LCFS intensity standards for each annual compliance period. They must report all fuels provided and track the fuels’ carbon intensity through a system of “credits” and “def icits.” Credits are generated from fuels with lower carbon intensity than the standard. Deficits result from the use of fuels with higher carbon intensity than the standard. A regulated pa rty meets its compliance obligation by ensuring that amount of credi ts it earns (or otherwise acquires from another party) is equal to, or greater than, t he deficits it has incurred. Credits and deficits are generally determined based on the amount of fuel sold, the carbon intensity of the fuel, and the efficiency by which a vehi cle converts the fuel into useable energy.
The calculated metric is tons of GHG emi ssions. This determination is made for each year between 2011 and 2020. Credits may be banked and traded within the LCFS market to meet obligations.

The proposed regulation provides flexibility for the regulated parties. The regulation is performance-based, and fuel providers have seve ral options. First, they may supply a

mix of fuels above and below the standard t hat, on average, equal the required carbon intensity. Second, they can choose to only provide fuels that have lower carbon intensity than the standard. For example, they may blend low carbon ethanol into gasoline, or renewable diesel fuel in diesel fuel. Third, they may purchase credits generated by other fuel providers to offset any accumulated deficits from their own

1 For petroleum-based fuels, the lifecycle analysis is also referred to as “well-to-wheels; for fuels produced from crops, the lifecycle analysis is sometimes referred to as “seed-to-wheels.”ES-3 production. For example, a fuel provi der may choose to purchase credits generated from another fuel provider that has banked cr edits from using electricity in a plug-in hybrid vehicle. Fourth, a f uel provider may bank excess credits generated in a previous year and use those credits when needed. As the objective is to ensure lower carbon intensity fuels are created and used in the California fuel s market, the LCFS does not allow the use of credits, or offsets, gener ated from outside the transportation fuels

market.

The LCFS standards established in this rule making will be periodically reviewed. The

first formal review will occur by January 1, 2012. Additional reviews are expected to be conducted approximately every three years t hereafter, or as necessary. The 2012

review will consider the stat us of efforts to develop lo w carbon fuels, the compliance schedule, updated technical information, and pr ovide recommendations on metrics to address the sustainable producti on of low carbon fuels.

To achieve Governor Schwarzenegger’s long term goal or reducing GHG emissions by 80 percent by 2050, the carbon intensity of transportation fuels will need to be substantially decreased over t he 2020 target of a 10 percent reduction. Therefore, the staff expects to consider targets for the 2030 timeframe in subsequ ent reviews of the

LCFS.

Establishing the LCFS is only one of seve ral important actions needed to reduce GHG emissions from the transporta tion sector. Additional actions are necessary to fully implement the motor vehicle and other transportation-relat ed GHG measures identified in the Scoping Plan that the Board approved in December 2008. 2 A summary of the transportation-related measures is presented in Table ES -1. The potential benefits of the LCFS have been adjusted assuming that these other measures are implemented.

In addition, the Scoping Plan also identified that, beginning in 2015, transportation fuels are to be included in the Cap and Trade Progr am. The ARB staff believes that the LCFS is a complementary program to any Cap and Trade Program.

2 The ARB’s approved scoping plan is available at: http://www.arb.ca.gov/cc/scopingplan/d ocument/scopingplandocument.htm.ES-4 Table ES-1

Recommended Transportation-Relate d Greenhouse Gas Reduction Measures

Identified in the Air R esources Board’s Scoping Plan

Measure Description Emission Reductions
Counted Towards 2020 Target (MMTCO 2 e)

Low Carbon Fuel

Standard Reduce the carbon intensity of transportation fuels used in California by an average of 10 percent 15.0

California Light-Duty

Vehicle Standards Implement adopted Pavley standard and planned second phase of the program. Align zero-emission vehicle, alternative and renewable fuel and vehicle technology program with climate change goals. 31.7

Regional TransportationRelated GHG Targets Develop regional GHG emissions reduction targets for passenger vehicles pur suant to Senate Bill 375. 5

Vehicle Efficiency

Measures Implement light-duty vehicle efficiency measures including properly inflated tires, consideration of minimum fuel-efficient tire standards, and reducing engine load via lower friction oil and reducing the

need for air conditioner use. 4.5

Medium/Heavy Duty

Vehicles Adopt medium and heavy-duty vehicle efficiency measure including retrofits to improve the fuel efficiency of heavy-duty trucks by reducing aerodynamic drag and rolling resistance and hybridization of medium-and heavy-duty vehicles. 1.4

Related Federal, State, and International Requirements

There are no similar existing regulations. T he Board has established specifications for California reformulated gasoline and California ultra-low sulfur diesel fuel. In addition, the Board has established specifications fo r a number of alternative fuels used in transportation, such as E85 and natural gas . The staff is currently developing specifications for other alternative fuels, such as biodiesel, and is considering revising other fuel specifications, including natural gas . These actions are complementary to the proposed LCFS rulemaking.

An important goal of the LCFS is to establish a durable fuel carbon regulatory framework that is capable of bei ng exported to other jurisdic tions. It is only through the wider adoption of fuel car bon standards that the numbe r of markets in which high-carbon fuels can legally be sold will be reduced. As other areas adopt an LCFS, significant reductions in fuel carbon content will begin to be realized on a global scale. Actions already underway in some jurisdictions outside of California indicate that the LCFS is already perceived as a potential regulatory template : carbon-reduction
measures similar to the LCFS are under c onsideration at the r egional, national, and

international levels.ES-5 At the Federal level, Congress adopted a renewable fuels standard (RFS) in 2005 and strengthened it (RFS2) in December 2007 as part of the Energy Independence and Security Act of 2007 (EISA). The RFS2 requires that 36 b illion gallons of biofuels be sold annually by 2022, of which 21 billion gallons must be “advanced” lower carbon

biofuels and the other 15 billion gallons can be corn ethanol. Although the RFS2 requires the production of specified volumes of lower carbon biofue ls, the fuel carbon intensity reductions it would achieve in Ca lifornia would be substantially below the reductions the LCFS is designed to achieve. The federal RFS would deliver only about

30% of the GHG benefits of the proposed regulation, and does little to incent fuels such as natural gas, electricity or hydrogen. California’s LCFS is designed to complement

the federal RFS2.

A regional consortium of eleven Northeastern and Mid-Altantic States has committed to developing an LCFS that is generally based on the same premise as the California

LCFS. Significantly, this commitment references California’s efforts to develop an

LCFS. Under the commitment , the states will seek to draft a Memorandum of Understanding concerning the development of a regional LCFS program, to be forwarded by December 31, 2009, or as soon t hereafter as is possible for each state, for consideration by the Governor s of each state. As with t he national standard, ARB staff supports the effort to develop an LCFS.

At the international leve l, the European Parliament adopted, in December 2008, a package of measures to addr ess climate change throughout the European Union. One of these measures is a revised fuel quality dire ctive. This revised di rective requires fuel suppliers to reduce GHG emissions, on a life cycle basis, by up to 10 percent by 2020. Regarding land use change, the Eur opean Commission will have to develop a methodology to measure the GHG emissions that result when crops for biofuel production are grown in areas which have prev iously been used to grow a food crop and this food crop production then moves to other areas which were not is use before. The fuel directive also includes provisio ns to address sustainability of biofuels production. The need for national and international efforts is critical to ensure that low carbon fuels are not concentrated in any par ticular area and higher carbon fuels are

shuffled to areas that do not hav e LCFS requirements, or both.

The following sections provide background on the legislative and policy initiatives related to the development of the LCFS, information on the key provisions of the proposed regulation, results of the environmental and economic analyses, and a brief discussion of major public co mments. Additional details are presented in the Initial
Statement of Reasons: Staff Report - Proposed California Low Carbon Fuel Standard (Staff Report).

Legislative and Policy Directives

The LCFS is supported by a number of legi slative and policy directives as presented

below. A more detailed discussion is presented in the Staff Report.ES-6 • Assembly Bill 32 - In 2006, the Legislatur e passed and Governor Schwarzenegger signed Assembly Bill (AB) 32, referred to the California Global Warming Solutions Act of 2006. AB 32 r equired the Board to develop a plan to
reduce GHG emissions in California to 1990 levels by 2020. Among other provisions, AB 32 required the Board to identify and adopt discrete early actions in 2007 and to approve a scoping plan in 2008.

• Executive Order S-06-06 - In April 2006, Governor Schwarzenegger signed an executive order that established target s to increase the production and use of bioenergy, including ethanol and bi odiesel fuels made from renewable

resources. 3 One of the executive order prov isions specified that, by 2020, 40 percent of biofuels used in the State should be produced in the State. The proposed regulation supports this goal by requiring the use of low carbon

alternative fuels and stimulat ing innovation in the producti on of these low carbon

fuels.

• Executive Order S-01-07 - In January 2007, Governor Schwarzenegger signed

an executive order that es tablished the goal of devel oping an LCFS to reduce the carbon intensity of transporta tion fuels by at least 10 percent by 2020 and to

consider whether the LCFS should be listed as a discrete early action. 4 In addition, the executive order identified that the LCFS shall apply to all providers of transportation fuels in California, s hall be measured on a full fuels cycle basis, and may be met through market-based methods. The proposed regulation

satisfies the directive of the executive order.

• AB 32 Discrete Early Action Measures - In June 2007, the Board approved the LCFS as a discrete early action measure. The proposed regulation is designed to implement this measure. Table ES-2 summarizes the discrete early action

measures and their status.

• State Alternatives Fuel Plan - In November 2007, the California Energy Commission and the Board each approved the “State Alternatives Fuel Plan (Fuels Plan),” required pursuant to Assembly Bill 1007. 5 The Fuels Plan presents strategies and actions California must take to increase the use of alternative nonpetroleum fuels. An LCFS was anticipat ed as part of this Plan. The proposed regulation supports and is consistent with the goals of the Fuels Plan.

• AB 32 Scoping Plan - In December 2008, the Board approved the AB 32 Scoping Plan to reduce GHG emissions in California to 1990 levels. The Scoping Plan identifies how emission reducti ons will be achieved from significant GHG sources via regulations, market mechanisms, and other actions. The proposed regulation is listed as one of t he key measures in the Scoping Plan.

3 Executive Order S-06-06 is available at: http://gov.ca.gov/executive-order/183/.

4 Executive Order S-01-07 is available at: http://gov.ca.gov/executive-order/5172/.

5 The Air Resources Board and the California Ener gy Commission approved the St ate Alternatives Fuel Plan in December 2007. The Plan is available at: http://www.energy.ca.gov/ab1007/.ES-7 Table ES-2

Status of Discrete Early Action Measures

Measure Status Board Hearing

Date Emission

Reductions

in 2020
MMTCO 2 e Green Ports – Cold Ironing Ships at Ports Adopted December 2007 0.2 Reduction of High Global Warming

Potential Gases in Consumer Products Adopted June 2008 0.2

SmartWay Truck Efficiency Adopted December 2009 0.9 Reduction of High Global Warming Gases Used in Semiconductor Operations Adopted February 2009 0.2

Sulfur Hexafluoride from the NonSemiconductor and Non-Utility Applications Adopted February 2009 0.1

Vehicles Operating with Under-Inflated Tire

Pressure Scheduled March 2009 0.6

Low Carbon Fuel Standard Scheduled April 2009 15.9 * Landfill Methane Control Measure Scheduled May 2009 1.0 Management of High Global Warming Potential Refrigerants Scheduled May 2009 11

* Estimated emission reductions based on t he “tank-to-wheel” analysis . See Chapter VII.

In support of an LCFS, University of Califor nia (UC) Professors Daniel Sperling and the

late Alexander Farrell directed a team of UC colleagues that developed two significant reports that provided an init ial framework for the LCFS. 6, 7 These two reports established the technical feasibility of an LCFS, identified many of the significant technical and policy issues, and provided a number of specific recommendations. These comprehensive reports were the backbone of ARB staff’s initial efforts to develop the LCFS. While not all of the specific recommendations have been incorporated in the LCFS, all of the recommendations have s purred a vigorous debate on the issues and facilitated the development of AR B staff’s proposed regulation.

Major Provisions of the Proposed LCFS

The basic framework of the LCFS was presented above. The following discussion provides a more detailed discussion of the proposed regulation. The proposed regulation is presented in Appen dix A to this Staff Report.

Fuels Included in the LCFS

With respect to the fuels, t he LCFS applies, either on a compulsory or opt-in basis, to most types of fuels used for transpor tation in California, including:

6 “A Low Carbon Fuel Standard for California, Part 1: Technical Analysis;” Alexander E. Farrell, UC Berkeley, Daniel Sperling, UC Davis, et al; August 1, 2007

7 “A Low Carbon Fuel Standard for California, Pa rt 2: Policy Analysis;” Alexander E. Farrell, UC Berkeley, Daniel Sperling, UC Davis, et al; August 1, 2007ES-8 • California reformulated gasoline;

• California ultralow sulfur diesel fuel;

• Compressed or liquefied natural gas;

• Electricity;

• Compressed or liquefied hydrogen;

• Any fuel blend c ontaining hydrogen;

• Any fuel blend containing greater than 10 percent ethanol by volume;

• Any fuel blend containi ng biomass-based diesel;

• Neat denatured ethanol;

• Neat biomass-based diesel; and

• Any other liquid or non-liquid fuel not otherwise exempted fr om the regulation.

Fuel Pool Carbon Intensity Standards

The LCFS achieves GHG emission reductions by incrementally reducing the allowable carbon intensity of transportati on fuel used in California. The LCFS does not limit the carbon intensity of individua l batches or types of fuel s, but does require regulated parties to comply with an annual standard for the total amount of fuel they provide. This annual standard is expressed as carbon intensity in g CO 2 e/MJ. The allowable carbon intensity of transportation fuels decreases eac h year, starting in 2011, until the carbon intensities of gasoline and diesel transpor tation fuels in 2020 are each reduced by 10 percent relative to 2010. Gasoline and diesel follow similar carbon intensity

reduction curves from 2011 through 2020 and beyond.

Under the proposal, the carbon intensity for al ternative fuels (biofuels, natural gas, hydrogen, electricity) would be judged against either the gas oline or diesel carbon intensity standards, depending on whether the alternative fuel is used for light- or medium-duty vehicles or for heavy-duty vehicles, as specified in the r egulation. In each year, the carbon intensity of each fuel is co mpared to the LCFS st andard for that year. Fuels that have carbon intensity levels below the standard generate credits. Fuels with carbon intensity above the standard create defi cits. To comply with the LCFS for a given year, a regulated party must show that the total amount of credits equal or exceed

the deficits incurred. Excess credits can be b anked or sold to other regulated parties.

A graphical representation of the compliance schedules is presented in Figures ES-1 and ES-2. Table ES-3 shows the compliance schedules for gasoline and diesel fuel.ES-9 Figure ES-1 Figure ES-2

Compliance Schedule from 2011 to 2020

for Gasoline or Gasoline Substitutes

80.0 82.0 84.0 86.0 88.0 90.0 92.0 94.0 96.0 98.0

2011 2012
2 01

3
2 014
2 015
2 016
2 017 2018
2 01

9
2 02

0

YearCarbon Intensity, gCO2e/MJ Compliance Schedule from 2011 to 2020 for

Diesel Fuel or Diesel Fuel Substitutes

80.0 82.0 84.0 86.0 88.0 90.0 92.0 94.0 96.0

2011 2012 2013 20 1 4 2015 2016 2017 20 1 8 2019 2020

YearCarbon Intensity, gCO2e/MJ

Table ES-3 LCFS Compliance Schedule

Year Carbon Intensity

for Gasoline

and Fuels Substituting for

Gasoline

(g/MJ) Gasoline and

Fuels Substituting for

Gasoline

% Reduction Carbon Intensity

for Diesel and

Fuels Substituting for

Diesel (g/MJ) Diesel and

Fuels Substituting for

Diesel

% Reduction

2010 Reporting Only

2011 95.61 0.25% 94.47 0.25%

2012 95.37 0.5% 94.24 0.5%

2013 94.89 1.0% 93.76 1.0%

2014 94.41 1.5% 93.29 1.5%

2015 93.45 2.5% 92.34 2.5%

2016 92.50 3.5% 91.40 3.5%

2017 91.06 5.0% 89.97 5.0%

2018 89.62 6.5% 88.55 6.5%

2019 88.18 8.0% 87.13 8.0%

2020 and subsequent

years 86.27 10.0% 85.24 10.0%

Regulated Parties

In general, the regulation places compliance obli gations initially on r egulated parties that are upstream entities (i.e., producers and importe rs that are legally responsible for the quality of transportation fuels in Californi a), rather than downs tream distributors and fueling stations. However, under specified conditions, the regulated party may be another entity further downstream that can be held responsib le for the carbon intensityES-10 of the fuels or blendstocks that they dispense in California. The proposed regulation specifies the criteria under which a person would be deemed a regulated party for each particular fuel and how the responsibility for complying with the LCFS can be transferred. Table ES-4 summarizes the regula ted parties for each transportation fuel.

Table ES-4 Regulated Parties Defined in the Low Carbon Fuel Standard

Fuel Description of the Regulated Party

Gasoline, diesel, and liquid blendstocks (including oxygenates and biodiesel) The regulated party is the producer or importer of the

fuel or blendstocks.

Fossil fuel-derived compressed natural gas (fossil CNG) The regulated party is generally the utility company, energy service provider, or other entity that owns the fuel dispensing equipment. Fossil fuel-derived liquefied natural gas (fossil LNG) The regulated party is the entity that owns the fuel when it is transferred to the fuel dispensing equipment in California. Other gaseous fuels (biogas/biomethane, hydrogen) The regulated party will generally be the person who produces the fuel and supplies it for vehicular use.

Electricity The regulated party will be either the load service entity supplying the electricity to the vehicle or another party that has a mechanism to provide electricity to vehicles and has assumed the LCFS compliance obligation.

Transfer of Compliance Obligatio ns and Regulated Party Status

Certain persons are initially designated as r egulated parties who are responsible for all LCFS compliance obligations. Except as pr ovided in the proposal, this status as a regulated party generally remains with the initia lly designated party even if ownership to

the fuel is transferred from one party to another. There are tw o major exceptions to this general rule. For gasoline and diesel fuel, the compliance obligations would generally transfer to another producer or importer t hat receives blendstock from the initial regulated party, with provisions for the init ial regulated party to retain the compliance obligation if so desired by the affected parties.

The principal rule noted above notwithstandi ng, the proposal generally allows the regulated party for a fuel to transfer its compliance obligat ions by written instrument to another party under specified conditions; the buyeror recipient of the transferred fuel, in turn, becomes the regulated party for that fuel. For a variety of reasons, the transfer of such compliance obligations, along with the potential for gener ating and selling credits, may be desirable for a company, and the proposal allows such transfers.ES-11 Voluntary Opt-In Provisions

The proposed regulation includes an opt-in pr ovision and specific exemptions. The proposal explicitly recognizes that certain al ternative fuels have full fuel-cycle, carbon intensities (including power train effici encies) that inherent ly meet the proposed compliance standards through 2020. As a re sult, these fuels may choose an opt-in provision. These fuels are:

• Electricity;

• Hydrogen and hydrogen blends;

• Fossil CNG derived from North American sources;

• Biogas CNG; and

• Biogas LNG.

Parties that opt into the LCFS program will be those parties that expect to generate LCFS credits under the regulation. By opt ing into the program, a person becomes a regulated party under the LCFS regulation and is required to meet the LCFS reporting obligations and requirement s. The provisions for opting in to the LCFS are set forth in the proposed regulation.

Exemptions

The proposal initially does not apply to regul ated parties providing liquefied petroleum gas (LPG or propane). There are also exempt ions for specific applications, including racing fuels, interstate loco motives, ocean-going vessels, ai rcraft, and military tactical

vehicles. These sources account for a sm all amount of the diesel fuel used in California. However, it is important to note that this exemption does not apply to

intra state locomotives and commercial harborcra ft. These sources are already subject

to the California standards for diesel fuel. As such, the diesel fuel used in intrastate

locomotives and commercial harborcraft wo uld be treated the same as any other transportation fuel subject to the LCFS.

Progress Reporting and A ccount Balance Reporting

The proposal provides for regulated parties to submit quarterly progress reports by specified dates. These quarterly progress re ports are intended to ensure that regulated parties keep track of their ability to comply with the allowable carbon intensity at the end of the annual compliance period. The quarte rly reports are required to contain a specified set of information and data, such as carbon intensities, fuel volumes sold or dispensed, fuel transfer info rmation, and other information.

The annual account-balance reporting inclu des all the information required for the quarterly reporting, along with additional information relating to the total credits and deficits generated during t he year or carried over from th e previous year; total credits acquired from another party; total credits tr ansferred to other parties; credits generated and banked in the current year; and any deficit s to be carried into the next year. AllES-12 quarterly and annual reporting will be done via a W eb-based, interactive form that ARB

staff will establish.

Recordkeeping

Regulated parties will be required to mainta in specified records in English for a minimum of three years. Upon request by the Executive Office r, regulated parties would need to provide such records within 48 hours, unless a mutual agreement has

been reached on an alternat ive time period.

Evidence of Physical Pathway

To ensure that low carbon fuels that are pr oduced outside of California are actually the source of fuels used in the State, regulated parties will be required to establish physical pathway evidence for transportation fuels subj ect to the LCFS. For each transportation fuel that a regulated party is responsible for under the LCFS, this could involve a four-part showing:

• A one-time demonstration that there ex ists a physical pathway by which the transportation fuel is expected to arrive in California. This includes any applicable combination of tr uck delivery routes, rail tanker lines, gas/liquid pipelines, electricity transmission lines, and any other fuel distribution routes that, taken together, accurately account for the fuel’s movement from the generator of the fuel, through intermediate entities, to the fuel blender, producer, or importer in California;

• Written evidence, by contract or similar evidence, showing that a specific volume of a particular transportation fuel with k nown carbon intensity was inserted into the physical pathway as dire cted by the regulated party;

• Written evidence, by contract or sim ilar evidence, showing that an equal volume of that transportation fuel was remo ved from the physical pathway by the regulated party for use as a transpor tation fuel in California; and

• An update to the initial physical pa thway demonstration whenever there are modifications to the initially demonstrated pathway.

Provisions Governing Credits and Defi cits and Reconciliation of Shortfalls

Detailed equations and calculatio ns are specified in the proposal for a regulated party to use in calculating its total deficits and cr edits within each compliance period. A regulated party will meet its annual compliance requi rements if its credit balance, at the end of the compliance year, is greater than or equal to zero . Conversely, a regulated party is in deficit and may be in violation if it s credit balance is less than zero at the end of a compliance year.

A regulated party whose credit balance is le ss than zero at the end of a compliance year is in deficit and may be in violati on of the LCFS, depending on the magnitude of the shortfall. Shortfalls are categorized in to two main categories. First, a regulatedES-13 party that ends a compliance year with a si gnificant credit balance shortfall, determined on a percentage basis, will be in violation of the LCFS and subject to a notice of violation and penalties commensur ate with the size of the vi olation. In addition, the regulated party must reconcile and remedy the shortfall within a specified period of time. By contrast, a regulated party that ends a compliance year with a relatively small shortfall (i.e., shortfall is 10 percent or le ss) will be required to reconcile the shortfall within the following year.

It should be noted that, under the proposal, two or more consecutive years in a shortfall

will be treated the same as a substantial cr edit balance shortfall, irrespective of the shortfall’s size. A regulated party may generate credits on a quarterly basis, and unused credits may be banked without expirati on. A non-regulated third party is prohibited from buying, selling, or trading LCFS credits unless that third party is acting on behalf of a regulated party. There is no prohi bition against retiring or exporting LCFS credits to other GHG reduction initiatives, but importing credits from such external programs into the LCFS progr am would not be allowed.

Determination of Carbon Intensity Values

The carbon intensity values represent the cu rrency upon which the LCFS is based. The carbon intensity is determined in two parts. The first part represents all of the direct emissions associated with produc ing, transporting, and using the fuel. This involves determining the amount of GH G emissions emitted per unit of energy for each of the steps in the fuel pathway. For example, t hese steps may involve the following for the production of ethanol:

• Farming practices (e.g., frequen cy and type of fertilizer used);

• Crop yields;

• Harvesting of the crop;

• Collection and transportation of the crop;

• Type of fuel production process;

• Fuel used in the production process (e.g. coal/CNG/biomass);

• Energy efficiency of the production process;

• The value of the co-products generated (e.g. distillers grain);

• Transport and distribution of the fuel; and

• Combustion of the fuel in vehicles.

The second part considers any other effects, both direct and indirec t, that are caused by the change in land use or other market-m ediated effects. For some crop-based biofuels, staff has identified land use changes as a signific ant source of additional GHG emissions. Therefore, staff is proposi ng that emissions associated with land use changes be included in the carbon intensity values assigned to those fuels in the proposed regulation. No other significant indirect effe cts that result in large GHG

emissions have been identified t hat would substantially affe ct the LCFS framework for reducing the carbon intensity of transportation fuels.ES-14 To assess the direct emissions, staf f used the Greenhouse Gases, Regulated Emissions, and Energy Use in Transportation model, modified for use in California (CA-GREET) model as the pr imary method for calculating carbon intensity values for various transportation fuels. The CA-G REET model is essential a very large spreadsheet that performs accounting of GHG emissions. The CA-GREET model incorporates many specific numeric values t hat allow for the calculation of the lifecycle

GHG emissions associated with producing, transporting, and usi ng various fuels. Staff used CA-GREET to develop specific car bon intensities for a number of different pathways. For some fuels, multiple pathways were developed that represent

differences in how and w here the fuel is produced.

To assess the emissions from land use c hanges, staff used a global trade model to

estimate the GHG emissions impact. The Global Trade A nalysis Project (GTAP) model

is discussed in detail in the Staff Report and related Appendice s. In general, the model

evaluates the worldwide land use conversion associated with the production of crops for fuel production. Different types of land us e have different rates of storing carbon. Multiplying the changes in land use times an emission factor per land conversion type

results in an estimate of the GHG emi ssions impacts of land conversions.

The proposed regulation has several differ ent methods for establishing carbon

intensities. With these di fferent methods, no fuel is excluded from the LCFS unless specifically exempted.

The first method, referred to as Method 1, establishes default values for a number of specified fuel pathways. Regulated parties may choose to use the default pathways to calculate credits and deficits. The staff is pr oposing that the Board approve this default Lookup Table. The Lookup Table reflects t hose fuel pathways that ARB staff has completed to date. The full documentati on supporting these carbon intensities is provided on the website. The Lookup Tables are presented in Tables IV-20 and IV-21 in Chapter IV. The various pathways that are completed and proposed for approval in this rulemaking are summarized in Table ES-5.

Note that these pathways do not represent all of the po ssible pathways for producing fuels. Staff continues to develop carbon in tensity values and has released preliminary values for a number of other pathways or is developing carbon intensities for additional pathways. The proposed regulat ion establishes that the Executive Officer may approve subsequent amendments to the Lookup Table after a specified public process. Table ES-6 summarizes the pathways where preliminary numbers have been developed or that are curr ently under development. Following a formal public review process as identified in t he regulation, the Executive Officer may approve additional carbon intensity values to be added to the Lookup Table.

Also note that the Staff Report presents pr eliminary estimates for land use changes for biodiesel from soy oil, as well as prelim inary estimates for other pathways. These estimates are provided to allow for an a ssessment of the compliance pathways and are not being proposed for approval at this rulemaki ng. Like the land use estimates for cornES-15 ethanol and sugarcane ethanol, the soy biod iesel land use change result was produced using GTAP. The biodiesel estimate is very pr eliminary: it does not appear in the LCFS Lookup Table. Its only use has been the prepar ation of the diesel fuel compliance scenarios appearing in Chapter VI. In particular, staff is c oncerned that our estimate of land use allocation for co-produc ts may significantly underes timate the land use impacts of soy-based biodiesel, t hereby overestimating its GH G benefits. Our ongoing assessment of biodiesel from soy oil may result in a significantly different estimate of its GHG impact. When a value sufficiently robu st for use in the regulation has been estimated, that val ue will be published for public comment and proposed for

certification.

Table ES-5 Fuel Pathways Completed for Use in the LCFS

Fuel Pathway Description of the Pathway

CARBOB (California Reformulated

Gasoline Blendstock for Oxygenate Blending) 1 average pathway based on the average crude oil used in
California refineries

CaRFG (California Reformulated Gasoline) 1 specific pathway combining CARBOB and a blend of an average Midwestern corn ethanol and California corn ethanol to meet a 3.5% oxygen content by weight (approximately 10% ethanol).

Ethanol from Corn 11 different specific pathways that reflect different options that are used to produce ethanol from corn.

Ethanol from Sugarcane 1 specific pathway for producing ethanol from sugarcane using average production processes.

Electricity 2 specific pathways representing average and marginal electricity used in California.

Hydrogen 4 specific pathways reflecting different options to produce hydrogen as a fuel.

ULSD (Ultra Low Sulfur Diesel) 1 average pathway based on the average crude oil used in
California refineries.

Compressed Natural Gas 3 specific pathways reflecting different options to produce compressed natural gas as a fuel.ES-16 Table ES-6 Fuel Pathways Under Development for Use in the LCFS

Fuel Pathway Description of the Pathway

Brazilian sugarcane using bagasse for electricity production as a co-product credit Ethanol from Sugarcane Brazilian sugarcane using mechanized production of

sugarcane Farmed trees using a fermentation process. Agriculture waste Ethanol from Cellulosic Material

Forest waste Midwest soybeans to soy oil for conversion to biodiesel (fatty acid methyl esters - FAME) Yellow grease, fats, and waste oil for conversion to biodiesel (FAME) Biodiesel

Palm oil from South East Asia for conversion to biodiesel (FAME) Midwest soybeans to soy oil for conversion to renewable

diesel. Renewable Diesel Yellow grease, fats, and waste oil using co-fed stream into refinery or bio-refinery for conversion to renewable diesel Remote LNG shipped to Gulfport, Texas; regasified and pipelined to California; CNG in California. Compressed Natural Gas Remote LNG shipped to Baja, CA; regasified and pipelined to California; CNG in California.

Crude Derived from oil sands.

Derived from oil shale. Canadian NG via pipeline to LNG liquefaction facility in California; liquefied in CA for use as LNG. Remote LNG shipped to Baja, CA; gasified and pipelined to California; liquefied in California for use as LNG. Remote LNG shipped to Baja, CA; LNG trucked to

California for use as LNG. Liquefied Natural Gas

LNG from landfill gas.ES-17 Under specified conditions, regulated parties may also obt ain Executive Officer approval to either modify the CA-GREET model inpu ts to reflect their specific processes (Method 2A) or to generate an additional fuel pathway using CA-GREET (Method 2B). For both Method 2A and 2B, there is a scient ific defensibility requirement for the regulated party to meet before the Execut ive Officer can approve new values. For Method 2A, there is an additional provision that requires a subs tantial change in the carbon intensity relative to the analogous value calculated for that pathway under

Method 1.

For CARBOB, gasoline, and diesel fuel, there ar e specific provisions with regard to the method for determining carbon intensity values, depending on whether the crude oil

used to make such fuels is deriv ed from crude oils with high carbon intensity relative to the average carbon intensity of crude oils used in California refineries. Examples include certain crude oils produced from o il sands, oil shale, or other high carbonintensity crude oils. With regard to CARBOB , gasoline, and diesel fuel made from crude oil extracted from any sour ce other than these high car bon-intensity crude oils, the regulated party would be required to use the carbon intensity specified in the Lookup

Table for that fuel.

By contrast, for CARBOB, gasoline, and dies el fuel made from high carbon-intensity crude oil, the regulated party w ould be required to use the car bon intensity value, if any, which is specified in the Lookup Table for that particular pathway. If there is no carbon intensity value specified for a particular hi gh carbon-intensity crude oil, the regulated party could use Method 2B (with Executiv e Officer approval) to generate an additional pathway for this type of crude.

Alternately, the regulated party coul d use the standard Lookup Table value for CARBOB, gasoline, or diesel for fuel derived from non-high carbon intensity crude oil, but only if the regulated party can demonstr ate to the Executive Officer that its crude production and transport carbon-in tensity value has been reduc ed to a specified level and meets other specifi ed criteria. To this end, staf f is proposing that any regulated party, using a high carbon-intensity crude oil (> 15 g CO 2 e/MJ) brought into California that is not already part of the California baseline crude mix, w ould have to report and

use the actual carbon intensit y for that crude oil unless the party demonstrates that it has reduced the crude oil’s carbon intensity below 15 g CO 2 e/MJ using carbon capture and sequestration (CCS) or other method. Upon this demonstration, the regulated party would be permitted to use the average carbon intensity value for the California baseline crude mix (i.e., crude oils currently used in California refineries).

The proposed uses of Method 2A and 2B ar e subject to public review under the proposal. In other words, the Executiv e Officer may not approve a carbon intensity value proposed pursuant to Method 2A or 2B unless the proposed method and associated information submitted in support of that method has been disclosed to the public and available for public review for the prescribed time period. Trade secrets, as defined under State law, t hat are submitted would be treated in accordance withES-18 established ARB regulations and procedur es (17 CCR §§ 91000-91022) and the Public Records Act (Government Code § 6250 et seq.).

Determination of Vehicle Efficiency Adjustment Factors

In calculating the credits and def icits, factors are used to recognize the fact that some fuels and vehicles are more energy efficient than others. The more energy efficient fuels and vehicles will travel more miles per unit of energy input to the vehicle, thus resulting in less fuel consumption and CO 2 emissions. Total emissions are dependent on both the emissions per unit of energy consumed and the fuel economy of the vehicle.

For example, the well-to-wheel CO 2 emissions from electric vehicles, in units of g CO 2 e/MJ of energy delivered to the vehicle, are generally higher than for gasoline vehicles. However, electric vehicles requi re much less energy to travel a specified distance. As a result of their much lower pe r mile energy consumption, electric vehicles emit less greenhouse gases than gasoline vehi cles on a per mile basis, even though they emit more per unit of energy consumed.

For purposes of the LCFS, staff has adopted the term “Energy Economy Ratio,” or EER,

to refer to the factor that is used to acc ount for differences in energy efficiency among different types of fuels and vehicles. The EE R is defined as the rati o of the number of miles driven per unit energy consumed for a fuel of interest to the miles driven per unit energy for a reference fuel. For purposes of the LCFS, the reference fuel is gasoline for light- and medium-duty vehicles, and diesel fo r heavy-duty vehicles. Thus, the EER for light-duty vehicles for a given fuel is defined as the ratio of the miles driven per energy

consumed for that fuel to the miles dr iven per energy consumed for a comparable vehicle using gasoline. Ther efore, the EER for gasoline is always 1.0 for light- and medium-duty gasoline-powered vehicles; similarl y, the EER for diesel is always one for diesel-fueled heavy-duty vehicles. The St aff Report and Appendices present examples

and data on how the EERs were calculated.

In general, the values for the number of mile s driven per unit energy used are based on data or estimates of fuel economy, in units of miles per gallon, and the energy density of the fuel, in units of energy (Btu or J oules) per gallon. However, for advanced technology or emerging vehicles such as batte ry electric vehicles (BEV), plug-in hybrid electric vehicles (PHEV), fuel cell vehi cles (FEV), and heavy-duty compressed natural gas (CNG) or liquefied natural gas (LNG) ve hicles, the data are relatively limited. Therefore, the staff has prov ided EER values that are to be used until such time that

there is more robust data available to be tter establish the EER. Table ES-7 presents the EERs specified in the regulation.

Tables ES–8 and ES-9 presents the adjusted carbon intensities for gasoline and fuels that substitute for gasoline and diesel and fuels that substitute for diesel, respectively. Staff is proposing that the pathways listed in these tables be approved as part of this rulemaking. Note that the carbon intensit ies in the tables hav e not been adjusted with
the EERs in Table ES-7 to reflect vehicular power train efficiencies.ES-19 As there will only be a limited num ber of these advanced vehicl es available in the first few years of the LCFS, the amount of credits generated is not likely to be significantly

affected. Staff is committ ed to review and update these and other EERs as more robust data become available, as well as develop EER s for other vehicles such as internal combustion engines using hydrogen.

Table ES-7 EER Values Proposed for Use in the Low Carbon Fuel Standard

Light- and Medium Duty Applications (Fuels Used in Vehicles Substituting for Gasoline Vehicles) Heavy-Duty/Off-Road Applications (Fuels Used in Vehicles Substituting for Diesel Vehicles)

Fuel/Vehicle Combination EER Values

Relative To

Gasoline Fuel/Vehicle Combination EER Values

Relative to

Diesel Gasoline (including 6% and 10% ethanol blends) Used In

Gasoline Vehicles

or 85% Ethanol/15% Gasoline

Blends Used In Flexible Fuel

Vehicles 1.0 Diesel Fuel Used in A Diesel

Vehicle or Biomass-Based

Diesel Blends 1.0

Compressed Natural Gas Used in Spark-Ignited Vehicles 1.0 Compressed or LiquefiedNatural Gas Used in a HeavyDuty Spark Ignited or Compression Ignition Engine 0.9

Electricity Used in a Battery

Electric or Plug-In Hybrid

Electric Vehicle 3.0 Electricity Used in a Battery Electric or Plug-In Hybrid Electric Heavy-Duty Vehicle 3.0

Hydrogen Used in a Fuel Cell

Vehicle 2.3 Hydrogen Used in a Heavy Duty Vehicle 1.9ES-20 Table ES-8 Adjusted Carbon Intensity Values

for Gasoline and Fuels that Substitute for Gasoline

Carbon Intensity Values (gCO 2 e/MJ) Fuel Pathway Description Direct

Emissions Land Use

or Other

Effect Total

CARBOB – based on the average crude oil delivered to California refineries and average California refinery efficiencies 95.86 0 95.86

CaRFG-CARBOB and a blend of 100% average Midwestern corn ethanol to meet a 3.5% oxygen content by weight (approximately 10% ethanol) 96.09 --- 96.09 1 Gasoline

CaRFG-CARBOB and a blend of an 80%

Midwestern corn ethanol and 20% California corn ethanol to meet a 3.5% oxygen content by weight blend (approximately 10% ethanol) 95.85 --- 95.85 1

Midwest average; 80% Dry Mill; 20% Wet Mill; Dry
DGS 69.40 30 99.40

California; Dry Mill; Wet DGS; NG 50.70 30 80.70 California average; 80% Midwest Average; 20% California; Dry Mill; Wet DGS; NG 65.66 30 95.66

Midwest; Dry Mill; Dry DGS 68.40 30 98.40
Midwest; Wet Mill 75.10 30 105.10 Midwest; Dry Mill; Wet DGS 60.10 30 90.10 California; Dry Mill; Dry DGS, NG 58.90 30 88.90 Midwest; Dry Mill; Dry DGS; 80% NG; 20%

Biomass 63.60 30 93.60

Midwest; Dry Mill; Wet DGS; 80% NG; 20%

Biomass 56.80 30 86.80

California; Dry Mill; Dry DGS; 80% NG; 20%

Biomass 54.20 30 84.20 Ethanol
from Corn

California; Dry Mill; Wet DGS; 80% NG; 20%

Biomass 47.44 30 77.40

Ethanol

from Sugarcane Brazilian sugarcane using average production

processes 27.40 46 73.40

California average electricity mix 124.10 0 41.37 2
Electricity California marginal electricity mix of natural gas and renewable energy 104.70 0 34.90 2

Compressed H 2 from central reforming of NG 142.20 0 61.83 3

Liquid H 2 from central reforming of NG 133.00 0 57.83 3

Compressed H 2 from on-site reforming of NG 98.30 0 42.74 3 Hydrogen SB 1505 Scenario; Compressed H 2 from on-site reforming with renewable feedstocks 76.10 0 33.09 3

1 Calculated value; land use part of the value

2 Adjusted by an EER factor of 3.0 to account for power train efficiency improvements over gasoline engines

3 Adjusted by an EER factor of 2. 3 to account for power train efficiency improvements over gasoline enginesES-21 Table ES-9 Adjusted Carbon Intensity Values for Diesel

and Fuels that Substitute for Diesel

Carbon Intensity Values (gCO 2 e/MJ) Fuel Pathway Description Direct

Emissions Land Use

or Other

Effect Total

Diesel ULSD – based on the average crude oil delivered to California refineries and average California refinery efficiencies 94.71 0 94.71

California NG via pipeline; compressed in

California 67.70 0 75.22 1

North American natural gas delivered via pipeline; compressed in California 68.00 0 75.56 1 Compressed

Natural Gas Landfill gas cleaned up to pipeline quality NG; compressed in California 11.26 0 12.51 1

California average electricity mix 124.10 0 45.96 2
Electricity California marginal electricity mix of natural gas and renewable energy 104.70 0 38.78 2

Compressed H 2 from central reforming of NG 142.20 0 74.84 3

Liquid H 2 from central reforming of NG 133.00 0 70.00 3

Compressed H 2 from on-site reforming of NG 98.30 0 51.74 3 Hydrogen
SB 1505 Scenario; Compressed H 2 from onsite reforming with renewable feedstocks 76.10 0 40.05 3

1 Adjusted by an EER factor of 0. 9 to account for power train efficiency losses compared to diesel engine

2 Adjusted by an EER factor of 2.7 to account for po wer train efficiency improvements over heavy-duty diesel engines

3 Adjusted by an EER factor of 1.9 to account for po wer train efficiency improvements over heavy-duty diesel engines

Executive Officer Review and Multimedia Evaluations

The proposal would require the Executive Of ficer to conduct a review of the LCFS implementation by January 1, 2012, t he scope and content of which would be determined by the Executive Officer. In addition, staff expects to periodically review the LCFS, likely on a three year schedule. Ther efore, the next revi ew would be conducted by January 1, 2015.

Pursuant to Health and Safety Code (H&S) section 43830.8(a), the Board may not adopt a regulation that estab lishes a specification for a motor vehicle fuel unless a

multimedia evaluation for the regulation undergoes the review process specified in the statute. However, this mu ltimedia requirement does not appl y if the regulation does not establish a motor-vehicle fuel specification. Based on its assessment as discussed in the Staff Report, staff has determined that the proposed LC FS regulation, by itself, does not establish a motor-vehicle fuel spec ification and therefor e does not trigger a multimedia evaluation requirement under H&S section 43830.8(i).ES-22 While the proposal, by itself, does not estab lish motor-vehicle fuel specifications, we expect that as new, lower-carbon intensit y fuels are developed over time, ARB may need to establish fuel specifications to allow the sale of such fuel s in California. In those cases, we anticipate the need to conduct multimedia evaluations for the specific fuels. Indeed, ARB has a multimedia evaluation already underway for biodiesel and renewable diesel, for which we hope to estab lish new fuel specifications in a future rulemaking. Similar multimedia eval uations may be needed if ARB amends the specifications for 85% ethanol gasoline (E-85) and adopts a new biobutanol fuel specification. Therefore, the proposal contains provisio ns relating to multimedia evaluations which, when applicable, would be conducted pursuant to H&S

section 43830.8.

Other Provisions under Consideration

Pursuant to H&S section 38580(b)(3), staff is considering inclusion of a method to convert a violation of any part of this pr oposed regulation into t he number of days in violation, where appropriate, for the purposes of the penalty provisions of Article 3 (commencing with Section 4240 0) of Chapter 4 of Pa rt 4 of, and Chapter 1.5 (commencing with Section 43025) of Part 5 of, Division 26. Staff is also considering language that would enumer ate specific acts pr ohibited under the LCFS.

Pursuant to H&S section 38597, staff is also considering inclusion of a schedule of fees, to be paid by the regulated parties, to fund the use of third-party services. These thirdparty services would be used to substant iate fuel pathways and other information

submitted to the Executive Officer under t he LCFS, particularly when the regulated parties are located outside the State. The tracking of cr edit trades and acquisitions may also be funded by these fees.

Finally, the Staff Report sustainability iss ues associated with land use changes. Staff will evaluate other issues with regard to the sustainability of alternative fuels. By December 2009, the staff will develop a plan for incorporating sustainability metrics into the LCFS. This plan will be developed thr ough a public process. Issues to be addressed in this process include, among ot hers, a discussion of: the definition of sustainability, what metrics will be reviewed for including the LCFS, a framework for how sustainability metrics will be incor porated and enforced in the LCFS, and a schedule for finalizing sustainab ility criteria and metrics by no later than December

2011. This effort will involve national and international cooperation.

Possible Compliance Scenarios

In order to determine the feas ibility of the LCFS, the staf f prepared several scenarios for achieving both the gasoline and diesel standard s. Four of the scenarios pertain to gasoline and fuels that can substitute for gas oline, and three pertain to diesel and its

substitute fuels. Each scenario descri bes a compliance path involving a different

combination of advanced renewable fuel s, and advanced electric and hydrogenpowered vehicles. The compliance scenario s demonstrate that demonstrate thatES-23 compliance is possible, given what is current ly known about the future availability of

alternative fuels and vehicles. In additi on, the compliance scenarios show that compliance is not contingent upon the availab ility of only a limited nu mber of alternative

fuel-vehicle combinations. Tables ES- 10 and ES-11 present a summary of the

contribution of various fuels for each of the scenarios.

Table ES-10 Contribution to Reducing the Deficits in the LCFS

For Fuels Substituting for Gasoline Fuel in 2020

Percent of Reductions Provided by Each Fuel Type Substituting for Gasoline in 2020 1 Fuel Type

Scenario 1 Scenario 2 Scenario 3 Scenario 4

CA Low-CI Ethanol 2 2 2 2

Cellulosic Ethanol 44 43 38 28

Advanced

Renewable Ethanol 43 41 36 27

Sugarcane Ethanol 0 3 3 3

Electricity 9 9 18 35

Hydrogen 2 2 3 5

1 Baseline gasoline consists of 90% CARBOB and 10% Ethanol by volume.

Table ES-11 Contribution to Reducing the Deficits for Fuels Substituting for Diesel Fuel in 2020

Percent of Reductions Provided by Each Fuel Type Substituting for Diesel in 2020 Potential Fuels

Scenario 1 Scenario 2 Scenario 3

CNG 0 2 2

Electricity 0 0 3

Conventional

Biodiesel 14 14 13

Advanced

Renewable

Biodiesel 86 84 81ES-24 Environmental Analysis

The environmental analysis of the proposed LCFS regulation focuses on significant

decreases in the GHG emissions that would re sult from the proposed regulation. These reductions would result from production and us e of lower carbon transportation fuels in California and changes in the vehicle fleet composition due to new, lower carbon fuels being available to the transportation fuel pool. Staff has estimated the GHG emissions

reductions for the combustion of trans portation fuels to be about 16 MMT CO 2 e by
2020. Staff has also estimated GHG reductions for the full fuel lifecycle, including fuel production through combustion, of 23 MMT CO 2 e in 2020. These reductions account for a 10 percent reduction of the GHG emissions from the use of tr ansportation fuel. These reductions compare to the expected 3 percent reduc tion in GHG emissions if only the federal RFS2 r equirements were met.

The proposed LCFS regulation is also expec ted to result in no additional adverse impacts to California’s air quality due to emissi ons of criteria and toxic air pollutants. Based on the best available data, there may be a benefit in fu rther reducing criteria air pollutants from the 2020 pr ojected vehicle fleet.

To meet the proposed LCFS and the federal RFS2, new biofuel production facilities will likely be built in California. Staff estimate s a total of thirty facilities producing corn ethanol (6), cellulosic ethanol (18), and biodi esel (6) could be operational by 2020 based on an assessment of the availability of feedstock material. Biofuel production on a commercial scale will require development of new technologies as well as the continued use of improved conventional te chnology with crop-derived feedstocks. Non-crop feedstocks could include biomass wastes from municipal solid wastes, agriculture wastes, waste oils, and forestry. Criteria pollutant emissions were estimated for the production of biofuels, the collection of feedstock, and delivery of the finished

biofuel.

The emissions estimated for the biofuel prod uction facilities reflect the use of the cleanest energy conversion technologies and ai r pollution control technologies. ARB

staff recommends that the emissions associ ated with the production of low carbon fuels be fully mitigated consistent with loca l district and CEQA requirements.

To provide additional information for local districts and to inform the CEQA process, ARB staff is committed to developing a guid ance document to provide information on the best practices available to reduce emissions from these types of facilities. This effort will commence immediately; ARB staff plans to have a draft available by the end

of December 2009.

The major criteria pollutant emissions are associated with the ad ditional biorefinery truck trips. As part of t he analysis, the staff analyzed the localized diesel PM impacts and localized facility emissions impacts.ES-25 A health risk assessment was conducted to estimate the potential cancer risk associated with newly establis hed biorefineries based on the facility specific emission inventory and air dispersion m odeling predictions. The esti mated potential cancer risk

levels are associated with onsite diesel PM emissions from three co-located prototype biorefinery facilities. The area with gr eatest impact was estimated to be the area surrounding the facility fence lines with a potent ial cancer risk of over 0.4 chances in a

million. The health risk assessment also examined combined onsite and offsite emissions of the three protot ype biofuel facilities. The area with the greatest impact was estimated with a potential cancer ri sk of about five chances in a million.

Staff also quantified seven non-cancer health impacts associated with the change in exposure to PM2.5 emissions due to the possible construction and operation of 24 new

biofacilities in California. The analysis shows that the stat ewide health impacts of the

emissions associated with these faciliti es are approximately 24 premature deaths; 8 hospital admissions; and 367 cases of asth ma, acute bronchitis and other lower respiratory symptoms.

Staff does not anticipate either a decrease or increase in t he emissions from petroleum refineries, power plants, or corn ethanol facilities over t he 2010 baseline. The capacity of the State’s electric system in 2020 will be sufficient to support 1.8 million electric vehicles due to the 33 perc ent renewable portfolio standard and off-peak charging.

Also included in the environmental analysis is an examination of other environmental impacts of the LCFS on water quality and us e, agricultural resources, biological resources, geology and soils, hazardous material s, mineral resources, and solid waste, among others.

Sustainability provisions will ensure that the LCFS regulat ion does not adversely impact the ability to continue the use of biofuels and other low ca rbon intensity fuels in the

future. The most critical sustainability component, addre ssing land use change, is part of the LCFS regulation. To addre ss other sustainability components, both environmental and socioeconomic, will require international cooperation and the development of enforceable cert ification standards. ARB is committed in the short term to develop a plan to address other sustainabi lity components, and within two years of adoption of the LCFS will develop proposed sustainability criteria.

The ARB is committed to making the achievem ent of environmental justice an integral part of the LCFS. As such, staff seeks to develop tools to ensure that the proposed regulation does not dispropor tionately impact low-income and minority communities,

does not interfere with the atta inment and maintenance of am bient air quality standards,

and considers overall societal be nefits (such as diversificatio n of energy resources). As part of ongoing AB 32 analysis, ARB staff is developing a screening method for geographically representing em ission densities, air quality exposure metrics, and indicators of vulnerable populations, as an evaluation aide for already adversely impacted communities.ES-26 Economic Analysis

For the economic analysis of the LCFS, staf f estimated the costs of producing the petroleum-based fuels—gasoline and diesel— and the costs of producing the lowercarbon-intensity transportation fuels that could be used in combination with petroleum

fuels to meet the LCFS. St aff applied these costs to po ssible compliance scenarios for both diesel fuel and gasoline. Each of these possible scenarios includes an assumed

mix of fuels that satisfies the LCFS reduction targets.

Staff estimated that the displacement of petroleum-based fuels with lower-carbonintensity fuels will result in an overall savings in the State, as much as $11 billion from 2010 -2020. These savings may be realized by the biofuel producers as profit, or some of the savings may be passed on to the cons umers. Should the savings be entirely passed on to consumers, it would represent le ss than three percent of the total cost of a typical gallon of transporta tion fuel ($0 - $0.08/gal).

Staff understands that the economic analysis of the LCFS is greatly affected by future oil prices and the actual production co sts and timing of lower-carbon-intensity alternative fuels. Economic factors, such as tight supplies of lower-carbon intensity fuels or a lengthy economic downturn keeping crude demand and hence prices down, could result in overall net costs, not savings, for the LCFS.

Staff determined that approximat ely 25 new biorefineries coul d be built in California based on an assessment of potential feedsto cks. Biofuel producers are expected to eventually recoup their costs through the sale of lower-car bon-intensity fuels, while consumers should see no significant changes in fuel prices to some savings. In addition to liquid fuels, such as ethanol and bi odiesel, other lower carbon-intensity fuels, including electricity, hydrogen, and compre ssed natural gas (CNG) may be used to meet the requirem ents of the LCFS.

The proposed regulatory action would not affect small businesses because: (1) most, if not all, regulated parties are expected to be relatively large businesses, and (2) small businesses (generally the fueling stati on owners and operators) would presumably invest in equipment that dispenses LCFS-c ompliant fuel with the expectation that the costs of such an investment would be recouped through sales of such fuels.

Staff conducted the economic analyses co nsidering all cost s of production and

distribution of alternative tr ansportation fuels, which, as mentioned above, resulted in overall savings to the State. Staff then recognized that the federal Renewable Fuel Standard (RFS2) will bri ng significant quantities of ethanol to California, and that the infrastructure required to meet the mandates of RFS2 is essentially the same infrastructure necessary to meet the potential ethanol require ments of the LCFS; therefore, nearly all of the ethanol-related infrastructure co sts can be attributed to RFS2.

RFS2 and the proposed LCFS regulation will result in a shift of capital from the petroleum sector to the agricul tural, chemical, electricity, and natural gas sectors. ThisES-27 redistribution of capital among these sectors is essential to the success of the LCFS

and RFS2. The diversification of California’s transportation fuels, which requires a shift of capital from the petroleum sector, is consistent with well-e stablished national and State policies.

The regulation would create cost s to the State in the form of lost transportation-fuel taxes, including excise taxes and sales ta x. Although there would be no estimated fiscal impact for the first th ree years of the pr oposed regulation, staff estimates the potential loss of annual state tax revenue to be $80 million to $370 million in 2020—the year of greatest impact—depending on comp liance path(s) chosen. For local government, the impact of sales tax on tr ansportation fuels from implementing the potential compliance scenarios co uld either create revenue or result in a revenue loss, depending on the complianc e path(s) chosen. The impacts to local sales taxes would be location specific. Although t here would be no fiscal impact fo r the first three years of the proposed regulation, staff estimates a po tential range of impa cts in annual local sales tax revenue of -$51 million to +$2 million from 2013 – 2020.

Enforcement Mechanisms

The ARB is developing a secure on-line LC FS Reporting Tool (L RT) to support the reporting requirements of fuels and other data to the Stat e. ARB plans to have the LRT available for use in early 2010. The LCFS mandates that all regul ated parties report required data on a quarterly and annual basis . The LRT will be a secure, web-based data collection and report generation applicati on designed to accommodate submittal of all required information and help regulated partie s meet their reporting obligations.

ARB will review the reports submitted via the LRT for completeness and accuracy, evaluate the data in the reports to determine if the regulated party is in compliance with the requirements of the regul ation, conduct field investi gations and audits of the regulated parties to verify and validate the in formation submitted in the reports, prepare and issue notices of violation, meet with vi olators for the purpose of mutual settlement, and participate in litigation if necessary.

Penalties and other remedies for violations of regulations adopted pursuant to AB 32, which includes the LCFS, are set forth in H&SC section 38580 et. seq. These include injunctive relief under H&S section 41513 an d criminal and civil penalties under H&S 42400 et seq. and H&S 43025 et seq. Further, H&S section 43029 provides additional penalties designed to elimi nate the economic benefits gained from a regulated party’s noncompliance.

H&S section 43031(b) states that in determi ning the amount assessed, the court, the Attorney General, or the state board, in reaching any settlement, shall take into

consideration all relevant factors. Those fa ctors include, but are not limited to: (1) the extent of harm to the public health, safety and welfare caused by the violation; (2) the nature and persistence of the violation, including t he magnitude of the excess emissions; (3) the compliance history of the defendant, including the frequency of pastES-28 violations; (4) The preventive efforts ta ken by defendant, including the record of maintenance and any program to ensure comp liance; (5) the innovative nature and the magnitude of the effort required to comply , and the accuracy, reproducibility, and repeatability of the available test methods; (6) the efforts to attain, or provide for, compliance; (7) the cooperation of the defendant during the course of the investigation and any action taken by the defendant, includ ing the nature, extent, and time of response of any action taken to mitigate the violation; and (8) for the person who owns a single retail service station, the size of the business.

Critical Issues and Arguments

Land Use Changes

Carbon intensities are calcul ated under the LCFS on a full lifecycle basis. This means that the carbon intensity value assigned to each fuel reflects the GHG emissions

associated with that fuel’s production, transport, storage, and use. In addition to these direct GHG emissions, some fuels create em issions due to indirect land use change effects. An indirect land use change impact is initially triggered when an increase in the demand for a crop-based biofuel begins to driv e up prices for the necessary feedstock crop. This price increase causes farmers to devote a larger proporti on of their cultivated acreage to that feedstock crop. Supplies of the displaced food and feed commodities subsequently decline, leading to higher prices for those commodities. The lowest-cost way for many farmers to take advantage of these higher commodity prices is to bring non-agricultural lands into production. Thes e land use conversions release the carbon sequestered in soils and vegetation. The resulting carbon emissions constitute the “indirect” land use change impact of increased biofuel production.

Efforts to model indirect land use impacts indicate that the full lifecycle carbon intensities of some biofuels may be similar to or even higher than the carbon intensities of conventional petroleum-based fuels. ARB staff has been and will continue to work

with modelers at t he University of Califor nia and Purdue University to derive indirect land use change estimates that are empiri cally based, defensible, and fully open to public scrutiny and comment.

Based on the work done to date, crop-based biofuel s contribute to some indirect land use impacts. However, the magnitude of this impact has been questioned by renewable fuel advocates. Land use change is driven by multiple factors. Because the tools for estimating land use change are few and relative ly new, biofuel producers argue that land use change impacts should be excluded fr om carbon intensity values pending the development of better estimati on techniques. Based on its work with university land use change researchers, however, ARB staff has concluded that the land use impacts of crop-based biofuels are significant, and mu st be included in LCFS fuel carbon

intensities. To exclude them would allow fu els with carbon intensitie s that are similar to gasoline and diesel fuel to function as lo w-carbon fuels under the LCFS. This would delay the development of truly low-carbon f uels, and jeopardize the achievement of a 10 percent reduction in fuel carbon intensity by 2020.ES-29 Other Indirect Effects

Staff has identified no other significant effect s that result in lar ge GHG emissions that would substantially affect the LCFS framew ork for reducing the carbon intensity of transportation fuels. In addition, stak eholders have not provided any quantitative analysis that demonstrates that these impacts are significant. Providers of crop-based biofuels continue to maintain, however, that significant market-mediated indirect effects other than land use change are likely to exist. Staff will continue to work with interested parties to identify and measure such effects.

Low Carbon Fuel Standard Initiatives Outside of California

Carbon-reduction measures similar to the LCFS are under considerat ion at the regional, national, and international levels. The most significant of these are summarized in Chapter II. Initiatives such as these are necessary to the achiev ement of meaningful, long-term fuel carbon reductions : without the wider adoption of fuel carbon standards, fuel producers are free to ship lower-carbon fuels to areas with such standards, while shipping higher-carbon fuels elsewhere. The end re sult of this fuel ‘shuffling’ process is little or no net change in fuel carbon conten t on a global scale. For this reason, ARB seeks to establish a fuel carbon regulator y framework that is durable enough to be exported to other jurisdictions. The su ccessful implementation of an effective framework in one jurisdiction should hasten the adoption of that fr amework elsewhere.

Meeting the State’s 2050 GHG-Reduction Goals

The LCFS is not designed to meet Gover nor Schwarzenegger’s long term goal of reducing GHG emissions by 80 percent by 2050 (E xecutive Order S-3-05). In order to meet that goal, the downward trend in the ca rbon intensity of fuels will need to continue following the achievement of t he 2020 target of a 10 percent r eduction. Therefore, staff plans to consider targets for the 2030 time frame in future re views of the LCFS.

Biofuel Production and Food Prices

The U.S. currently has the capacity to produ ce about 13 billion gallons of corn ethanol annually. Producing this volume of ethanol r equires more than 30 per cent of America’s available corn acreage. Removing that much cropland from food and feed crop production will reduce food suppl ies and increase prices. Because food prices are determined by multiple factors—including fuel prices—estimat ing the incremental impact of ethanol production is difficult. As crop-based biofuel production increases, the upward pressure exerted by t hat production on food prices is likely to also increase. Note, however, that the LCFS is designed to stimulate t he production of lower-carbon, non-crop-based fuels. The Feder al Renewable Fuels Standard, on the other hand, calls for the production of 15 billion gallons per y ear of corn ethanol beginning in 2015. Federal biofuel regulations ra ther than the LCFS, will, t herefore, exert the greatest pressure on food prices.ES-30 High Intensity Crude Oils

The methods used to extract, refine, and tran sport some crude oils may result in a relatively high carbon intensity rating fo r that feedstock. For example, many stakeholders have expressed concern about the increase in crude oil produced from

Canadian oil sands. Staff is developing a pathway for petroleum fuels refined from high carbon intensity crude oil, including crude o il from oil sands. The carbon intensity for that pathway will be higher than will the carbon intensit y of fuels refined from conventional crude oils. As discussed above, staff is proposing specific regulatory language to address high intensity crude oils that are currently not part of the current California crude oil mix in any significant am ount. More details on these provisions are provided in Chapter V.

Impacts on Transportation Fuel Supplies and Prices

Staff has concluded, based on the best av ailable data and fuel price projections presented in the AB 32 Scoping Plan, that the LCFS will not significantly impact either the price or supply of transportation fuels in California. Supplies of biofuel feedstocks appear to be sufficient to sustain the alter native fuel production volumes necessary for LCFS compliance. The staff acknowl edges that advances in the production of advanced biofuels are necessary to fully im plement both the Ca lifornia LCFS and the

federal renewable fuels standard. As such, staff will continue to monitor these issues as implementation of the LCFS occurs over time and will adjust t he LCFS standard as necessary to ensure that price and s upply disruptions do not occur.

Public Process for LCFS Regulation Development

To support regulatory development, ARB staff initially formed four workgroups to help develop specific provisions or address specific issues. These workgroups are

summarized below:

• Policy and Regulatory Workgroup – This workgroup was designed to be the overarching workgroup that would bring t ogether the various overarching issues and address policy considerations. In addition, this workgroup was designed to develop the specific regulatory language.

• Lifecycle Analysis Workgroup – The lifecycle analysis is the heart of the LCFS

and was one of the most c hallenging aspects. This workgroup was designed to be the primary method of vetting re sults and discussing approaches to the lifecycle analysis.

• Compliance and Enforcement Workgroup – Identifying how the compliance and

enforcement mechanisms would be estab lished was the focal point of this workgroup.

• Economic and Environmental Workgroup – The objective of this workgroup was to discuss the economic and environmental analysis.ES-31 In practice, the workgroups evolved into a series of public workshops with topics designed to cover the range of issues expected. All of the work group meetings were public. The announcements were posted on the ARB website and distributed through a listserve that included over 6, 000 recipients. All material s presented at the workshops were also posted on the ARB website. Almo st all of the meetings were telecast, available by teleconference, or both. In all, ARB staff held a total of 15 public workshops to support the development of the LCFS. The dates of the workshops and the materials presented at each works hop are available on the ARB website. 8

In cooperation with Argonne National Labor atories and the California Energy Commission, the ARB staff hosted two special public training sessions on the CA-GREET model used to develop carbon intens ities for the various fuel pathways. These sessions, held in the first quarter of 2008, were designed to provide stakeholders with a basic understanding of ho w the CA-GREET model worked. Training materials on these training sessions is also posted on the ARB website. Additional and very detailed hands-on training for about 10 stakeholders and agency personnel were also provided in the first quarter of 2008.

The ARB staff has also participated in ov er 200 individual meetings with various stakeholders, supported by numerous indi vidual telephone calls. All comments submitted through the entire proce ss are posted on the ARB website. 9 Over

200 individual comment letters have been subm itted either in response to the public workshops or to raise specific issues. In addition, the website contains a number of supporting documents that we re related to the devel opment of the LCFS.

Evaluation of Alternatives

Staff evaluated several alternatives to t he proposed Regulation. Two of the more significant alternatives are presented below.

1. Take no action at the St ate level and, instead, defer to the Federal Renewable
Fuels Standard. The federal RFS is an important complementary strategy to California’s RFS. However, the feder al RFS would deliver only about 30 to 40 percent of the GHG benef its of the proposed regulation, and does little to incentivize the development of fuels such as natural gas, electricity, or hydrogen.

2. Implement a gasoline standar d only. The LCFS includes separate standards for gasoline and the low carbon f uels that can replace it, and for diesel fuel and its replacements. The Western States Petroleum Association has advocated a gasoline standard only approach to allow fo r a simpler implementation of the regulation in the early years. AR B does not support this approach. A comprehensive approach from the beginning wil l allow for the development of a more robust credit market and will prov ide greater certainty on future

8 The dates and materials from the ARB workshops are presented at: http://www.arb.ca.gov/fuels/lcfs/lcfs_meetings.htm.

9 All comments are posted at the following ARB webs ite: http://www.arb.ca.gov /fuels/lcfs/lcfscomm.htm.ES-32 expectations. Fuel producers will need to consider overall approaches to providing low carbon transportation fuels. Given the fact that the compliance requirements are substantially less in the early years should provide fuel producers adequate time to develop appropriate compliance options. In addition,

failure to include diesel will result in a loss of approximatel y 20 percent of the

LCFS benefits.

Requirements of AB 32

AB 32, at Health and Safety Code section 385 60.5, requires that ARB adopt regulations by January 1, 2010, to implement discret e early action GHG emission reduction

measures. These measures must “achieve the maximum technologically feasible and cost-effective reductions in greenhouse gas em issions” from the sources identified for early action measures. AB 32 contains addi tional standards in Health and Safety Code section 38562 that apply to regulations that will be adopted for general emissions reductions consistent with ARB’s scoping plan.

In addition, AB 32 requires that the r eductions be real, permanent, quantifiable, verifiable, and enforceable. Furthermore, section 38565 requires the Board to “ensure that the greenhouse gas emission reduction rules, regulations, pr ograms, mechanisms, and incentives under its jurisdiction, where appl icable and to the extent feasible, direct public and private invest ment toward the most disadvan taged communities in California and provide an opportunity for small business, schools, affordable housing associations, and other community institutions to participat e in and benefit from statewide efforts to reduce greenhouse gas emissions.”

Staff believes that the LCFS was developed in accordance with the requirements of AB 32 and the Staff Report pres ents supporting details. The following provides a brief response to each of the requirements set forth in section 38562 below.

1. Design the regulations, including dist ribution of emissions allowances where appropriate, in a manner that is equitable, seeks to minimize costs and maximize the total benefits to California, an d encourages early action to reduce greenhouse gas emissions.

The design of the regulation is performanc e-based to ensure that all fuels that contribute to the goals of t he LCFS are treated equitably. The costs and benefits of the measures have been developed to ma ximize the benefits in consideration of the costs of compliance. The m easure has been designed with a compliance schedule that encourages early complianc e by allowing the development of credits that can be banked in the early years for future use in the LCFS.

2. Ensure that activities undertaken to comply with the regulations do not disproportionately impact low-income communities.ES-33 This regulation will provide an over-all GH G and criteria pollutant reduction within

the State. There is a potential for additional fuel producing facilities to be built in California and some of these facilities may be proposed for construction in

low-income communities. These facilitie s will be large enough to trigger local permitting and environmental review. To a ssist in that effort, ARB staff is committed to developing a guidance document to provide information on the best practices available to reduce emissions fr om these types of facilities, thereby encouraging minimal impact. This effort will commence immediately; ARB staff plans to have a draft available by the end of December 2009.

3. Ensure that entities that have voluntarily reduced their greenhouse gas emissions prior to the impl ementation of this section receive appropriate credit for early voluntary reductions.

This requirement is not applicab le to the proposed regulation.

4. Ensure that activities undertaken purs uant to the regulations complement, and do not interfere with, efforts to achieve and maintain federal and state ambient air quality standards and to reduce toxic air contaminant emissions.

The proposed regulation is not expected to adversely affect federal or State ambient air quality standards. This i ssue has been analyzed and the results are provided within the environmental chapter . Staff expects there to be some increase in local emissions if potentia l biofuel facilities are constructedin

California. These facilities are s ubject to local permitting and environmental review. See Chapter V II for a detailed discussi on of this issue.

5. Consider cost effectiveness of these regulations

The proposed regulation is expected to result in a net benefit for Californians by reducing fuel consumption and reducing em issions. See Section VIII (Economic Impacts) for a detailed discussion.

6. Consider overall societal benefits, incl uding reductions in other air pollutants, diversification of energy sources, and other benefits to the economy environment and public health.

The proposed regulation will pr ovide overall societal benefits by reducing GHG emissions from the transportation fuel pool, decrease our dependence on petroleum, and increase t he production of cleaner, low carbon fuel within the state. See Section VII (Environmental Impacts) for a detailed description.

7. Minimize the administrative burden of implementing and co mplying with these regulations.ES-34 The proposed regulation has recordkeeping and reporting requirements for fuel producers that is necessary to ensure compliance. These requirements have been limited to only information that is nec essary to demonstrate compliance. See Chapter V for a detailed descrip tion of the reporting requirements.

8. Minimize leakage.

Leakage occurs when an emission limit or regulatory requirement set by the State causes business activities to be disp laced outside of Calif ornia. If leakage were to occur, emissions, jobs and ot her economic benefits to California would be lost. Leakage is not expected as a result of the prop osed regulation. However, the ARB staff encourages the broad adoption of the LCFS in other jurisdictions as the effectiveness of t he regulation will be enhanced if there are fewer opportunities to use high-carbon fuels.

9. Consider the significance of the cont ribution of each source or category of sources to statewide emissions of greenhouse gases.

The transportation sector, which inclu des on-road vehicles, aviation, rail and ships, is the largest contributor to the total statewide GHG emissions inventory, producing approximately 38 perc ent of the state’s total GHGs. Emissions from the transportation sector must be signific antly reduced in order to achieve 1990 GHG levels by the year 2020.

The statewide GHG emission benefits of the pr oposed regulation ar e projected to
be about 16 MMTCO 2 e emissions in 2020. This accounts for approximately 10 percent of the reductions needed to meet the 2020 requirement. See Section VII (Environmental Impac ts) for a detailed discussion.ES-35 

### I. Introduction

This Staff Report presents the Air Resource s Board’s (ARB/Board) basis and rationale for the proposed regulation for the Low Carb on Fuel Standard (LCFS). The LCFS is designed to reduce emissions of greenhouse gases (GHG) by lowering the carbon content of transportation fuels used in Californ ia. This Introduction briefly discusses the relationship between greenhouse gases and clim ate change, outlines the public process used to develop the LCFS, and presents an overview of the Staff Report.

A. Greenhouse Gases and Climate Change

The impacts of climate change on California and its residents are occurring now. Of greater concern are the expected future im pacts to the state’ s environment, public health and economy, justifying the need to sharply cut greenhouse gas emissions.

In the Findings and Declarations for Global Warming Solutions Act of 2006 (AB 32), the Legislature found that:

“The potential adverse impacts of globa l warming include the exacerbation of air quality problems, a reduction in quality and supply of water to the state from the Sierra snowpack, a rise in sea levels resulting in the displacement of thousands of coastal businesses and residences, damage to the marine ecosystems and the natur al environment, and an increase in

the incidences of infectious diseas es asthma, and other health-related problems.”

The Legislature further found that global wa rming would cause detrimental effects to some of the state’s largest industries, incl uding agriculture, winemaking, tourism, skiing, commercial and recreational fishing, forest ry, and the adequacy of electrical power.

The impacts of global warming are being felt in California. The Sierra snowpack, an important source of water supply for the st ate, has shrunk 10 percent in the last 100 years. It is expected to continue to dec rease by as much as 25 percent by 2050. World-wide changes are causing sea levels to rise – about 8 inches of increase has been recorded at the Golden Gate Bridge ov er the past 100 years – threatening low

coastal areas with inundation an d serious damage from storms.

California is the fifteenth largest emitter of greenhouse gases on the planet, representing about two percent of the worldwide emissions. Carbon dioxide (CO 2 ) is the largest contributor to c limate change. However, AB 32 also references five other greenhouse gases: methane, nitrous oxide, su lfur hexafluoride, hydrofluorocarbons, and perfluorocarbons. Many other gas es contribute to climate change.

According to ARB’s greenhouse gas inventory, the transportation sector, largely the cars and trucks that move goods and people, is the largest contributor with 38 percentES-36 of the State’s total greenhouse gas emissi ons. If no action is taken to reduce greenhouse gas emissions the transportation sector is expected to increase by 25 percent by 2020, an increase of 46 million metric tons of CO 2 e (MMTCO 2 e).

There are three major c ontributing components to transportation greenhouse gas emissions: vehicle or engine efficiency, vehicl e use, and the carbon int ensity of fuels.

Vehicles : Passenger vehicles (cars and light tru cks) are responsible for 74 percent of the emissions from the transportation sector and are the primary fo cus of reductions strategies for the transportation sector. The Pavley (AB 1493) regulation, which the Board has already adopted, requires GHG em ission reductions from passenger cars and light trucks. This regul ation will provide about 27 MMTCO 2 e reductions in 2020 – an 18 percent fleet wide reduction. The U.S. Environmental Protection Agency (U.S. EPA) is currently reconsidering its previ ous denial of the waiver to implement this

measure.

Although the Pavley regulation results in significant GHG reductions, more is needed. Additional strategies are being pursued to ens ure that new Californi a vehicles achieve

the maximum feasible and cost-effective re ductions in GHG emissions, including strengthening GHG tailpipe emission standards from passenger cars and light trucks and improving overall vehicle efficiencies. AR B is also pursuing strategies to increase the efficiency of medium and heavy duty vehi cles through both engine specifications and devices that reduce aerodynamic drag and rolling resistance.

Vehicle Use: Another factor in GHG emissions fr om transportation is the use of the vehicle. In the case of passenger vehicl es, the metric for use is most commonly

referred to as vehicle miles traveled (VMT). Statewide VMT increased about 35 percent from 1990 to 2007, and with current trends is expected to increase another 20 percent by 2020, and more than double between now and 2040 . For California to meet its long

term GHG emission reducti on goal, this trend must be slowed.

The key to addressing the VMT challenge is providing people with more choices through diversified land use patterns, gr eater access to alternative forms of transportation including transit, biking and wa lking, and promoting development patterns where people can work and play without havi ng to drive great distances. Current regional planning efforts are beginning to move in a direction to create choices needed to reverse the projected VMT growth. A st rategy of coordinated State, regional, and local land use and transportation planning, po licies and finance, must be developed to encourage reductions in VMT, but can also r educe the carbon footprint of developments by reducing land consumption, energy use, water use and waste generation. These strategies are likely to provide modest reductions in GHG emissions by 2020 because of the time required to change land use pattern s. In the long term, these strategies are key elements in ensuring that California gets on a low-carbon traj ectory as the State gets to and beyond 2020.ES-37 Fuel : As indicated above, the fuel used in cars and trucks has a significant impact on emissions. Achieving emissions reductions by reducing the aggregate carbon intensity of fuels can be accomplished through flexib le compliance mechanisms. The LCFS applies to all transportation fuel providers, including refiners, bl enders, producers or importers of transportation f uels in California and applies to providers of gasoline, diesel, natural gas and propane, electric ity, hydrogen, ethanol, biodiesel and other mixed blends. Considering the vast quantitie s of gasoline and diesel sold per year in California, and that sales of petroleum-based fuels make up almost all transportation fuel sold in California, reducing the carbon intensity of these fuel s will provide important environmental and possibly economic opportunities.

B. Public Process for LCFS Regulation Development

To support regulatory development, ARB staff initially formed four workgroups to help develop specific provisions or address specific issues. These workgroups are

summarized below:

• Policy and Regulatory Workgroup – This workgroup was designed to be the overarching workgroup that would bring t ogether the various overarching issues and address policy considerations. In addi tion, this workgroup was designed to develop the specific regulatory language.

• Lifecycle Analysis Workgroup – The lifecycle analysis is the heart of the LCFS

and was one of the most c hallenging aspects. This workgroup was designed to be the primary method of vetting re sults and discussing approaches to the lifecycle analysis.

• Compliance and Enforcement Workgroup – Identifying how the compliance and

enforcement mechanisms would be estab lished was the focal point of this workgroup.

• Economic and Environmental Workgroup – The objective of this workgroup was to discuss the economic and environmental analysis.

In practice, the workgroups evolved into a series of public workshops with topics designed to cover the range of issues expect ed. All of the wo rkgroup meetings were public. The announcements were posted on the ARB website and distributed through a listserve that included over 6, 200 recipients. The materials presented at the workshops were also posted on the ARB website. Almo st all of the meetings were telecast, available by teleconference, or both. In all, ARB staff held a total of 15 public workshops to support the development of the LCFS. The dates of the workshops and the materials presented at each works hop are available on the ARB website. 10

In cooperation with Argonne National Labor atories and the California Energy Commission, the ARB staff hosted two special public training sessions on the CA-GREET model used to develop carbon intens ities for the various fuel pathways. These sessions, held in the first quarter of 2008, were designed to provide stakeholders with a basic understanding of ho w the CA-GREET model worked. Training materials on

10 The dates and materials from the ARB workshops are present ed at: http://www.arb.ca.gov/fuels/lcfs/lcfs_meetings.htm.ES-38 these training sessions is also posted on the ARB website. Additional and very detailed hands-on training for about 10 stakeholders and agency personnel were also provided in the first quarter of 2008.

The ARB staff has also participated in ov er 200 individual meetings with various stakeholders, supported by numerous indi vidual telephone calls. The comments submitted through the entire proce ss are posted on the ARB website. 11 Over

200 individual comment letters have been subm itted either in response to the public workshops or to raise specific issues. In addition, the website contains a number of supporting documents that we re related to the devel opment of the LCFS.

C. Report Organization

The remaining Chapters of the Staff Report place the development of the regulation in the context of enabling policy and legislative directives, an assessment of the current low-carbon fuels and producti on technologies, methodologi es for determining fuel carbon intensity, likely compliance trajectori es that fuel producers might follow, and several other related issues. The following bul lets provide thumbnail descriptions of the contents of each Chapter of the report.

• Chapter II reviews the c limate-change-related program s the ARB is currently developing, other fuel regulations t he Board administers, and climate change programs under development outside of the State.

• Chapter III describes the low-carbon transpor tation fuels that are likely play a role in the LCFS. The descriptions focus on production processes, and on an assessment of the ability of production te chnologies to yield significant volumes of low-carbon fuels. For fuels not ye t in production, assessments are based on our current knowledge of potent ial production technologies.

• Chapter IV provides details on the met hods ARB uses to determine fuel carbon intensities. The direct, well-to-wheels ca rbon intensities of all fuels currently covered by the LCFS have been determined us ing a California-specific version of the Greenhouse Gases, Regulated Emission s, and Energy Use in Transportation (CA-GREET) model. An additi onal carbon intensity incr ement for fuels produced from crops is also calc ulated, using the Global Tr ade Analysis Project (GTAP) model. This addition increment captures t he indirect land us change impacts of biofuel crops. Carbon intensity is meas ured in units of grams of carbon dioxide equivalent per megajoule (gCO 2 e/MJ).

• Chapter V provides a detailed straightfo rward description of provisions of the LCFS Regulation. This discussion em phasizes what the Regulation requires, and who is obligated to meet each requirement. The actual text of the regulation appears in Appendix A.

11 All comments are posted at the following ARB websit e: http://www.arb.ca.gov/fuels/lcfs/lcfscomm.htm.ES-39 • Chapter VI presents several potential LCFS compliance scenarios, each showing the specific, year-by-year mix of fuels needed to achieve compliance with the Regulation. One set of scenarios demonstr ates four alternative paths toward compliance with the gasoline standard, while another three scenarios demonstrates alternative paths to dies el compliance. The Chapter ends by discussing a series of supplemental scenar ios showing the effects of special circumstances and potential modifications to the LCFS: ignoring indirect land use change carbon intensities, allowing light-duty diesel vehicles to earn credits under the gasoline standard, re lying entirely (or almost entirely) on ethanol, and

others.

• Chapter VII provides an analysis of the env ironmental impacts of the LCFS. This analysis is designed to comply with t he California Environmental Quality Act (CEQA).

• Chapter VIII presents the economic analysis . The analysis presents the costs of compliance based on the compliance scenar ios identified in Chapter VI.

• Chapter IX describes the enforcement mechanisms that ARB will employ to achieve compliance on the part of regulated parties.

• During the course of developing the LC FS, ARB staff considered a wide range of policy mechanisms for achieving the mandat ed fuel carbon intensity reduction. Chapter X discusses alternative approache s and addresses staff’s rationale for rejecting the alternative approaches in fa vor of the approach that was eventually adopted.

Finally, there are a number of appendi ces supporting the Staff Report. These appendices provide additional details supporting the various Chapters.ES-40 This Page Left Intentionally BlankII-1 

### II. Government Programs Affecting Transportation Fuels

This Chapter provides a summary of the va rious programs that affect transportation fuels and specifically the development of Ca lifornia’s LCFS. T hese programs broadly include legislative actions, regulations, policie s, or initiatives that have effects on the development of the LCFS. These include programs initiated in California, on the national level, and the in ternational level.

This Chapter is organized as follows:

• California programs to reduce GHG emissions;

• California fuels regulations;

• California incentive programs for transportation fuels;

• Federal renewable fuels program; and

• Other transportation fuel and LCFS initiatives.

A. California Programs to Reduce Tr ansportation-Related GHG Emissions

There are a number of program s that are designed to reduce GHG emissions that affect the development of the LCFS. Early pr ograms, such as the GHG standards for passenger cars and the State’ s Alternative Fuels Plan, established baselines and important background for the LC FS. Other programs include A ssembly Bill (AB) 32, the Global Warming Solutions Act of 2006 and subseque nt actions taken to implement this bill, and various executive orders issued that established the low carbon fuel standard and set statewide goals for the production of bi ofuels in California. These programs are

discussed in this section.

1. Early Climate Change Work

a. AB 1493 – Pavley GHG Emi ssion Standards for Cars

In 2002, Assemblywoman Fran Pavley authored Assembly Bill (AB) 1493. This bill authorized the Board to adopt r egulations to reduce GHG from passenger vehicles. In September 2004, the Board adopted the implementing r egulation, designed to be effective beginning 2009. This regulation is often referr ed to as the “Pavley” or “AB 1493” regulation. The regulation would reduce GHG emissions from California passenger vehicles by about 22 percent by 2012 and about 30 percent by 2016. The regulations were stalled by automaker laws uits and the U.S. EPA’s refusal, under the previous administration, to gr ant California an implementa tion waiver. President Obama recently ordered the U.S. EPA to reconsider its denial of California’s request for a waiver. Staff now assumes the Pavley regulat ion will be implemented. Therefore, the

emission benefits of those r egulatory changes are included in the baseline for purposes of the LCFS analyses. The Pavley regulat ion and the LCFS are two critical components

of California’s work to reduce GH G from transportation sources.II-2 b. AB 1007 – State Al ternative Fuels Plan

Assembly Bill 1007 (Pavley, Statutes of 2005) directed the California Energy Commission (CEC) and the ARB to develop a St ate Alternative Fuels Plan (Plan) to

increase the use of alternative fuels. The Plan, jointly approved in 2007, recommended a strategy that combines private capital in vestment, financial incentives, and technology advancement approaches.(1) The Plan also highlighted the need to:

• Promote alternative fuel blends with gas oline and diesel in the near and mid term and stimulate innovation through the development of a low-carbon fuels standard;

• Maximize alternative fuels in early adopt er market niches, such as heavy-duty vehicles, fleets, off-road vehicles, and ports;

• Maximize use of alternative fuels in internal combustion engines and develop new transportation technologies, such as el ectric drive and hydrogen fuel cells, in the mid-to-long term;

• Maximize the use of mass transit, encour age smart growth and land use planning to help reduce vehicle miles travel ed and vehicle hours traveled; andI

• Improve vehicle efficiency to r educe the total energy needed to power transportation in California.

The Plan highlighted a number of strategies that coul d be used to promote the development and use of alternative fuels in California and provided a sound basis upon which to develop the LCFS. In addition, the Plan was based on full fuel lifecycle analyses. This early work on lifecycle analys is was a critical starting point for the development of the lifecycl e analyses done for the LCFS.

2. Executive Order S-01-07 – Low Carbon Fuel Standard

In January 2007, Governor Schwarzenegger iss ued Executive Order S-01-07 calling for a low carbon fuel standard for transportation fuels to be established for California.(2) This Executive Order was thus the genesis of the proposed regulation proposed in this Staff Report. The Executive Order calls for a reduction of at least 10 percent in the average carbon intensity of California's transportation fuels by 2020.

The Executive Order specifies that the LC FS shall apply to a ll refiners, blenders, producers, or importers (provider s) of transportation fuels in California. It also states

that the LCFS shall be measured on a full fuels cycle basis, and may be met through market-based methods by which providers exceeding the performance required by an LCFS shall receive credits that may be app lied to future obligations or traded to providers not meeting the LCFS.

The Executive Order instructs the Califor nia Environmental Protection Agency to coordinate activities between the University of California, t he California Energy Commission (Energy Commission) and other State agencies to develop and propose aII-3 draft compliance schedule to meet the 2020 ta rget. Furthermore, it directed ARB to consider initiating a regulat ory proceeding to establish and implement the LCFS.

In support of the LCFS and as directed in the Executive Order, University of California (UC) Professors Daniel S perling and the late Alexander Farrell directed a team of UC colleagues that developed two significant r eports that provided an initial framework for the LCFS.(3, 4) These two reports esta blished the technical f easibility of an LCFS, identified many of the signifi cant technical and policy issues, and provided a number of specific recommendations. These comprehens ive reports were the backbone of ARB staff’s initial efforts to develop the LCFS. While not all of the specific recommendations have been incorporated in the LCFS, all of the recommendations have spurred a vigorous debate on the issues and facilitat ed the development of ARB staff’s proposed regulation.

3. Other Executive Orders and Legislation

a. Executive Order S-06-06 – St ate Bioenergy Action Plan

Executive Order S-06-06 direct ed various State agencies to wo rk together as part of the Bioenergy Interagency Working Group to prom ote the development and use of biomass resources in California.(5) Among other provisions, the Exec utive Order lists targets to increase the production and use of bioener gy, including the production and use of

ethanol and biodiesel fuels m ade from renewable resources. Key targets for biofuels and bioenergy are presented below:

• The State produces a minimum of 20 perc ent of its biofuels, including ethanol

and bio-diesel fuels made fr om renewable sources, within California by 2010, 40 percent by 2020, and 75 percent within California by 2050; and

• The State meets a 20 percent target within the established State goals for renewable power gener ation for 2010; and 2020.

If these goals are met, they w ould ensure that a significant portion of the biofuels used in the LCFS are produced in California. The 20 percent renewab le power generation requirement would provide lower carbon intens ity electricity, including electricity used for transportation under the LCFS.

Currently, there is production capacity for ethanol and biodiesel in the State totaling about 485 million gallons. About 87 percent of this total is ethanol produced from corn, with the balance being biodiesel produced from yellow grease and waste oils. There is over 300 million gallons of ethanol capacity that is either constructed, but idle, or is permitted but not constructed. The total c onsumption of ethanol an d biodiesel use in
the State in 2010 is estimated to be about 1. 45 billion gallons. Therefore, the 2010 target should be met, but additional capac ity will be needed to meet the 2020 target.II-4 The California Energy Commission estima tes that approximatel y 12 percent of California’s retail electricity is currently met with renewable energy resources. Renewable energy includes, but is not lim ited to, wind, solar, geothermal, small hydroelectric, biomass, anaerobic digestion, and landfill gas. Electricity from renewables is required to be 20 percent of total electricit y generated by 2010 per
California’s current Renewab les Portfolio Standard (RPS).

Increasing the use of renewable energy s ources will decrease California’s reliance on fossil fuels, thereby reducing GHG emissi ons from the electricity sector. Per Governor Schwarzenegger’s order for a 33 percent RPS, it is anticipated that California will have 33 percent of its electricity pr ovided by renewable resources by 2020.

b. SB 1505 – Environmental Standards for Hydrogen

Senate Bill (SB) 1505 ( Lowenthal, 2006) calle d for the Board to adopt regulations regarding environmental standards for hydro gen production. The bill requires that emissions associated with hydr ogen used as a vehicle fuel must be lower than baseline gasoline values. Emissions val ues of oxides of nitrogen (NO
x ) plus reactive organic compounds (ROG) and toxic air contam inants (TAC) associated with hydrogen production are to be compared on a well-to-tank basis to the “average motor gasoline.” Emissions of greenhouse gases are to be co mpared on a well-to-wheels basis to the “average new gasoline vehicle.” The bill al so requires that one third of the hydrogen must be made from eligible renewable resources.

ARB staff is currently developing the regul ation setting the environmental and energy standards for hydrogen production. Information on this rulemaking can be found at the following website: http://www.arb.ca.gov/msp rog/hydprod/hydprod.htm . The proposed requirements will be in effect for State-funded hydrogen stations once the regulation is adopted, and for hydrogen stations in Califo rnia upon reaching a statewide annual throughput of 3,500 metric tons . As part of SB 1505, the AR B would require providers of hydrogen fuel for transportation in the State to report annual amount of hydrogen dispensed.

SB 1505 is important to the LC FS because it will ensure that hydrogen fuel produced at state-funded stations (as most are expecte d to be) has lower carbon intensity than gasoline and is one-third renewable.

4. California Global Warming Solutions Act of 2006 – AB 32

In September 27, 2006, Governor Schwar zenegger signed AB 32, the Global Warming Solutions Act of 2006 (Nuñez, Chapter 488, St atutes of 2006). This landmark bill

establishes a first-in-the-world econom y-wide program of r egulatory and market mechanisms to achieve real, quantifiable, cost effective reductions of greenhouse gases. ARB is the lead agency for implementation.II-5 AB 32 requires the ARB to establish a st atewide GHG emissions cap for 2020, adopt GHG reporting rules, adopt a plan to reduc e GHG emissions (the Scoping Plan), and to adopt a list of discrete early action m easures to reduce GHG. AB 32 formally established California’s climate change progra m, of which the LCFS is a part.

The following subsections highlight the ke y AB 32 actions relevant to the LCFS.

a. Climate Change Early Actions

Under AB 32, ARB is required to identify and adopt regulations for discrete early actions

that could be enforceable on or before Januar y 1, 2010. In 2007, the Board identified nine discrete early action measures. In addi tion to this LCFS, the measures included regulations high global warming gases in various uses, port operations, heavy duty truck efficiency, tire inflation, and landfills . Table II-1 lists the discrete early action

measures and their status.

Table II-1
Status of Discrete Early Action Measures

Measure Status Board Hearing

Date Emission

Reductions

in 2020
MMTCO 2 e Green Ports – Cold Ironing Ships at Ports Adopted December 2007 0.2 Reduction of High Global Warming

Potential Gases in Consumer Products Adopted June 2008 0.2

SmartWay Truck Efficiency Adopted December 2009 0.9 Reduction of High Global Warming Gases Used in Semiconductor Operations Adopted February 2009 0.2

Sulfur Hexafluoride from the NonSemiconductor and Non-Utility Applications Adopted February 2009 0.1

Vehicles Operating with Under-Inflated Tire

Pressure Scheduled March 2009 0.6

Low Carbon Fuel Standard Scheduled April 2009 15.9 * Landfill Methane Control Measure Scheduled May 2009 1.0 Management of High Global Warming Potential Refrigerants Scheduled May 2009 11

* Estimated emission reductions based on t he “tank-to-wheel” analysis . See Chapter VII.

As the table shows, all of the measur es are on schedule to be adopted prior to the January 1, 2010 implementation dat e. From a GHG emission reduction perspective, the LCFS is a major GHG emission reduction meas ure, accounting for over 50 percent of

the total emission reductions from the discrete early action measures.

b. Climate Change Scoping Plan

In December 2008, the Board approved t he Climate Change Scoping Plan.(6) The Scoping Plan is the State’s roadmap to reach the greenhouse gas reduction goals in AB 32. Reducing greenhouse gas emissions levels to 1990 levels means cuttingII-6 approximately 30 percent from business-as-us ual emissions levels projected for 2020, or about 15 percent from today’s levels. The Scoping Plan ident ified a number of recommended actions necessary to achieve the goal s of AB 32. In addit ion to a specific action to develop the LCFS, the Scoping Plan i dentified other actions that would impact the LCFS. These are highlighted below:

• Light-Duty Vehicle Greenhouse Gas Standards : As discussed above, the Pavley regulations are an important measure to re duce GHG emissions. In addition to the existing measure, the Scoping Plan identifies a planned second phase of the program that would align the zero-e mission vehicle program, alternative and renewable fuel and vehicle technology program with long-term climate change goals to achieve additional GHG emissi on reductions. These strategies are referred to as Pavley II. Collectively, Pavley I and II are expected to achieve
31.7 MMCO 2 e in 2020.

• Regional Transportation-Related GHG Targets : In September 2008, Governor Schwarzenegger signed Senat e Bill 375 (Steinberg, 2008). SB 375 establishes regional targets for reduc ing passenger vehicle GHG emissions. ARB is working with the metropolitan planning organizations in the State to align their regional transportation, housi ng, and land-use plans and prepare a Sustainable Communities Strategy (SCS) to reduce the amount of vehicle miles traveled in respective regions and demons trate a region's ability to attain its greenhouse gas reduction targets. AR B must propose draft targets by June 10, 2010, for the purpose of reduc ing greenhouse gas emissions from passenger vehicles, and adopt final targets by September 30, 2010. Overall, the Scoping Plan estimated that t he measure could achieve 5 MMTCO 2 e in 2020.

• Light-Duty Vehicle Efficiency Measures : The Scoping Plan identifies several measures to reduce light-duty vehicle GH G emissions. These measures include properly inflated tires, cons ideration of minimum fuel-e fficient tire standards, and reducing engine load via lower fricti on oil and reducing the need for air conditioner use. Collectively, thes e measures are targeted for 4.5 MMTCO 2 e in

2020.

• Medium/Heavy Duty Vehicle Efficiency Measures : The Scoping Plan also identifies several measures to improve the efficiency of medium- and heavy-duty

vehicles. These measures include retrof its to improve the fuel efficiency of heavy-duty trucks by reducing aerody namic drag and rolling resistance and hybridization of medium- and heavy-duty tr ucks. These measures are targeted
for 1.4 MMTCO 2 e in 2020.

These measures are all signif icant to the LCFS because they affect estimates of the

amount of fuel used in 2020. To ensure that the LCFS does not double count emission reductions, these measures have all been ac counted for in the LCFS. Additional information on these adjustments is presented in subsequent chapters.II-7 In addition to these measures , the recommended action in t he Scoping Plan to develop a California Cap and Trade Program is rele vant to the LCFS. The cap and trade program provides a firm cap on 85 percent of the State’s greenhouse gas emissions. Sectors under the cap must r educe their emissions. Sectors under the cap starting with the first compliance period include electric ity generation, oil produ ction operations, and petroleum refineries. Transportation fuel is not presently under the cap, but will be brought under the cap beginning in 2015. A dditional discussion on the relationship between the LCFS and the cap and trade pr ogram is presented in Chapter V.

B. California Fuels Programs

The following section provides a brief over view of California’s reformulated gasoline regulations, a description of the California Predictive Model, and the impacts of adding ethanol to gasoline. The LCFS is a comple mentary measure to these regulations.

1. Phase 2 California Reformulated Gasoline

The California Clean Air Act requires the AR B to adopt regulations that produce the

most cost-effective combinations of cont rol measures on motor vehicles and motor vehicle fuels. This directive led to many actions, including the Bo ard approval of the

Phase 2 California Reformulated Gaso line (CaRFG2) regulations in 1992. 12 The CaRFG2 regulations set stringent standards for California gasoli ne that produced costeffective emission reductions in new and in-use gasoline-powered vehicles. The regulations set specifications for the following eight fuel properties:

• Sulfur;

• Aromatic hydrocarbon content;

• Oxygen content;

• Benzene content;

• 50 Percent distillation temperature;

• 90 percent distilla tion temperature;

• Olefin content; and

• Reid vapor pressure.

With the exception of oxygen, the regulations set three limits for each property: a ”cap” limit that applies to all gas oline anywhere in the gasolin e distribution and marketing system and does not vary; and “flat” and “averaging” limits that apply to gasoline when it is released by refiners, importers, and blenders (collectively, “producers”). 13 For oxygen, the regulations est ablish a range of flat limits and caps that may vary depending on the location and the s pecific fuel formulation.

12 For additional information on the Phase 2 reformulat ed gasoline regulations, see the following website: http://www.arb.ca.gov/fuels/ gasoline/carfg2/carfg2.htm

13 For fuels regulations, we generally use produc ers to represent those that are affected by the regulations. The specific regulations, however, have requirements that sometimes differ depending on whether the affected entity is a refiner, importer, or blender. The reader is referred to the regulations for specific applicable requirements.II-8 Gasoline producers could comply with the limits in one of three ways. First, for a given property, each producer may choose to meet eit her the flat limit or the averaging limit. Second, a producer may use the Predictive Model to identify ot her sets of property limits (flat, averaging, or mixed) that can be appli ed to that producer’s gasoline. Third, a producer may validate an alternative set of property limits through emission testing per a prescribed protocol. Whet her validated by the Predictiv e Model or by testing, no alternative limit may exceed t he cap limit for the property.

To comply with the oxygen content requi rement, producers generally chose to use methyl-tertiary-butyl-ether (MTBE). Soon af ter CaRFG2 implementation, the presence of MTBE in groundwater began to be reported. An investigation and public hearings were conducted resulting in the i ssuance of Executive Order D-5-99 on March 25, 1999.(7) The Executive Order dire cted the phase-out of MTBE in California’s gasoline. In addition, the Legislature passe d Senate Bill 989. Among other provisions,

the bill directed the ARB to ensure that regulations adopt ed pursuant to the Executive Order maintain or improve upon emissions a nd air quality benefits achieved by CaRFG2 as of January 1, 1999 (Health and Safety Code section 43013.1).



### 2. Phase 3 California Reformulated Gasoline

In response to the Governor’s and Legislat ure’s directive, the Board approved the Phase 3 California Reformulated Gasoline (CaR FG3) regulations on December 9, 1999 and amended them on July 25, 2002. 14 The CaRFG3 regulations prohibited California gasoline produced with MTBE starting Dece mber 31, 2003, established revised CaRFG3 standards, established a CaRFG3 Pr edictive Model, and made various other changes. The CaRFG3 regulations also placed a conditional ban, starting December 31, 2003, on the use of any oxyge nate other than ethanol, as a replacement for MTBE in California gasoline.

On June 14, 2007, the Board approved amendm ents to the CARFG3 regulations as

summarized below:

• Amend the California Predictive Model to ensure that permeation emissions

associated with ethanol use are mitigated and to incorporate new data;

• Add an option to use an alternative emissi ons reduction plan ( AERP) for a limited time period to help mitigate permeation emissions;

• Decrease the sulfur cap limit from 30 parts per million by weight (ppmw) to 20 ppmw to improve enforceability and fac ilitate new motor vehicle emissions control technology;

• Allow emissions averaging for low leve l sulfur blends to provide additional flexibility for producers;

14 For additional information on the Phase 3 reformulat ed gasoline regulations, see the following website: http://www.arb.ca.gov/fuels/ga soline/carfg3/carfg3.htm.II-9 • Apply the 7.00 psi RVP limit to oxygenat ed gasoline to reflect that virtually all gasoline will be oxygenated and comminglin g emissions are not a problem for these fuels; and retain the 6.90 RVP limit for non-oxygenated gasoline to ensure that no increase in hydrocarbon emissi ons from commingling with oxygenated gasoline will occur;

• Allow flexibility in setting oxygen content in the Predictive Model to account for variability in test methods;

• Increase the maximum allowable am ount of denaturant in ethanol to be

consistent with new f ederal requirements;

• Update the test method for oxygenate content of gasoline;

• Require producers to use the re vised Predictive Model starting December 31, 2009, with the AERP as a mitigation option; and

• Require the production of gasoline that is compliant with the revised Predictive Model beginning December 31, 2011.

The current specifications for CaRFG3 are presented in the Table II-2.

Table II-2
Current California Reformulated Gasoline Standards

Property Flat Limits Averaging

Limits Cap Limits

Reid Vapor Pressure 1 (psi) 7.00 or 6.90 2 NA 6.40 -7.20

60 3

30 3 Sulfur Content (parts per million by weight) 20 15

20 3

Benzene Content (% by volume) 0.80 0.70 1.10

Aromatics Content (% by volume) 25.0 22.0 35.0

Olefins Content (% by volume) 6.0 4.0 10.0

T50 (degrees Fahrenheit) 213 203 220

T90 (degrees Fahrenheit) 305 295 330

1.8 4 -3.5 5 Oxygen Content (% by weight) 1.8 – 2.2 Not Applicable 0 4 - 3.5 5

Methyl tertiary-butyl ether (MTBE) and oxygenates other than

ethanol Prohibited as provided in

§ 2262.6 Not Applicable Prohibited as provided in

§ 2262.6

1 The Reid vapor pressure (RVP) standards apply only during the warmer weather months identified in

section 2262.4.

2 The 6.90 pounds per square inch (psi) flat limit applies when a producer or importer is using the CaRFG Phase 3 Predictive to certify a final blend not containing ethanol. Otherwise, the 7.0 psi limit applies.

3 The CaRFG Phase 3 sulfur content cap limits of 60, 30, and 20 parts per million are phased in starting December 31, 2003, December 31, 2005, and December 31, 2011, respectively, in accordance with section 2261(b)(1)(A).

4 The 1.8 percent by weight minimum oxygen content cap onl y applies during specified winter months in the areas identified in section 2262.5(a).

5 If the gasoline contains more than 3.5 percent by weig ht oxygen from ethanol but no more than 10.0 volume percent ethanol, the maximum oxygen cont ent cap is 3.7 percent by weight.II-10 3. California Reformulated Diesel

In November 1988, the Board approved regulations limiting the allowable sulfur content of motor vehicle diesel fuel to 500 parts per million by weight ( ppmw) statewide and the aromatic hydrocarbon content to 10 percent by volume with a 20 percent limit for small

refiners. 15 These diesel fuel regulations, which became effective in 1993, are a necessary part of the State’s strategy to reduce air pollution through the use of clean fuels and lower-emitting motor vehicles and o ff-road equipment. T he regulation limiting the aromatic hydrocarbon content of diesel fuel has included provisions that enable diesel fuel producers and importers to comply through alternative diesel formulations that may cost less. The alternative specif ications must result in the same emission benefits as the 10 percent arom atic standard (or in the case of small refiners, the 20 percent standard).

On July 24 2003, the Board approved amendm ents to the California diesel fuel regulations. The amendments reduced the sulfur content limit from 500 ppmw to 15 ppmw for diesel fuel sold for use in Cali fornia in on-road and off-road motor vehicles starting in mid-2006. The lowe r sulfur limit aligned the Ca lifornia requirement with the on-road diesel sulfur limit adopted by the U. S. EPA. However, t he California sulfur requirement applies to on and off-road motor vehicle diesel fuel. The new sulfur

standard enabled the use of t he emissions control technology required to ensure compliance with the new emissions standar ds adopted by the U.S. EPA for 2007 and subsequent model-year heavy-duty engines and vehicles.

In 2005, the Board also adopted a measure t hat applied the diesel fuel standards to

harborcraft and intrastate locomotives.

4. California Standards for Alternative Fuels

“Alternative fuel” generally means any motor vehicle transportation fuel that is not gasoline or diesel fuel. This includes, but is not limited to, those fuels that are commonly or commercially known or sold as one of the following: M-100 fuel methanol, M-85 fuel methanol, E-100 fuel ethanol, E- 85 fuel ethanol, biodiesel, compressed natural gas (CNG), liquefied natural gas (L NG), liquefied petroleum gas (LPG), or hydrogen. For purposes of the LCFS regulation, alternative fuels also include electricity for motor vehicle transportation use, but there are currently no quality specifications in the State for electricity used as a motor vehicle fuel.

With exceptions as discussed below, the qualit y of alternative motor vehicle fuels is subject to composition specif ications under title 13, Calif ornia Code of Regulations (CCR), sections 2291.1 through 2292.7, as follows:

• M-100 fuel methanol (13 CCR §2292.1);

15 For additional information on California reform ulated diesel, see the following website: http://www.arb.ca.gov/fuels/diesel/diesel.htm.II-11 • M-85 fuel methanol (13 CCR §2292.2);

• E-100 fuel ethanol (13 CCR §2292.3);

• E-85 fuel ethanol (13 CCR §2292.4);

• Compressed natural gas (13 CCR §2292.5);

• Liquefied petroleum gas (13 CCR §2292.6); and

• Biodiesel specifications (13 CCR§2292.7 – Under development).

For E-85, the Division of Measurement Standards (DMS) adopted a specification for E-85 in 4 CCR §4145 (effective May 22, 2004) . More recently, ASTM updated its specification for E-85 in D5798-07, “S tandard Specification for Fuel Ethanol (Ed75-Ed85) for Automotive Spark-Ignition Engines.” 16 Because the newer ASTM specification better reflects current technologies, ARB plans to update its E-85 specifications in a rule making tentatively scheduled for Board consideration in late

2009.

Liquefied natural gas is converted to CNG in LNG vehicles prior to being supplied to the engine for combustion. Therefor e, the fuel used in LNG vehi cles is subject to the CNG motor vehicle fuel specifications cited above.

In 2005, Senate Bill 76 (SB 76, Stats. 2005, ch. 91) placed th e responsibility to adopt specifications for hydrogen fuel on DMS. This law required DMS to have the standards in place on or before January 1, 2008. The DMS is required to adopt by reference the latest standards for hydrogen established by an American National Standards Institute (ANSI) accredited, standards -development organization. If such a standard has not been developed, DMS is required to develop interim standards.

Pursuant to SB 76, DMS determined that no ANSI-accredited, standards-development organization had established standards for hydr ogen fuel used in fuel cell or internal

combustion motor vehicles before 2008. Therefore, DMS promulgated interim standards for hydrogen fuel to be used in fuel cell or internal combustion vehicles. The
DMS standards are set forth in 4 CCR §§4180 and 4181 and became effective September 11, 2008.

Biodiesel is considered to be an alternat ive fuel, but there are currently no ARB standards for biodiesel. Until recently, biodiesel blendstock (B-100) and biodiesel blends were subject to the specificati ons promulgated by DMS and set forth in 4 CCR §4147 (effective August 8, 2004). Howeve r, DMS is required by law to adopt by

reference the latest standards established by a recognized consensus organization or standards writing organization, such as ASTM or the Society of Automotive Engineers (SAE). 17

In June 2008, ASTM adopted three biodiesel spec ifications. First, ASTM updated its specification for B-100 blendstock, D6751-08, “Standard Specification for Biodiesel Fuel

16 ASTM International, formerly known as the American Society for Testing and Materials (ASTM).

17 Business And Professions Code sections 13450-13451.II-12 Blend Stock (B100) for Middle Distillate F uels.” Second, ASTM approved revisions to D975-08, “Standard Specification for Diesel F uel Oils,” which would subject biodiesel blends from B-1 to B-5 to the same specificat ion as regular diesel fuel. Finally, ASTM adopted new specifications for B-6 to B-20 in D7467-08, “Standard Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to B20).”

As noted, the 2008 ASTM specifications for biodiesel and biodiesel blends cited above are the standards that currently apply to such fuels sold in the St ate. However, staff plans to consider a rulemaking for adopting new biodiesel specifications for motor vehicle fuel, which is currently calendared for la te 2009. In support of that effort, staff is currently conducting a multimedi a evaluation of biodiesel and renewable diesel pursuant to H&S §43830.8. Also, if necessary, an emi ssions test program is being conducted to evaluate potential alternative specifications that would re sult in biodiesel having the

same emission characteristics as diesel complying with 13 CCR sections 2281-2285

and 2299.

C. California Incentive Program s for Transportation Fuels

Two recent California incentive programs af fect alternative fuels. These are the Alternative Fuel Incentive Program ( AB 1811) and the California Alternative and Renewable Fuel, Vehicle Technology, Cl ean Air, and Carbon Reduction Act of 2007 (AB 118). These programs are briefly described below.

1. AB 1811 – Alternative Fuel Incentive Program

Assembly Bill 1811 provided $25 million in funding to ARB to incentivize biofuels and high efficiency, low emitting vehicle technology and thereby reduce air pollution and greenhouse gas emissions. 18 These funds were awarded by June 30, 2007, consistent with proposed expenditure ca tegories developed jointly by ARB and the Energy Commission. In general, the original f unding and categories are presented below:

• $5.4 million for infrastructure for dispens ing E85 and potentially other alternative fuels;

• $6 million for the startup of sm all biofuels production facilities;

• $5 million for hybrid electric vehicle demonstration projects;

• $2 million for transit bus projects;

• $1.8 million for incentives for partial-z ero electric vehicles (PZEV) and zero electric vehicles (ZEV);

• $3.2 million for alternative fuel vehicle research; and

• $1.6 million to fund consumer education and outreach.

This program is currently in progress and is expected to expend the funds by the deadline of June 30, 2009. 19

18 SEC. 14. Item 3900-001-0044 of Section 2.00 of the Budget Act of 2006

19 Additional information on the projects funded unde r the AB 1811 program can be found at the following website: http://www.arb.ca.gov/fuels/ altfuels/incentives/incentives.htm.II-13 2. AB 118 – California Alternativ e and Renewable Fuel, Vehicle Technology, Clean Air, and Carbon Reduction Act of 2007

Assembly Bill (AB) 118 (Núñez, Chapter 750, Statutes of 2007) provides grant funding for the alternative fueling infrastructu re, fuels, and vehicl es needed to meet the requirements of AB 32. The AB 118 funding wil l help ensure the successful reduction of global warming emissions from California’s tr ansportation sector. Three different State agencies have responsibilities from AB 118 implementation.

a. AB 118 – California Energy Commission

Assembly Bill 118 authorizes the Energy Commission to spend up to $120 million per year for over seven years to “develop and depl oy innovative technologies that transform California’s fuel and vehicle types to help attain the state’s c limate change policies.” The statute, amended by AB 109 (Núñez, 2008), di rects the CEC to create an advisory committee to help develop and adopt an Inve stment Plan for the program. The

Investment Plan is intended to determine program priorities and opportunities, and describe how funding will comple ment existing public and privat e investments, including existing state and federal programs. T he ARB is represented on the advisory

committee.

The Energy Commission staff released a draft Investment Plan (Plan) in December 2008 that was presented at an advisory committee meeting on January 8, 2009. The draft Plan includes re commendations for distributing $176 million to six funding categories during the first two years of the pr ogram. The draft recommended funding is as follows:

• $62 million for low carbon fuels (e.g ., natural gas, propane, biodiesel and renewable diesel);

• $22 million for ultra-low carbon f uels (e.g., biomethane and biogas);

• $41 million for super-ultra-low carbon f uels (e.g. electric drive and hydrogen);

• $22 million for efficiency improvem ents (vehicle and engine efficiency improvements);

• $19 million for non-GHG reduction cat egories (e.g., workforce training, sustainability, public educ ation and outreach); and

• $10 million for manufactu ring and production.

The Energy Commission staff held four publ ic workshops on the Plan and AB 118 Program in February 2009. T he CEC adopted a regulation to administer the Alternative

and Renewable Fuel and Vehicle Technol ogy Program on Febr uary 25, 2009. A

revised Plan is scheduled to be released and proposed to the Energy Commission for adoption in March 2009.II-14 b. AB 118 –Air Resources Board

Under AB 118 provisions, ARB was allocat ed $50 million annually beginning in fiscal year (FY) 2009-10 for the Air Quality Impr ovement Program (AQIP). AB 118 allows for the AQIP to fund a variety of clean advanced technology vehicle and equipment projects to reduce criteria pollutant emissions. ARB staff is developing a proposed AQIP FY 2009-10 Funding Plan. The Board is scheduled to consider the Funding Plan in April 2009. At AQIP public workshops , staff has discussed a draft proposal that
directs about half of the FY 2009-10 AQIP funds to a new hybrid truck and bus voucher program, with additional funds targeting el ectric light-duty vehicles, farm equipment, and lawn and garden equipment, as well as advanc ed technology demonstr ation projects. Staff expects to solicit FY 2009-10 proj ects in mid-2009 (once AQIP funds are appropriated as part of the FY 2009-10 Californ ia budget), and begin funding projects in

late 2009.

The Board will also consider adoption of ARB staff’s Proposed AQIP Guidelines -- which define the program’s structure and administrative requirement s -- in April 2009. The program Guidelines are intended to apply to multiple funding years, while the AQIP Funding Plan shall be updated and approved by the Board annually.

c. AB 118 – Bureau of Automotive Repair

AB 118 provides the Bureau of Automotive Repair about $30 million annually through 2015 for an Enhanced Fleet Modernization Progr am, which is a voluntary vehicle retirement program for high-polluting cars and light- and medium-duty trucks. The program will be available statewi de, with an initial outreach effort in the South Coast and San Joaquin Valley.

D. Federal Renewable Fuels Standard

At the federal level, Congr ess adopted a renewable fuel s standard (RFS) in 2005 and strengthened it (RFS2) in December 2007 as part of the Energy Independence and Security Act of 2007 (EISA). The RFS2 co ntains, among other provisions, increasing volumes of biofuels every year, up to a requi red volume of 36 billion gallons by 2022.(8) Of the 36 billion gallons, 16 billion gallons mu st be advanced biofuels from cellulosic sources. Successful implementat ion of the RFS2 would result in significant quantities of low carbon intensity biofuels that could be used toward compliance with California’s LCFS. In addition, successful implementat ion would also signal that the necessary technological breakthroughs to produce se cond and third generation biofuels have

occurred.

1. Renewable Fuel Volume Requirements

The RFS2 requires fuel producers to use a pr ogressively increasing amount of biofuel, culminating in at least 36 billion gallons of biofuel by 2022. The U.S. EPA must establish regulations to ensur e that transportation fuel sold in or imported into theII-15 United States contains at l east the applicable quantit y of renewable fuels. Responsible parties under the U.S. EPA r egulations relating to biofuels include large refiners, blenders, and importers of gasoline, and small refi ners beginning in 2010.

The RFS2 volume requirements are given in T able II-3. The total volume of renewable fuel required in the U.S. in 2009 is 9.0 billi on gallons, increasing to 36 billion gallons in
2022. RFS2 differentiates between "conv entional biofuel" (corn-based ethanol) and

"advanced biofuel." Advanced biofuel is renew able fuel, other than corn-based ethanol, with lifecycle greenhouse gas emissions t hat are at least 50 percent less than greenhouse gas emissions produced by gasolin e or diesel. Beginning in 2009, a progressively increasing porti on of renewable fuels must be advanced biofuels, such as

cellulosic ethanol.

Table II-3 Federal Renewable Fuels Standard 2 Volume Requirements

Advanced Biofuel

Year Cellulosic

Biofuel (billion gal) Biomass-Based

Biodiesel * (billion gal) Total (billion gal) Total

Renewable

Fuel (billion gal)

2008 --- --- --- 9.0

2009 --- 0.5 0.6 11.1

2010 0.1 0.65 0.95 12.95

2011 0.25 0.8 1.35 13.95

2012 0.5 1.0 2.0 15.2

2013 1.0 * 2.75 16.55

2014 1.75 * 3.75 18.15

2015 3.0 * 5.5 20.5

2016 4.25 * 7.25 22.25

2017 5.5 * 9.0 24.0

2018 7.0 * 11.0 26.0

2019 8.5 * 13.0 28.0

2020 10.5 * 15.0 30.0

2021 13.5 * 18.0 33.0

2022 16.0 * 21.0 36.0
* Per RFS2 requirement, the U.S. Administrator shall determine the applicable biomass-based

biodiesel volume and shall not be less than the volume listed from 2012.

2. Renewable Fuels GHG Requirements

The RFS2 does not specifically require GH G reductions for the various categories of

renewable fuels and is not a carbon intensit y standard like the LCFS . However, there are specific requirements for t he different classifications of renewable fuels. In general, these specifications are set relative to t he baseline lifecycle GHG emissions for gasoline

and diesel fuel sold or distributed in 2005. The lifecycle GHG emissi ons are specifically

defined as:II-16 “The term ‘lifecycle greenhouse gas emissi ons’ means the aggregate quantity of greenhouse gas emissions (including direct emissions and significant indirect emissions such as significant emissions from land use changes), as determined by the Administrator, related to the full f uel lifecycle, including all stages of fuel and feedstock production and distributi on, from feedstock generation or extraction through the distri bution and delivery and use of the finished fuel to the ultimate consumer, where the mass val ues for all greenhouse gases are adjusted

to account for their relative global warming potential.” 20

There are four general classifications of renewable fuels defined in RFS2 as

summarized below:

• Conventional Biofuels : Renewable fuel that is ethanol derived from corn starch. Any new facility that commences construc tion after the date of enactment of the RFS2 must achieve at least a 20 perc ent reduction compared to the baseline emissions. Practically, about 13 billion gallons for ethanol derived from corn starch is excluded from the 20 percent requirement.

• Advanced Biofuels : As discussed above, an advanced biofuel is any renewable fuel that has lifecycle GHG emissions at least 50 percent less than baseline

emissions. An advanced biofuel excludes ethanol derived from corn starch.

• Cellulosic Biofuels : Cellulosic biofuels are a specific subset of advanced

biofuels. These fuels must achieve at least a 60 percent reduction in GHG emissions compared to t he baseline emissions.

• Biomass-Based Diesel : Biomass-based diesel fuels are also a subset of advanced biofuels. These fuels are specif ically defined as biodiesel fuels and

must have GHG emissions that are at least 50 percent less than the baseline

emissions. A renewable diesel fuel derived from co-processing biomass with a petroleum feedstock can be an advanced bi ofuel, but is not a biomass-based

diesel fuel.

A comparison of the GHG emissions benefits of RFS2 compared to the LCFS is given in the Environmental Chapter and Appendix F.

3. Renewable Biomass Definition

The RFS2 defines renewable fuel as fuel th at is produced from renewable biomass.

Renewable biomass is then defi ned as each of the following:

• Planted crops and crop residue harvested from agricultural land cleared or cultivated at any time prior to the enactm ent of this sentence that is either actively managed or fa llow, and nonforested;

20 Title II-Energy Security Through Increased Prod uction of Biofuels; Subtitle A-Renewable Fuel Standard; Section 201-Definitions;II-17 • Planted trees and tree residue from actively managed tree plantations on nonfederal land cleared at any time prior to enactment of this sentence, including land belonging to an Indian tribe or an Indian individual, that is held in trust by the United States or subject to a restricti on against alienation imposed by the United States;

• Animal waste material and animal byproducts;

• Slash and pre-commercial thinnings fr om 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, but not fo rests or forestlands that are ecological communities with a global or State ranking of critically imperiled, imperiled, or rare pursuant to a State Natural Heritage Progr am, old growth forest, or late successional forest;

• Biomass obtained from the immediate vi cinity of buildings, camps, or public infrastructure facilities (includi ng roads), at risk from wildfire;

• Algae; and

• Separated yard waste or food waste, in cluding recycled cooking and trap grease; and street tree and urban park trimmings.

One aspect of the definition of renewable biomass is that there are signif icant federal incentive funds for producing advanced biofuel s. To qualify for these incentives, the renewable fuels must be produc ed from renewable biomass. Additional discussion of the relationship between the federal definition of renewabl e biomass and the LCFS is presented in Chapter 6.

4. U.S. EPA Rulemakings Implementing the RFS2

U.S. EPA is responsible for implementing the volume requirements in the RFS2. Section 211(o) of the Clean Air Act (CAA or the Act), as amended, requires the U.S. EPA Administrator to annually determi ne a renewable fuel standard which is applicable to refiners, importers and cert ain blenders of gaso line, and publish the standard in the Federal Register . On the basis of this st andard, each obligated party

determines the volume of renewable fuel that it must ensure is consumed as motor

vehicle fuel. This standard is calculated as a percentage, by dividing the amount of renewable fuel that the Act requires to be blended into gasoline for a given year by the amount of gasoline expected to be used during that year, in cluding certain adjustments specified by the Act.

U.S. EPA published a renewable fuel standard of 7.76 percent for 2008, which was intended to lead to the use of 9 billion gallons of renewable fuel in 2008.(9) Similarly, U.S. EPA published a renewable fuels standard of 10.21 percent for 2009, which was intended to lead to the use of 11.1 billion gall ons of renewable fuel in 2009.(10) NoteII-18 that the 11.1 billion gallons of renewable fuel required in 2009 is projected to include approximately 0.5 billion gallons of biodiesel and renewable diesel.

The U.S. EPA is scheduled to release anot her proposed rulemaking in the next few months. Among other provisions, the propos ed rulemaking will present the preliminary

results of its determinations for the full fuel life cycle analysis and the fuel volume requirements as required by EISA.

E. Other LCFS Initiatives

1. Northeast and Mid-Atlantic States

Eleven Northeast and Mid-Atlantic States hav e committed to developing a regional Low
Carbon Fuel Standard in order to reduce greenhouse gas emissions from fuels for

vehicles and other uses. 21 These States will work toget her to create a common fuel standard that will reduce greenhouse gas emissi ons on a technology-neutral basis. The standard will be a market-based, technologically neutral po licy to address the carbon content of fuels by requiring reducti ons in the average lifecycle greenhouse gas emissions per unit of useful energy.

The standard would be applicable to transpor tation fuels. In addition, the standard would apply to fuel used for heating buildin gs, industrial processes, and electricity generation. Fuels that may have potentia l to reduce the carbon intensity of transportation include electricity and advanced biofuels that have lower lifecycle carbon emissions and are less likely to cause indirect effects from crop diversion and land use changes than those on the market today. A Memorandum of Understanding concerning the development of the regional low carbon fuel standard progr am is to be forwarded to the Governors of each State by December 31, 2009, or as soon thereafter as is possible.

ARB staff has been coordinating with representatives of t hese States and will continue to do as the ultimate success of any LC FS is dependent adoption across jurisdictions.

3. Canadian Provinces

On May 31, 2007 British Columbia and Ontario have signed memoranda of understanding wit h California to match California’s Low Carbon Fuel Standard (LCFS), requiring that the average carbon intensity of transportation f uels sold in the province be reduced by at least 10 percent by 2020.(11)

4. European Fuel Quality Directive

As a part of its plan to reduce overa ll GHG emissions, the European Commission amended the European Fuel Qua lity Directive 98/70/EC on December 17, 2008 to include the de-carbonization of transport fuel.( 12, 13) Fuel suppliers will be required to

21 The States are Connecticut, Delaware, Maine, Ma ryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, and Vermont.II-19 report on the lifecycle GHG emissions of the f uel (petrol, diesel, and gas-oil) they supply

and reduce these emissions fr om 2011 onward. Suppliers will be required to gradually reduce GHG emissions per unit of energy by up to 10 percent in 2020. This is to be accomplished through the use of biofuels, alternative fuel, and reductions in flaring and venting.

The major provisions of the amendments are presented below.

• Applicability : Applies to suppliers of fuel for road vehicles, non-road machinery (including inland waterway vessels when not at sea), agricultural and forestry

tractors and recreational craft when not at sea.

• Standards :

o Baseline year is 2010

o 2 percent reduction by December 31, 2014

o 4 percent reduction by December 31, 2017

o 6 percent reduction by December 31, 2010

o Additional 2 percent reduction require ments by 2020 for either one or both:

 The supply of energy for transport supplied for use in any type of road vehicle, non-road mobile machinery (inc luding inland waterway vessels), agricultural or forest ry tractor or recr eational craft; or

 The use of any technology (includi ng carbon capture and storage) capable of reducing life cycle greenhouse emissions per unit of energy from fuel or energy supplied.

• Sustainability Criteria :

o Minimum GHG reductions threshold for biofuels (initially 35 %, will eventually increase to 60 % GHG reduction)

o Biofuels shall not be from made from raw material obtained from land with biodiversity value;

o Biofuels shall not be from made from raw material obtained from land with high carbon stock (wetlands, continuously forested areas, peat lands); and

o Biofuels shall not be from made from raw material obtained from land that was peat land in January 2008 unless it is proven that the cultivation and harvesting of this raw material does not involve drainage of previously undrained soil.

• Verification :

o Member States shall require economic operators to show that sustainability criteria above have been fulfilled; Ec onomic operators must use a mass balance system to ensure that sustainability criteria apply to all raw materials used in biofuels production;II-20 o Member States shall require econom ic operators to show appropriate and

relevant information on measures taken for soil, water and air protection, the restoration of degraded l and, and the avoidance of excessive water consumption in areas where water is scarce;

o Member States shall take measures to ensure that economic operators submit reliable information and to make available to the Member State upon request the data that were used to develop the information; and

o Member States shall require eco nomic operators to arrange for an adequate standard of independent auditing of the information they submit. The auditing shall verify that the systems used by the economic operators are accurate, reliable, and fraud-resistant.

• Lifecycle GHG Emissions from Biofuels :

o GHG calculation by JCR/ EUCAR/CONCAWE

o Direct land use included;

o A study reviewing the impact of indi rect land use change is required to be submitted to the European Parliament by December 31, 2010 per the

amended directive

o Look up tables provided for:

 Default % reduction for each biofuel based of biomass type; and

 Carbon intensity values for each st ep in the production of biofuels.III-1 

### III. Technology Assessment

This chapter contains a brief description of some of the fuels that might be used to comply with the LCFS. Also discussed for each fuel are conversion technologies and production pathways currently available (c ommercially) or under development. The diversity of promising low- carbon fuel options along with the substantial research and development efforts to bring advanced technologies to the market leads us to conclude that compliance with the LCFS is feasible . The mandate of the federal Energy Independence and Security Act of 2007 (EISA) to use increasing amounts of advanced and cellulosic biofuel(8) beginning in 2009/2010 and continuing on through 2022 will further stimulate improvement s to the current conversion technology of advanced biofuels. A more detailed version of this chapter is included as Appendix B.

A. Overview of Current Ca lifornia Transportation Fuels

1. Gasoline

Currently, most gasoline in California cont ains six percent ethanol by volume. Some blends of eight percent ethanol by volume are av ailable for sale in the State. California

consumed about 15.8 billion gallons of gasoline(14) 22 in 2008. California’s gasoline consumption represents about 11 percent of the total gasoline consumption in the United States.(15) According to EMFA C2007, there are appr oximately 25 million gasoline-powered vehicles in California. There are 15 refineries in California making gasoline and diesel fuel.(16) Recently, Ki nder Morgan, a common carrier pipeline and terminal operator responsible fo r distribution of 60 percent of California’s motor vehicle fuels, announced that in 2010 ga soline they distribute woul d have 10 percent ethanol.

2. Diesel

In California, approximately 4.2 billion gallons of diesel fuel (17) were consumed in 2008, which represents about eight perc ent of the total diesel fuel consumption in the United
States. California diesel fuel must meet a 15 parts-per-million-by-w eight sulfur standard and specifications limiting the aromatic hy drocarbon content to 10 percent for large refiners and 20 percent for small refiners. There are approxim ately 875,000 diesel fuel vehicles in California(17). A majority of those diesel-fuel vehicles are heavy-duty

vehicles.

B. Current Technologies

This section presents the staf f’s assessment of fuels and conversion technologies that are currently available for commercial use.

1. Ethanol from Grains and Sugars

22 The remaining months of 2008 were projected.III-2 Ethanol is an alcohol made by fermenting and distilling simple sugars. Therefore, any biological feedstock that eit her contains sugar or can be broken down into simple sugars is a potential source fo r ethanol production. The th ree main types of biomass feedstock for ethanol production ar e sugar syrup from sugar cr ops, starch from grains, and biomass containing cellulose. Howe ver, at present, ethanol is produced commercially in large quantities only from enz ymatic fermentation of starch from grains and fermentation of sugars from sugar crops (sugarcane, sugar beets, sweet sorghum).

The easiest way to produce ethanol is to begin with sugar-produc ing plants. For example, sugarcane, sugar beets, and sweet sorghum stalks contain high levels of sugar. The sugar syrup obtained when the f eedstock is pressed can be fermented with minimal processing. In contrast, grains c ontain starch, a polymer of glucose, which must be broken apart before the sugar c an be fermented. Therefore, ethanol production from starch-based feedstocks requires more effo rt than production from sugar-based feedstocks. The third type of bi omass feedstock contains cellulose, such as trees, grasses, wood wastes, etc. The cellulose in these feedstocks is part of a lignocellulosic composite in the cell walls that resists degradation. Hence, more energy is required break down this feedstock to it s component sugars than wit h grains or sugar crops. However, the energy r equirements to grow cellulosic material are far less than for sugar or starch, which is a significant advantage.(3) Lignocellulosic biomass to ethanol conversion technologies are discussed in the Midterm Technologies section of this chapter. This section focuses on ethanol production from grains and sugar crops.

a. Ethanol from Grains

Currently, corn is the primary feedstock fo r ethanol production in the United States. Studies indicate that approximately 98 per cent of current et hanol production in the United States uses corn, with about 80 percent of the ethanol produc ed from a dry-mill process.(18) New plants are projected to be dry-mill only, with t he exception of a new 100 MGY wet-mill plant for Iowa and a plant expansion project in Tennessee.(19) In California, the existing corn ethanol comme rcial plants have a production capacity of approximately 150 million gallons per year. Additional corn -to-ethanol plants are under construction that will add to this capacity. Newer plants in operation or under construction in California are energy effi cient, maximize co-product value, and produce lower-carbon-intensity ethanol.

(1) Dry Mill

In the dry mill process the gr ain feedstock is milled into a flour or fine meal to expose

the starch. Starch is a polymer of glucose and must be broken down before

fermentation. The flour is mixed with wa ter and then cooked at high temperatures with enzymes to convert the starch to sugar and reduce bacterial contamination. After the starch has been hydrolyzed to its component s ugars (glucose), the glucose is fermented using yeast under anaerobic conditions. T he hydrolysis and fermentation process usually takes 40-50 hours.(18) After ferme ntation, the ethanol is concentrated to 95 percent using conventional distillation and then dehydrated (e.g. by using molecularIII-3 sieves, azeotropic distillation, or extractive distillation). The ethanol is denatured, usually by the addition of gasoline, to pr event consumption as an alcoholic beverage.

The whole stillage co-product contains any unfermented starch an d the fiber, oil, and protein components of the original grain. The whole stillage is also known as distillers’ grain and may be partially dri ed and mixed with solids to pr oduce wet distillers’ grains with solubles (65 percent moisture) for direct use as an animal feed or further dried to 10 -12 percent moisture to produce dry distillers’ grain with solubles. The drying process is energy intensive, requiring up to 33 percent of the tota l energy needs.(18) Wet distillers’ grains must be used within hour s to days, whereas dry distillers’ grain has a much longer shelf life.

(2) Wet Mill

Wet-mill ethanol production differs from dr y-mill production in the initial processing steps. In the wet mill process, the grain is steeped in a mixture of water and dilute

sulfurous acid for 24 to 48 hours. After st eeping, the germ is separated and undergoes further processing to produce an oil product. The gluten is separated from the starch and may be used as a gluten meal for anima l feed. The separat ed starch is then hydrolyzed, fermented, and distilled to produc e ethanol as described above for the drymill process. Corn is the only grain used in wet mill facilities. The wet-mill process generates valuable co-products, although actual ethanol yield is a little lower than in the dry-mill process.

b. Ethanol from Sugar Crops

The conversion of sugars to ethanol is simp ler than the conversion of starch to ethanol as the sugar syrup from pre ssed sugarcane or sweet sorghum stalks (or obtained from sugar beets) may be readily fermented by y east with little pre-processing. Under anaerobic conditions, yeast metabolizes suga r to produce ethanol. Fermentation is followed by distillation and purif ication of the ethanol.

The bagasse (leftover biomass) from sugar cane or sweet sorghum may be used as animal feed, as a potential feedstock for cellu losic ethanol, or burned for electricity. Pulp from sugar beets can be used for animal feed. Waste sugars (such as molasses) or surplus sugar from existing sugar-refini ng plants are other possible feedstocks for ethanol production.

Sugar-to-ethanol conversion technology is fully commercial (mostly in Brazil). Sugarcane ethanol production is efficient and results in a lower-carbon-intensity ethanol. However, indirect land use effects impact the carbon intensity.

Ethanol produced from sugar crop s grown in the United States is also an option, though availability is limited. Ethanol is generally produced from sugars where there is a large supply of feedstock, such as sugarcane in Br azil and sugar beets in parts of Europe.

Feedstocks in North America are limited but coul d be increased. California and otherIII-4 states produce sugar crops for the sugar industry. United States Department of Agriculture (USDA) statistics show that the United States produced a total of 34 million tons of sugar beets and 30 million tons of sugar cane.(18) In California, both sugarcane and sugar beets are farmed in the Imperial Vall ey. Sugar beets are also cultivated in parts of the Central Valley. Sweet sor ghum grows well in California but has not been widely cultivated.

Staff is aware of one sugarcane-to-ethanol facili ty planned for California. The project is in the permitting phase. The facility will be powered by combusting bagasse and will be located in Brawley near the source of sugarcane cultivation. Production capacity is expected to be 55 milli on gallons per year.

c. Commercialization Status – Ethanol

In 2007, approximately 13 billion tons of ethanol were produced worldwide. Ethanol production in the United States , nearly all from grains, a ccounted for about half of the

total. Grain-to-ethanol conver sion technology is fully commercial. As of February 2009, the Renewable Fuels Association listed appr oximately 162 operating facilities in the United States that produced etha nol from grain (nearly all from corn), with a total annual production capacity of approx imately 10.4 billion gallons of ethanol. Refer to Appendix B for a listing based on the Renewable Fuels Associ ation’s list of fuel ethanol

biorefineries in the United States, including location, feedstocks, and production capacity.(20) In California, there are five ethanol plant s with a production capacity of approximately 150 million gallons.

Ethanol production from sugar crops is also fully commercial. Ethanol production from sugarcane (almost all in Brazil) accounted fo r roughly 40 percent of the world’s fuel ethanol in 2007. Sugar beets are used for ethanol production in parts of Europe. Refer to Table III-1 below for ethanol production in the top five producing nations in 2007.(21)

Table III-1 Ethanol Production in Top Five Producers and

World Ethanol Production Total in 2007 Country Millions of Gallons Percent of Total

United States 6498.6 49.6

Brazil 5019.2 38.3 European Union 570.3 4.4

China 486.0 3.7

Canada 211.3 1.6
World Total 13,101.7

In addition to grain and sugar ethanol plants, there are six facilit ies operating in the United States with a total production of approx imately 20 million gallons per year of ethanol from food and beverage wastes. Al though the technology is fully developed, there is limited opportunity for growth in this category. Refer to Appendix B forIII-5 information regarding the location, feeds tocks, and operating capacity for these

facilities.

2. Biodiesel and Renewable Diesel

a. Biodiesel

Biodiesel is a fuel composed of a mixture of fatty acid alkyl esters that can be made from almost any plant oil or anima l fat. “Bio” refers to the biol ogical source of the fuel in contrast to traditional petroleu m-based diesel fuel. Biodiesel is an alternative fuel that can be blended with petroleum-based diesel or used in straight unblended form as B100. Biodiesel fuel blends are designated as “BX” where “X” is the percent biodiesel by volume in the fuel. Biodiesel that meet s ASTM D975-08ael, ASTM D7461-08, and ASTM D6751-08 is a legally registered fuel and fuel addit ive with the U.S. Environmental Protection Agency.

The choice of plant feedstocks used to ma ke biodiesel is dependent upon the vegetable oils that are economically available. In the U.S. there are many potential plant-oil feedstocks that can be used, including so ybean, peanut, canola, cottonseed and corn oil.(19) Most of the world’ s production of biodiesel comes from plant oils such as soybean, rapeseed (canola), and palm oil. About 90 percent of U.S. biodiesel is made from soybean feedstocks.(22) The process us ed to convert virgin oils into biodiesel involves the use of a catalyst and alc ohol and is called transesterification.

Biodiesel can also be made from animal fats , such as used restaurant grease (yellow grease) and tallow. These feedstocks are wastes so there is no CO 2 associated with land use, as there is with crop based feedstocks. Biodiesel from wastes is referred to

as advanced biodiesel in order to differentiate it from conventional biodiesel because of its lower carbon intensity. These waste animal fats can be converted into biodiesel through transesterification.

Raw vegetable and animal oils contain triglycerides. Though these oils can be directly used in diesel engines and give short-term pe rformance, this is highly discouraged, as their use can cause severe engine problems. This is primarily due to the raw oils forming engine deposits, with coking and pluggi ng in engine injector nozzles, piston rings, and lubricating oil. Th is happens due to polymerization of the triglycerides in the

raw oils as the fuel is combust ed. Therefore, it is necessary to convert the raw oils into

a form of esters or biodiesel to prevent these issues.(19)

The conventional biodiesel manufacturing proce ss converts oils and fats into chemicals called long-chain mono-alkyl-esters. These c hemicals are also referred to as fatty acid methyl esters (FAME), and the conversion proce ss is referred to as transesterification.

Before transesterification is conducted, the raw oils and fa ts are filtered and pretreated

to remove water and contaminants. Water in the feedstock leads to the formation ofIII-6 soaps, which is an undesirable by-product, reduc es the yield of biodiesel, and makes the separation of glycerin in t he products more difficult.

Transesterification involves reacting triglyceri de oils with alcohol (usually methanol) in the presence of a catalyst in a simple cl osed-reactor system at low temperature and pressure. In the transesterifi cation reaction vessel, the mixt ure of alcohol and oils is allowed to settle for one to eight hours.(18) The products of t he transesterification reaction are methyl esters (crude biodiese l) and glycerin as a co-product. After transesterification, a majority of the alc ohol is removed from the glycerin and recycled back into the system to continue the process. The biodiesel from the process is purified

and washed to remove residual cata lyst and soaps. The glycerin from transesterification can be purified and sold to the pharmaceutical or cosmetic industries to be processed into lotions and creams.

According to the National Biodiesel Board as of September 2008 there were 176 operational commercial biodiesel product ion plants in the U.S. with a total production capacity of 2.61 bill ion gallons. There are about seven major plants in California with annual production capacitie s varying between 350,000 gallons to ten million gallons. The total capacity in Califor nia is nearly 35 million gallons per year. See Appendix B for a biodiesel commerciali zation status summary from the National Biodiesel Board giving plant location, capacity, and feeds tock of plants in the U.S.

b. Renewable Diesel

Hydrogenation-derived renewable diesel (HDRD) is produced by refining fats or vegetable oils. This process is also know n as the Fatty Acids to Hydrocarbon (FAHC – Hydrotreatment) process. V egetable oils and animal fats can be converted into diesel, propane, and other light hydroc arbons through hydrotreatment with hydrogen. Biomass based diesel produced from the FAHC process is referred to as renewable or “green”

diesel to differentiate it fr om biodiesel produced by tran sesterification. Renewable

diesel has a chemical structure that is identical to petroleum based diesel since it is free of ester compounds.

The product distribution of the FAHC process results in (by weight) 83 to 86 percent diesel, two to five percent light hydrocarbons, carbon dioxide gas, and water. The oxygen within the ester compounds of the oils is removed through the release of the

carbon dioxide and water.

Renewable diesel has several advantages to FAME and petroleum biodiesel. Renewable diesel has a superior emission pr ofile. Using renewable diesel results in reduced particulate, NOx, hy drocarbons, and CO emissions. Unlike FAME biodiesel, the production of renewable diesel thr ough the FAHC process does not produce a glycerin co-product. Renewable diesel is produced using exis ting hydrotreatment process equipment in a petroleum refinery, resulting in an economic advantage by reducing the costs of production.III-7 Renewable diesel has a lower sulfur content than petroleum diesel resulting in lower
SOx emissions. Renewable diesel has a lowe r cloud point than conventional biodiesel; therefore, it has better low- temperature operability and can be used in colder climates without gelling or clogging of fuel filters.

Waste animal fats can also be hydrogenated to produce diesel-range hydrocarbons. Renewable diesel produced from wastes has a lower carbon intensity and is also

referred to as “Advanced” renewable diesel.

ConocoPhilips completed a commercial demons tration plant in Cork, Ireland, that produces 42,000 gallons per day of renewable diesel usi ng vegetable oil and crude oil feedstocks. ConocoPhilips also partnered with Tyson to build a facility that can process animal fats in the U.S. The facility opened in late 2007 with a capacity of 500,000 gallons per day of renewable diesel.(18)

Neste has developed a plant to process veget able and animal fats into renewable diesel by the hydrotreatment process. The facility demonstrated at the Porvoo oil refinery in Finland has a capacity of 60 million gallons per year. The company is planning to build a second plant of the same size to meet gr owing demand. The company also has plans to build plants in Austria and Singapore.

The Petrobras “H-BIO” process uses co-proce ssing of vegetable oils to make renewable diesel. Petrobras plans to have H-BIO operati ons in at least three refineries by the end of 2007 with a total capacity to handle more t han 250,000 tons of vegetable oil annually. Two more refineries were planned for 2008.

Other companies that have plans to produc e renewable diesel through hydrogenation include Nippon Oil in Japan, BP in Australia, Syntroleum and Tyson Foods in the U.S., and UOP-Eni. The Nippon Oil plant expects to be operating commercially in three years. The BP plant is planned to have a dem onstrated capacity of 80,000 gallons per day. Syntroleum and Tyson Foods are sc heduled to start operation in 2010 with a capacity of 5,000 barrels a day. UOP-Eni is an American and Italian project supported by the U.S. Department of Energy that is scheduled to come online in 2009. Refer to Appendix B for a summary of the ma in HDRD projects in the world.

3. Biogas

Biogas typically refers to a gas produced by the biological breakdo wn of biodegradable organic matter in the absence of oxygen. This process is also referred to as anaerobic digestion. The resulting biogas consists of methane, carbon diox ide, and other trace amount of gases and can be used to generate heat, electricity, and alternative fuels. Depending on where it is pr oduced, biogas can be categorized as “landfill gas” or “digester gas.” Landfill gas is produced by decomposition of organic waste in a municipal solid waste landfill. Digester gas refers to applications using livestock manure, sewage, food waste, et c. Biogas is also referred to as biomethane. It has properties similar to natural gas and can pot entially be used for similar applications. ForIII-8 example, biomethane might be compressed and used as a transportation fuel in compressed natural gas vehicles.(3) The vehi cle fuel potential in landfill and sewage digester biomethane is equivalent to between 300 to 400 million gallons of gasoline, whether as compressed or liquefied gas (i.e; CNG or LNG) or converted to hydrogen.(3)

a. Landfill Gas (LFG)

The California Integrated Waste M anagement Board (CIWMB) has identified approximately 366 landfills with potential to generate landfill gas, of which 145 are active permitted facilities receiving waste. Of the active l andfills, approximately 66 percent are owned by public entities.(23) The total potential biomethane resource
from landfills in California is estimated at 80 billion cubic feet per year(24). Active landfills must control landfill gas to cont rol migration and reduce explosion risks to adjacent structures. LFG co llection systems are well estab lished and use a network of wells, headers, and blowers to collect the gas and route it to a treatment plant or a flare. Raw landfill gas is about 50 percent met hane, 45 percent carbon dioxide and a small percentage of other compounds, such as nitrogen and hydrogen sulfide. The average heating value is about 450 Btu/scf.

LFG is currently used for power generation, mostly with reciprocating engines and microturbines. The gas is also used with fuel cells, as boiler fuel, and as vehicle fuel, although much is still flared without energy re covery. The potential use of LFG as a transportation fuel in the form of compressed natural gas (CNG) or liquefied natural gas (LNG) is discussed below.

(1) Vehicle Fuel from Landfill Gas

The main steps involved in processing la ndfill gas into CNG are water removal,
pretreatment to remove trace organics, membrane technology to separate CO 2 , and final compression to about 3600 psi.

Production of LNG from landfill gas is more c hallenging and requires additional steps in the form of purification and cr yogenic systems.

(2) Commercialization Status - LFG

The technology for producing CNG from LF G is well established. The Los Angeles County Sanitation District has successfully converted LFG to CNG since 1994 at its Clean Fuels facility. This facility has a design capacity equivalent to 1000 gallons of gasoline per day. The total capital cost for this project was approximately $1 million.(25) In Sonoma County, a landfill-gas-to-CNG projec t will result in a system to

fuel six buses.

The ECOGAS Corporation has operated an 8, 500 gallon-per-day (GPD) LNG plant in Rosenberg, Texas, since 1995.(25) Current ly, California does not have any commercial plants in operation for producing LNG. However, ARB and CIWMB have approvedIII-9 grants in 2007 for two commercial-scale demonstr ation projects. Thes e projects include a 13,000 GPD LNG plant at the Altamont Landfill (by Gas Technology Institute) to be used for the waste-hauler fleet and an 18,600 GPD plant at the Bowerman Landfill (by Prometheus Energy Company) to provide fuel for the local bus fleet.(26) These plants are expected to be commissioned by June 2009 and will provide good data on technical feasibility and costs.

b. Digester Gas

Typical feedstocks for anaerobic digestion include manure from confined animal facilities, such as dairies and feedlot s, sewage sludge, and wastes from food processing. Anaerobic digestion is a bioche mical process in which several types of bacteria work together in a seri es of steps to digest bioma ss in the absence of oxygen. First, bacteria break down the carbohydrates , proteins and fats present in biomass feedstock into fatty acids, alcohol, carbon dioxide, hydrogen, ammonia and sulfides. This stage is called "hydrolysis" or "liquefac tion.” Next, acid-forming bacteria further metabolize the products of hydrolysis into ac etic acid, hydrogen and carbon dioxide. Finally, methane forming (methanogenic) bacter ia convert these products into biogas.(27)

The biogas generated by digesters contai ns methane, carbon dioxide, sulfur compounds, PM, and water. Be cause the methane in the biogas is dilute and contains contaminants, the biogas must be pretr eated, conditioned, and compressed before use as a fuel. The energy content of biogas d epends on the amount of methane it contains. Methane content may vary from about 55 percent to 80 percent. 2

( 1) Digester Gas Applications

Digester gas can be used in many applicatio ns. The level of pretreatment depends upon the application and is designed to remo ve carbon dioxide, sulfur compounds, particulates, water, and other contaminants. Typical applications are onsite use in reciprocating internal combustion engines, tu rbines, boilers, or fuel cells to produce energy. Biomethane can also be injected in to a natural gas transmission pipeline or used for transportation purposes. Using di gester methane generated onsite to power electricity-generating engines co uld replace electricity generat ed from fossil-fuel power plants. In addition, biomet hane generated from onsite digeste rs could power vehicles used for transportation common to a particu lar industry (e.g. biomethane produced from dairy lagoon digesters can power converted diesel milk trucks).

(2) Commercialization Status – Digester Gas

Production of renewable energy , improvement on environmental pollution in air and water, reduction of agricultural wastes, and utilization of byproducts as fertilizers from anaerobic digestion has increased the attrac tiveness of this application. Anaerobic digestion technology to produce biogas is we ll developed worldwide. Currently, the European Union has a total generating capaci ty of 307 megawatts (MW) from this technology. In California, only 0.37 MW of power is generated from five existingIII-10 digesters, although the total potential for anima l waste to energy in dairies is over 105 MW. There are approximat ely 2,300 dairy farms in California. There are 10 sewage treatment plants in California wit h digesters that generate about 38 MW of electrical power.(28)

Use of digester gas to power vehicles is not prevalent but can be achieved. Hilarides Dairy was awarded a grant by ARB in 2007 to produce methane from the waste generated by the dairy’s 9,100 cows. This project is an attempt to manage

environmental issues and create an onsite self-c ontained system of e nergy supply. The biogas generated will power the dairy’s four converted milk trucks (reducing diesel consumption by 650 gallons per day) and creat e an additional 250 kW of electricity for on-site use.(29)

4. Natural Gas (CNG, LNG)

The production of natural gas, in both co mpressed (CNG) and liquefied (LNG) forms, involves mature technologies and is clearly technologically feasible vis-à-vis the LCFS regulation. Britain wa s the first country to commercialize the use of natural gas. Around 1785, natural gas produced fr om coal was used to light houses, as well as streetlights.(30) In 1821, W illiam Hart dug the first well in the U.S. (in Fredonia, New York) specifically intended to obtain natural gas.(30) Natural gas liquefaction dates

back to the

19 th century,(31) and the first commercial li quefaction plant began operation in West Virginia in 1917.(32) Today, t he natural gas industry has existed in this country for over 100 years, and it cont inues to grow.(30)

CNG is typically transported by pipeline. According to the Energy Information Administration (EIA), the U.S. produced nearly 19.1 trillion cubic feet(33) (Tcf) of “dry” natural gas 23 and imported about 3.8 Tcf in 2007( 34), primarily from Canada and a small percentage from Mexico.

LNG is typically transported by specialized ta nker with insulated walls, and is kept in liquid form by autorefrigeration, a process in which the LNG is kept at its boiling point, so that any heat additions are countered by the energy lost from LNG vapor that is vented out of storage and used to power the vessel.(30) Accord ing to the EIA, the U.S. imported about 0.77 Tcf of LNG in 2007.(34) In 2008, the U.S. imported the vast majority of its LNG from Trinidad, Eg ypt, Nigeria and Algeria, with much smaller amounts from Qatar and Equatorial Guinea.(34)

The actual practice of proc essing natural gas to pipeline dry-gas-quality levels can be quite complex, but usually involves four main processes to remove the various impurities:

• Oil and Condensate Removal

23 Dry gas is natural gas that is almost entirely methane, produced from “wet” gas that is stripped of other molecules during processing or that is produced from non-associated gas fields as “dry” gas.III-11 • Water Removal

• Separation of Natural Gas Liquids

• Sulfur and Carbon Di oxide Removal.(30)

In addition to the four proce sses above, heaters and scrubbers are installed, usually at

or near the wellhead. The scrubbers serve primarily to remove sand and other largeparticle impurities. The heaters ensure that the temperature of t he gas does not drop too low. With natural gas that contains even low quantities of water, natural gas hydrates have a tendency to form when temperat ures drop. These hydrates are solid or semi-solid compounds, resembling ice crystal s. Should these hydrates accumulate, they can impede the passage of natural gas through valves and gathering systems. To reduce the occurrence of hydrates, small nat ural gas-fired heating units are typically installed along the gathering pi pe wherever it is likely th at hydrates may form.(30)

For LNG, the gas must be liquified which invo lves cooling natural gas at its initial production facility to about -260°F at norma l pressure.(30) Upon arrival at its destination in the U.S., LNG is generally tr ansferred to specially designed and secured storage tanks and then warmed to its gaseous state – a process called regasification.(35) The r egasified natural gas is generally fed into pipelines for distribution to consumers. However, if t he regasified natural gas is intended to be transported or otherwise used as LNG (e.g., in LNG vehicles), it would need to undergo a second liquefaction step, which would substant ially increase the fue l’s carbon intensity

value.

5. Electricity

The power system (“the grid”) produces and de livers electrical energy to customers. Electricity is produced by power plants of di fferent sizes and types, which can be fueled by a number of energy sources, such as c oal, nuclear, natural gas, wind, solar, and hydropower.

Battery electric vehicles (BEVs) and plug-in hybrid electric vehicles (PHEVs) are examples of two technologies that use electric ity as a transportation fuel. The status of zero-emission vehicle technologies was ex amined by an independent expert review panel (Panel) established by ARB in 2006. The Panel organized its efforts around three main ZEV-enabling technologies: energy st orage, hydrogen storage, and fuel cells.(36) Refer to Appendix B for the Executive Summary of the Panel’s repor t published in April

2007.

It is the Panel’s opinion that PHEVs have the potential to provide significant direct societal benefits and are likely to become av ailable in the near future. The Panel’s projection is that PHEVs can achieve mass commercialization (100,000’s of vehicles per year) based on global volumes in the 2015+ timeframe.

Full-performance battery electric vehicles capable of high-speed U.S. urban/suburban freeway driving will grow more slowly due to customer acceptanc e of limited range andIII-12 long recharge times. ZEVs are not likely to achieve mass commercialization in the foreseeable future. The Panel projects this technology to achieve early commercialization (10,000’s of vehicles per year) based on global volumes in the 2015

timeframe.

Concerns have been raised about the potential impact of a growing number of plug-in hybrid or electric vehicles on the supply of available electrical power and the need for additional power plant developm ent. Recent research has shown that there is an ample supply of idle electrical generation and transmission capacity to accommodate a significant increase in electric vehicle use.

A 2007 Department of Energy St udy found the nation’s supply of fossil-fuel based, offpeak electricity production and transmission capac ity could fuel up to 84 percent of the country’s existing 220 million vehi cles if they were all pl ug-in hybrids. The study assumed drivers would charge their vehicles overnight when demand for electricity is much lower and did not include hydroelectric , nuclear, renewable, or peaking power plants in its estimates.

The study found that in the Midwest and Eas t, there is sufficient off-peak electrical generation and transmission capacity to provide fo r all of today’s vehicles if they ran solely on batteries. In parts of the West, and specifically the Pacific Northwest, where there is a large amount of hy droelectric generation that’s already heavily utilized and cannot be easily expanded, there is a more li mited supply of extra electricity-generating capacity. However, the study found 15 to 23 percent of California and Nevada’s 26 million light-duty vehicles could be fueled with idle, off-peak electricity generating capacity within the California/Nevada study area.(37)

Research conducted by the Electric Power Research Institute found that more than 40 percent of the nation’s elec tric generating capacity sits id le or operates at reduced loads overnight and could accommodate tens of millions of plug-in hybrids without requiring new plants.(38) The research also concludes utilities could better capitalize their power-generating assets by allowing fo r more efficient operation and gaining a new market for off-peak power that now sits idle.

The additional 1.8 million electric vehicles by the year 2020 are expected to increase the State’s electric system load demand by 4. 6 TW-hrs by 2020. Since most of this additional demand would be supplied by off- peak power, electric vehicles would not create an adverse impact on California’s supply of available electric power within the

2020 timeframe.

A potential benefit of plug- in or electric vehicles for the “smart” power grid of the future involves the concept of using the stored energy in electric vehicles to supply power to the grid during peak demand periods. This “vehicle-to-grid” (V2G) concept would involve advanced technology that would allow future plugged-in vehicles to transmit their location and storage capacity to the electr ic power grid. Utilit ies could potentially draw small amounts of power from the v ehicle’s battery packs to provide voltageIII-13 regulation, spinning reserves, and other pow er balancing functions. While some V2G research has been conducted, deploying this technology will require significant investments to evolve the existing grid and will require large-scale use of plug-in vehicles to provide any potentia l value to utilities or grid operators.(39)

6. Hydrogen

Hydrogen can be used in vehicles with high efficiency and zero tailpipe emissions. Hydrogen can be produced from a range of primary sources, including fossil fuels (natural gas, coal, oil), renewables (biomass, wind, solar), or nuclear energy. Syngasbased processes like steam methane reforming or coal gasification are well established. Water electrolysis is a commercial technology t hat is used where low-cost electricity is

available. It should be noted that with the use of car bon capture and sequestration, hydrogen from traditional sources can be close or equivalent in carbon intensity to hydrogen from renewable sources.

For storage and transport to users, hydrogen is compressed to high pressure or liquefied at very low temperature. Hydrogen can be produced onsite at refueling stations (via small-scale steam reforming of natural gas or water electrolysis) or in a large central plant and delivered to users in compressed gas or liquid hydrogen trucks or via gas pipelines.

The status of zero-emission vehicle te chnologies was examined by an independent expert review panel (Panel) established by the ARB in 2006. For the Executive Summary of the Panel’s report published in April 2007, refer to Appendix B. It is the Panel’s view that storing hy drogen on a vehicle to power it for adequate distance in a

safe and cost-effective manner without excessive weight is a serious challenge in the development of fuel cell electr ic vehicles. In the near te rm, the most common means of storing hydrogen onboard light vehicles will continue to be compressed hydrogen gas. The Department of Energy has selected hydrogen storage parameters corresponding to a 300 mile range as a 2015 target. Liquid hydrogen storage is being demonstrated as
workable but with limitations. The Californi a Hydrogen Highway Network Blueprint Plan calls for a total of 50 hydrogen refueling stat ions by 2010, and as many as 250 in the longer term.(3)

Automotive fuel cell technology continues to make substantial progress but is not yet proven to be commercially viable. The Panel ’s 2007 report states that “there are still large technical barriers to be solved but thes e might well be overcome over the next five to 10 years.” The Panel’s projection is that the intense effort on fuel cell electric vehicles will result in technically capable vehicles by the 2015 to 2020 timeframe, but successful commercialization is dependent on meeting chal lenging cost goals and availability of an adequate hydrogen infrastructure. The Panel pr ojects this technology to be in a precommercial stage (1000’s per year) based on global volumes in the 2010 to 2020

timeframe.III-14 A National Academy of Sciences study also suggests the possibility of introducing hydrogen fuel cell vehicles on a commercial bas is in the United States in the 2015-2020 timeframe.(40)

C. Mid-Term Technologi es Projected by 2015

This section groups the fuels and conversion technologies expected to be available for

commercial use in the 2015 timeframe.

1. Lignocellulosics to Ethanol

Producing ethanol from cellulose has the potential to greatly increase the volume of ethanol that can be produced. Cellulose is the main component of plant cell walls and is the most common organic co mpound on earth. The quantity and diversity of potential feedstocks is substantial compared to starch and sugar crops. In addition to biomass from dedicated agricultural crops, crop and forest residues and waste biomass may be

collected and used for cellulosic feedstock. In addition, cellulosic pathways to

bioethanol and other biofuels have the potential to result in lower-carbon-intensity values and improved net-energy ratios than the traditional starch- and sugar-based ethanol production.(3)

Lignocellulosic (cellulosic) feedstocks includ e dedicated crops, crop and forest residues, or wastes (municipal solid wast e, furniture manufacturing wa stes, etc.). Lignocellulosic biomass from all the principal feedstocks consis ts mainly of cellulose (40-60 dry weight percent) and hemicellulose (20-40 dry weight percent). Ce llulose and hemicellulose are both sugar-based complex carbohydrates and, after hydrolysis to their component sugars, may be fermented to et hanol. Most of the remain ing fraction of cellulosic biomass is lignin (10-28 dry weight percent ), but there are also smaller amounts of proteins, lipids, and ash. Lignin cannot be fe rmented but can be used directly for fuel or thermochemically treated to produce syngas (gasif ication) or bio-oils (flash pyrolysis). Currently, the combustion of lignin is used to generate electricity and/or as a heat source for boilers in some existing sm all-scale fermentation pathway plants.

The chemical composition of a particular feeds tock (cellulose/hemicellulose/lignin ratio) is an important factor in t he ethanol yield for the hydrolysis/fermentation pathway. A lower lignin percentage results in a higher ethanol yield. Woody biomass has about 27 percent lignin, while grasses such as switchgrass have about 18 percent.

An emerging source of cellulosic feedsto ck is native prairie grasses, such as switchgrass, that may be grown on marginal l ands with little water and no fertilizer. This feedstock is particularly attrac tive for some Midwestern locations. Other potential cellulose-to-ethanol feedstocks include fast-g rowing woody crops such as poplar and

willow trees.

Crop residues, such as corn stover or rice straw may be collected as a co-product of other crops. In other states , facilities have been proposed to utilize corn stover as aIII-15 feedstock. However, studies have noted t hat crop residue removal can affect soil erosion or decrease soil organic composit ion, which can impact life-cycle greenhouse gas reductions. Other potential biomass f eedstocks include bagasse from sugarcane or sweet sorghum, orchard prunings, and forest residues. Cellulosic waste feedstock includes municipal solid waste, wood waste from furniture manufacturing, and

construction and demolition debris. The cellulosi c ethanol plants proj ected to be built in
California will use residues or wastes as feedstocks. Ethanol produced from wastes has no land use component for carbon inte nsity and qualifies as advanced renewable

ethanol.

a. Lignocellulose to Ethanol Conversion Technologies

The traditional pathway to produce lignocellu losic ethanol from biomass is through hydrolysis and fermentation. This process is similar to production of ethanol from grains, except that it is significantly more di fficult to hydrolyze ligno cellulose than starch. An alternative pathway involves gasifica tion of lignocellulosic biomass to produce syngas. The syngas can be converted to ethanol using a modified Fischer-Tropsch synthesis or by fermentation techniques.

b. Commercialization Status – Lignocellulosic Ethanol

Current studies typically categorize lignocel lulose-to-ethanol conversion technology as ready for commercialization in the midterm. However, current technology is available for limited near term (2010) production. 24 Good progress has been made during the last few years toward producing etha nol from cellulosic feedstocks. 25 Several technologies, proven in pilot-scale facilities are moving towa rd commercialization. Challenges remain in scaling the technologies, r educing production costs, and fi nancing large-scale plants.

There are a number of government and r enewable-fuels-industry research and development programs dedicated to overco ming remaining hurdles to large-scale commercial production of renewable fuels from ce llulosic biomass. Areas of interest for continued research include developing more efficient pretreatm ent technologies, developing lower-cost and more effective ce llulase enzymes, engineering strains of microorganisms that have higher conversion yields, and int egrating multiple process steps into fewer reactors.

The Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007 (EISA) provide funds for research and devel opment that should facilitate improvements to the current conversion technologies. Both the United States D epartment of Energy

24 The Antares Group 2008 paper (pg 26) categorized as near term (2010) dilute acid hydrolysis conversion technology. Small size facilities of 25 to 60 MGY were modeled. With current technology, a 35 percent conversion to ethanol and an overall process efficiency of about 60 percent were projected for the near term (pg 24). Mid term processes (2015 to 2020) were modeled with the assumption of higher conversion efficiencies and yields. With dilute acid pretreatment, a facility size of 60-100 MGY is modeled. Steam explosion pretreatment is modeled for large facilities > 100 MGY (pg 26).

25 Regulatory Impact Analysis, April 2007, pg 263 stat es that “good progress continues to be made and we remain optimistic that cellulosic ethanol will beco me increasingly important in the future,” pg 263.III-16 (DOE) and the USDA are funding research to improve cellulosic conversion and to develop higher yielding biomass crops. On February 28, 20 07, the DOE announced that it would provide six grants of up to $385 million in cost-share funding for the construction of six biorefinery projects over the next four years. These facilities were expected to produce more than 130 million gallons of cellulosic ethanol per year.(19) Of the original six grant reci pients, two have dropped out of the program. The remaining four recipients expect to complete commercia l-scale facilities between 2009 and 2012.

In addition to funding research and devel opment, the EISA prov ides a compelling incentive for cellulosic ethanol production. Beginning in 2010 and continuing through 2022, the EISA mandates that tr ansportation fuels sold or introduced into commerce in

the United States must include increasing amounts of cellulosic biofuels (a subset of advanced biofuels) as part of the Renewabl e Fuel Standard. By 2015, the EISA requires that transportation fuels contain at leas t 3.0 billion gallons of cellulosic biofuel. In 2020, the mandated volume of cellulosic biofuel s increases to 10.5 billion gallons. By 2022, 16.0 billion gallons of tr ansportation fuels must come from cellulosic feedstocks. Corresponding EISA-mandated volumes of adv anced biofuels for 2015, 2020, and 2022 are 5.5, 15.0, and 21.0 billion gallons, respectively.

Given the progress in current research and development efforts and the EISA mandate of at least 3.0 billion gallons of cellulosic biofuel (5.5 b illion gallons of advanced biofuel) in 2015, staff is optimistic that significant volumes of cellulosic ethanol can be produced by 2015.

2. Lignocellulosics to Renewable Diesel

Biomass feedstocks including lignocellulosic crops, crop residues, and wastes can be converted into diesel-range hydrocarbons. T he two main pathways for the conversion

of biomass into renewable dies el include the pyrolysis and hydrotreatment process to make bio-oil and the gasification and Fische r-Tropsch (F-T) process to produce F-T

diesel. Bio-oil and F-T fuels can be upgraded into gasoline or diesel-range hydrocarbons (renewable gasolin e or renewable diesel fuel). In general, the processes using biomass feedstocks to produce renew able diesel are more complex and less commercialized than those used to produce biodie sel from virgin plant oils and animal fats. However, the processing through lignoc ellulosic pathways, especially for wastes,

can result in lower-car bon-intensity fuels.

3. Lignocellulosics to Renewable Gasoline

As with renewable diesel, biomass feedsto cks including lignocellulosic crops, crop residues, and wastes, can be converted into gasoline-range hydrocarbons. The two main pathways for the conver sion of biomass into renew able gasoline include the pyrolysis and hydrotreatment process to ma ke renewable gasoline and the gasification and Fischer-Tropsch (F-T) proce ss to produce F-T gasoline. As with renewable diesel, the processing through lignocel lulosic pathways, especially for wastes, can result in lower-carbon-intensity-fuels.III-17 4. Classic Fischer-Tropsch Fuels

Synthetic liquid fuels are produced from foss il-fuel resources t hat cannot reasonably be classified as petroleum. The two fuels di scussed here are natural gas-based synthetic fuels (also called gas-to-liquids, GTLs, or GTL synfuels) and coal-based synthetic fuels (also called coal-to-liquids, CTLs, or CTL synfuels). The classic Fischer-Tropsch process is a catalyzed chemical reaction in which synthesis gas, a mixture of carbon monoxide and hydrogen, is conv erted into liquid hydrocarbons of various forms. Many refinements and adjustments have been made to t he original process invented in the

1920s.

a. Coal to Liquids

The production of CTL fuels begins with coal as a raw material or feeds tock. In indirect coal liquefaction, prepared coal is subject ed to heat and pressure in the presence of steam and oxygen to create a syn thesis gas. The synthesis gas is treated to remove impurities and is sent to a high-temper ature (300-350 degrees Ce lsius) or a lowtemperature (200-240 degrees Celsius) Fisc her-Tropsch (F-T) reactor. A lowtemperature reactor is used to maximize t he production of renewable diesel, while the other is used to maximize renewable gasoli ne production. The syngas must be cleaned by removing sulfur halides and nitrogen befor e it enters the reac tor because they will poison the F-T catalyst which is usually made of iron or cobalt. F our different types of beds have been used commercially, including mu lti-tubular fixed bed, circulating fluidized bed, fixed fluidized bed, and fixed slurry bed reactors.

Commercialization Status - CTL

Sasol in South Africa has been producing coal -derived fuels using F-T technology since 1955. The total capacity of the South Afri can CTL operations now stands in excess of 160,000 barrels per day of pr oduct. There are a number of CTL projects around the world at various stages of development, t he most advanced being in China, the U.S.,

and Australia.

b. Gas to Liquid (GTL) Fuels

Gas-to-liquid (GTL) fuels are fuels derived by converting natural gas into longer-chain hydrocarbons by the low temperature Fische r-Tropsch process to produce diesel range fuels and co-products for the California mark et.(41) The GTL process is an umbrella term for a group of technologies that conver t natural gas into these products. The processes are based on those first conducted by Sasol’s plant mentioned above that uses natural gas as a feeds tock for the F-T process.

The GTL conversion process involves reforming the natural gas feedstock, and converting it into a syngas rich in hydrogen and carbon monoxide. The syngas is thenIII-18 run through the F-T reactor. The products from the F-T r eactor are then separated into GTL diesel, naphtha, lubricant ba se oils, and normal paraffin.

Project proponents for GTL have claimed that their GTL products are low in sulfur and aromatics and in many cases have a lower carbon intensity than conventional refinery analogues. The low sulfur and aromatics resu lt in a superior emission profile for GTL

diesel.

D. Long-Term Technologies Projected after 2020

This section discusses the f uels and conversion technologies which are expected to be

available on a commercial scale after 2020. In addition, a discussion of carbon capture and geologic sequestration is in cluded in this section.

1. Biofuels from Algae

The overall potential of biofuel production fr om algae is significant. It is generally accepted that approximately half of the global biomass originates in the oceans.(42) Algae use the energy from sun light to produce simple sugar s, then convert these simple sugars into oils or complex carbohydrates, and store these substances in cells. Cultivation of algae can be the route to mult iple bioenergy sources and an especially effective way to reduce greenhouse gas emissi ons. Potential algal-derived fuels include biodiesel, ethanol, Fischer-Tropsch fuels, hydrogen, alkanes, and methane. Typically, oils from microalgae (microsc opic) are the feedstock for biodiesel production, whereas polysaccharides from macroalga e (seaweed) are the feedsto ck for ethanol. However, the biomass fraction of microalgae can also be converted to ethanol and other biofuels.(3) Current research and development efforts in t he U.S. have largely focused on microalgae as a source of oils. Several s pecies produce high oil yields that greatly outweigh yields from conventional crops.(3)

There are significant environmental benefit s from cultivating algae for biofuel production. Algae fix atmospheric CO 2 normally but may also sequester CO 2 in waste streams from power plants, refi neries, or other industrial sour ces. Algae can thrive in

small areas of land that are unsuitable for c onventional crops, using high salinity water that is unfit for agricultural or domestic use. Algae also hav e value in managing

nutrients in wastewater treatm ent. Cultivation of algae may provide multiple benefits concurrently. For example, production of algae in conjunction with wastewater treatment (with CO 2 addition from combustion emission s) has the potential of fixing

CO 2 , removing soluble nitrogen and phosphorous in the wastewater, and producing O 2 , as well as generating bioma ss for biofuel feedstock.

Biofuel production from algae ha s been a continuous topic of research since the 1970s. The DOE investigated algae-to-b iofuel production in the A quatic Species Program from

the late 1970s to 1996. There are a number of companies conducting research using pilot-scale projects to pr oduce fuels from algae. These projects include using openIII-19 ponds to grow algae, using bi oreactor system s that feed CO 2 combustion emissions to algae, and using algae grown in wa ter systems to produce biofuel.

Although research is progressing, there ar e still a number of hur dles that must be overcome before commercial production of biof uels from algae is a reality. Algae have particular culture requirements that must be met in order to produce near their theoretical potential. Maintaining require ments for optimal algal growth can be a challenge. For example, light conditions ch ange as the density of cultures increases, which can limit the ability of the algae to conv ert sunlight into biomass. Solutions to problems so far have been specific rather th an general in applicati on. As research progresses, there are opportunities for breakthroughs, but it appears that the technology will not be fully commercialized until sometime after 2020. Harvesting, oil extraction, and cell-wall deconstruction for sugars still present technical and economic hurdles.(3) To date, there are no commerc ially operating algae-to-biofuel production facilities in

California.

2. Butanol

Butanol is a four-carbon alcoho l that is typically derived from petroleum refining and is

used as an industrial solvent and an intermediat e feedstock for the manufacture of other

chemicals. This section discusses the feedstocks, pathways, and commercialization status of butanol produced fr om biomass. Efforts are being made to commercialize biobutanol for use in blends with gasoline to be offered for sale within California. The

benefits of biobutanol as an alte rnative fuel are recognized through its explicit mention

in the Renewable F uel Standard in EISA.

The properties of biobutanol make it amenable to blending with gasoline. It is also compatible with ethanol bl ending and can improve t he blending of ethanol with gasoline.(43) As a renewab le fuel, butanol has a number of advantages over ethanol. Butanol has higher energy density than ethanol, can be mixed with gasoline in more flexible proportions than ethanol, and is less corrosive, less volatile, and less water soluble than ethanol. As a result, butanol can be transported through existing fuel pipelines. However, the incomplete combus tion of butanol can result in small amounts of butyric acid, which has a strong odor.(3)

a. Feedstocks

Biobutanol can be produced from the same feedstocks as ethanol. Any biological feedstock that contains sugar or that c an be broken down into simple sugars is a potential source for biobutanol production via fermentation. The three main types of biomass feedstock for biobutanol production pathw ay are starch from corn, sugars from sugar crops, and biomass containing cellulose.

The easiest way to produce butanol via fe rmentation is to begin with sugar-producing plants like sugarcane or sugar beets. The sugar syrup obt ained when the feedstock is pressed can be fermented with minimal processing. In contrast, corn contains starch, aIII-20 polymer of glucose, which must be broken apart before the sugar can be fermented, requiring more energy input. The third type of biomass feedstock contains cellulose, such as trees, grasses, wood wastes, etc. The cellulose in these feedstocks is part of a lignocellulosic composite in the cell walls that resists degradation. Hence, more energy is required break down this feedstock to it s component sugars than with corn or sugar

crops.

b. Conversion Technology

Several conversion technologies exist to pr oduce butanol from biomass, including biochemical mechanisms (fermentation) and thermochemical mechanisms (gasification followed by a mixed alcohol reactor). However, alcohols derived from biomass (including butanol) are generally produced th rough fermentation. The traditional fermentation pathway that yields butanol is known as clostridial acetone butanol ethanol (ABE) fermentation. The ABE fermentat ion process to produce butanol has been known since World War I and was commonly used until the 1950s, when butanol derived from petroleum refining became widel y available and more cost effective. During the oil crisis of the 1970s, interest resumed in biobutanol production for a while and then waned by the 1990s. At present , due to environmental and economic concerns, active research is again under way to improve the technology and costeffectiveness of biobutanol production.

The ABE pathway produces n-butanol, one of f our possible butanol isomers. As the name of the fermentation pathway implies, in addition to butanol, acetone and ethanol are co-products. Hydrogen is also a co-produc t of ABE fermentation. Historically, a few naturally occurring species of the bacterial genus Clostridium were used in the ABE fermentation process. Howe ver, recent advances in gen etic engineering have produced other types of microorganisms capable of ma king butanol. For example, researchers have demonstrated that genetically al tered strains of the common yeast Saccharomyces cerevisia e (the yeast used for ethanol production) can produce butanol through the ABE fermentati on process.(44)

In addition to ABE fermentation, other fermentation pathways with proprietary microorganisms are under research and dev elopment to produce butanol (n-butanol and other isomers). One pr oject has demonstrated a pat ented dual-pathway process that eliminates the co-products produced by the ABE fermentation process. This dualpathway process uses carbohydrates to produc e butyric acid in the first stage, which is

then converted to butanol in the second stage.(45)

c. Commercialization Status

Biobutanol production is current ly being demonstrated in sma ll-scale plants, often in association with universities. BP/DuPont, ButylFuel, and other groups are conducting research and development efforts to impr ove conversion technology and cost
effectiveness. Staff is not aware of any facility producing biobutanol on a commercial basis. Although there are opportunities for breakthroughs, it appears that the technology will not be fully commercia lized until sometime after 2020.III-21 Biobutanol could be produced from new plants using corn and sugar crops (sugarcane, sugar beets, sweet sorghum, molasses) or by making modest retrofits to existing ethanol plants. As the technology develops, production of biobutanol could be extended to include lignocellulosic feedstocks.

The Energy Independence and Security Act of 2007 provides an incent ive for biobutanol production. The EISA includes butanol or other alcohols as produced through the conversion of organic matter from renewabl e biomass in the “Advanced Biofuel” category description. EISA definitions specif y all corn-based ethanol as a conventional biofuel. However, corn-based butanol woul d be able to qualify for the Advanced Biofuel category, provided that it was able to m eet the 50-percent reduction in lifecycle greenhouse gas performance from baseline gasoline.

3. Carbon Capture a nd Geologic Sequestration

Carbon capture and geologic se questration (CCS) is the process of capturing CO 2 and then compressing, transporting, and injecting it into a suitable geologic formation for long-term isolation from the atmo sphere. Alternatively, the CO 2 could be sequestered in novel ways, such as industrial fixation of CO 2 into inorganic carbonates. Separation technologies used for carbon ca pture adsorption, absorpti on, membranes, cryogenics, and others. The level of development, cost, and efficiencies vary; breakthrough advances would greatly im pact CCS viability.

Large stationary sources of ca rbon dioxide, such as refi neries and power plants are
most viable candidates for CCS. Gasoline and diesel produced from such refineries could receive lower lifecycle carbon intensity values under the LCFS.III-22 THIS PAGE LEFT INTENIONALLY BLANKIV-1 

### IV. Determination of Ca rbon Intensity Values

A. Summary

This Chapter describes the methods used to determine the carbon intensity values and presents proposed carbon intensity values fo r a number of common pathways. This Chapter also presents prelim inary data for additional fuel pathways, identifies fuel pathways currently under development, explains the adjustment factor s used to account for vehicle power train efficiencies, and di scusses the process of accounting for GHG emissions that occur over a period of time rather than at a discr ete point in time.

The LCFS regulatory framewor k builds upon estimates of t he carbon intensity (CI) of each fuel pathway. ‘Carbon intensity’ is a measure of the greenhouse gas emissions per unit of fuel energy delivered. In the LC FS regulation, the units used are grams of carbon dioxide equivalent per megajoule (gCO 2 e/MJ). Carbon intensity estimates play a key role in determining whether a regulat ed party has complied with the LCFS rule. Therefore, it is important that the methods used for assi gning carbon intensity values accurately reflect the multiple steps involved in producing and using a fuel.

Carbon intensity is determined using lifecycle analysis (LCA). LCA is an analytical method for estimating the aggregate quantity of greenhouse gas emissions from a full fuel cycle. In general, the lifecycle analysis in cludes the direct effects of producing and using the fuels and “indirect” effects that may be associated with the particular fuel.

The direct effects typically include f eedstock generation or extraction; feedstock conversion to finished fuel or fuel blendstock; distribution; storage; delivery; and final use of the finished fuel by the end user. Direct effects are responsible for the generation of several species of GHGs, including CO 2 , CH 4 , N 2 O, VOC and CO.

Non-CO 2 species are adjusted to account for t heir global warming poten tial, relative to carbon dioxide. The combined global warming potential of all GHGs emitted during the fuel cycle comprise that portion of a fuel’s carbon intensity value a ttributable to direct

effects.

To reflect the full impact of producing and using a fuel, at least some CI values must be adjusted to account for indirect effects that are not among the direct effects captured through LCA. One important i ndirect effect is land use change. Indirect land use change produces GHG emissions above and bey ond those generated during the direct fuel life cycle. In general, a land use chang e occurs when farmland devoted to food and feed production is diverted into biofuel crop production causing supplies of the displaced food and feed crops to be reduced. Supply reduc tions cause prices to rise, which, in turn, stimulates increased food and feed producti on. If that production takes place on land formerly in non-agricultural uses, an indi rect land use change impact results. The specific impact consists of the CO 2 released to the atmosphere when converted lands

are cleared and the soils distur bed. Although some of thes e releases are essentially immediate, some continue for several years. Land use change impacts can occur domestically, and in countries that trade with the U.S. Some of the food and feed cropsIV-2 which these trading partners can no longer im port from the U.S. are grown on lands converted from non-agricultural to agricultural uses.

Although not specifically calculated as par t of the lifecycle analysis, the power train efficiency of the vehicles affects the overall ca rbon intensity of a fuel and its ultimate use in the LCFS. These adjustments are made using an Energy Economy Ratio (EER).

The EER is defined as the ratio of the miles traveled per unit energy input for a fuel of interest to the miles traveled per unit energy fo r a reference fuel. Each EER is specific

to one fuel-vehicle combination. The deriv ation and use of EERs are described briefly this Chapter and presented in more detail in Appendix C.

Table IV-1 presents a summary of the carbon intensities for a number of pathways for gasoline and fuels that substitute for gasolin e. As identified in the table, the carbon intensities have been adjusted by the EERs, where appropriate, to provide an indication

of the relative carbon intensities of various pathways. This table does not represent the full range of possible fuels that could be used in the LCFS. As discussed later in this Chapter, staff is continuing to develop carbon intensity values for additional pathways and the proposed regulation itself provides for a public process to modify or add other pathways. Table IV-2 presents similar data for diesel and fuels that substitute for diesel

fuel.

The Chapter is divided into three basic sections. The first section discusses the analysis for determining direct effects. The second section discusses the analysis for determining indirect effects. The C hapter concludes with a discussion of the uncertainties associated with the analysis, with an emphasis on the analysis of indirect effects. Appendix C provides additi onal details supporting the analysis.IV-3 Table IV-1 Adjusted Carbon Intensity Values

for Gasoline and Fuels that Substitute for Gasoline

Carbon Intensity Values (gCO 2 e/MJ)

Fuel Pathway Description Direct

Emissions Land

Use or

Other

Effect Total

CARBOB – based on the average crude oil delivered to California refineries and average California refinery

efficiencies 95.86 0 95.86

CaRFG-CARBOB and a blend of 100% average Midwestern corn ethanol to meet a 3.5% oxygen content by weight blend (approximately 10% ethanol) 96.09 --- 96.09 1 Gasoline

CaRFG-CARBOB and a blend of an 80% Midwestern average corn ethanol and 20% California corn ethanol (dry mill, wet DGS) to meet a 3.5% oxygen content by weight blend (approximately 10% ethanol) 95.85 --- 95.85 1

Midwest average; 80% Dry Mill; 20% Wet Mill; Dry
DGS 69.40 30 99.40

California average; 80% Midwest Average; 20% California; Dry Mill; Wet DGS; NG 65.66 30 95.66

California; Dry Mill; Wet DGS; NG 50.70 30 80.70 Midwest; Dry Mill; Dry DGS, NG 68.40 30 98.40
Midwest; Wet Mill, 60% NG, 40% coal 75.10 30 105.10 Midwest; Dry Mill; Wet, DGS 60.10 30 90.10 California; Dry Mill; Dry DGS, NG 58.90 30 88.90 Midwest; Dry Mill; Dry DGS; 80% NG; 20% Biomass 63.60 30 93.60 Midwest; Dry Mill; Wet DGS; 80% NG; 20% Biomass 56.80 30 86.80 California; Dry Mill; Dry DGS; 80% NG; 20% Biomass 54.20 30 84.20 Ethanol from

Corn

California; Dry Mill; Wet DGS; 80% NG; 20% Biomass 47.40 30 77.40

Ethanol from Sugarcane Brazilian sugarcane using average production

processes 27.40 46 73.40

California NG via pipeline; comp ressed in California 67.70 0 67.7 1

North American NG delivered via pipeline; compressed in California 68.00 0 68.00 1 Compressed

Natural Gas Landfill gas (bio-methane) cleaned up to pipeline quality NG; compressed in California 11.26 0 11.26 1

California average electricity mix 124.10 0 41.37 2
Electricity California marginal electricity mix of natural gas and renewable energy sources 104.70 0 34.90 2

Compressed H 2 from central reforming of NG 142.20 0 61.83 3

Liquid H 2 from central reforming of NG 133.00 0 57.83 3

Compressed H 2 from on-site reforming of NG 98.30 0 42.74 3 Hydrogen SB 1505 Scenario; Compressed H 2 from on-site reforming with renewable feedstocks 76.10 0 33.09 3

1 Adjusted by an EER factor of 1.0 to account for no po wer train efficiency improvements over gasoline engines

2 Adjusted by an EER factor of 3.0 to account for power train efficiency improvements over gasoline engines

3 Adjusted by an EER factor of 2. 3 to account for power train efficiency improvements over gasoline enginesIV-4 Table IV-2 Adjusted Carbon Intensity Values

for Diesel and Fuels that Substitute for Diesel

Carbon Intensity Values (gCO 2 e/MJ) Fuel Pathway Description Direct

Emissions Land Use

or Other

Effect Total

Diesel ULSD – based on the average crude oil delivered to California refineries and average California refinery efficiencies 94.71 0 94.71

California NG via pipeline; compressed in

California 67.70 0 75.22 1

North American NG delivered via pipeline; compressed in California 68.00 0 75.56 1 Compressed

Natural Gas Landfill gas (bio-methane) cleaned up to pipeline quality NG; compressed in California 11.26 0 12.51 1

California average electricity mix 124.10 0 45.96 2

Electricity California marginal electricity mix of natural gas and renewable energy sources 104.70 0 38.78 2

Compressed H 2 from central reforming of NG 142.20 0 74.84 3

Liquid H 2 from central reforming of NG 133.00 0 70.00 3

Compressed H 2 from on-site reforming of NG 98.30 0 51.74 3
Hydrogen SB 1505 Scenario; Compressed H 2 from onsite reforming with renewable feedstocks 76.10 0 40.05 3

1 Adjusted by an EER factor of 0. 9 to account for power train efficiency losses compared to diesel engine

2 Adjusted by an EER factor of 2.7 to account for po wer train efficiency improvements over heavy-duty diesel engines

3 Adjusted by an EER factor of 1.9 to account for po wer train efficiency improvements over heavy-duty diesel engines

B. Direct Effects Analysis

1. Fuel Pathways

Determining the carbon intensity of a particu lar fuel requires that each step in the production and use of that fuel be fully characte rized. These steps comprise the direct effects associated with a fuel pathway. The production of ethanol from corn, for example, involves many steps, each of which contributes to that fuel’s ultimate carbon intensity value. Those steps include:

• Farming practices (e.g., frequen cy and type of fertilizer used);

• Crop yields;

• Harvesting practices;

• Collection and transportation of the crop;

• Type of fuel production process (technol ogy, efficiency of plant/process, etc.);

• Fuel used in the production process (Coal/Natural Gas/Biomass);

• Energy efficiency of the production process;IV-5 • The value of co-products generated (e.g. distillers grain);

• Transport and distribution of the fuel; and

• Combustion of the fuel in vehicles.

Once the pathway is fully characterized, t he carbon intensities of each of the steps can be summed to generate a fuel’s total direct ca rbon intensity. As discussed in the next section, any effects beyond those included in the direct fuel pathway analysis are then

added to the direct effects to obtain the total carbon intensity value for the fuel pathway.

The success of the LCFS at reducing fuel carbon intensity depends upon the extent to which it is able to encourage the development and use of low-carbon alternative fuels. The regulation does not, however, specify whic h fuels will and will not comply. Instead,

the carbon intensities of all f uels, including the reference f uels (gasoline and diesel fuel) are determined, and made available to fuel suppl iers for use in determining compliance. Suppliers are free to use these values, or to propose (using a process described in the regulation) different values.

Table IV-3 identifies the fuel pathways t hat have been completed and are proposed for approval as part of this rulema king. Note that most of t he default fuel pathways include one or more sub-pathways. These sub-pathw ays provide carbon intensity defaults for fuels produced using processes that deviate somewhat from the process used for the primary pathway. Under the corn ethanol pathway, for example, the sub-pathways identified vary according to the fuel used in the production process (natural gas, coal, biomass), the type of technology used (wet mill or dry mill), and t he type of co-product generated (dry distillers grain, wet distillers grain). The supporting documentation for each of these pathways is described in deta il on the ARB website and is incorporated by reference into this Staff Report ( http://www.arb.ca.gov /fuels/lcfs/lcfs.htm ).

Table IV-4 presents other pathways that are under development an d references any supporting preliminary documentat ion that may be available. Pursuant to the proposed regulation, the Executive Officer may appr ove new or modified pathways following a formal public comment period. New or modified pathways may be developed in response to public comments or staff-ident ified need. These analyses represent the

default values for the LCFS. In addition, as discussed in Chapter V, the proposed regulation allows regu lated parties to modify or s ubmit new pathways under specified

conditions.IV-6 Table IV-3 Fuel Pathways Completed for Use in the LCFS

Fuel Pathway Description of the Pathway

CARBOB (California Reformulated

Gasoline Blendstock for Oxygenate Blending) 1 average pathway based on the average crude oil used in
California refineries. http://www.arb.ca.gov/fuels/lcfs/022709lcfs_carbob.pdf

CaRFG (California Reformulated Gasoline) 1 specific pathway combining CARBOB and a blend of an average Midwestern corn ethanol and California corn ethanol to meet a 3.5% oxygen content by weight (approximately 10% ethanol). http://www.arb.ca.gov/fuels/lcfs/022709lcfs_carfg.pdf

Ethanol from Corn 11 different specific pathways that reflect different options that are used to produce ethanol from corn. http://www.arb.ca.gov/fuels/lcfs/022709lcfs_cornetoh.pdf

Ethanol from Sugarcane 1 specific pathway for producing ethanol from sugarcane using average production processes. http://www.arb.ca.gov/fuels/lcfs/022709lcfs_sugarcane.pdf

Electricity 2 specific pathways representing average and marginal electricity used in California. http://www.arb.ca.gov/fuels/lcfs/022709lcfs_elec.pdf

Hydrogen 4 specific pathways reflecting different options to produce hydrogen as a fuel. http://www.arb.ca.gov/fuels/lcfs/022709lcfs_h2.pdf

ULSD (Ultra Low Sulfur Diesel) 1 average pathway based on the average crude oil used in
California refineries. http://www.arb.ca.gov/fuels/lcfs/022709lcfs_ulsd.pdf

Compressed Natural Gas 3 specific pathways reflecting different options to produce compressed natural gas as a fuel. http://www.arb.ca.gov/fuels/lcfs/022709lcfs_cng.pdfIV-7 Table IV-4 Fuel Pathways Under Development for Use in the LCFS

Fuel Pathway Description of the Pathway

Brazilian sugarcane using bagasse for electricity production as a co-product credit Ethanol from Sugarcane Brazilian sugarcane using mechanized production of

sugarcane Farmed trees using a fermentation process. Preliminary

documentation: http://www.arb.ca.gov/fuels/lcfs/022709lcfs_trees.pdf Agriculture Waste Ethanol from Cellulosic Material

Forest Waste. Preliminary documentation: http://www.arb.ca.gov/fuels/lcfs/022709lcfs_forestw.pdf Midwest soybeans to soy oil for conversion to biodiesel (fatty acid methyl esters - FAME)

. Preliminary

documentation: http://www.arb.ca.gov/fuels/lcfs/022709lcfs_biodiesel.pdf Yellow grease, fats, and waste oil for conversion to biodiesel (FAME) 1 Biodiesel

Palm oil from South East Asia for conversion to biodiesel (FAME) Midwest soybeans to soy oil for conversion to renewable diesel. Preliminary documentation: http://www.arb.ca.gov/fuels/lcfs/022709lcfs_rd.pdf Renewable Diesel Yellow grease, fats, and waste oil using co-fed stream into refinery or bio-refinery for conversion to renewable diesel 1
Remote LNG shipped to Gulfport, Texas; regasified and pipelined to California; CNG in California. Compressed Natural Gas Remote LNG shipped to Baja, CA; regasified and pipelined to California; CNG in California.

Crude Derived from oil sands.

Derived from oil shale. Canadian NG via pipeline to LNG liquefaction facility in California; liquefied in CA for use as LNG. Remote LNG shipped to Baja, CA; gasified and pipelined to California; liquefied in California for use as LNG. Remote LNG shipped to Baja, CA; LNG trucked to

California for use as LNG. Liquefied Natural Gas

LNG from landfill gas. http://www.arb.ca.gov/fuels/lcfs/022709lcfs_lpg.pdf

1 Staff has prepared a very preliminary estimate of 15 gCO 2 e/MJ for biodiesel and renewable diesel produced from waste fats and oils. This estimate wa s used in the diesel compliance scenarios found in Chapter VI, but will not be used for regulatory purposes. Once a revised value, sufficient for use in the Regulation, is available, Staff will publish that value. Details of the preliminary analysis are available on
the LCFS websiteIV-8 2. Methodology

As discussed above, an LCA of a transportation fuel evaluates the complete energy use and associated GHG emissions for all steps in fuel production and use cycle. LCA analysis typically consists of two stages. T he first evaluates the steps leading up to the dispensing of the finished fuel (or blendstock) into the vehicl e’s fuel tank. The second stage assesses the combustion of the fuel or fuel blendstock in the vehicle. 26 The following discussion presents the basic methodol ogy for calculating the direct effects

and the related carbon intensities fo r the LCFS fuel pathways.

As discussed in Chapter II, the Energy Commi ssion, in partnership with ARB, developed and adopted the State Alternativ e Fuels Plan in 2007, pursuant to the requirements of AB 1007. In support of the Plan, the CEC conducted an extensive LCA for transportation fuels under contra ct with TIAX LLC.(1) This analysis formed the basis for the LCA analyses performed for the LCFS. Since that time, ARB staff has been working closely with the Energy Commission, Life Cycle Associates, TIAX, and other stakeholders to update and augment the LCA done for the State Alternative Fuels Plan. In general, existing pathways have been updated and new pat hways added.

For both the AB 1007 effort and the LCFS, the bas ic analytical tool for identifying and combining the necessary fuel life cycle data and calculating the direct effects has been the “Greenhouse Gases, Regulated Emission s, and Energy Use in Transportation” (GREET) model.(46) Dr. Michael Wang, of the U.S. Department of Energy’s Argonne National Laboratory, began dev eloping the GREET model in 1996. Dr. Wang and his colleagues have updated the model several ti mes since then—most recently in September 2008.

For purposes of AB 1007 and the LCFS, the model has been modified to better represent California conditions. This revised version of t he Argonne model is referred to as the California-modified GREET (CA-GREET). The version used to determine LCFS

fuel carbon intensities is version 1.8b. The CA-GREET model is posted on the ARB website and is incorporated by refe rence into the St aff Report.(47)

a. General Description of the CA-GREET Model

The CA-GREET model, like the original GREET model, was developed in Microsoft Excel. The CA-GREET Excel spreadsheet is pub licly available at no cost. The model is a sophisticated computational spreadsheet, with thousands of inputs and built-in values that feed into the calculation of energy input s, emissions, carbon intensities, and other values. The model has two parallel branche s. The first evaluates the energy use and

26 These two stages are often referred to as Well- to-Tank and Tank-to-Wheels. The Well-to-Tank analysis includes all steps from recovery or producti on of the feedstock, transpor t of the feedstock to the production facility, production of the fuel, and blendi ng and transport of the finished fuel to the retail

service station for distribution to the vehicle tank. For biofuels, this stage is sometimes referred to as “Seed-to-Tank.” The Tank-to-Wheel analysis includ es the use of the fuel in an automobile. Together

WTT and TTW are combined to create a Well-To-Wh eel (WTW) analysis of transportation fuels.IV-9 GHG generation from the recovery, production and final use of a fuel in a transportation vehicle (the fuel cycle). A more recent branch addresses the ener gy used for vehicle production (the vehicle cycle). The GREET fuel cycle evaluation framework was developed using industrial process informati on from several industries, including agriculture, power generation, and petroleum extraction and refining. This framework establishes the data requirements and the calc ulations necessary for the determination of energy use, emissions- generation, and—ultimately—fuel carbon intensity. The default values used by the program (many of which can be overridden by the user) are

derived from the same source s. For purposes of carbon intensity determination under the LCFS, ARB staff used only the fuel cycl e branch of the model. The GREET model has over 100 different fuel pathways and over 70 vehicle/fuel combinations.

In general, each fuel pathway is modeled in GREET as the sum of the GHG emissions resulting from the followin g sequence of processes:

• Feedstock production (e.g., production of cr ude for gasoline and diesel, of corn or other biomass for ethanol, etc.);

• Feedstock transportation, storage, and distribution (T&D);

• Fuel production (e.g. gasoline producti on at refineries, et hanol production at ethanol plants, etc.);

• Fuel transportation, storage, and distribution (T&D); and

• Fuel combustion in a vehicle.

The CA-GREET modifications are mostly rela ted to incorporating California-specific conditions, parameters, and data into the or iginal GREET model. The major changes incorporated into the CA-G REET model are listed below:

• Marine and rail emissions reflect in- port and rail switcher activity with an adjustment factor for urban emissions;

• Natural gas transmission and distribution lo sses reflect data fr om California gas utilities;

• The fuel properties data for CARBOB, ul tra-low sulfur diesel (ULSD), California reformulated gasoline, natural gas, and hydrogen were revised to reflect California-specific parameters;

• The electricity transmission and distributi on loss factor was co rrected to reflect California conditions; the electricity mi x was also changed to reflect in-State conditions, both for average and marginal electricity mix;

• The California crude oil recovery effici ency was modified to reflect the values specific to the average crude used in Ca lifornia including crude that is both produced in, and imported into, the St ate (See Appendix C for details);

• Crude refining for both CARBOB and UL SD was adjusted to reflect more stringent standards for thes e fuels in California;

• Tailpipe CH 4 and N 2 O emission factors were adapted for California vehicles where available;

• The process efficiencies and emission fa ctors for equipment were changed to reflect available California-specific data; andIV-10 • Landfill gas to CNG pathway was coded into the CA-GREET pathway.

b. Calculation of Carbon Intensity

Carbon intensity as proposed for the regulat ion is a measure of the greenhouse gas emissions per unit energy of fuel. As discu ssed earlier, it includes contributions from

direct emission for all fuels and from indirect effects for some fuels. Discussed below is the methodology of how carbon intensity is calculated for direct effects using the CA-GREET model. The methodology for indire ct effects is presented later in this Chapter.

Figure IV-1 Block Diagram for the various Components for a Fuel Pathway

Figure IV-1 presents the compon ents that are representative fo r either a fossil or biofuel being considered for inclusion under the regulation. The components on the left are

those that contribute to t he direct emissions and are calculated using the CA-GREET model. The individual components include l and use or feedstock recovery (includes farming, crude extraction, transportation of f eedstock, etc.), processing (conversion to ethanol, refining to gasoline, etc.), transportati on and distribution of the fuel for final use,

and use of the fuel in an internal combus tion engine. The component on the right includes land use change and is di scussed later in this Chapter.

Carbon Intensity for Biofuels:

As an example for biofuel pathway, details of the process of calculating carbon intensity for a corn ethanol pathway is presented bel ow. For corn ethanol, land use includes farming operations, agricultural chemicals pr oduction and use, and transport of corn to an ethanol production plant. The CA-GREET m odel utilizes an average energy use for farming obtained by survey data conducted by the United States Department of 

### + + + - Co-products

T&D -

Processing/ Refining +

Combustion Total
Carbon Intensity

Land Use Change Feedstock Recovery/

Land Use Total

Direct

EffectsIV-11 Agriculture (USDA). The average energy use is calculated by using the energy used by

individual entities such a trac tors, electric motors, etc. This value was determined by conducting a survey of farming practices in several corn farming regions. The CA-GREET model then utilizes the total energy use, the efficiency of energy use (from available published information; for a tractor, it uses published data on fuel economy for an average farm tractor), and the breakdown of energy use by resource (tractor, electric motor, etc.). This information is t hen combined with emission factors for various pollutants (CO 2 , CO, VOC, etc.) obtained from sources such as AP-42, the U. S. EPA’s MOBILE6 model, ARB EMFAC Model, Electric Power Research Institute, etc.

This analysis is conducted for all the energy s ources to provide total emissions for each of the individual po llutants. For CH 4 and N 2 O, the model converts these into CO 2 equivalent using factors published by the Intergovernmental Panel on Climate Change (IPCC)(48). The CA-GREET model also as sumes that CO and VOCs are oxidized to

CO 2 in the atmosphere and uses fact ors to convert these into CO 2 equivalent emissions. The CA-GREET pathway documents published on the LCFS detail the

conversion factors used. The individual pollutant emissions are then summed up to provide a total for this component.

For agricultural chemicals, the model uses lit erature data related to production of these chemicals and calculates energy use and attendant emissions derived from the specific energy sources and equipment used for the production and transport of agricultural chemicals to the farm. Survey data (agai n from the USDA) to estimate average fertilizer, herbicide and pesticide use in farms for producing corn is used by the model to estimate average energy used to produce thes e chemicals and the resulting emissions from the production of these chemicals.

For transportation, the model utilizes publis hed data on the modes of transporting these to a farm. They include cargo tankers (i mports), rail and heavy-duty trucks. Utilizing published data for these modes of transpor tation and weighted transportation distances, the model calculates the energy needed to tr ansport these to a farm. The attendant GHG emissions are calculated using published emission factors for the different modes of transport. For fertilizers in particular, there are N 2 O emissions resulting from the use of nitrogen based fertilizers. T he IPCC has estimated average N 2 O emissions based on nitrogen application in soil and the model uses this value to estimate N 2 O emissions

from the use of fertiliz ers. Use of lime leads to generation of CO 2 from the carbonate and this is directly calculated from the amount of carbonate in the applied lime.

For the processing component, the model ut ilizes published data for an average ethanol bio-refinery on energy requirements and types of equipment used in the refinery. As explained in the farming component section, the model calculates an average energy use, efficiency of use, and utilizes emissi on factors from published sources for the different equipment (boilers, turbines, motors , etc.) to calculate total GHG emissions from the production of ethanol (on a per MJ basis).IV-12 The next component of the dire ct emissions shown in Figure IV-1 is co-products. The pathway from feedstock to final fuel produc tion and use involves several processes and operations. These processes have the pot ential to generate products besides the primary fuel of interest. These additiona l products are termed co-products. For a current generation ethanol plant, a co-product produced is dry distiller’s grain solubles (DDGS). This can be used as a replacem ent for traditional feed for livestock. A complete lifecycle analysis requires an appr opriate GHG credit be provided to the pathway since the use of this co-product wil l displace the need to produce the displaced product. For corn ethanol, DDGS could replace feed corn that is used as animal feed. The model therefore has provided a GHG credi t to the pathway equi valent to producing 1 lb. of feed corn for every lb. of DDGS produced. Appendix C has details of co-product crediting methodologies used in the lifecycle analysis.

For transport and distribution from the et hanol plant, the model uses rail and truck transport for this component. It uses pub lished data on energy use, efficiency, and emissions for rail and trucks using diesel fuel. Distances are estimated based on transport from the Mid-Wester n U. S. to CA for ethanol produced in the Mid-West.

Trucks are considered to distribute the ethanol (blended with CARBOB) to local gas

stations. The total from each mode of trans port and distribution is summed to calculate a total for this component.

The last component is the act ual use of the fuel in an internal combustion engine. For corn ethanol, since the feedstock was produced by ‘capturing’ CO 2 from the atmosphere, the net CO 2 released from the use of ethanol is considered ‘carbon neutral’ and assigned a value of zero. Since ethano l is blended with CA RBOB for use as California Reformulated Gasoline (CaRFG), tailpipe emissions data (from ARB’s EMFAC model, the U. S. EPA’s MO BILE6, etc.) from the use of this fuel is used to calculate the GHG impact from the relevant species in tailpipe exhaust. For corn ethanol, a proportional amount is attribut ed based on the energy contributions of

ethanol in CaRFG.

The CA-GREET model then sums the totals from each of the st eps detailed above to

arrive at a carbon inte nsity expressed as gCO 2 e/MJ. This part is from the direct emissions. For detailed analysis of the co rn ethanol pathway, refer to the pathway

document on the LCFS website.

Carbon Intensity for Fossil Fuels:

As an example for a fossil fuel pathway, det ails of the process of calculating carbon intensity for the diesel pathway is pr esented below. The GREET model utilizes a recovery efficiency based on data published by the Energy Information Administration (EIA), the American Petroleum Institute (API), and other lifecycle studies. For the LCFS, however, staff obtained detailed breakdow n of crude slates used in California in 2006 (from the Energy Commission).IV-13 Crude slates are generally classified as being pr imary, secondary, or tertiary, based on the gravity of the recover ed crude. The higher the grav ity, the lighter the crude and hence the lower the energy use required to recover the crude. Crude recovered in California amounts to approximately 40 percent of all crude delivered to California in 2006. Of the crude produced in California, 40 percent requires tertiary methods to recover the crude and requires steam generation fo r the process. Therefore, the energy use is higher compared to primary extraction.

Staff used data available from the Department of Oil, Gas and Geothermal Resources (DOOGR) and the Energy Commission to estima te the energy use for crude recovered

in California. This was then combined for all crude used in California to compute an average energy use for crude used in Californ ia. The energy use was correlated to the types of energy sources utilized (coal , natural gas, etc.) and the corresponding equipment used to generate proce ss energy (turbines, motors, etc.). Emission factors for the various equipment used was obtain ed from AP-42 (U. S. EPA) and other published sources. The total GHG emissions was then calculated as detailed in the

biofuels discussion earlier in this section.

Transport of crude to California refineries is modeled as being delivered by tankers and pipeline. The energy use and corresponding emissions are obtained from published data on tanker capacity, energy consumption, etc. from sources such as the EIA, U.S. EPA and API. Carbon intensity for this component is calculated by correlating energy use for transport with the corresponding mode of transport and emission factors.

For refining, the GREET model uses published data on refining efficiency. Staff used an adjusted refining efficiency from the AB 1007 study(1) which considered stricter fuel specifications in California to require additional energy use translating to a lower efficiency. This efficiency for energy use was correlated to different energy sources and the attendant equipment used to generat e process energy and combined with respective emission factors (from AP-42, U. S. EPA, etc.) to calculate total GHG emissions (carbon intensity) for this component.

Transport and use of this fuel is similar to th e details provided for corn ethanol. For the

combustion of diesel in an internal com bustion engine, the carbon content in the fuel (from published sources such as the ARB, U.S. EPA, EIA, API, etc.) is used to estimate

the amount of CO 2 generated by complete combustion of the fuel. It then combines this with other tailpipe emission species (fro m ARB’s EMFAC model, the U.S. EPA’s MOBILE6, etc.) on a CO 2 equivalent basis to arrive at a total carbon intensity from use in an internal combustion engine. The GHG emissions from all the components

described above is summed to estimate carbon in tensity for diesel. Complete details of the calculations and pathway are provided in the pathway document for diesel on the

LCFS website. Carbon Intensity for Other Fuels:

For fuels such as electricity and hydrogen, t he CA-GREET methodology is similar. It

uses data from various sources to esti mate average energy use for feedstockIV-14 production or recovery (uranium mining, natural gas recovery , etc.). The energy use is disaggregated into types of energy sour ces and the equipment used to generate process energy. These are used to calculat e GHG emissions for th e recovery of the feedstock for any fuels. As detailed above, transport modes and their emission factors

are utilized to calculate GHG emissions for tr ansport of the feedstock. Fuel production efficiencies are estimated from published data (or for new process, modeling tools such as ASPEN(49) is utilized) and combined with energy sources and their respective
emission factors to calculate GHG emissions for the production of t he fuel. Transport

and distribution is also handled as detailed in the discussion for corn ethanol and diesel. For electricity, distribution is handled by attributing transmission losses as the energy losses related to transport and distribution.

The CA-GREET model incorporates several di fferent fuel pathways. However, for the proposed regulation, ARB staff is recommendi ng that only a subset of these pathways

be included. Staff is therefor e committed to ensuring that a ll relevant inputs, factors, etc. necessary to compute the carbon in tensities of the re commended pathways have

been locked into the model and are invariant.

Table IV-5 presents the proposed carbon int ensity values that represent the direct emissions part of the Lookup Ta ble for the proposed LCFS regul ation. For all the other pathways, until staff proposes the pathway s for approval, values, factors, carbon intensities, etc. for t hese fuel pathways cannot be utilized by stakeholders for compliance with the regulation.IV-15 Table IV-5 Proposed Default Carbon Intensity Va lues for the Direct Pathways

Fuel Pathway Description Carbon Intensity

Values (gCO 2 e/MJ)

Direct

Emissions CARBOB – based on the average crude oil delivered to California refineries and average California refinery

efficiencies 95.86

CaRFG-CARBOB and a blend of 100% average Midwestern corn ethanol to meet a 3.5% oxygen content by weight blend (approximately 10% ethanol) 96.09 Gasoline

CaRFG-CARBOB and a blend of an 80% Midwestern average corn ethanol and 20% California corn ethanol (dry mill, wet DGS) to meet a 3.5% oxygen content by weight blend (approximately 10% ethanol) 95.85

Diesel ULSD – based on the average crude oil delivered to California refineries and average California refinery

efficiencies 94.71

Midwest average; 80% Dry Mill; 20% Wet Mill; Dry DGS 69.40 California average; 80% Midwest Average; 20% California; Dry Mill; Wet DGS; NG 65.66

California; Dry Mill; Wet DGS; NG 50.70 Midwest; Dry Mill; Dry DGS, NG 68.40
Midwest; Wet Mill, 60% NG, 40% coal 75.10 Midwest; Dry Mill; Wet, DGS 60.10 California; Dry Mill; Dry DGS, NG 58.90 Midwest; Dry Mill; Dry DGS; 80% NG; 20% Biomass 63.60 Midwest; Dry Mill; Wet DGS; 80% NG; 20% Biomass 56.80 California; Dry Mill; Dry DG S; 80% NG; 20% Biomass 54.20 Ethanol from
Corn

California; Dry Mill; Wet DG S; 80% NG; 20% Biomass 47.40

Ethanol from Sugarcane Brazilian sugarcane using average production processes 27.40

California NG via pipeline; compressed in California 67.70 North American NG delivered via pipeline; compressed in

California 68.00 Compressed

Natural Gas Landfill gas (bio-methane) cleaned up to pipeline quality NG; compressed in California 11.26

California average electricity mix 124.10 Electricity California marginal electricity mix of natural gas and renewable energy sources 104.70

Compressed H 2 from central reforming of NG 142.20 Liquid H 2 from central reforming of NG 133.00 Compressed H 2 from on-site reforming of NG 98.30 Hydrogen SB 1505 Scenario; Compressed H 2 from on-site reforming

with renewable feedstocks 76.10IV-16 c. Adjustments for Vehicle Efficiencies

The carbon intensities of certain fuels need to be adjusted to account for lower (or higher) efficiencies for those fuels rela tive to baseline fuels when used in a transportation vehicle. This is captured by using an Energy Economy Ratio (EER). The

EER is defined as the ratio of the miles tr aveled per unit energy input for a fuel of interest to the miles traveled per unit energy fo r a reference fuel. For light duty vehicles, gasoline is the reference fuel. For heavy duty v ehicles, diesel is the reference fuel. The EER for each type of light duty alternative f uel vehicle was calculated by dividing the fuel economy for that vehicl e by the fuel economy for a corresponding gasoline vehicle that is most similar in size and style, referred to as the reference vehicle. EERs were calculated using test data using the fuel of interest and the reference fuel in similar engines. For areas where data was either lacking or insufficient, EERs were estimated using engineering analysis. Table IV-6 s hows the use of EERs for fuels when they substitute for gasoline and diesel in light, medium and heavy duty vehicles. Complete

details of the EER calculati ons are provided in Appendix C.

Table IV-6

EER Values for Fuels Used in Light- and Medium-Duty, and Heavy-Duty Applications

Light/Medium-Duty Applications (Fuels used as gasoline replacement) Heavy-Duty/Off-Road Applications (Fuels used as diesel replacement)

Fuel/Vehicle Combination EER Values

Relative to

Gasoline Fuel/Vehicle Combination EER Values

Relative to

Diesel Gasoline (incl. E6 and E10) or E85 (and other ethanol blends) 1.0 Diesel fuel or Biomass-based

diesel blends 1.0

CNG / ICEV 1.0 CNG or LNG 0.9 Electricity / BEV, or PHEV 3.0 Electricity / BEV, or PHEV 2.7

H2 / FCV 2.3 H2 / FCV 1.9 (BEV = battery electric vehicle, PHEV=plug-in hybrid electric vehi cle, FCV = fuel cell vehicle)

C. Indirect Effects Analysis

The lifecycle GHG-generating effects described in Section A, above result directly from the production, transport, storage, and use of a fuel. In addition to these direct effects, some fuel production processes generate GHGs indirectly , via intermediate market mechanisms. If, for exampl e, the propulsion system of an advanced vehicle requires a

certain metal that is surfaced-mined in re mote forested areas, the increased demand for that propulsion system would in crease the demand for the requir ed metal. Meeting that demand would result in the expansion of the mi nes that supply the or e for that metal. Expansion of the mines would require the cl earing of forests, and the disturbance of underlying soils—both of which releas e GHGs to the atmosphere.

Stakeholders participating in the LCFS pr ocess have suggested that most or all transportation fuels generate varying levels of indirect GHG emissions. To date,IV-17 however, ARB staff has only identified one indi rect effect that generates significant quantities of GHGs: land use change effects. A land use change effect is initially triggered by a significant increase in t he demand for a crop-bas ed biofuel. When farmland devoted to food and feed production is diverted to the production of that biofuel crop, supplies of the displac ed food and feed crops are reduced. Supply reductions cause prices to rise, which, in tu rn, stimulates increase d production. If that production takes place on land formerly in non-agricultural uses, a land use change impact results. The specific impact consis ts of the carbon released to the atmosphere from the lost cover vegetati on and disturbed soils in the periods following the land use

conversion. This section describes how AR B estimates the land use change impacts of biofuel crop production, and summarizes the impact estimates obtained to date.

1. Overview

Increasing worldwide demand for biofuels will stimulate a corresponding increase in the price and demand for the crops used to produce those fuels. To meet that demand,

farmers can:

• Grow more biofuel feedstock crops on existing crop land by reducing or eliminating crop rotations, fallow periods, and other prac tices which improve soil conditions but reduce the number of harvests over time;

• Convert existing agricultural lands from food to fuel crop production;

• Convert lands in non-agricultural uses to fuel crop production; or

• Take steps to increase yields bey ond that which would otherwise occur.

Land use change effects occur when the acreage of agricultural production is expanded to support increased biofuel production. Lands in both agricultural and non-agricultural uses may be converted to the cultivation of biofuel crops. Some land use change impacts are indirect or secondary. When biofuel crops are grow n on acreage formerly devoted to food and livestock feed production, supplies of the affected food and feed commodities are reduced. These reduced suppl ies lead to increased prices, which, in turn, stimulate the conversion of non-agricultural lands to agricultural uses. The land conversions may occur both domestically and internationally as trading partners attempt to make up for reduced imports from the Un ited States. The land use change will result
in increased GHG emissions from the rel ease of carbon sequestered in soils and land cover vegetation. These emissions constitu te the land use change impact of increased biofuel production.

Not all biofuels have been linked to indirect land use change impacts. The use of corn

stover as a feedstock for cellulosic ethanol production, for example, is not likely to produce a land use change effect. Feedstocks such as native grasses grown on land that is not suitable for agricultural produc tion are unlikely to cause land use change impacts. Waste stream feedstocks such yellow grease, waste cooking oils and municipal solid waste, are al so unlikely to lead to land use change impacts. Staff is in the process of identifying feedstocks that have no measurable land use change impacts.IV-18 Figure IV-2 depicts the process used to quant ify the GHG emissions from land use change and to convert those emissions to a carbon intensity value that can be added to a fuel’s direct carbon intensity value.

Figure IV-2 Land Use Change Impact Estimation Process

Estimating how much non-agricultural land is c onverted to agricultural uses in response to increased demand for biofuels requires a model capable of simulating the multiple economic forces driving the land use change process. Models of the international agricultural system have been adapted to esti mate the magnitude of biofuel-driven land use change impacts. The GHG emissions g enerated by the conversion of land to agricultural uses are estimated by applying emission factors to the acreage of land

converted. Emission factors are estimates of the GHGs re leased from each converted

unit of land area. GHGs are released fr om burned or decomposin g cover vegetation and disturbed soils. Land use change emissions vary substantially with time. Large initial releases of GHGs from clearing nativ e vegetation are followed by slower releases from below-ground materials. The time-varyi ng emission flows are converted to a land use change carbon intensity value us ing a time accounting model.

In Section 2, we discuss the choice of an ec onomic model, key inputs to that model, the application of emission factor s, and the process of accounting for time. Modeling results for corn and sugarcane ethanol, soy bi odiesel, and cellulo sic material are presented in Section 3, followed by a brief discussion of ongoing analyses in Section 4. Note that the results for soy biodiesel and cellulosic material are preliminary. Economic Modeling Application

of Emission

Factors Accounting

for Time LUC Carbon Intensity Increased

Demand for

Biofuel Land

Converted Estimates for

GHG

EmissionsIV-19 2. Methodology

a. Selection of the Estimation Model

The land use change effects of a large expan sion in biofuel production will occur both domestically and internationally. A sufficiently large increase in biofuel demand in the U.S. will cause non-agricultural land to be conver ted to crop land both in the U.S. and in countries with agricultural trade relations with the U.S. Models used to estimate land use change impacts must, ther efore, be international in scope. In cooperation with

researchers from the Universi ty of California, Berkeley (UCB) and Purdue University, ARB staff chose the Global Trade Analysis Project (GTAP) model for conducting the analysis. Other models considered are discussed in Appendix C.

The GTAP is a computable general equilibri um (CGE) model developed and supported by researchers at Purdue University. Wi thin the GTAP’s scope are 111 world regions, some of which consist of single countries, ot hers of which are comprised of multiple neighboring countries. Each region contains data tables that des cribe every national economy in that region, as well as all significant intr a- and inter-regional trade relationships. The data for this model is contributed and maintained by more than 6,000 local experts.

The GTAP has been extended for use in land-use change modeling by adding land use data on 18 worldwide agro-ecological zones, a carbon emissions factor table, and a coproducts table (which adjusts GHG emission impacts based on the market displacement effects of co-products such as the dri ed distillers’ grains with soluble—an ethanol production co-product). Predicted land use c hange impacts are aggregated by affected land use type (forest, and pasture).

The GTAP has a global scope, is publicly ava ilable, and has a long history of use in modeling complex inter national economic effects. Theref ore, ARB staff determined that

the GTAP is the most suitable model for es timating the land use change impacts of the crop based biofuels that will be regulated under the LCFS. The GTAP is relatively mature, having been frequently tested on large- scale economic and policy issues. It has been used to assess the impacts of a variet y of international economic initiatives, dating back to the Uruguay and Doha Rounds of the World Trade Organization’s General Agreement on Tariffs and Trade. 27 More recently, it has been used to examine the expansion of the European Union, regi onal trade agreements , and multi-national climate change accords. A detailed discussion of the indirect land use change model selection process is provided in Appendix C.

27 The Uruguay Round began in September of 1986 and concluded in April, 1994. The Doha Round began in November of 2001 and is ongoing.IV-20 b. Key Inputs to GTAP

The primary input to com putable general equilibrium m odels such as GTAP is the specification of the changes that will, by moving the ec onomy away from equilibrium, result in the establishment of a new equilibri um. Parameters such as elasticities are

used to estimate the extent which introduced changes alter the prior equilibrium. Listed below are the inputs and paramet ers that the GTAP uses to model the land use change impacts of increased biofuel production levels.

• Baseline year: GTAP employs t he 2001 world economic database as the analytical baseline. This is the most rec ent year for which a complete global land

use database exists.

• Fuel production increase: The primary input to computable general equilibrium models such as GTAP is the specification of the changes that will result in a new equilibrium.

• Land use change analysis: The primary input is the change in biofuel production expected to occur in response to feder al energy legislation and GHG emission regulations such as the LCFS.

• Crop yield elasticity: This parameter determines how much the crop yield will increase in response to a price increase fo r the crop. Agricultural crop land is more intensively managed for higher priced crops. If the crop yield elasticity is 0.25, a P percent increase in the price of the crop relative to input cost will result in a percentage increase in crop yields equal to P times 0.25. The higher the elasticity, the greater the yield increases in response to a price increase.

• Elasticity of crop yields with respec t to area expansion: This parameter expresses the yields that will be realized from newly converted lands relative to yields on acreage previously devoted to that crop. Because almost all of the land that is well-suited to crop production has already been converted to agricultural uses, yields on newly converted lands are almost always lower than corresponding yields on existing crop lands.

• Elasticity of harvested acreage response: This parameter expresses the extent to which changes occur in cropping patterns of existing agricultural land as land costs change. The higher the value, the more cropping patterns will change (e.g. soybean to corn) in response to land costs.

• Elasticity of land transformation across cropland, pasture and forest land: This elasticity expresses the extent to which expansion into forestland and pastureland occurs due to increased dema nd for agricultural land (driven by higher crop prices).IV-21 • Trade elasticity of crops: These elas ticity values express the likelihood of substitution among imports fr om all available exporters. They express the extent to which an importer will respond to a price increase for a given commodity by switching to a different exporter who can su pply the commodity at a lower price.

c. Land Conversion Emission Factors

GTAP modeling provides an estimate for the amounts and types of land across the globe that is converted to agricultural produc tion as a result of the increased demand for biofuels. The next step in calculating an es timate for GHG emissions resulting from land conversion is to apply a set of emission factors. Emission fa ctors provide average values of emissions per unit land area for carbon stored above and below ground as

well as the annual amount of carbon sequestered by native vegetation. The amount of “lost sequestration capacity” per unit land ar ea results from the conversion of native vegetation to crops. This value may be signific ant for areas with rapidly growing forests.

Staff has chosen to use emission fact or data from Searchinger et al. (2008) 28 . These

emission factors—known as the “Woods Hole ” data—include data on a wide variety of terrestrial ecosystems. A spreadsheet detaili ng emission factors used for the LCFS is located at http://www.arb.ca.gov /fuels/lcfs/ef_tables.xls.

In applying the Woods Hole emission factors, ARB assumed that 90 percent of the above-ground and 25 percent of the below-gr ound carbon is emitted over the fuel production period (50-52). The carbon that would have been sequestered in the lost cover vegetation is also included in the total emissions value. Applying these assumptions to the locations, types and am ounts of land conversion predicted by GTAP, staff calculated estima tes of the total GHG emissions from those converted land

areas.

These land use change emissions totals are used to derive the carbon intensity values appearing in the LCFS Lookup Tables. Some of the available methods for converting

emissions totals to carbon intensities ta ke time-varying emissions profiles into

consideration. These methods ar e discussed in the next section.

d. Accounting for GHG Emi ssions That Occur Over Time

As we discussed in section c above, the conv ersion of forest, grassland, or pasture to agricultural uses releases much of the carbon stored in thes e ecosystems. The releases happen over a peri od of years, as follows:

• An initial GHG burst from burning and/or decaying cover vegetation; this is referred to as the above ground release;

• A slower release of carbon from disturbed soils: larger emissions occur during the first few years, followed by declining releases. This process is referred to as the below-ground release; and

28 This data set is referred to as the “Woods Hole” data because it was compiled by Searchinger’s coauthor, R. A. Houghton, who is affiliated wi th the Woods Hole Oceanographic Institute.IV-22 • Loss of the carbon sequestration c apacity of the cleared vegetation.

Figure IV-3 shows a representative time-profi le for emissions resulting from land use change assuming a project star t date of 2010 and an end date of 2040. The above and below-ground emissions and foregone sequestrati on values used in these scenarios are for illustrative purposes only and are not final LCFS values. The spreadsheet used to perform these calculations is available at http://www.arb.ca.gov/fuels/lcfs/btime1- 1_arb.xls.(53) The land use change emissions profile depicted in Figure IV-3 assumes

that:

• All above-ground carbon is released in year one due to burning of native vegetation to clear the land for cultivation;

• The majority of below-ground release occurs over the first five years followed by

a much slower release ov er the next 15 years; and

• Forgone sequestration occurs ov er the entire pr oject period.

Figure IV-3 Representative Land Use Change Emissions Profile

Calculating the carbon intensity for a crop ba sed biofuel (e.g. corn ethanol) requires that time-varying emissions be accounted for in a manner that allows meaningful comparison with the carbon inte nsity of a reference fuel (e .g. gasoline displaced by the biofuel) which releases greenhouse gases at a rela tively constant rate over the years in which it is used. Figure IV-4 shows a r epresentative comparison of gasoline emissions 0 100 200 300 400 500

2010 2015 2020 2025 2030 2035 2040 2045 2050 2055

YearLUC Emissions (gCO2e/MJ of annualproduction)

Foregone sequestration Below ground and foregone sequestration Below ground and foregone sequestration Above and below ground and foregone sequestrationIV-23 to total biofuel emissions (direct emi ssions and land use change emissions). To compare emissions for the two fuels in the LCFS, we need to convert the time-varying biofuel emissions into an equivalent se ries of constant annual emissions.

Figure IV-4 Comparison of Corn Ethanol and Gasoline Total Emissions

0 100 200 300 400 500 600

2005 2010 2015 2020 2025 2030 2035 2040 2045 2050

YearTotal Emissions: Direct and LUC (gCO2e/MJ annualproduction) Corn ethanol emissions

Gasoline emissions

Four aspects critical to such an analysis are presented below.

• Estimating the time distribution of em ission of greenhouse gases resulting from land use change predicted by the GTAP model.

• Establishing a timeframe over which a biofuel will likely be utilized within the LCFS (project horizon). This value is ve ry important as it determines how long a biofuel has to “pay back” the land use change emissions it generates. For corn ethanol and other crop-based biofuels, staff has assum ed project horizons of 20 to 30 years. Specification of the proj ect time horizon is important because the GHG costs and benefits of a crop-based biofuel ‘project’ accrue at very different rates through time. Most of the costs generated by land use change events accrue within the first two y ears of project initiation. The benefits are relatively low, and accrue at a more or less const ant rate through time. The longer the project time horizon, the more time the benefits have to catch up with the costs. Because crop-based biofuels do not begin yi elding net benefits for many years,IV-24 ARB staff anticipate that they will be disp laced relatively quickly by fuels that provide greater benefits and do so earlie r in their project lifetimes.

• Establishing the impact horizon. The im pact horizon gives the period of time or the point in the future at which we des ire to compare the relative global warming effects of different fuels. Choosing a short impact horizon (e.g. 20 to 30 years) places an emphasis on achieving early emissions reductions which may be appropriate if one assumes that irreversib le effects of global climate change may

occur if GHG emissions are not reduced quickly. Staff has evaluated impact horizons ranging from 10 to 100 years.

• Establishing a weighting or discounting sch eme that captures the relative global warming effect of greenhouse gases released at different time s and converting that information into a meaningful single value that reasonably reflects the carbon intensity attributable to a fuel’s land use change effects. ARB staff considered

three different schemes to account for time when calculating land use change impacts for biofuels.

The first time accounting method staf f considered is an averaging approach which sums all land-use-change-induced carbon emissions over the project period, and then divides that value by the total fuel production (measured on an energy basis) over the assumed project hor izon. The resulting land use change carbon intensity value is then added to the fu el’s direct carbon intensity value.

This sum is the fuel’s total carbon in tensity under the LCFS. This method is

referred to as “annualization” in this Staff Report.

The second method utilizes a net present value (NPV) calculation to discount

future emissions so that a ton of em issions occurring today is weighted more heavily than a ton of emissions occurring in the future.

The third method—developed by researcher s at the University of California, Berkeley and the Union of Concerned Scientists(53)—calculates the Fuel Warming Potential (FWP) of GHG emissi ons. The FWP is the cumulative atmospheric warming effect of the emi ssions released over the assumed impact

horizon.

A more detailed discussion of these thr ee methods is provi ded in Appendix C.

Comparison of Time Accounting Methods:

Figure IV-5 compares the three time account ing methods considered by ARB staff. In this figure, the “additional” ca rbon intensity resulting from land use change emissions is plotted over the impact time horizon. The emi ssions plotted in this Figure are calculated

from the same data that wa s used in Figure IV-3.IV-25 Figure IV-5 Comparison of Time Accounting Methods

0 20 40 60 80 100 120

10 30 50 70 90


### Impact Horizon (years)LUC Carbon Intensity (gCO2e/MJ) 30 year Annualized Fuel Warming Potential Net Present Value (2%)

These plots show that both the FWP and NPV me thods result in larger carbon intensity values than the 30-year annualized method. This is to be expected because both methods weight early carbon dioxide emissi ons more than later emissions while the

annualized method treats all emissions over the project horizon as being equivalent.

The FWP and NPV methods also result in the calculation of large land use change carbon intensity values for short impact horizons due to the large up-front emissions associated with land use change. When ca lculated using the annualized method, carbon intensity is a function only of the project horizon: because it is independent of the impact horizon, the annualized carbon intensity value is constant over all impact horizon lengths. However, the same is not tr ue for the project horizon. As the length of the project horizon de creases, the annualized carbon int ensity value increases.

Choosing an Appropriate Accounting Method:

The land use change intensity values depicted in Figure IV-5 for impact horizons of 30 and 50 years are summarized below in Table IV-7.IV-26 Table IV-7 Land Use Change Carbon Intensity Values for Three Accounting Methods

Accounting

Method Project Horizon (years) Impact Horizon (years) LUC CI (gCO 2e /MJ)

Annualized 30 N/A 30 NPV (2%) 30 30 or more 37

FWP 30 30 48

FWP 30 50 37

The NPV method (using a 2% discount rate) yields a higher land use change impact estimate than the 30-year annualized method. This estimate is dependent on the choice of a discount rate. Choosing a discoun t rate of 5% would produce a significantly different (higher) value. Unfortunately, the relationship between the timing of GHG emissions and the damages caused by those emissions has not been established. Even if this relationship had been defined, a further relationship between damages and the choice of a discount rate would have to be worked out. This second relationship presents significant challenges because disc ounting was developed to evaluate flows of financial or economic values. Applying this technique to physical flows is far from straightforward. Given these difficulties, ARB staff ruled out the use of the NPV method in determining LCFS carbon intensity values.

The FWP method, on the other hand, was desi gned to capture the re lative atmospheric warming impacts of time-varying land use change emissions, given the choice of an appropriate impact horizon. For a 30 year impact horizon, the FWP method yields a land use change carbon intensity value higher than the annualized value. For a 50 year impact horizon, the FWP method yields a l and use change carbon intensity value which is much closer to—but still higher than—t he annualized value. As the length of the impact horizon increases, the two values continue to converge.

Of the three methods, annualizati on is the simplest to apply: it does not depend upon the development of an emissions time profil e. Total emissions are simply allocated equally over all project horizon time periods. All that is requir ed, therefore, is an

estimate of the total emissions attribut able to land use change, and the total fuel production (on an energy basis) over the assu med project horizon. As long as the project horizon used in the analysis is not ov erly long (no longer than about 30 years),

this method is reasonable to use. With l onger time periods, the use of a method that weights earlier emissions becomes necessary. A detailed discussion of the issues that must be considered when choosing a time a ccounting method can be found in Appendix

C.

For calculating land use change carbon intens ity, ARB staff has chosen to use the

annualized method. Staff will continue to ana lyze the FWP method, however, and may

reconsider this decision after a mo re thorough analysis has been completed.IV-27 3. Results and Discussion of Land Use Change Effects

In this section, we present land use change impact modeling results for corn and sugarcane ethanol. Results for each fuel include a sensitivity analysis performed on key model inputs. All land use change carbon intensity values were calculated using the annualized method and a 30 y ear project horizon.

a. Indirect Effects: Land Use Change Effects for Corn Ethanol

The corn ethanol land use change results pres ented in this section were produced using the GTAP global economic model. Table IV - 8 summarizes the key inputs for the GTAP analysis. The parameters appearing in this table are described in Appendix C.

Table IV-8 Key Inputs into the GTAP Model

Inputs/Parameters Ranges (if appropriate)

Baseline Year 2001
EtOH production increase (billion gallons) 13.25 *
Crop Yield Elasticity 0.1 to 0.6
Elasticity of Harvested Acreage Response 0.5

Elasticity of land transformation 0.1 to 0.3

Elasticity of crop yields with respect to area expansion 0.25 to 0.75

Trade elasticity 1 Std. Dev. Below and

1 Std. Dev. Above the Central Value

* One sensitivity analysis run used 8.25 billion gallons

Parameters that affect corn ethanol results from GTAP:

GTAP employed the 2001 world economic database as the analytical baseline. This is the most recent year for which a complete global land use database exists. In order to

assess the relative influence of each model input on model outputs (land conversion totals and GHG emissions), staff conducted a s ensitivity analysis. To test the model’s sensitivity to a given input par ameter, the modeler completes a series of runs in which the input parameter is varied across its full range. All other input values are held

constant.

An ethanol production increase of 13.25 billion gallons was assumed for all but one of the modeling runs. This pr oduction increment corresponds to increasing U.S. corn ethanol production from 1.75 billion gallons in produced 2001 to the 15 billion gallon volume authorized by the Energy Independenc e and Security Act of 2007 (EISA). The sensitivity of the model output to this par ameter was assessed by performing a run in which the ethanol production increase wa s set at 8.25 billion gallons. The crop yield elasticity (elasticities are described in Appendix C) was varied from 0.1 to 0.6. Based

on a review of the liter ature on corn yields, the historic al average yield response in theIV-28 U.S. had been 0.4. However, there is evidence that the corn yield elasticity has been falling over time; the most recent study produced a yield response of 0.27(54). The GTAP modelers applied a relatively high value of 0.5 for the elasticity of harvested

acreage response . The higher the value, the more cropping patterns will change (e.g. soybean to corn) in response to land costs. Va riation in this value is known to have little effect on GHG emission estimates; it was therefore not included in the sensitivity analysis. Because the available evidence indicates that land use changes across agricultural, forest, and pasture cover types are not readily triggered by changes in land costs, the elasticity of land transformation across cropland, pasture, and forestry was set to the relatively low value of 0.2 and for the sens itivity analysis it was varied

between 0.1 and 0.3.

The elasticity of crop yields with respect to area expansion expresses the yields that will be realized from newly conver ted lands relative to yields on acreage previously devoted to that crop. Based on the best availa ble professional judgment of those with experience in this area, the modelers sele cted a value of 0.50. For purposes of the sensitivity analysis, this parameter was varied from 0.25 to 0.75. GTAP modelers

estimated the trade elasticity values based on an analysis of bilateral trade data from a variety of nations in the western hemisphere. The central trade elasticity values are presented in Appendix C along with the s ensitivity analysis ranges of one standard

deviation below and one standard dev iation above the central values.

Table IV-9 shows sensitivity analysis result s obtained by independently varying the corn ethanol production increase and elasticity inputs to the model and tracking the percentage change in land use change carbon in tensity (from low input value to high input value). Sensitivities are critical to assess the performance of a model in providing reasonable outputs relative to variation in inpu t values. As an example, if outputs are highly sensitive to the volume of ethanol production increase, then the modelers would have to consider using a change that could be reasonably expected over a shorter time period. As seen in the analysis here for co rn ethanol, input production volumes resulted in insignificant changes in model outputs. Vari ation of some of the elasticity parameters resulted in moderate to significant changes in the outputs. More detailed discussion of these is provided in Appendix C.IV-29 Table IV-9 Sensitivity Analysis Results for Corn Ethanol

Input Variable Ranges Input variable Low

Value High

Value Percent Change

in LUC

Carbon Intensity
EtOH production increase (billion gallons) 8.25 13.25 2

Crop Yield Elasticity 0.1 0.6 -49

Elasticity of Harvested Acreage Response 0.5 0.5 Not varied

Elasticity of land transformation 0.1 0.3 30

Elasticity of crop yields w.r.t. area expansion 0.25 0.75 -77

Trade elasticity 1 Std.

Dev.

Below 1 Std.

Dev.

Above -2

Adjustment of GTAP Model Results:

Because the modeling runs used a basel ine year of 2001, the model output corresponds to a new equilibrium achieved in 2001 after introducing a 13.25 billion gallon increase in corn ethanol production. These results must be corrected for the changes in agriculture that have occurred between 2001 and present. The change that most significantly affects model output is an increase in crop yields. In 2001, the average corn yield in the U.S. was 138.2 bushels per acre(55) and the average corn yield for 2006 to 2008 was 151.3 bushels per ac re which represents a 9.5% increase over 2001. We used a three y ear average because yields c an fluctuate significantly on a year to year basis. An adjustment for this yield incr ease was applied to the model

results. The model itself was not modifi ed and re-run. Figure IV-6 below shows the “adjusted” land conversions for corn et hanol as predicted by the GTAP model for an increase in ethanol producti on of 13.25 billion gallons.IV-30 Figure IV-6 Average Land Conversions Predicted by the Model for Corn Ethanol

0 0.5 1 1.5

2 2.5 3 3.5

Total Forest

Land Forest Land in

the U. S. Total Pasture

Land Pasture Land in

the U. S.Land Converted ( million ha)

Calculating the Land Use Change Carbon Intensity for Corn Ethanol:

In order to select an appropr iate central value for the land use change impact of corn ethanol production, staff narrowed down the range of values from the sensitivity analysis by removing the results obtained fr om the most improbabl e combinations of input elasticity values. These variables , and the narrowed, ‘most reasonable’ ranges

used are:

• Elasticity of crop yield with res pect to area expansion: 0.5 to 0.75;

• Crop yield elasticity: 0.2 to 0.4;

• Elasticity of land transformation: 0.1 to 0.3; and

• Trade elasticity: central case.

The seven sensitivity runs that remained foll owing the exclusion of runs outside of the above ranges are shown in T able IV-10. As shown in the rightmost column of Table IV-10, the mean global land conversion value across this narrowed range of runs
is 3.89 million hectares. When the total GH G emissions from the conversion of these lands are annualized ove r a 30-year period, the result is a mean land use change impact of 30 gCO 2 e/MJ.IV-31 Table IV-10 GTAP Modeling Results for Corn Ethanol Land Use Change

Scenario A B C D E F G Mean

Economic Inputs

EtOH production increase (bill. gal.) 13.25 13.25 13.25 13.25 13.25 13.25 13.25

Elasticity of crop yiel ds wrt area expansion 0.5 0.75 0.5 0.5 0.5 0.66 0.75

Crop yield elasticity 0.4 0.4 0.2 0.4 0.4 0.25 0.2

Elasticity of land transformation 0.2 0.2 0.2 0.3 0.1 0.2 0.2

Elasticity of harvested acreage response 0.5 0.5 0.5 0.5 0.5 0.5 0.5

Trade elasticity of crops See Appendix C

Model Results

Total land converted (million ha) 4.03 2.68 5.48 4.56 3.01 3.83 3.66 3.89

• Forest land (million ha) 1.04 0.37 1.46 0.89 1.00 0.73 0.55 0.86

• Pasture land (million ha) 3.00 2.32 4.02 3.65 2.01 3.10 3.10 3.03

U.S. land converted (million ha) 1.74 1.16 2.01 2.12 1.14 1.46 1.32 1.56

• U.S. forest land (million ha) 0.70 0.36 0.82 0.81 0.48 0.46 0.40 0.58

• U.S. pasture land (million ha) 1.04 0.79 1.19 1.31 0.66 1.00 0.92 0.99

LUC carbon intensity (gCO 2e /MJ) 33.6 18.3 44.3 35.3 27.1 27.4 24.1 30

The 30-year annualized value fo r carbon intensity (30 gCO 2 e/MJ) differs from the value previously reported by ARB in October (35 gCO 2 e/MJ). As discussed previously, our current analysis removes the results obtained from the most im probable combinations of input elasticity values by establishing “most reasonable” ranges for these elasticity values. As reflected in the sensitivity anal ysis, GTAP model output is most sensitive to

the elasticity of crop yields with respect to area expansion . A major concern expressed
about our October result was t hat the range chosen for this parameter (0.25 to 0.75) extended too low. ARB agreed with this opi nion and has excluded a ll modeling runs for which this elasticity was less than 0.5. A pplication of these new elasticity criteria

reduces the carbon intens ity from 35 to 32.9 gCO 2 e/MJ. The carbon intensity value is further reduced to 30 gCO 2 e/MJ by applying the external adjustment for increase in corn yield.

b

. Indirect Effects: Land Use Ch ange Effects for Sugarcane

Ethanol

Like the corn ethanol results presented abov e, the sugarcane ethanol land use change results presented in this section were pr oduced using GTAP with a 2001 baseline. The results simulate the GHG-generation impac ts of an increase in Brazilian sugarcane ethanol production from 3.61 billion gallons to 5.61 billion gallons. Model outputs were updated to reflect the 8.2% increase in Br azilian sugarcane yields observed between 2001 and the average for the 2006- 2008 time period(56). Se nsitivity analyses were performed for sugarcane ethanol as described in the preceding corn ethanol discussion.

The results are shown in Table IV-11. More complete details are available in Appendix C.IV-32 Table IV-11 Sensitivity Analysis Resu lts for Sugarcane Ethanol

Input Variable Ranges Input variable Low

Value High

Value Percent Change

in LUC

Carbon Intensity
EtOH production increase (billion gallons) 2.00 2.00 Not varied

Crop Yield Elasticity 0.1 0.5 -34

Elasticity of Harvested Acreage Response 0.5 0.5 Not varied

Elasticity of land transformation 0.1 0.3 15
Elasticity of crop yields with respect to area expansion 0.25 0.75 -76

Trade elasticity 1 Std.

Dev.

Below 1 Std.

Dev.

Above -3

In order to select an appropria te central value for the indi rect land use change impact of sugarcane ethanol production, staff narrow ed down the range of values from the sensitivity analysis by removing the re sults obtained from the most improbable combinations of input elasticity values . These variables, and the narrowed, ‘most reasonable’ ranges used are:

• Elasticity of crop yield with respect to area expansion: 0.5 to 0.75 (0.80 for Brazil);

• Crop yield elasticity: 0.20 to 0.40;

• Elasticity of land transformation: 0.1 to 0.3; and

• Trade elasticity: central case.

The five sensitivity runs that remained foll owing the exclusion of runs outside of the above ranges are shown in T able IV-12. As shown in the rightmost column of Table IV-12, the mean global land conversion value across this narrowed range of runs

is 1.09 million hectares. When the total GH G emissions from the conversion of these

lands are annualized over a 30- year period, the result is a mean indirect land use change impact of 46 gCO 2 e/MJ.IV-33 Table IV-12 GTAP Modeling Results for Sugarcane Ethanol Land Use Change

Scenario A B C D E Mean

Economic Inputs

EtOH production increase (bill. gal.) 2.00 2.00 2.00 2.00 2.00

Elasticity of crop yields wrt ar ea expansion 0.50 0.75 0.50 0.50 *

Crop yield elasticity 0.25 0.25 0.25 0.25 0.25

Elasticity of land transforma tion 0.20 0.20 0.30 0.10 0.20

Elasticity of harvested acreage response 0.50 0.50 0.50 0.50 0.50

Trade elasticity of crops See Appendix C

Model Results

Total land converted (millio n ha) 1.28 0.85 1.46 0.94 0.94 1.09

• Forest land (million ha) 0.43 0.22 0.36 0.40 0.26 0.33

• Pasture land (million ha) 0.85 0.63 1.10 0.54 0.68 0.76

Brazil land converted (millio n ha) 0.89 0.59 1.06 0.60 0.55 0.74

• Brazil forest land (million ha) 0.30 0.15 0.25 0.26 0.13 0.22

• Brazil pasture land (million ha) 0.59 0.44 0.81 0.34 0.42 0.52

ILUC carbon intensity (gCO 2e /MJ) 56.7 32.3 54.5 48.3 38.3 46

* Brazil = 0.80, all other = 0.50

c. Indirect Effects: Land Use Change Effects for Soy Biodiesel

Like the corn ethanol and sugarcane ethanol re sults presented above, the soy biodiesel land use change results presented in this section were produced using GTAP. The biodiesel estimate presented in this section, however, is very preliminary: it does not appear in the LCFS Lookup Table. Its only use has been the preparation of the diesel fuel compliance scenarios appearing in Chapte r VI. When a value sufficiently robust for use in the regulation has been estimated, that value will be published for public comment and proposed for certification.

The results of all soy biodiesel sensitivity r uns are summarized in Table IV-13. Starting with the 2001 soy biodiesel production level of 0.005 billion gallons, the GTAP sensitivity analysis considered two producti on increments: 0. 295 billion gallons and 0.695 billion gallons. T he model was quite insensitive to variation in production volumes over this range. As a result, all subsequent sensitivity runs on elasticity values were based on a 0.695 billion gallon bi odiesel production increase. More complete details are available in Appendix C.IV-34 Table IV-13 Sensitivity Analysis Results for Soy Biodiesel

Input Variable Ranges Input variable Low

Value High

Value Percent Change

in LUC

Carbon Intensity
Biodiesel production increase (billion gallons) 0.295 0.695 2

Crop Yield Elasticity 0.1 0.5 -40

Elasticity of Harvested Acreage Response 0.5 0.5 Not varied

Elasticity of land transformation 0.1 0.3 26

Elasticity of crop yields w.r.t. area expansion 0.25 0.75 -76

Trade elasticity 1 Std.

Dev.

Below 1 Std.

Dev.

Above -4

For soy biodiesel, the GTAP model used an aggregated oil seeds (soybeans, canola, etc.) category. The average yield for aggregate oilseeds biodiesel used in the model was 2.06 gal/bushel as compared to a yield fo r soy based biodiesel of 1.47 gal/bushel. To address this difference, land conversi on was adjusted by t he ratio of 2.06/1.47

outside of the model. The GTAP model also does not account for soy meal co-product credit. As an initial estimate, we assumed a 75 percent co-product credit for soy meal.

In order to select an appropr iate central value for the land use change impact of soy biodiesel production, staff narrowed the range of values from the sensitivity analysis by removing the results obtained from the most im probable combinations of input elasticity values. These variables, and the narrow ed, ‘most reasonable’ ranges used are:

• Elasticity of crop yield with res pect to area expansion: 0.5 to 0.75;

• Crop yield elasticity: 0.2 to 0.4;

• Elasticity of land transformation: 0.1 to 0.3; and

• Trade elasticity: central case.

The four sensitivity runs t hat remained following the excl usion of runs outside of the above ranges are shown in T able IV-14. As shown in the rightmost column of Table IV-14, the mean global land conversion value across this narrowed range of runs

is 0.44 million hectares. When the total GH G emissions from the conversion of these

lands are annualized over a 30- year period, the result is a mean indirect land use change impact of 42 gCO2e/MJ. This analysis is preliminary since the modeling has been conducted for an aggregated oil seed s scenario and then adjusted outside the model for soybeans. Future work includes ex ploring the use of soybeans only in the

model to determine effects attributable di rectly to soybean based biodiesel.IV-35 Table IV-14 GTAP Modeling Results for So y Biodiesel Land Use Change

Scenario A B C D Mean

Economic Inputs

Biodiesel production incr ease (bill. gal.) 0.695 0.695 0.695 0.695

Elasticity of crop yields wrt area expansion 0.50 0.75 0.50 0.50

Crop yield elasticity 0.25 0.25 0.25 0.25

Elasticity of land transfo rmation 0.20 0.20 0.30 0.10

Elasticity of harvested acreag e response 0.50 0.50 0.50 0.50

Trade elasticity of crops See Appendix C

Model Results

Total land converted (mill ion ha) 0.476 0.317 0.536 0.358 0.441

• Forest land (million ha) 0.154 0.071 0.144 0.142 0.137

• Pasture land (million ha) 0.323 0.246 0.392 0.217 0.304

U.S. land converted (mill ion ha) 0.109 0.073 0.129 0.075 0.100

• U.S. forest land (million ha) 0.036 0.013 0.030 0.032 0.030

• U.S. pasture land (million ha) 0.073 0.059 0.099 0.043 0.070

ILUC carbon intensity (gCO 2e /MJ) 49 27 51 40 42

d. Indirect Effects: Land Use Change Effects for Cellulosic

Ethanol

No currently available model is capable of estimating the land-use-change effects of plant-based feedstocks that do not displace agricultural commodities. To assess the land use change effects of cellulosic ethanol produced from such feedstocks, therefore, staff turned to an analysis prepared by Purdue University(57). This analysis evaluated the potential land use change impacts of corn stover, which can be used as feedstock for the production of cellulosic ethanol. Purdue’ s estimate, however, is very preliminary: it does not appear in the LCFS regulatory Lookup Table. Its only use has been in the preparation of the gasoline compliance scena rios appearing in Ch apter VI. When a value sufficiently robust for use in the regulat ion has been estimated, that value will be published.

Purdue’s results indicate that, not only is the use of this feedstock unlikely to generate land use change impacts, it may actually yield benefits in the form of a reduction in the amount of land required for fuel crop cultivation. The Purdue study also analyzed the potential for dedicated energy crops grown on id led or pasture land s to create land use change impacts. Preliminary results indicate that the land use c hange impacts of these crops are likely to be significantly lower t han those for feedstocks that displace food and feed crops.

Some cellulosic feedstocks may be cultivat ed as crops, but on lands not capable of supporting traditional food and feed crops. In the absence of a model capable ofIV-36 evaluating the land use change im pacts of fuels produced fr om such feedstocks, staff prepared a preliminary analysis of the potential direct land use change impacts of the cellulosic ethanol production requirements contained in t he federal Renewable Fuels Standard (RFS2, which is discussed in Chapte r II). The RFS2 requires the production of 16 billion gallons of cellulosic ethanol by 2022. Table IV-15 shows the inputs used for this analysis. The feedstock considered—swit chgrass—is assumed to yield 250 gallons of ethanol per acre. Given this yield, swit chgrass would have to be grown on a total of 25.9 million hectares. For purposes of this analysis, the marginal lands that would be converted to switchgrass cult ivation are assumed to emit carbon at a rate that is 25 percent of the Woods Hole rate for U. S. grassland conversion. The Woods Hole emission factor for U.S. grasslands is 110 MgCO2/ha; the result ing factor for the marginal switchgrass land ar eas, therefore, is 27.5 MgCO 2 /ha. Based on these assumptions, the land use c hange carbon intensity value fo r switchgrass is 18 gCO 2 /MJ (see Table IV-16).

This preliminary value for fuels produced fr om feedstocks grown on marginal lands will be updated when more rigorous modeling result s are available. Staff is currently working to integrate the necessary dataset s for this analysis into the GTAP model. Once these modifications have been made, staff will prepare and pr esent the modeling

results.

Table IV-15 Inputs Used for Preliminary Cellulosic Ethanol Analysis

Parameter Value Quantity of cellulosic ethanol 16B gallons Feedstock Switchgrass Ethanol yield 250 gallons/acre 1

Total land converted in the U. S. 25.9 million ha (approx 64 million acres) Type of land converted Grassland or marginal land

1 The literature contains a wide range of ethanol yi elds from switchgrass. 250 gallons/acre is the approximate midpoint of this range.(58, 59)

Table IV-16 Preliminary Results for Cellulosic Ethanol

Carbon factor

(MgCO2/ha) Land Use Change (gCO 2 e/MJ)

25% of Woods Hole Data for grassland in

the U. S.=27.5 18IV-37 e. Land Use Impacts from Crude Production in California

This section summarizes work completed by researchers from U.C. Davis and their collaborators(60) on estimating the land use impacts from crude production in California. The scope of the analysis extend s to land use change resulting from land disturbance associated with oil oper ations in California oil fields.

As with biofuels production, producing fossi l fuels from a new crude source will likely

result in carbon releases from disturbed land . The amount of land disturbed per unit of refined fuel delivered depends on t he following characteristics:

• The areal energy density of the deposit (e.g. the amount of primary energy contained per m 2 of surface area);

• The rate at which the primary energy re source (crude) is extracted from the deposit;

• The conversion efficiency between the primary energy resources and refined fuel product; and

• The amount of carbon contained on the land before and after the land

disturbance occurs.

Data for California conventional oil pr oduction was obtained fr om the California Department of Oil Gas, and Geothermal Re sources (California Department of Conservation 2006(61)). The dataset c ontains 308 oil fields covering 3×10 9 m 2 (1180 square miles), and a total of 9,775 wells. The cumulative crude oil produced to date is

25.1 billion bbl. Details of the production we ighted averages are provided in

Table IV-17.

Table IV-17
California Oil Fiel d Characteristics

Number of fields 308 Total area of field (m 2 ) 3×10 9

Total number of wells 9,775 Average number of wells per field 349 Crude oil produced to date (B bbl) 25.1 Production weighted averages: Spacing per well (ha/well) 9.6 Total energy produced to date per well (PJ crude oil/well) 5.94 Energy produced per disturbed area (PJ/ha) 6.74

In consultation with the UC Davis researcher s who provided this information, ARB staff determined the most likely cover types, and a ssociated emission factors, for the landsIV-38 that have been disturbed by oil field development in the St ate. The results are as

follows:

Land use assumptions:

• Drilling is expensive, so o il fields are lightly developed, with tens of acres per well (10-40 sometimes cited), although some will hav e infill drilling at tighter spacing. Add in roads, and disturbance is still likely to be quite low. We assume 25 percent of field surface area is disturbed 29 ;

• Disturbance is defined as removal of 100% above-ground biomass carbon and oxidation of 20 percent of soil carbon ( scraping of soil at su rface for roads, drainage, drill pads);

• Given that nearly all Californi a oil fields are in the sout hern half of the State, we assume that the land above the California fields is 25 percent chaparral and 75 percent grassland; and

• The carbon emission factors for these l and types are assumed to be identical to those used by Searchinger et al. ( 2008(50)); these fact ors are shown in

Table IV-18.

Table IV-18 Carbon Intensity Assumptions for Oil Production Fields in California

Landscape Type C in Vegetation (Mg C/ha) C in Soil (Mg C/ha) Fraction of Total Disturbed

Chaparral 40 80 0.25

Grassland 10 80 0.75

Preliminary calculations indicate that the GHG emissions associated with oil field land use conversion are in the range of 0.025–1.40 gCO 2 e/MJ for California crude production. When adjusted for producti on-weighted average land use, the GHG emissions from California oil production ar e 0.061 g CO2e/MJ. Appendix C provides details of the preliminary calculations.

A similar analysis is planned for crude oil from o il sands. Currently, California refineries do not use any crude derived from oil sands. Staff will publish the results of this analysis when it is available.

29 To estimate the fraction of land in California oil fields that is disturbed, an image analysis program is used to convert the images of three oil fields into binary files (black and white). Black being the vegetation, which is typically much darker than the dirt roads and areas around wells. The percentages without vegetation (white) range from 25-35% for the 3 fields analyzed, with a few images having as low as 10% cleared.IV-39 f. Comparison of GTAP Results with Observed Market Behavior

The GTAP is designed to project the specif ic effects of one carefully defined policy change—namely the increased production of a bi ofuel. Because it focuses narrowly on a specific set of economic changes, the resu lts obtained from GTAP will not necessarily reflect observed aggregate trends. The model pr edicts, for example, that the expanded use of domestic corn for the production of ethanol will reduce U.S. corn exports. That prediction appears to be inconsistent wit h the actual trade data appearing in Appendix C. Those data show that the production of co rn, soybeans and wheat in the United States has generally been on the incr ease over the last decade. Exports meanwhile have remained relatively steady. In the case of corn, production increases have been sufficient to supply the ethanol industry while maintaining export levels. The

effects of increased biofuel production on export markets are masked by other phenomena that are not address ed by the GTAP analysis.

The primary influences on exports in rec ent years have been an in creased demand for American agricultural products in rapidly growing economies such as China, a weakening U.S. dollar, and grow th in demand for corn ethanol 30 . A significant component of the increased dem and in China and other rapidl y developing countries is a sharp increase in the consumption of meat and soy products in those countries. This has created a demand for imported soybeans and corn, which are used as livestock feed. This demand has helped to increase pr ices and has kept U.S. exports steady, despite the rapidly increasing use of corn for the production of ethanol.

The increased demand for corn ethanol, along with strong corn export demand, stimulated a significant increase in corn production over the 2005 through 2007 period (production and planted acreage data are present ed in Appendix C). This expansion in corn production coincided with significant dec line in soybean production. When U.S. corn acreage is expanded, the crop that is most often disp laced is soybeans(50, 62). The resulting shortage of soybeans increas ed soybean prices, driving production back up in 2007/08.

The overall trend in corn exports , therefore, is the result of many factors, only one of which is the growth in corn ethanol producti on. Because the observed trend is the net result of several factors, the independent in fluence of increased ethanol production was masked by competing influences not consider ed in the GTAP results. It is true, however, that the downward pressure from domestic ethanol production kept exports lower than they would otherwise have been. 31

31 The LCFS GTAP analysis was designed to isolate th e incremental contribution of ethanol production to export levels. Other influences, which can mask the e ffects of ethanol production, are not included in the model. It is important to keep this fact in mind when evaluating GTAP projections in the context of observed market behavior. GTAP is not predicting the overall aggregate market trend—only the incremental contribution of a single factor to that tr end. If GTAP projects reduced exports, for example, this should be understood to mean that exports will be lower that what they would have been in the absence of the effect being modeled (increased ethanol production, in this case). It is the differenceIV-40 The increasing demand for corn ethanol also results in the movement of significant U.S. crop land area out of food and feed production. The USDA ’s Economic Research Service reports that almost five billion gallo ns of ethanol were produced in the U.S. in 2006. Production is expected to exceed ten billion gallons by 2009 (Westcott, May 2007). If the targets estab lished in the Energy Independenc e and Security Act of 2007 are met, production should r each about 15 billion gallons by 2015. Table IV-19 shows the land area requirements for ethanol production leve ls of this magnitude.

Table IV-19 U.S. Corn Ethanol Production Acreage Requirements

Year Gallons of Ethanol Produced (Billions) Acres of Ag. Land Required (Millions) Percentage of 2008
Planted Corn Acres

2006 5 11.8 13.8%

2009 10 22.6 26.3%

2015 15 31.8 37.0%

1 Based on ethanol production yields of 2.8 gallons per bushel of Corn(18), and

corn yields from USDA Economic Resear ch Service, October 2008. Projected yields for 2009 and 2015 are based on the average yield increase between 2005-06 and 2007-08 (1.3 percent).

2 Based on a 2007/08 planted corn acreage of 85.9 million acres (USDA

Economic Research Service, October 2008)

The implications of diverting cropland to biofuel production on this scale are discussed in section h below (“Food versus Fuel Analysis”).

g. Location of Land Use Changes

The GTAP model is designed to respond to changed economic conditions by solving for the most economically efficient new equilibri um point. In response to a 13.25 billiongallon-per-year increase in the demand for corn ethanol, the model seeks the least-cost

source of the corn needed to sustain that demand. Although some additional corn can be obtained through higher yields, the over all demand cannot be met unless the number of acres devoted to corn producti on can be expanded significantly.

When additional corn acreage is needed, Americ an farmers are most likely to convert soybeans to corn. This is especially true w hen returns from exports are high, as they have been until very recently. If returns from exports are low, more of the demand for corn would be met through reduc ed exports, driving a greater proportion of the land use change impact overseas to America’s tradi ng partners. Reduced soybean supplies increase soybean prices, stimulating the demand for more land to support soybean production. As with corn, soybean exports have remained high (See Appendix C), causing much of the demand for soybean ac reage to met domestically. Soybeans can be grown on land previously devoted to other crops, such as wheat, but, some of the

between predicting an absolute change and a relative change. GTAP projections are incremental and

relative.IV-41 displaced soybeans, wheat, and other crops must be grown on land that was not previously under cultivation. This is the source of the domestic land use change impact identified by GTAP.

The GTAP brings new land into agricultural production from forest and grassland areas. It isn’t specific about exactly where that land will come from. Some could come from the Conservation Reserve Program (CRP). Most CRP lands are in the arid far west and could support soybean production but not corn. Although the penalties for breaking CRP contracts are steep enough to prevent CRP lands from being used before their contracts expire, contracts are currently ex piring on two million acres due to provisions
contained in the recent Farm Bill. The US DA has the authority to make additional CRP

lands available. If sufficient CRP land is not available to indirectly support an expansion of corn acreage, a large supply of non-CRP pasture land that was formerly in crops could be brought back into production. It is the availability of this non-CRP former crop land that is behind the GTAP’s projection t hat about 40 percent of the land converted worldwide in response to the increased demand for corn ethanol biofuel will occur in the

U.S.

The GTAP modelers assumed that no CRP l and would be converted in response to

increased biofuel demand. Al though some CRP land has been released for cultivation, an abundance of previously farmed pasture land is also available. These pasture lands are generally more productive than the lands released from the CRP system. Before it becomes economical to convert the least productive domestic land areas, land use change tended to shift overseas.

The staff is continuing to analyze the effects of including CRP land in the land pool used by the GTAP model.

h. Food Versus Fuel Analysis

The LCFS, together with biofuel production m andates in the U.S. and Europe, will result in the diversion of agricultural land from food production to biofuel feedstock production. This diversion of agricultural land to bi ofuel production will exert an upward pressure on food commodity prices, and potentially lead to food shortages, increasing food price volatility, and inability of the world’s poores t people to purchase adequate quantities of food (63, 64). As both food prices and corn ethanol production levels rose during 2007 and the first part of 2008, warnings about a possible linkage between the two trends began to surface(65). Controversies over the trade-offs between food and fuel crops are likely to intensify as crop-based biofuel production increases over the next decade. In this section, ARB staff discusses various food-versus-fuel issues associated with the production of corn and sugarc ane ethanol—the biofuels that are expected to dominate

the alternative fuels market over the next five years.

The primary benefits of increas ed production and consumption of biofuel are thought to be twofold. The first—an increase in energy security—is the ration ale for the Energy Independence and Security Act (EI SA). In 2007, the U.S. impor ted roughly two-thirds ofIV-42 its oil with over 50% of the imports comi ng from OPEC countries (EIA 2009). This dependence on foreign oil leaves the U.S. vu lnerable to supply disruptions and price shocks. Increasing the domestic production of co rn ethanol will diversify our fuel supply and potentially leave us less vulnerable to dec isions made by foreign countries and oil producers.

The second perceived benefit of increased re liance on biofuels—a reduction in GHG

emissions—is the rationale behind the LC FS. On an energy basis, direct GHG

emissions 32 from the production and use of co rn and sugarcane ethanol are less than the comparable emissions from gasoli ne. When land use change emissions are considered, however, the emi ssion-reduction benefit from co rn and sugarcane ethanol

is diminished.

Some of the costs and benefits associated with a 50 million gallon per year corn ethanol plant operating in California are summarized below (See Appendix C for a description of how the values appearing in this summary were derived). Such a plant would:

• Provide enough fuel for approximately 80,000 vehicles capable of operating on E-85;

• Displace about 34 million gal lons of petroleum fuel;

• Reduce direct GHG emissions by about 0.19 million metric tons per year;

• Require almost 18 million bushels of corn per year;

• Require about 110,000 acre s of U.S. farmland to produce the feedstock;

• Result in about 36,000 acres of land c onversion, 14,000 acres of which would be in the U.S.; and

• Result in the release of 3.6 million metric tons of greenhouse gases due to land conversions; and

• Result in a net greenhouse gas emission benefit after 19 year s of production.

In addition to the costs listed above, the conver sion of agricultural land to the production of biofuel feedstocks has the potential to incr ease the price for food, increase food price volatility, and increased pressure on water s upplies. The production capacity of the ethanol plants currently operating and under c onstruction in the U.S. is approximately 13 billion gallons per year (BGPY)(54). A bout 4.6 billion bushels of corn—more than 30 percent of the annual U.S. corn crop—is nee ded to support this level of production.

32 Direct and indirect GHG emissions, as well as the co ncept of indirect land use change, are discussed in detail in preceding sections of this ChapterIV-43 Diverting this much of the American corn har vest to ethanol production is likely to exert upward pressure on food prices(66).

Historically, the price of corn has been rela tively stable varying from about $2.00 to $2.50 per bushel between 2000 and 2006. Prices in 2008, how ever, spiked at over $5 per bushel and are currently near $4 per bushel(55). The rec ent sharp increase in corn prices was not caused solely by the conv ersion of acreage devoted to food and feed production to biofuel crops. The cost of energy appears to have been the largest contributor (65, 67). The demand for biofuel feedstocks may, however, be overwhelming a food supply system that was already overextended by weather-induced production shortfalls and surging demand from a worldwide population that is both increasing in size and affluence. Increas ed meat and dairy consumption by newly affluent populations places additional demands on soy and corn—feed crops that are also used for direct human consumption and biofuel production(64). Moreover, the increased production of biofuels may more fi rmly link prices of biofuel feedstocks with petroleum prices, thereby leading to increased price volatility for food(63): as petroleum fuel prices increases, biofuels become more profitable which, in turn, allows producers to raise their feedstock prices as they increase production levels. Because those with

the lowest incomes must devot e a large percentage of those incomes to food, they are less able to adjust to changing food prices in the short term.

An important factor in the food versus fuel debate that has received relatively little attention until recently is the impact of ex panded biofuel production on water supply and water quality. The shift in U.S. agricultur al production toward corn, the conversion of land to agriculture (indirect land use change), and the growth in the number of bio-refineries will place additional demands on already overburdened water supplies. The water use impact of devoting a larger pr oportion of available agricultural land to corn production depends on the crop that is being replaced as well as its geographical location. Of more concern, however, is the ex pansion of agriculture in dry areas like the western U.S.: altered cropping patterns on relati vely moist agricultural lands will usually have less of an impact than expa nding irrigated production in relatively arid areas.

Bio-refineries can also place a strain on loca l water supplies. A refinery that produces 100 million gallons of corn et hanol uses as much water as a town of 5,000. More intensely managing land to improve yields ma y also exacerbate water quality problems: soil erosion along with fertilizer and pesticide runoff can increase as crop management intensifies(68, 69). Bringing non-agricultura l lands into production can also increase
erosion and runoff. Conservation Reserve Pr ogram (CRP) lands are of special concern: the CRP was created, in part, to protect environmentally s ensitive or highly erodible

acreage.IV-44 4. Ongoing Analyses

a. Additional Analyses of Indir ect Effects of Other Feedstocks

As discussed above, the results of the anal yses for biodiesel and cellulosic ethanol are preliminary. Additional data must be added to the GTAP model before it can be used to estimate the land use change im pacts of these fuels.

Staff is currently working with CEC, Purdue researchers, the U.S. EPA and others in determining appropriate inputs, values, etc. for soybean based biodiesel and cellulosic ethanol from non-food crops and waste. Results will be published when the analyses are completed.

Staff is also continuing to analyze and refine the corn ethanol land use change results. Work is underway in the following areas:

• The possible inclusion of Conservation Reserve Program Land in the analysis;

• The use of improved emission fact ors, as they become available;

• The evaluation and possible use of dat a and analyses provided by stakeholders;

and

• Characterizing in greater detail of t he land use types that are subject to conversion by the GTAP model (forest, grassland, idle and fallow croplands, etc.).

The results of these analyses will be published when they are completed.

b. Comparison to U.S. EPA’s Approach

The U.S. EPA is evaluating the potential in direct land use impacts of the Federal

Renewable Fuel Standard r egulation (RFS). The RFS establishes volumetric requirements for various categories of biofuel s (the RFS is discussed in Chapter II of this Report). Its primary goal is increased energy independence rather that reduced fuel carbon intensity. Despite these differences , the economic forces driving indirect land use change are the same in the RFS and th e LCFS. For that reason, the ARB is working closely with the U.S. EPA to assu re that the approaches taken in the two analyses are as consistent and transparent as possible.IV-45 D. Uncertainties in the Analysis

Chapter IV and Appendix C describe a number of modeling inputs that affect the fuel carbon intensity estimates. The lifecycl e analysis process used to determine the contribution of fuel production, distribution, and use is fairly mature: direct carbon intensity values calculated via lifecycle analys is are relatively non-controversial. The land use change analysis, however, has gener ated large numbers of comments on all sides of the issue. Some stakeholders argu e that the land use change carbon intensity value for crop based biofuels should be near 0 gCO 2 e/MJ. Others argue that ARB

should err on the side of caution and set t he land use change carbon intensity value at 100 or more gCO 2 e/MJ.

In this section, we briefly summarize those inputs that result in the greatest uncertainty and discuss decisions made by the ARB with re spect to those inputs. We organize this

discussion into issues associated with es timating land conversion, applying emission factors, accounting for time, and other factors. This list is meant to summarize some of the more significant issues ra ther than to be comprehensive.

The uncertainties associated with the land conv ersion estimates are largely the result of the following model inputs:

• Elasticity values used in the economic modeling . As discussed in the results section, model output is moderately to highl y sensitive to the crop yield elasticity; elasticity of land transformation acro ss cropland, pasture, and forest land; and elasticity of crop yields with respect to area expansion (relativ e productivity of marginal land). In calculating a value for land conversion, ARB staff and GTAP

modelers have determined what we believe to be the most reasonable ranges for these elasticity values. These ranges are derived from appropriate research results, unless no such results are ava ilable. In the absence of research findings, the best professional judgment of experts has been relied upon. In particular, model outputs are highly sensitiv e to the value assigned to the relative productivity of marginal land. The l and conversion predicted by the model is inversely proportional to the relative produc tivity assumed for marginal land. A range from 0.25 to 0.75 was or iginally assigned to this elasticity (e.g. marginal land is 25 to 75 percent as productive as land currently used for agriculture). Based on feedback from stakeholders, ARB staff and GTAP modelers decided that 0.50 to 0.75 was a more appropriate range for this elasticity value which resulted in a lower estimate for land conversion. We will continue to analyze available evidence for this key input parameter.

• DGGS and co-product credit . A recent report by Dr . Michael Wang et al.(70) (2008) of Argonne National Laboratory arrive d at a distiller’s grain co-product value that is higher than the value used in the LCFS life cycle emissions model.

This issue is discussed in more deta il in Appendix C. Although Dr. Wang’s analysis was based on a limited data set, t he results were generalized to the entire livestock industry. For the reasons presented in Appendix C, staff believesIV-46 that it may not yet be appropr iate to generalize from Dr. Wang’s limited findings. In fact, DDGS appears to face significant barriers to widespread adoption as a replacement for corn and soybean meal. For this reason, staff feels that providing a co-product credit equating 1l b of DDGS to 1lb of feed corn is

reasonable.

• Increases in crop yield with time . GTAP uses the 2001 world economy as a baseline and does not account for changes that have occurred over the past eight years. The change that has the most significant effect on the land

conversion estimate is the increase in crop yields since 2001. An increase in crop yields will lead to a corresponding decr ease in land conversion. In response to this stakeholder concern, ARB st aff and GTAP modelers have adjusted the

land conversion estimate to account for the observed increase in crop yields. This adjustment was made to the model results rather than within the GTAP itself. Some stakeholders have responded to this adjustment by claiming that it is based on faulty logic. ARB sta ff and GTAP modelers do not agree with this comment. A more thorough discussion of our response is given in Appendix C.

• Inclusion of Conservation Reserve Program land . The GTAP model does not

include Conservation Reserve Program land in the pool of available land in the U.S. for agricultural expansion. AR B staff and GTAP modelers are updating

GTAP to include Conservation Reserve Pr ogram land, as appropriate. We will then analyze the effect that this c hange has on the estimate for amount and

location of land conver ted within the U.S.

An additional source of uncertainty is the application of emission factors to land use change data. These uncertainties are largel y the result of the following assumptions:

• The percentage of the above ground carbon that is rel eased to the atmosphere upon land conversion . Stakeholders argue that w hen forests are converted to cropland, some of the above ground ma ss will be converted to wood products, paper, and other consumer goods. The carbon in these items will continue to be stored while these products ar e used, and, in many cases, after they have been deposited in landfills. ARB staff recognizes the validity of this argument and is continuing to analyze the issue to determi ne the most appropriate percentage of above ground carbon that is released to t he atmosphere. Our current modeling assumes 90 percent of the above ground ca rbon is released to the atmosphere following land conversion. ARB staff also notes that decay of biomass in landfills will more likely lead to release of me thane (a more potent GHG) rather than

carbon dioxide. This would have to be considered if a non-trivial percentage of biomass from converted lands is placed in landfills.

• The percentage of below gr ound carbon that is released to the atmosphere upon

land conversion . A literature review conducted by Murty et. al.(52) of scientific studies of land conversion reported that the percentage of soil carbon released upon land conversion varied from 0 to 72 percent with an average reported lossIV-47 of approximately 30 percent. When these values were corrected for changes in bulk density of the soil, the average loss was 22 per cent. Another review conducted by Guo and Gifford(51) reported t he average loss of carbon in soils for forests converted to crops was 42 perc ent and from pasture converted to crops was 59 percent. Lower losses were repor ted for forests and pa stures converted to plantations (13 percent and 10 percent respectively). ARB staff and GTAP modelers assume that 25 perc ent of the carbon stored in the soil is released

when land is cultivated. We believe this value is a reasonable compromise given the variability in data.

The uncertainties associated with time accounting are largely the result of:

• The choice of time accounting method used . The Fuel Warming Potential method yields larger values for land use change carbon intensit y compared to the

Annualized method. ARB staff has chosen the annualized method but will continue to analyze the FWP method.

• The choice of project horizon . A shorter project horizon yields larger land use change carbon intensity values. ARB sta ff has chosen a 30 year project horizon for crop based biofuel but is cons idering a shorter 20 year horizon.

• The choice of impact horizon . A shorter impact horizon yields larger land use change carbon intensity values for the FWP method. The duratio n of the impact

horizon is has no effect on the annualization method.

• The amount of land reversion to include and the time period for land reversion

. Including land reversion yields significantly lower land use change carbon intensity values for the annualized met hod as well as for the FWP method at impact horizons long enough to include land reversion.

• The time profile assumed for above and below ground emissions . The assumed length of time over which above and bel ow ground emissions occur affects the land use change carbon intensity values for the FWP method but not the

annualized method.

These topics are discussed in more detail in both Chapter IV and in Appendix C. In Appendix C, we present scenar ios that explore these issues and show the effect of changing assumptions on the land use change carbon intensity value for corn ethanol. For the annualized method we present land use change carbon intensity values ranging from 22 to 43 gCO 2 e/MJ, for the FWP me thod (30 year impact horizon) we present values ranging from 44 to 55 gCO 2 e/MJ and for the FWP method (50 year impact horizon) we pr esent values ranging from 34 to 48 gCO 2 e/MJ.

Other issues that affect the uncertain ty in the carbon intensity value are:IV-48 • Reduced enteric fermentation in li vestock fed with distillers grains . Stakeholders have commented that a recent report from Argonne National Laboratory indicates that use of distillers grains as livesto ck feed reduces enteric fermentation. ARB staff has not included an emissions adjus tment for reduced enteric fermentation but will continue to analyze relevant scientific studies and make appropriate adjustments in the future if deemed necessary.

• GTAP modeling neglects other possible effects of land conversion such as changes in Earth’s albedo . The albedo is the extent to which an object diffusely reflects light from the sun. Converti ng from one land use type to another may

affect the albedo. ARB staff has not conducted an analysis of this effect.

• The land use change analysis neglects t he potential for converting grassland into

forest . One strategy menti oned for reducing the atmospheric concentration of carbon dioxide is to convert current gr asslands into forest which results in sequestration of carbon dioxid e. This land conversion is often mentioned as a

method for GHG emitters to offset emissions under cap and trade emissions programs. The conversion of grasslands to agriculture removes this land from the potential pool of land that could be conver ted to forest. Ther efore, it could be considered as a “lost opportunity” or “opportunity cost” and be included in the land use change carbon intensity calculation(71).

• Uncertainties associated with the nitrogen cycle . Stakeholders have commented that significant uncertainty ex ists in the estimates for N 2 O release used in lifecycle analysis models such as GR EET. The non-trivial impact of N 2 O

emissions on the direct carbon intensit y calculated by GREET and the large uncertainty in actual measurements of N 2 O emissions suggests we need more

research in this area. ARB staff will continue to analyze relevant scientific studies and make adjustments to t he CA-GREET model if necessary.

The above discussion points out the large number of fa ctors that signific antly affect the carbon intensity value for a biofuel. As part of the LCFS, ARB has committed to determining the total direct and indire ct emissions associated with production, distribution, and use of all fuels through c onducting complete lifecycle analyses based on the best available science. Although one may argue that there is no scientific consensus as to the precise magnitude of land use change emissions and that the methodologies to estimate these emissi ons are still being developed, scientists generally agree that the impac t is real and significant. Our analyses support this conclusion. We believe that we have conducted a fair and balanced process for determining reasonable values for land use change carbon intensity and we will continue to investigate many of the i ssues presented above through discussion with stakeholders and analysis of curr ent and new scientific data.IV-49 E. Proposed Lookup Tables

The results of ARB’s carbon intensity analyses to date are shown in Tables IV-20 and

IV-21. These are the same values reported in Tables IV -1 and IV-2, without the vehicle energy efficiency ratio adjustmen ts. As such, these are the combined direct and indirect carbon intensity values that ARB proposes for inclusion in the LCFS regulation. These tables represent the proposed Lookup Tables for the default carbon intensities. Note

that in the calculations of credits and deficits, these values would adjusted by the Energy Economy Ratios.IV-50 Table IV-20 Lookup Table for Carbon Intensity Values

for Gasoline and Fuels that Substitute for Gasoline

Carbon Intensity Values (gCO 2 e/MJ)

Fuel Pathway Description Direct

Emissions Land

Use or

Other

Effect Total

CARBOB – based on the average crude oil delivered to California refineries and average California refinery

efficiencies 95.86 0 95.86

CaRFG-CARBOB and a blend of 100% average Midwestern corn ethanol to meet a 3.5% oxygen content by weight blend (approximately 10% ethanol) 96.09 --- 96.09 Gasoline

CaRFG-CARBOB and a blend of an 80% Midwestern average corn ethanol and 20% California corn ethanol (dry mill, wet DGS) to meet a 3.5% oxygen content by weight blend (approximately 10% ethanol) 95.85 --- 95.85

Midwest average; 80% Dry Mill; 20% Wet Mill; Dry
DGS 69.40 30 99.40

California average; 80% Midwest Average; 20% California; Dry Mill; Wet DGS; NG 65.66 30 95.66

California; Dry Mill; Wet DGS; NG 50.70 30 80.70 Midwest; Dry Mill; Dry DGS, NG 68.40 30 98.40
Midwest; Wet Mill, 60% NG, 40% coal 75.10 30 105.10 Midwest; Dry Mill; Wet, DGS 60.10 30 90.10 California; Dry Mill; Dry DGS, NG 58.90 30 88.90 Midwest; Dry Mill; Dry DGS; 80% NG; 20% Biomass 63.60 30 93.60 Midwest; Dry Mill; Wet DGS; 80% NG; 20% Biomass 56.80 30 86.80 California; Dry Mill; Dry DGS; 80% NG; 20% Biomass 54.20 30 84.20 Ethanol from

Corn

California; Dry Mill; Wet DGS; 80% NG; 20% Biomass 47.40 30 77.40

Ethanol from Sugarcane Brazilian sugarcane using average production

processes 27.40 46 73.40

California NG via pipeline; comp ressed in California 67.70 0 67.70 North American NG delivered via pipeline; compressed in California 68.00 0 68.00 Compressed

Natural Gas Landfill gas (bio-methane) cleaned up to pipeline quality NG; compressed in California 11.26 0 11.26

California average electricity mix 124.10 0 124.10 Electricity California marginal electricity mix of natural gas and renewable energy sources 104.70 0 104.70

Compressed H 2 from central reforming of NG 142.20 0 142.20 Liquid H 2 from central reforming of NG 133.00 0 133.00 Compressed H 2 from on-site reforming of NG 98.30 0 98.30 Hydrogen SB 1505 Scenario; Compressed H 2 from on-site reforming with renewable feedstocks 76.10 0 76.10IV-51 Table IV-21 Lookup Table for Carbon Intensity Values

for Diesel and Fuels that Substitute for Diesel

Carbon Intensity Values (gCO 2 e/MJ) Fuel Pathway Description Direct

Emissions Land Use

or Other

Effect Total

Diesel ULSD – based on the average crude oil delivered to California refineries and average California refinery efficiencies 94.71 0 94.71

California NG via pipeline; compressed in

California 67.70 0 75.22

North American NG delivered via pipeline; compressed in California 68.00 0 75.56 Compressed

Natural Gas Landfill gas (bio-methane) cleaned up to pipeline quality NG; compressed in California 11.26 0 11.26

California average electricity mix 124.10 0 124.10

Electricity California marginal electricity mix of natural gas and renewable energy sources 104.70 0 104.70

Compressed H 2 from central reforming of NG 142.20 0 142.20 Liquid H 2 from central reforming of NG 133.00 0 133.00 Compressed H 2 from on-site reforming of NG 98.30 0 98.30 Hydrogen SB 1505 Scenario; Compressed H 2 from onsite reforming with renewable feedstocks 76.10 0 76.10IV-52 This Page Left Intentionally BlankV-1 

### V. Summary of the Proposed Regulation

In this Chapter, we provide a plain Englis h discussion of the ke y requirements of the proposed LCFS regulation. This Chapter begins with a general overview of the regulation and the approach taken in developing the requirements in the proposal. The remainder of the Chapter follows the struct ure of the proposed regulation and provides an explanation of each major requirement of the proposal. This Chapter is intended to satisfy the requirements of Government C ode section 11346.2, which requires that a non-controlling “plain Englis h” summary of the regulati on be made available to the public.

A. Overview of the Proposed Regulation

The proposed regulatory action would reduc e greenhouse gases (GHG) emissions by reducing the carbon intensity of transportation fuels used in California by an average of 10 percent by the year 2020. Carbon intensit y is a measure of the direct and other

GHG emissions associated with each of t he steps in the full fuel-cycle of a transportation fuel (also referred to as the “w ell-to-wheels” for foss il fuels, or “seed or field-to-wheels” for biofuels). Depending on the circumstances, GHG emissions from each step can include carbon dioxide (CO 2 ), methane, nitrous oxide (N 2 O), and other GHG contributors. Moreover, the overall GHG contribution fr om each particular step is a function of the energy that the step requires. Thus, ca rbon intensity is typically expressed in terms of grams of CO 2 equivalent per mega-Joule (gCO 2 e/MJ).

The LCFS achieves a 10 percent reduction in average carbon intensity by starting specified providers of transportation fuels (refe rred to as “regulated part ies”) at an initial level and incrementally loweri ng the allowable carbon intensity for transportation fuels used in California in each subsequent year. A regulated party’s ov erall carbon intensity for its pool of transportation fuels would then need to meet each year’s specified carbon intensity level. Regulated parties can m eet these annual carbon in tensity levels with any combination of fuels they produce or supply and with LCFS credits acquired in previous years or from other regulated parties.

As indicated, the LCFS is based on a syst em whereby credits, which are generated

from fuels with lower car bon intensity than the annual carbon intensity standards,

balance the deficits that result from the sale of fuels in California that have higher carbon intensity than the annua l carbon intensity standards. A regulated party would meet the carbon intensity require ments if the amount of credits at the end of the year is equal to, or greater, than the deficits. Credits and deficits are determined based on the amount of fuel sold, the carbon intensity of the fuel, and the efficiency by which a

vehicle converts the fuel into useable energy. Credits may be retained and traded by regulated parties within the LCFS mark et to meet their obligations.

Under the LCFS, a regulated party’s co mpliance with the annual carbon intensity requirements is based on end-of-year credit/d eficit balancing for each year betweenV-2 2011 and 2020 and beyond. Technically, the LCFS goes into effect in 2010, but the first year of the program is int ended as a “break in” reporting y ear, which will allow both the regulated parties and ARB program staff to acclimate to the LC FS rule’s intricacies and to identify any programmatic changes t hat may be needed as the program is implemented.

A key function of the LCFS is to incentiviz e the use of lower-carbon intensity alternative fuels (i.e., fuels that are not conventional gasoline or diesel fuel). Alternative fuels include, but are not limited to, biofuels such as ethanol, biodiesel, and renewable diesel fuel; compressed or liquefied natural gas, both from petroleum or from biomass sources; hydrogen; and electricity. Each of these fuels will have carbon intensity values associated with a lifecycle analys is that will ultimately include other effects, including effects from land use changes, if any.

The proposal contains carbon intensity values for a variety of fuel pathways that have been analyzed by ARB staff. These specific ca rbon intensity values will be published in a Lookup Table, which will make it easier for fuel producers and importers to identify the appropriate carbon intensity value for the fuel pathway that corresponds with the pathway for their respective fuels. T he Lookup Table contained in the proposal is intended to be a “living document ,” representing the starting point for carbon intensity values and specific fuel pathways. Howeve r, the proposal contains provisions for regulated parties to generate modified or additional fuel pathw ays with associated carbon intensity values; these provisions are intended to accommodate innovations in producing lower carbon intensity fuels in the futu re. As these modified or additional fuel pathways are approved by the Executive Office r in a public proces s, the modified or additional approved carbon int ensity values will become incorporated into the Lookup

Table.

B. Applicability of the Standard

In order to meet the 10 percent reduction target and addi tional climate stabilization beyond 2020, California must rely on a diverse portfolio of fuels, su ch as a mixture of advanced low-carbon fuels, low-carbon bl endstocks, and vehicle technologies. The scope of the standard is designed to capture the diverse fuel portfolio available today and in the near future, while offering a fuel- neutral platform in which alternative fuels can be incentivized without choosing winners or losers. Therefore, staf f proposes the LCFS apply, either on a compul sory or opt-in basis as set forth in the proposal, to most types of fuels used for transporta tion in California, including:

• California reformulated gasoline;

• California diesel fuel;

• Compressed or liquefied natural gas;

• Electricity;

• Compressed or liquefied hydrogen;

• Any fuel blend c ontaining hydrogen;

• Any fuel blend containing greater than 10 percent ethanol by volume;V-3 • Any fuel blend containi ng biomass-based diesel;

• Neat denatured ethanol;

• Neat biomass-based diesel; and

• Any other liquid or non-liquid fuel not otherwise exempted fr om the regulation.

As noted below, the proposal contains a few fuel- and application-specific exemptions.

1. Credit Generation Opt-In Prov ision for Specific Alternative Fuels

The proposed regulation includes an opt-in provision for certain alternative fuels that have full fuel-cycle, carbon intensities that inherently meet the proposed compliance requirements through 2020. These fuels are electricity, hydrogen and hydrogen blends,
fossil CNG derived from North American sources, biogas CNG, and biogas LNG. Regulated parties for these f uels are required to meet t he LCFS requirements (e.g., reporting, credit balancing) only if they elect to generate credits based on these fuels as provided under the proposal. Generally, parti es that opt into the LCFS program will be those parties that expect to generate LCFS cr edits under the regulation. By opting into the program, a person becomes a regulated party under the LCFS regulation and is required to meet the LCFS r eporting obligations and requirem ents. The provisions for opting into the LCFS are set forth in the proposal.

2. Exemption for Specifi c Fuels and Applications

The proposal exempts any alternative fuel that is not biomass-based or renewable biomass-based and for which the aggregated volume by all parties for that fuel is less than 420 million mega-Joules per year (3.6 million gasoline gal lon equivalent per year). This is intended to exempt research fuels ent ering the market or very low volume niche fuels. The exemption is int ended to allow alternative fuel providers, particularly smallvolume producers whose fuels have inherently low carbon intensities, adequate leadtime to develop the technologies necessary to make their fuel s viable for future transportation applications.

Not all alternative fuels, however, qualify for the low volume exemption. Biomass-based fuels, such as denatured fuel ethanol and biomass-based diesel, and fuel blends containing biomass-based fuels, do not qual ify for the exempti on regardless of the quantity produced due to the pot ential land-use impacts and other global sustainability

and economic considerations of biofuels. Persons claiming this exemption would need

to demonstrate to the Executiv e Officer’s satisfaction that they meet the requirements for this exemption.

It should be noted that this exemption dates back to the beginnings of the LCFS rule development, but it currently may be of limited utility. It was originally intended as a “catch-all” provision that w ould provide incentives for low volume, low carbon-intensity fuels, as well as those fuels for which an exemption was justified on other bases. However, the proposal as currently written s pecifically addresses m any of the original reasons underlying this exempt ion. For example, hydrogen was originally intended toV-4 be subject to this exemption, but that f uel is now covered by the voluntary opt-in provision noted above. Because the exempti ons in the proposal are now explicit for a

number of alternative fuels and specific fuel applications, this general low-volume exemption has been made moot for the vast majority of its originally intended uses. Thus, staff may propose am endments to this exemptio n as a 15-day change to eliminate or more narrowly focus the exemption.

In addition to the low volume exemption noted above, the proposal does not apply to regulated parties providing liquefied petrole um gas (LPG or propane). Staff is proposing to exempt propane because it neit her plays a significant role as a transportation fuel in the current market, nor is it anticipated to be a significant

contribution to the tran sportation pool in the 2010 to 2020 timeframe.(72) 33

There is also an exemption for specific applications of tr ansportation fuels, including fuels used in aircraft, racing vehicles, inte rstate locomotives, ocean-going vessels, and military tactical vehicles. However, it is important to note that this exemption does not apply to recreational watercraft and to intra state locomotives and commercial harborcraft, for which the diesel fuel is al ready subject to the requirements in 17 CCR § 93117 (i.e., required to use on-road California di esel). Because of this, the fuel sold

or offered for sale for use in recreational watercraft (subject to existing ARB on-road fuels regulations) and the diesel fuel sold or offered for sale for use in intrastate

locomotives and commercial harborcraft su bject to 17 CCR § 93117 would be treated the same as any other transportati on fuel subject to the LCFS.

C. Definitions

There are numerous definitions specified in order to facilitate im plementation of the LCFS program, including key definitions such as:

• “Transportation fuel,” which means any fuel used or intended for use as a motor vehicle fuel or for transportation purposes in a nonvehicular source.

• “Blendstock,” which means a component t hat is either used alone or is blended with another component(s) to pr oduce a finished fuel used in a motor vehicle. Each blendstock corresponds to a f uel pathway in the CA-GREET. A blendstock that is used directly as a transportation fuel in a vehicle is

considered a finished fuel.

• “Carbon intensity,” which means the amount of lifecycle greenhouse gas emissions, per unit of energy of fuel del ivered, expressed in grams of carbon dioxide equivalent per megajoule (gCO 2 e/MJ).

33 Western Propane Gas Association, citing ICF Inte rnational’s memorandum on Assessment of Propane Engine Fuel Sales in California, January 8, 2009 “(... anal ysis indicates that propane used in this market [engine fuels in California] has been relatively flat for the last several years. Mo dest growth in the forklift market, which is driven by economic growth, has be en offset by declines in propane used in on-road vehicles. There has been very few new propane vehicles added in California during this period due to the lack of suitable OEM propane vehicles and certified propane vehicl e conversion kits.”).V-5 • “Credits” and “deficits,” which ar e the measures used for determining a regulated party’s compliance with average ca rbon intensity requirements in the proposal. Credits and deficits are denominated in units of metric tons of carbon dioxide equivalent and are calculated in accordance wit h the specified procedures.

• “Finished fuel,” which means a fuel t hat is used directly in a vehicle for transportation purposes without requiring additional chemical or physical processing.

• “Lifecycle greenhouse gas emissions,” wh ich means the aggregate quantity of greenhouse gas emissions (including direct emissions and significant indirect emissions such as significant emissions from land use changes), as determined by the Executive Officer, related to the fu ll fuel lifecycle, incl uding all stages of fuel and feedstock production and distribut ion, from feedstock generation or extraction through the distri bution and delivery and use of the finished fuel to the ultimate consumer, where the mass values for all greenhouse gases are adjusted to account for their re lative global warming potential.

• “Regulated party,” which means a per son who must meet the average carbon intensity requirements specified in the proposal.

D. Average Carbon Intensity Requirements

1. Compliance Schedule

As noted, the LCFS achieves the goals of Executive Order S-01- 07 by incrementally reducing the allowable carbon in tensity of transportation fuel used in California. The

LCFS does not limit the carbon in tensity of individual batches or types of fuels, but it does require regulated parties to comply wit h annual, average carbon-intensity levels for the total amount of fuel they provide in California. The allowable carbon intensity of transportation fuels decreases each year, starti ng in 2011, until the ca rbon intensities of gasoline and diesel transportation fuel s in 2020 and beyond are each reduced by and average of 10 percent relative to 2010.

Under the proposal, the carbon intensity for alte rnative fuels that substitute for gasoline or diesel fuel (e.g., biofuels, natural gas , hydrogen, electricity) would be judged against either the gasoline or diesel carbon in tensity requirements, depending on whether the alternative fuel is used for light- and medi um-duty vehicles or for heavy-duty vehicles, as specified in the regulation. In general, alternative fuels that substitute for gasoline and are used in light-duty or medium-duty applications will be compared to the gasoline standard. Similarly, alternative fuels that substitute for diesel fuel and are used in lightduty, medium-duty, or heavy-duty vehicles, locomotives, and off-road vehicles are compared to the di esel standard.

It is important to note that li ght-duty use of diesel fuel is treated similarly to heavy-duty use of the fuel and a regulated party referenc es the diesel standard for all applications of diesel. A separate standard for diesel woul d minimize fuel shuffling to diesel as a method of compliance with the LCFS and the health effects associated withV-6 dieselization, and would in centivize improvements in petroleum-based conventional

fuels.

In each year under the LCFS, the carbon int ensity of each fuel is compared to the carbon intensity requirement for that year. Fuels that have ca rbon intensity levels below the requirement generate credits. Fuels with carbon intensity levels above the requirement create deficits. To comply with the LCFS for a given year, a regulated party must show that the total amount of cr edits equal or exceed the deficits incurred. Excess credits can be retained or sold to other regulated parties.

Staff expects that more stringent standards wil l be set in the future for the years past

2020 in order to achieve additional GHG em ission reductions to help meet 2050 GHG emission reduction goals.

As noted, the proposed compliance schedules for gasoline and diesel fuel follow similar carbon intensity reduction percentages fr om 2011 through 2020. The schedules are back-loaded or technology-forci ng, with the majority of r eductions occurring after 2015. Table 1 shows the carbon intensity values of gasoline and gasoline-substitutes, and diesel and diesel-substitutes from 2011 to 2020. The back-loaded compliance

schedules take into consideration the ava ilability of biofuels through the Energy Independence and Security Act, the availability of advanced electric vehicles such as plug-in hybrid electric vehicles (PHEVs) and battery electric vehicles (BEVs), and the availability of flex-fuel vehicles (FFVs) during the implementation of the LCFS.

Additional information about the scenarios used to determine the compliance schedules can be found in Chapter VI.

Table V-1 LCFS Compliance Schedules

Year CI for Gasoline

and Fuels Substituting for

Gasoline 1

(g/MJ) Gasoline and

Fuels Substituting for

Gasoline

% Reduction CI for Diesel

and Fuels Substituting for

Diesel (g/MJ) Diesel and

Fuels Substituting for

Diesel

% Reduction

2010 Reporting Only Reporting Only

2011 95.61 0.25% 94.47 0.25%

2012 95.37 0.5% 94.24 0.5%

2013 94.89 1.0% 93.76 1.0%

2014 94.41 1.5% 93.29 1.5%

2015 93.45 2.5% 92.34 2.5%

2016 92.50 3.5% 91.40 3.5%

2017 91.06 5.0% 89.97 5.0%

2018 89.62 6.5% 88.55 6.5%

2019 88.18 8.0% 87.13 8.0%

2020 86.27 10.0% 85.24 10.0%V-7 The carbon intensity reductions shown in Ta ble 2 are displayed gr aphically in Figure 1 and Figure 2.

Figure 1 Figure 2

Compliance Schedule from 2011 to 2020

for Gasoline or Gasoline Substitutes

80.0 82.0 84.0 86.0 88.0 90.0 92.0 94.0 96.0 98.0

2011 2012
2 01

3
2 014
2 015
2 016
2 017 2018
2 01

9
2 02

0

YearCarbon Intensity, gCO2e/MJ Compliance Schedule from 2011 to 2020 for

Diesel Fuel or Diesel Fuel Substitutes

80.0 82.0 84.0 86.0 88.0 90.0 92.0 94.0 96.0

2011 2012 2013 20 1 4 2015 2016 2017 20 1 8 2019 2020

YearCarbon Intensity, gCO2e/MJ

2. Baseline Year and Baseline Carbon Intensity

The proposed regulation considers 2010 as the baseline year against which a 10 percent reduction in GHG emissions is mandated by 2020.(2) 34 Staff believes it is important to allow regulated par ties the opportunity in the first year to get acclimated with the LCFS requirements and to allow LCFS design improv ements to be identified. Therefore, under the pr oposal, 2010 is the first year of implementation, which imposes only reporting requirements on regulated parties.

The baseline carbon intensities for gaso line and diesel were calculated using CA-GREET version 1.8b. The gasoline carbon intensity was determined using 10 percent by volume corn ethanol and has a carbon intensity of 95.85 gCO 2 e/MJ. The carbon intensity of diesel in 2010 was determined to be 94.71 gCO 2 e/MJ. Details for both gasoline and diesel carbon intensity ca lculations can be found in Chapter IV.

In 2006, California reformulated gasoli ne (CaRFG3) contai ned an average of six percent ethanol by volume. However, as a re sult of the implement ation of the Federal Energy Independence and Security Act of 2007 and compliance with the amended CARFG3 regulations, the amount of ethanol in CaRFG is expected to increase to about 10 percent by volume. Therefore, the baseline carbon intens ity for gasoline is determined using 10 percent by volume corn ethanol to reflect the expected changes in gasoline formulations between 2006 and 2010. Furthermore, for the purpose of baseline calculations, staff proj ects that in 2010 the following mix of corn ethanol will be

34 The Executive Order S-01-07 was issued in Jan uary 2007, therefore the objective is to achieve an overall 10 percent reduction in the carbon intensity of fuels by 2020 from 2006. The proposed regulation achieves this objective because the carbon intensity of the 2010 baseline is essentially equivalent to the

baseline in 2006.V-8 available for blending in California: 80 percent produced in the Midwest 35 and 20 percent produced in California. 36

Staff does not expect any significant penetration of alternative fuels that would affect the carbon intensity of the basel ine diesel fuel between 200 6 and 2010. Therefore, the diesel baseline carbon intensity is determined us ing California ultra-low sulfur diesel fuel (ULSD).

E. Applicable Standards for Alternative Fuels

As noted, a regulated party that provides an alternative fuel such as ethanol, biomass-based diesel, electricity, and hydr ogen and hydrogen blends will use either the gasoline or diesel standard, depending on how the fuel is used in a vehicle. Fuels using the gasoline standard are referred to in the regulation as gasoline-substitutes and those using the diesel standard are referred to as diesel-substitutes.

1. Single-Fuel Vehicles

Single fuel vehicle means a v ehicle that uses a single external source of fuel for its operation. Generally in such vehicles, light -duty or medium-duty applications of an

alternative fuel will use the gasoline standard. All other app lications will use the diesel

standard.

While the application of an alternative fuel is an important factor in determining which standard to use, another important factor is w hether gasoline or diesel is displaced by the use of the alternative fuel. Thus, an ex ception to the general rule above applies to

biomass-based diesel fuels. The diesel fuel standard is to be used for all applications of

the biomass-based diesel fuel that are regulated under the LCFS, since typically biomass-based diesel displaces ULSD.

2. Multi-Fuel Vehicles

A multi-fuel vehicle use two or more fuels fo r its operation. For alternative fuels used in such vehicles, the gasoline average carbon-in tensity requirement is used if one of the fuels used by the vehicle is gasoline. Si milarly, the diesel average carbon-intensity requirement is used if one of the fuels used by the vehicle is diesel fuel.

In the case of multi-fuel vehicles using alte rnative fuels only (i.e., no gasoline or diesel fuel), provisions similar to single fuel vehi cles would apply. Fo r light-duty or mediumduty applications, the gasoline average carbon-intensity requi rement is used for all

alternative fuels. For a ll other applications, the di esel average carbon-intensity requirement is used.

35 In the Midwest, 80 percent corn ethanol is produc ed via dry milling and 20 percent via wet milling, dry DGS process.

36 In California, all corn ethanol is pr oduced via dry milling, wet DGS process.V-9 F. Requirements for Regulated Parties

1. Using “Regulated Party” in stead of “Point of Regulation”

In developing the regulatory l anguage, staff believes it is important to recognize the potential enforcement differences between t he LCFS and current standards for liquid fuels such as CaRFG3 and ULSD. The CaRFG3 regulation considers the point of regulation to be the point at which the f uel producers release finished fuel CaRFG3 throughout the distribution system. Comp liance can be determined systematically through fuel sampling and testing.

Unlike the CaRFG3 and ULSD rules, t he proposed LCFS regulation uses calculated lifecycle fuel carbon intensity. Carbon inte nsity is based on properties inferred from a fuel’s production; it cannot be abstracted directly from the f uel or measured by analytical instruments. Therefore, in addition to t he ideal attributes above, the LCFS point of compliance needs to take into consideration which entity is in the best position to document that a fuel’s appropr iate carbon intensity values have been used. Based on this and other considerations, staff determi ned that identifying the “regulated party” would better serve the LCFS program than identifying the “point of regulation.”

2. Identification of Regulated Parties

The proposed regulation designates which ent ities in the fuel supply chains are obligated to demonstrate complia nce with the LCFS. These entities are referred to as “regulated parties” and are responsible for the fuel and for reporting fuel information to the Board. In general, the r egulation places compliance obligations initially on regulated parties that are upstream entities (i.e., producers and importers that are legally responsible for the quality of transportation fuels in Califor nia), rather than downstream distributors and fueling stations . However, under specified conditions, the regulated party may be another entity further downstream that can be held responsible for the carbon intensity of the fuel s or blendstocks that they dispense in California.

For gasoline, diesel, and other liquid blendstocks (including oxygenates and biodiesel), the regulated party will generally be the producer or importer of the fuel or blendstock. With regard to compressed and liquefied natu ral gas derived from petroleum sources (fossil CNG and fossil LNG, respectively), the regulated party for fossil CNG will generally be the utility company, energy service provider, or other entity that owns the fuel dispensing equipment; for fo ssil LNG, it is the entity that owns the fuel when it is transferred to the fuel dispensing equipment in California. For other gaseous fuels (biogas/biomethane, hydrogen), the regulat ed party will generally be the person who produces the fuel and supplies it for vehicular use. For electricity, the regulated party will be either the load service entity (LSE) su pplying the electricity to the vehicle or another party that has a mechanism for prov iding electricity to vehicles and has assumed the LCFS compliance obligation. The proposed regulation specifies the criteria under which a person wo uld be deemed a regulated party for each particular fuel and how the responsibility of complying with the LCFS can be transferred.V-10 As noted, certain persons are initially designated as regulated parties who are responsible for the LCFS comp liance obligations. Except as provided in the proposal, this status as a regulated party generally re mains with the initially designated party even if ownership to the fuel is transferred fr om one party to another. There are two major exceptions to this general ru le. First, for CARBOB, the compliance obligations would generally transfer to another producer or im porter, with provisions for the initial regulated party to retain the compliance obligation if so desired by the affected parties. For diesel fuel, the compliance obligations would generally transfer to another producer or importer that receives the diesel fuel from the initial regulated party before the final distribution point, with provisions for the init ial regulated party to retain the compliance obligation if so desired by the affected parties.

Second, the proposal generally allows the regulated party fo r a fuel to transfer its compliance obligations by written inst rument to another par ty under specified conditions; the buyer or recipient of the tr ansferred fuel, in turn, becomes the regulated party for that fuel. For a variety of reasons , the transfer of such compliance obligations, along with the potential for generating and se lling credits, may be desirable for a company, and the proposal allows such transfers.

The following sections describe staff’s analysis for identifying the regulated party for all

fuels considered under the LCFS.

a. Regulated Parties for Gasoline and Diesel

For gasoline and diesel fuel (i.e., “traditi onal” transportation fuels) , crude oil is taken from the ground and then transport ed to a refinery where it is processed into various refinery products, including mate rial that eventually goes into gasoline and diesel fuels. California refineries produce Californi a Reformulated Gasoline Blendstock for Oxygenate Blending (CARBOB), which is transported through pipelines, blended with ethanol at distribution terminals, and distributed to retail outlets as finished gasoline.

The CaRFG3 regulations describe the standards applicable to all gasoline produced or imported into California. 37 Imported gasoline must be Ca RFG3 compliant. Enforcement is done initially at the distribution terminal s and, if necessary, continued further downstream up to the final distribution fac ilities. However, as described earlier, CaRFG3 provides standards that can be enforced through quant itative analysis. Fuel quality can be tested and compliance can be easily determined. For the LCFS regulation, however, the definition of regulated parties must also take into consideration the availability of carbon intens ity data and the extent to which the data are verifiable.

Currently, seven large oil companies supply about 90 percent of t he gasoline sold in California. Producers and importers are alre ady subject to CaRFG3 regulations and are also considered to be the regulated parties for the federal Rene wable Fuel Standard

37 Title 13, California Code of Regulations, section 2260 et seq.V-11 (RFS2). Therefore, it seem s logical to make them the regulated parties for LCFS as

well.

Through staff analysis and discussions wit h stakeholders and ARB Enforcement personnel, staff proposes that a modified approach to regulat ion at the producer and importer is likely to be the most admini stratively feasible approach and has the advantage of consistency with ex isting federal regulations. Thus, for gasoline, diesel, and other liquid blendstocks (includi ng oxygenates and biodiesel):

• The regulated party is the producer or importer of the fuel or blendstock, or certain recipients, as spec ified in the regulation;

• Upon transfer of title to the fuel, the obligation to maintain compliance with the LCFS regulation may flow from the tr ansferor to the recipient (i.e., the transferee). For example, the compli ance obligation would flow from the regulated party to the recipi ent if the recipient is anot her producer or importer. However, the parties may enter into a c ontract for the transferor to retain the compliance obligation (along with the credits and deficits for the tr ansferred fuel). The transfer document would be requir ed to clearly state either that:

o The recipient accepts it is now the regulated party that is responsible for the acquired fuel or blendstock and for meeting the requirements of the LCFS regulation for the transferred fuel or blendstock. In this case,

the transfer document would need to specify the volume and average carbon intensity of t he transferred fuel; or

o The transferor has elected to remain the regulated party fo r that fuel or

blendstock.

b. Regulated Parties for Natu ral Gas (CNG, LNG, and Biogas)

The general production and distribution path for most fossil CNG is as follows. Natural gas, after extraction from the production we ll, may be treated to bring it up to gas pipeline specifications at a processing plant. The gas is then sent through the transmission system to the “cit y gate,” where it is decompr essed and odorized. The gas

is then sent to the fueli ng station via the low-pressu re distribution system.

There may be several approaches for choosi ng the appropriate regulated party. In selecting the regulated party for fossil CNG, staff focused on identifying the entity in the production and distribution process that:

• Is as far downstream in the process wit hout involving numerous end users to the extent feasible;

• Involves an actual physical facility or other presence within California for jurisdictional purposes;

• Has a relative low number of potential facilities that enforcement staff need to visit; andV-12 • Has access to records that would prov ide insight on the upstream steps so that ARB staff can verify the lifecycle carbon in tensity that is clai med by the regulated party.

Given the above goals and the process by wh ich CNG is produced and imported into California, staff proposes that the regulated party for fossil CNG be the person or entity that owns the fuel dispensing equipment in California.

In most cases, the regulated party would be the local utility company. However, if the gas is purchased from an energy service provi der (ESP) or other entity that owns the fuel dispensing equipment, the ESP or the owner of dispensing equipment will be the regulated party since title to the gas would belong to them, and they are providing the gas for transportation use. In this case, t he local utility company is serving only as a conduit for the gas to be trans ported at the behest of these entities. The ESP or the owner of dispensing equipment are providin g the gas for transportation use, is responsible for the gas quality, and therefore it should be the regulated party in such

cases.

For LNG as a transportation fuel, production methods and fuel providers can vary. At present, LNG for motor vehicle fuel use is derived via two main routes. These are liquefaction of pipeline natural gas, which may be used directly at the source of liquefaction or involve truck transport of the LNG to a separate end-user, and the liquefaction and direct-use of bio-methane der ived from landfill gas. Other production routes for LNG are possible, and are briefly stated below:

• Liquefaction and direct use of bio -methane derived from anaerobic digestion. Here, anaerobic digestion includes stand-al one digesters receiving one or more types of biodegradable, organic residue; dige sters located on dairy, cattle and pig farms; and water treatment/wastewate r treatment plant facilities;

• Truck transport of liquefied bio-methane;

• Pipeline transmission of bio-meth ane, which later is used as LNG;

• Truck transport of LNG received from LN G shipping of NG derived from remote sources; and

• Re-gassed LNG that is transmitted by pipeline before being re-liquefied for motor

vehicle fuel use.

Fuel providers can also vary. Although LN G service stations are privately held and operated by fleets, some also provide public access. A few LNG stations also provide CNG. At present LNG used in the State at LNG service stations is either transported by truck or provided directly from landfill gas (for example, the Wa ste Management, Inc. landfill gas-to-LNG demonstration project). However, initiati ves are underway to provide LNG from pipeline natural gas, particularly in the northern part of the State, where gas quality issues are current ly not a concern.

The sources of natural gas used for the production of CNG and LNG tend to be same; only the end application and lifecycle steps tend to vary. Both can be produced fromV-13 any source of fossilized natural gas. These can include associated gas wells, non-associated gas wells, and coal-bed methane deposits. The source of natural gas can either be domestic and pipeline-based, or it can be imported and either pipeline or LNG-derived from remote natural gas. LN G can also be produced from biogas, landfill gas, or even manufactured gas.

The lifecycle pathways for LNG and CNG share some similarities, but they also have important differences. CNG production typica lly involves four life cycle segmentsproduction, processing, transmission and distribut ion, and only requires compression at the point of end-use. In contrast, depending upon the way the LNG is sourced, its production may involve as few as four life cycle segments (production, processing, liquefaction and shipping/truck transport) and as many as nine lifecycle segments before the point of end-use. Finally, it is possible at the point of end-use to produce CNG from LNG, which further complicates the analysis of lifecycle pathways.

Based on the above considerations, staff pr oposes that the regul ated party for fossil LNG be the person or entit y that owns title to the LNG w hen it is transferred to the fuel dispensing equipment in California.

For biogas CNG and biogas LNG, staff believes it is important to provide regulated party status for persons producing such fuels. Th is will allow those producers to retain the ability to generate credits for such fuels, ev en if the biogas CNG or LNG is blended with

fossil CNG or LNG. Therefor e, for biogas CNG and biogas LNG, staff proposes that the regulated parties for those fuel s be the producers of the fuel.

c. Regulated Part ies for Electricity

Electricity in California is delivered to customers by Load Servicing Entities. Load Servicing Entities are composed of public utili ties and investor owned utilities. In the electricity delivery system, Load Servicing Entities have the most comprehensive knowledge of emissions associ ated with the fuel lifecycle that will influence the carbon intensity. Load Servicing Entities also have the most influence on the availability, cost, convenience and public knowledge of electricity as a transportation f uel. Staff therefore believes Load Servicing Entities will most o ften be the regulated parties for electricity provided under the regulation. However, Load Servicing Entities are not the only potential regulated parties. There may be ca ses where a separate entity has contracted with the Load Servicing Entity to install charging stations for electric transport. In these cases, the entity supplying t he electricity to the vehicle would become the regulated party, as specified in the proposal.

Unlike most liquid fuels, electricity is c onsumed in sectors that are both regulated and unregulated by the LCFS. The regulated party would be responsible only for electricity that is delivered to vehicles. Therefore, the quantification of electricity used as a transportation fuel is a critical consi deration in the design of the LCFS.V-14 Existing electricity generation infrastructure should be able to support a high level of plug-in hybrid electric vehicle (PHEV) and battery electric vehicle (BEV) penetration, particularly if off-peak refuelin g is encouraged. In the case of private residences, this could be achieved by offering rate incent ives and by supplying advanced direct metering systems. Direct meters are capable of detecting electric vehicle electricity consumption only.

Direct meters can be installed as separat e electricity meters associated with garaged electric vehicles. However, this type of re fueling is not practical for many Californians living in urban areas or apartm ent buildings. In addition, m any electric vehicle owners will require the option to refuel away from home as necessary. To provide electricity away from home, a network of charging stations can be es tablished by municipalities and parking lot owners in central public areas. In any case, public charging stations and charging stations installed in apartment co mplexes will likely be necessary for high PHEV and BEV penetration.

The proposal’s metering requirements vary depending on the type of charging facility involved. Because private fleet and public -access charging facilities will be supplying electricity only to electric vehicles, the propos al requires for these facilities only the total amount of electricity dispensed for transpor tation use (in KW-hr) in each compliance period. On the other hand, electricity s upplied to residential charging facilities can supply both transportation electricity and non-trans portation electricity (i.e., for all other electricity uses in a home). Thus, for re sidential charging facilities, the proposal requires direct metering of the electric ity provided for transportation purposes. However, to reduce the costs of installi ng direct metering, staff may consider

amendments to allow alternativ e measurement methods in lieu of direct metering for a specified period of time (i.e., in the ear ly years of the LCFS program when PHEV/BEV penetration is lower). Such alternatives may include meters installed on individual

electric vehicles or other methods for meas uring the amount of electricity dispensed.

Staff proposes Load Servicing Entities (LSE) and other providers of el ectricity services serve as regulated parties for the LCFS regulation for electr icity used for transportation purposes. The compliance obligation can be tr ansferred by contract to another party that assumes the responsibility for meeting t he requirements of LCFS regulation. Such

downstream entities identified in the proposal include electr icity services suppliers (those supplying bundled infrastructure and other related services); certain owners and operators of electric charging equipment; and homeowners that have their own electric charging equipment.

d. Regulated Parties for Hy drogen or Hydrogen Blends

Regulating hydrogen use by vehicles present s some challenges, due primarily to the variety of hydrogen production sources and dist ribution channels. Cu rrently, 95 percent of the hydrogen produced in the United States (approximately nine million tons per year) is generated by steam methane reformation of natural gas feedstock. Hydrogen can also be generated by other ther mal processes such as gasific ation of coal or biomass,V-15 reformation of renewable liquid fuels or high temperature water splitting. Electrolytic processes (using electricity from grid, so lar, or wind to split water) and photolytic processes (using light energy to split water) are also potential sources for hydrogen as a transportation fuel.

Hydrogen can be generated on-site at the fueling station or off-site at a production facility and trucked to the station as compre ssed gas or as a liquid. Hydrogen pipelines are also under development with approxim ately 700 miles of pipeline currently operating. Research is focused on overcomi ng technical concerns related to pipeline transmission, including the potential for hy drogen pipelines to become embrittled (including welds); the need to control hy drogen permeation and leaks; and the need for lower cost, more reliable, and more durable hydrogen compression technology.

For purposes of the LCFS, the poi nt of fuel delivery to vehicl es can be considered to be the point of sale. Since there are divers e production and delivery methods with a range
of differences in GHG emissi ons, identifying the regulated party would center on which entity produces and supplies the hydrogen fo r transportation use in California.

Thus, for hydrogen and hydrogen blends, staff proposes that:

• The regulated party is the owner of the finished fuel at the time blendstocks are blended to produce the finished fuel.

• Upon transfer of title to the finished f uel, the obligation to maintain compliance with the LCFS regulation remains with the transferor. However, the parties may

enter into a contract for the transferor to transfer the compli ance obligation to the transferee (along with the credits and def icits for the transferred fuel). The

transfer document would be r equired to clearly state:

o The volume and average carbon int ensity of the transferred fuel; and

o the recipient is now the regulated party for the acquired fini shed hydrogen fuel and accordingly is responsible for m eeting the requirem ents of the LCFS regulation with respect to the acquired finished hydrogen fuel.

3. Requirements for Reporting

Under the LCFS, each regulated party mu st report to ARB a specified set of information, including carbon intensity, fuel quantity, and other information for each fuel or blendstock supplied in Califor nia on a quarterly and yearly basis. Any party that voluntarily opts into the LCFS to generate credits must also submit a quarterly and yearly report. The reports are due according to the schedules specified in the propos ed LCFS regulation.

While quarterly reports are used to gauge progress and for credit generation, a regulated party must also submit an annua l report covering the current year for determination of compliance by April 30th of the following year. The annual report

must be submitted to the Executive Offi cer, demonstrating t he yearly aggregatedV-16 fuel quantity, the carbon intensity associ ated with the fuel or blendstock, and additional supporting documents or contract s for each fuel or blendstock supplied in California. In addition, credit transactions with other regulated parties and any prior year credit obligations are required to be reported. The Ex ecutive Officer will determine whether the regulated party co mplies with the LCFS based on this annual report.

Staff is developing an online, interactive LCFS Compliance and Reporting Tool (CRT) that will be used for reporting, credit bank ing, and credit transactions during the implementation of the LCFS. This tool is discussed in Chapter IX. The CRT will serve as the central tool to facilitate the large quantity of information submission and validation that will be required under the LCFS, in addition to serving as a communication tool between the Executive Officer and regulated parti es. The first year of the program is intended as a “break in” reporting year, whic h will allow both the regulated parties and ARB program staff to acclim ate to the LCFS rule’s intricacies and to identify any programmatic changes that may be needed as the program is implemented.

4. Requirement to Maintain Adequate Credit Balance

For each compliance period, a regulated party must maintain an adequate number of credits in the account in order to comp ly with the LCFS. The credit balance for a regulated party is an accounting balance shee t that takes into consideration all the credits generated for providing a fuel or a ble ndstock, the amount of credits carried over from the previous compliance period, the amount of credit s acquired, the amount of deficits generated, and t he amount of credits sold, exported or retired. All credits and deficits are reported in units of metric tons of CO 2 equivalent (“MT”). The credit balance is computed as follows:

itred Exported Sold Gen Acquired er CarrivedOv Gen

Credits Credits Credits Deficits Credits Credits Credits nce CreditBala

Re

− − − + + + = V.1

where

Gen Credits are the total credits generated calcul ated according to Equation V.3 in section V.F of this report.

er CarrivedOv Credits are the credits or deficits ca rried over from the previous compliance period.

Acquired Credits are the credits purchased or ot herwise acquired in the current compliance period.

Gen Deficits are the total deficits generated calcul ated according to Equation V.4 in
section V.F of this report.

Sold Credits are the credits sold in t he current compliance period.V-17 Exported Credits are the credits exported to pr ograms outside the LCFS for the current compliance period.

itred Credits Re are the credits retired within t he LCFS for the current compliance period.

For each compliance period, a regulated party uses the carbon inte nsity value of the fuel or blendstock and fuel quantity in formation to calculate the amount of credits/deficits generated under the gas oline and/or diesel standard for each fuel or blendstock, according to Equation V.5 in secti on G of this report. The total credits or deficits generated under either the gasoline or diesel standard is summed across all the fuels or blendstocks, according to Equations V.3 and V.4 in section G. These become

the Gen Credits and Gen Deficits terms in the credit balance equation above. All other

sources of credits and deficits are t hen added and a final credit balance value is determined for the compliance pe riod. Appendix D of this r eport contains illustrative examples that demonstrate LCFS credit balance calculations.

For a compliance period, depending on the val ue of the current credit balance and regulated party’s previous compliance status , a regulated party could fall within one of three categories below:

a. Meets LCFS Credit Balance

If a regulated party has acquired or gener ated enough LCFS credits such that the

nce CreditBala is greater or equal to zero for a given compliance per iod, the regulated party has demonstrated compliance with the LCFS carbon intensity requirements. The

nce CreditBala for a given compliance period may be rolled over to the next compliance
period as er CarrivedOv Credits

.

b. Small Credit Balance Shortfall (“In Deficit”)

If a regulated party has not generat ed, acquired, or carried over sufficient LCFS credits to meet its obligation for the given complian ce period, a regulated party is in deficit status if the following conditions are met:

• The regulated party has not incurred a negative nce CreditBala in the previous compliance period, and

• The total credits in the account must be at least 90 percent of the total deficits for the current compliance period. The follo wing equation shows the credit to deficit

ratio:

% 90

Re ≥

− − − + +

itred Exported Sold Gen Acquired er CarrivedOv Gen

Credits Credits Credits Deficit Credits Credits Credit V.2V-18 The regulated party meeting the two conditions above may carry over the negative nce CreditBala from one compliance period to the next compliance period automatically without incurring a penalty. St aff is proposing this as a compliance flexibility provision that is similar to w hat is allowed under t he federal RFS2. The regulated party has unt il December 31 of the next compliance period to clear the carried-over negative nce CreditBala . The additional deficit clearance time given to the regulated party is called a Deficit Clearance Period, during which the regulated party must have enough credits to clear the carried-over deficits and meet the obligation of the new compliance period. For instance, if a regulated party incurred a negative nce CreditBala of -100 MT in 2012 but was in compliance

in 2011 and has a credit to deficit rati o of 95% in 2012, the regulated party may carry over the -100 MT to 2013 automat ically without incurring any penalties. During 2013, the regulated par ty must clear the -100 MT and meet the obligations

of 2013.

c. Large Credit Balance Shortfall (“In Violation”)

If a regulated party has met one of the c onditions below, then the regulated party

is considered to be in violation of t he LCFS and subject to the penalties and

enforcement actions authorized by the LCFS regulation.

• Incurred a negative nce CreditBala for two or more cons ecutive years; or

• Incurred a credit to defici t ratio of less than 90 percent for a given a compliance period.

A discussion of penalties is presented in Chapter IX.

5. Requirement for Demonstrati ng Evidence of Physical Pathway

It is important to ensure that low ca rbon fuels and blendsto cks produced outside of California are actually the source of fini shed fuels used in the State. Therefore, regulated parties will be required under the proposal to establish physical pathway evidence for transportation fuels subject to the LCFS. For each transportation fuel that a regulated party is respons ible for under the LCFS, this could involve a four-part showing:

• A one-time demonstration that there ex ists a physical pathway by which the transportation fuel is expected to arrive in California. This includes applicable combination of truck delivery routes, rail tanker lines, gas/liquid pipelines, electricity transmission lines, and any other fuel distribution routes that, taken together, accurately account for the fue l’s movement from the generator of the fuel, through intermediate entities, to t he fuel blender, producer, or importer in California;

• Written evidence, by contract or similar evidence, showing that a specific volume of a particular transportation fuel with k nown carbon intensity was inserted into the physical pathway as dire cted by the regulated party;V-19 • Written evidence, by contract or sim ilar evidence, showing that an equal volume of that transportation fuel was remo ved from the physical pathway by the regulated party for use as a transpor tation fuel in California; and

• An update to the initial physical pa thway demonstration whenever there are modifications to the initially demonstrated pathway.

G. LCFS Credits and Deficits

The LCFS is structured much like an emissions reduction credit program in which credits are awarded based on fuel performanc e that exceeds a regulatory standard.
The LCFS includes a flexible combination of fuel-vehicle systems and awards credits to the fuel provider if the to tal emissions generated by the supply and consumption of the fuel are below those of the corresponding ga soline or diesel standards. Beginning 2011, regulated parties could start generating credits on a quarterly basis. These

credits can be banked indefinit ely and used for compliance purposes, sold to other regulated parties, and purchas ed and retired by regulated parties. In addition, the credits can be exported to other GHG emissi ons reductions programs such as AB 32, subject to the requirement s of these GHG programs.

1. Calculation of Credits and Deficits Generated

This section covers the overall method for calculating the credits and deficits generated

or the Gen Credits and Gen Deficits terms in the credit balance in equation V.1.

In the LCFS regulation, the amount of credits generated (or the deficits incurred) by a regulated party contributes to the overa ll credit/deficit balance used for the determination of compliance for a regulated par ty. For each compliance period, a fuel provider calculates the amount of credits and deficits generated for the amount of fuel supplied as either a gasoline or diesel fuel replacement. The total credits and deficits generated under the gasoline and di esel standard are respecti vely summed over all the fuels and blendstocks supplied by the regulated par ty. All credit and deficit are reported

in units of metric tons of CO 2 equivalent (MT). The equati ons V.3 and V.4 illustrate the

calculation.V-20 diesel

i n

i gasoline

i n

i Gen Credits Credits MT Credits 

# ∑ ∑ + = ) ( (V.3)

diesel

i n

i gasoline

i n

i Gen Deficit Deficit MT Deficits 

# ∑ ∑ + = ) ( (V.4)

where:

Gen Credits represents the total credits (a zero or positive value);

Gen Deficit represents the total def icits (a negative value);

i is the fuel or blendstock index; and

n is the total number of fuels and blendstoc ks provided by the regulated party in a compliance period.

For each applicable fuel under the LCFS, credi t/deficit is determined by the overall performance of the fuel, indica ted by the carbon intensity va lue, and the extent to which the fuel displaces a conventional fuel such as gasoline or diesel. The equation V.5

illustrates the calculation.


# ( ) C E CI CI MT Deficits or Credits XD displaced XD reported XD

dard s XD × ×

− = tan ) ( ) ( (V.5)

where:

) ( ) ( MT Deficits or Credits XD indicates the amount of LCFS credits generated (a

zero or positive value), or deficits incurr ed (a negative value), in metric tons of

CO 2 equivalent, by a finished fuel or blendstock under the gasoline standard ( XD =”gasoline”) or diesel standard ( XD =”diesel”); and

C is the factor used to convert credits to units of metric tons and has the value of:



## ( ) ( ) e gCO

MT

x C

2 6 10 0

. 1

− =

The term XD

dard s CI

tan indicates the carbon intensit y of the gasoline or diesel
standard for a given year, which is establis hed as part of the LCFS. Notice the amount of credits generated depends on the extent to which the carbon intensity

value of a fuel is below that of the standard.V-21 For each alternative fuel, the amount of cr edits/deficits generated is also determined by the amount of conventional gasoline or diesel fuel that is displaced, indicated by the

parameter XD displaced E . The amount of conventional energy displaced is determined using a

fuel displacement factor called the Ener gy Economy Ratio (EER) which compares the fuel economy of an alternative fuel vehicle to that of a conventional gasoline vehicle. In addition, the carbon intensity of alternative fuels is adjusted with the EER value of the alternative fuel vehicle. The more energy e fficient fuels and vehicles travel more miles per unit of energy input to the vehicle, t hus resulting in less fuel consumption and CO 2 emissions (carbon intensity). Thus, the carbon intensity is dependent on both the emissions per unit of energy consumed and the fuel economy of the vehicle.

For each fuel or blendstock:

XD i XD reported EER CI CI = ; and XD

i i XD displaced EER E E × =

where:

XD reported CI is the adjusted carbon intensity value reported for credit determination,

in gCO 2 e/MJ;

i CI is the unadjusted carbon intensity value, in gCO 2 e/MJ, determined by a
CA-GREET pathway or a custom pathway and incorporates a land use modifier (if applicable);

XD displaced E is the total amount of gasoline ( XD =”gasoline”) or diesel ( XD =”diesel”)

fuel energy displaced, in MJ, by the use of an alternative fuel;

i E is the energy of the f uel or blendstock, in MJ , determined from the energy

density conversion factors in Table V-2.

XD

i EER is the dimensionless EER relative to gasoline ( XD =”gasoline”) or diesel

fuel ( XD = “diesel”) as listed in Table V-3. For a vehicle-fuel combination not

listed in Table V-3, XD

i EER =1 is used. Chapter IV contains more information on

the EER numbers used in the proposed regulation.

Appendix D of this report shows sample ca lculations of credits and deficits generated for regulated parties providing a single or multiple fuels and blendstocks.V-22 Table V-2 Energy Densities of LCFS Fuels and Blendstocks

Fuel (units) Energy Density

CARBOB (gal) 119.53 (MJ/gal) CaRFG (gal) 115.63 (MJ/gal) Diesel fuel (gal) 134.47 (MJ/gal) CNG (scf) 0.98 (MJ/scf) LNG (gal) 78.83 (MJ/gal) Electricity (KWh) 3.60 (MJ/KWh) Hydrogen (kg) 120.00 (MJ/kg) Neat denatured Ethanol (gal) 80.53 (MJ/gal) Neat Biomass-based diesel (gal) 126.13 (MJ/gal)

Table V-3

EER Values 38 for Fuels Used in Light- and Medium-Duty, and Heavy-Duty Applications

Light/Medium-Duty Applications (Fuels used as gasoline replacement) Heavy-Duty/Off-Road Applications (Fuels used as diesel replacement)

Fuel/Vehicle Combination EER Values

Relative to Gasoline Fuel/Vehicle Combination EER Values

Relative to Diesel

Gasoline (incl. E6 and E10)

or

E85 (and other ethanol blends) 1.0 Diesel fuel

or

Biomass-based diesel

blends 1.0

CNG / ICEV 1.0 CNG or LNG 0.9

Electricity / BEV, or PHEV 3.0 Electricity / BEV, or PHEV 2.7

H2 / FCV 2.3 H2 / FCV 1.9

(BEV = battery electric vehicle, PH EV=plug-in hybrid electric vehicle, FCV = fuel cell vehicle, ICEV = internal combustion engine vehicle)

H. Retaining, Trading, a nd Borrowing of LCFS Credits

As noted, beginning 2011, regul ated parties could start gener ating credits on a quarterly basis. Both the gasoline and diesel standards are backloaded so that, if necessary, credits that were banked in the early years wil l help with compliance in the later years.

38 Chapter IV provides additional information on these EER values.V-23 1. 3rd Party Credit Acquisition and Trading

One of the key cost-reduction LCFS design elements is the creation of a market for carbon intensity credits. Under a market- based system, regulated parties would be able to buy and sell credits. To keep LCFS credit transactions simple in the early years and to ensure there are an adequate num ber of credits in the pr ogram, staff proposes that 3rd party entities not be allowed to purchase, sell, and retire LCFS credits at the onset of the LCFS. As part of the periodic reviews, staff will re-evaluate t he ability of 3rd party entities to participate in LCFS credit transactions.

2. Importing and Exporting Credits to Other Markets

Credit import/export is the process of bringing credits generated in one GHG emission reduction program into a complementary, ex ternal program for compliance under that program and vice versa. The proposed regula tion allows for the exporting of credits to other GHG trading programs, su bject to the requirements of those other programs. However, the staff proposal pr ohibits the imports of credit s from other programs outside

the LCFS.

The range of responses from stakeholders on this issue is diverse. Several stakeholders caution that credits exported to AB 32 could undermine t he integrity of the AB 32 cap and force the LCFS to be consider ed a substitute policy rather than a complementary policy. They further argue that since transpor tation should be already included in an economy-wide market, tradi ng between the two pr ograms would amount to double counting. Other stakeholders belie ve that reductions in areas overlapping
both the LCFS and AB 32 should receive credi ts under both programs , thus eliminating the need for exports. Still other s support the export of LCFS credits and see it as a

mechanism to ensure there is a market fo r the generated credits. ARB staff believes

that the LCFS should not restri ct the use of these credits in other markets. However, the use of these credits will be dictated by the requirements of t hose other programs, including the AB 32 trading progr ams. Such flexibility ma y incentivize the development

of innovative low-carbon fuel te chnologies within the LCFS.

ARB staff is proposing not to allow the us e of GHG credits generated outside the LCFS program to be used in the LCFS program. This is to ensur e that improvements in the LCFS fuel pool occur. As a possible except ion, however, staff will continue to evaluate the feasibility and effectiveness of allowing cr edits generated from marine and aviation transportation areas, which are not currently in cluded in the LCFS fuel pool, to be used in the LCFS program. AR B staff will provide an update on the potential use of GHG

credits from lower carbon marine and aviation fuels to be used in the LCFS program, at the scheduled milestone review point.

3. Borrowing of Credits

Under a credit borrowing system, credits would be ‘borrowed’ from anticipated future emissions reductions in order to meet compli ance in the present. Funds raised from theV-24 sale of borrowed credits could be used to increase a regulated entity’s near-term ability to invest in the development of lower-carbon fuels. These increased investments could bring lower carbon fuels to market sooner than might otherwise be possible. Credit borrowing systems are relatively untested, and any attempt to implement one in California could be problematic. Staff is proposing to not allow the borrowing of LCFS

credits.

I. Determination of Carbon Intensity Values

The carbon intensity values represent the cu rrency upon which the LCFS is based. The carbon intensity is determined in two parts. The first part represents all of the direct emissions associated with produc ing, transporting, and using the fuel. This involves determining the amount of GH G emissions emitted per unit of energy for each of the steps in the fuel pathway. The second part considers other effects, including those caused by changes in land use. For some crop-based biofuels, staff has identified land use changes as a significant source of addi tional GHG emissions. Therefore, staff is proposing that emissions associated with land use changes be included in the carbon intensity values assigned to those fuels in the proposed regulation. No other significant effects that result in large GHG emissions have been identified that would substantially
affect the LCFS framework fo r reducing the carbon intensit y of transportation fuels.

As discussed in the last se ction, staff used the CA-GR EET model as the primary method for calculating carbon intensity values for various transportation fuels. CA-GREET is essentially a very large spr eadsheet that incorporates many specific

numeric values that allow for the calculation of the life cycle GHG emissions associated with producing, transporting, and using various fuels. Staff used CA-GREET to develop specific carbon intensities for a number of di fferent pathways. For some fuels, multiple pathways were developed that represent diffe rences in how and where the fuel is produced.

To assess the emissions from land use changes, staff used the Global Trade Analysis Project (GTAP) to estimate the GHG emi ssions impact. The GTAP model is also discussed in Chapter IV. In general, the model evaluates the worldwide land use conversion associated with the pr oduction of crops for fuel production. Different types of land use have different rates of storing ca rbon. In general, multiplying the changes in land use times an emission factor per land conv ersion type results in an estimate of the GHG emissions impacts of land conversions.

The proposed regulation has several differ ent methods for establishing carbon intensities. The first method, referred to as Method 1, establishes values in a Lookup Table for a number of specif ied fuel pathways. Regulated parties may choose to use these pathways to calculate credits and deficit s. The staff is proposing that the Board approve this Lookup Table. The proposed regul ation establishes that the Executive Officer may approve subsequent amendments to the Lookup Table after a specified public process.V-25 Under specified conditions, regulated parties may also obt ain Executive Officer approval to either modify the CA-GREET model inpu ts to reflect their specific processes (Method 2A) or to generate an additional path way using CA-GREET (Method 2B). For both Method 2A and 2B, there is a scientific defensibility re quirement for the regulated party to meet before the Ex ecutive Officer can approve new values. For Method 2A, there is an additional provision that requires a substantial change (5.00 g CO 2 e/MJ decrease in source-to-tank CI) relative to the analogous value calculated for that pathway under Method 1.

For all requests under Methods 2A and 2B, ARB staff will conduct analysis or modeling to determine the new pathway’s impact on total carbon intensity due to indirect effects, including land-use changes. This analysis will be performed using the GTAP model or other model determined by the Executive Officer to be at least equivalent to the GTAP

model.

For CARBOB, gasoline, and diesel fuel, there ar e specific provisions with regard to the method for determining carbon intensity values, depending on whether the crude oil

used to make such fuels is deriv ed from crude oils with high carbon intensity relative to the average carbon intensity of crude oils used in California refineries. Examples include certain crude oils produced from o il sands, oil shale, or other high carbonintensity crude oils. With regard to CARBOB , gasoline, and diesel fuel made from crude oil extracted from any sour ce other than these high car bon-intensity crude oils, the regulated party would be required to use the carbon intensity specified in the Lookup

Table for that fuel.

By contrast, for CARBOB, gasoline, and dies el fuel made from high carbon-intensity crude oil, the regulated party w ould be required to use the car bon intensity value, if any, which is specified in the Lookup Table for that particular pathway. If there is no carbon intensity value specified for a particular hi gh carbon-intensity crude oil, the regulated party could use Method 2B (with Executiv e Officer approval) to generate an additional pathway for this type of crude.

Alternately, the regulated party coul d use the standard Lookup Table value for CARBOB, gasoline, or diesel for fuel derived from non-high carbon intensity crude oil, but only if the regulated party can demonstr ate to the Executive Officer that its crude production and transport carbon-in tensity value has been reduc ed to a specified level and meets other specifi ed criteria. To this end, staf f is proposing that any regulated party, using a high carbon-intensity crude o il (> 15 g CO2e/megajoul e) brought into California that is not already part of the California baseline crude mix, would have to report and use the actual ca rbon intensity for that crude oil unless the party

demonstrates that it has reduced the crude oil’s carbon intensity below 15 g CO2e/megajoule using carb on-capture-and-sequestration (CCS) or other method. Upon this demonstration, the regulated party would be permitted to use the average carbon intensity value for the California bas eline crude mix (i.e., crude oils currently used in California refineries).V-26 The proposed uses of Method 2A and 2B ar e subject to public review under the proposal. In other words, the Executiv e Officer may not approve a carbon intensity value proposed pursuant to Method 2A or 2B unless the proposed method and associated information submitted in support of that method has been disclosed to the public and available for public review for the prescribed time period. Trade secrets, as defined under State law, t hat are submitted would be treated in accordance with established ARB regulations and procedur es (17 CCR §§ 91000-91022) and the Public Records Act (Government Code § 6250 et seq.).

J. Requirements for Multimedia Evaluation

1. Statutory Requirements

Senate Bill 529, enacted in 1999 and set fort h in Health and Safety Code (H&S)

section 43830.8 (“the statute”), 39 generally prohibits ARB from adopting a regulation establishing a specification for motor vehicl e fuel unless the regulation is subject to a multimedia evaluation by the California Environmental Poli cy Council (CEPC). (Stats. 1999, ch. 813; SB 529, Bowen.) Pursuant to Public Resources Code section 71017(b),

the CEPC was established as a seven-mem ber body comprised of the Secretary for Environmental Protection; the Chairpersons of the ARB, State Water Resources Control Board, and Integrated Waste Ma nagement Board; and the Direc tors of the Office of

Environmental Health Hazard Assessmen t, the Department of Toxic Substances Control, and the Department of Pestici de Regulation. Ke y components of the evaluation process are the ident ification and evaluation of significant adverse impacts on public health or the envir onment and the use of best av ailable scientific data.

“Multimedia evaluation” means the identification and eval uation of any significant adverse impact on public health or the environm ent, including air, water, or soil, that may result from the production, use, or disposal of the mo tor vehicle fuel that may be

used to meet the state board’s motor vehi cle fuel specifications. H&S §43830.8(b).

The statute generally provides that ARB may adopt a regul ation establishing a motorvehicle fuel specificati on without undergoing the prescr ibed multimedia evaluation process if the CEPC, following an initial evaluation of the pr oposed regulation, finds that the regulation will not have significant adverse impacts on public health or the

environment.

2. Applicability of H&S §43830. 8 to the LCFS Regulation

The provisions in H&S §43830.8 are relatively straightforward for a fuel regulation that unquestionably constitutes a fuel specificat ion. However, bef ore the substantive requirements of the statute can be discusse d, we first need to address an important threshold question in this case: Does the st atute apply to the LCFS regulation itself, or

39 All statutory references in this chapter are to H&S §43830.8 unless otherwise noted.V-27 does it apply onl y to subsequent ARB rulemakings establishing new or amended motor-vehicle fuel specifications to implement the LCFS program?

a. H&S §43830.8 Applies to ARB Adoption of Regulations that Establish Specifications for a Motor Vehicle Fuel

By its terms, the statute clearly focuses on prohibiting ARB from adopting regulations that establish specifications for motor vehicle fuels unless the regulation has been subjected to a multimedia evaluation as specifi ed. Presumably, this is to avoid, among other things, requiring ARB to conduct a multimedia evaluation for rule amendments that are merely technical in nature and have no substantive effect on motor vehicle fuel specifications. Another possibility is that the Legislature did not want to require a

multimedia evaluation w henever ARB adopted fuel use requirements, which affect the use of a fuel and operation of equipment using t hat fuel, rather than affecting the fuel

itself. 40 A third possibility is that the Legislat ure did not want to require multimedia evaluations for emissions averaging or si milar regulatory schem es for which an enforceable goal is set but the exact methods for achieving that goal are not specified by the regulation (i.e., through motor vehicle fuel specifications).

Further, the Legislature presum ably used the term “specifi cation,” rather than more broad terms such as “standard” or “requiremen t,” to express an intent to focus on those regulations in which ARB is proposing to di ctate what is added (or prohibited from being added) into a motor vehicle fuel. This would be consistent with the le gislative history of SB 529, which was promul gated after fuel producer s began to use methyl tert -butyl ether (MTBE) in gasoline in the 1990s to meet ARB oxygenate requirements. The Legislature enacted SB 529 after MTBE was s ubsequently shown to leak out of underground storage tanks unexp ectedly into aquifers.

With these considerations in mind, the next questions that follow are, “What is a motor vehicle fuel specification?” and “Is the LCFS a regulatio n that establishes a fuel specification for motor vehicle fuels?”

b. The LCFS Regulation Does Not Establish a Specification for

Motor Vehicle Fuels

For purposes of this discussion, the primar y LCFS requirement of interest is the requirement for regulated parties to r educe their average carbon intensity by 10 percent. 41 This 10 percent reduction in over all carbon intensity would cover the party’s overall motor vehicle fuel pool, includi ng all fuels subject to the LCFS, as well as

40 An example is the California requirement for locomo tives and commercial harbor craft to use California ultralow sulfur diesel. 13 CCR §2299 and 17 CCR §93116.

41 That is, the regulated party’s carbon intensity must be no greater than the carbon intensity (CI) for gasoline or diesel as the CI for those fuels ar e reduced by 10% between 2010 and 2020 in accordance with the proposed regulation’s compliance schedul e (the gasoline CI applies generally for light duty vehicles and the diesel CI for heavy duty vehicles).V-28 any credits/deficits from ov ercompliance and undercompliance with the requirement in a given compliance period.

Unfortunately, the statute provides no explicit definition for “specification.” However, there is evidence indicating that the Legislat ure intended the term “specification” as a reference to the permissible ingredients t hat comprise a fuel (i.e., the fuel’s “composition”). In H&S §43018, a statute last amended ni ne years before SB 529 was enacted, the Legislature mandated that ARB:

“adopt standards and regulations which will result in the most costeffective combination of control measur es on all classes of motor vehicles

and motor vehicle fuel , including, but not limited to, all of the following:...(4) [s]pecification of vehicular fuel composition ...” [emphasis added].

H&S §43018(c)(4) [Added St ats. 1988, ch. 1568; amended Stats. 1989, ch. 559; amended Stats. 1990, ch. 932].

In this context, the Legislature seems to us e the term “specificat ion” as a subset of motor vehicle “standards,” “regula tions,” and “measures.” Thus, one can reasonably presume that, in the context of motor vehicle fuels, the Legislature intended the term “specification” to be an ARB mandate on a vehicular fuel’s permissible composition, rather than on the production process for the fuel.

This view of the legislative intent is further supported when one looks at the common usage for the term “specification” in the area of motor vehicle fuels. To this end, we first discuss the general characteristics of a specif ication and then look at several examples of existing ARB specifications. From these examples, it is possible to glean whether the Legislature intended for a regulation like the LCFS to trigger the multimedia evaluation requirement.

The American Heritage (4 th Ed.) dictionary(73) defines “specification” as follows:

“ A detailed, exact statement of particula rs, especially a statement prescribing materials, dimensions, and quality of work for something to be built, installed, or

manufactured. ”

This suggests that a specification is prescrip tive in nature, i.e., telling the reader that material X is required in Y amount. A usef ul analogy is a typical cooking recipe, in which not only are the ingredi ents specified, but also their relative quantities. Motor vehicle fuel specifications, like cooking re cipes, also specify what materials are permitted to be in a legal motor vehicle fuel and the relative quantities of those

materials.

There are numerous examples of motor vehi cle fuel specifications that were in

existence at the time SB 529 was enacted. Fo r instance, California’s diesel regulationV-29 in 1999 applied specifications that limited aromatic hydrocarbons to 10% by volume and 500 parts per million (ppm) sulfur in diesel. 42 Another example is the California regulation establishing specifications fo r E-85 (gasoline with 85% ethanol), which is presented in Table V-4.

Table V-4 Select Specifications for E-85 Fuel Ethanol

Specification Value Test Method

Ethanol 79 vol. % (min.) ASTM D 3545-90 Other Alcohols 2 vol. % (max.) ASTM 4815-89 Hydrocarbons + aliphatic

ethers 15-21 vol. % ASTM D 4815-89, and then subtract concentration of alcohols, ethers and water from 100 to obtain percent hydrocarbons Acidity as acetic acid 0.007 mass % (max.) ASTM D 1613-85

Total chlorine as chloride 0.0004 mass % (max.) ASTM D 3120-87 modified for the det. of organic chlorides, and ASTM D 2988-

86 Copper 0.07 mg/l (max.) ASTM D 1688-90 as modified in ASTM

D 4806-88 Source: 13 CCR § 2292.4 (adopted by ARB in 1992); footnotes omitted.

A third, more current example is the CaRF G3 regulation is pres ented in Table V-5.

Table V-5 Select Current Specifi cations for CaRFG3

Property Flat Limits Averaging Limits Cap Limits

Reid Vapor Pressure, psi, max 7.00 or 6.90 -- 6.40 – 7.20

Benzene vol%, max 0.80 0.70 1.10 Sulfur, ppmw, max 20 15 30 20 (2011) Aromatic HC, vol%, max 25.0 22.0 35.0
Olefins, vol% max 6.0 4.0 10.0 Oxygen, wt% 1.8 to 2.2 -- 1.8 - 3.5

0 – 3.5 T50 (temp. at 50% distilled) o F, max 213 203 220

T90 (temp. at 90% distilled) o F, max 305 295 330

Source: 13 CCR §2260 et seq.; footnotes omitted.

42 13 CCR §2282(a)(1)(A) and §2281(a)(1), respectively . The 500 ppm sulfur limit was reduced for most applications to 15 ppm beginning in June 2006. Id . at §2282(a)(2).V-30 Of course, motor vehicle fuel specifications ar e not cooking recipes, as they entail highly technical properties and measurements for the affected fuels. But like a cooking recipe, all the above examples of exis ting fuel specifications share a common characteristic – the specifications contained in the r equirements are quantif iable and measurable chemical or physical properties that are intrin sic to the final fuel itself, not how it is produced. In other words, one can take a sa mple of diesel and measure its sulfur and

aromatic content to see if it meets the specified limits on t hose properties. Similarly, a sample of gasoline can be analyzed in a laborato ry for its Reid vapor pressure or sulfur content. To determine compliance with the specific ations for these fuels, it is irrelevant

to ask how these fuels were made – the onl y question is whether the finished product has the desired physical and chemical properties.

In contrast, it is as important, or even more important, to know how a fuel or blendstock was made under the LCFS regulation than knowi ng the fuel’s actual constituents. The LCFS requires a regulated party to achieve a specified performance reduction in its motor vehicle fuel pool’s overall carbon inte nsity. This is the sum of all carbon

intensities associated with all steps required to produce, distribute, market and use the party’s fuel, plus any credits purchased, gene rated, or used by the party. As such, a regulated party’s carbon intensity cannot be dire ctly measured in a sample of gasoline, diesel, or any other fuel. Simply put, one cannot take a gallon of gasoline and measure its carbon intensity in a labor atory like one would for determining the fuel’s boiling point.

Rather, a fuel’s carbon intensity is inferred from the various steps taken to produce that fuel and the relative impacts to climate c hange associated with each step (vis-à-vis the steps’ carbon intensity), as well as accounting for any credits used, generated, or traded by the regulated party. Thus, the relevant question for the LCFS is exactly the opposite of the above examples of actual fuel specif ications: Exactly how was the product made, since the process for producing and distributing the product is what affects the product’s carbon intensity?

To further illustrate, a gallon of ethanol ma de from corn grown and processed in the Midwest will, under a microscope or other analytical device, look identical in every material way to a gallon of ethanol processe d from sugar cane grown in Brazil. Both samples of ethanol will have the same boiling point, the same molecular composition, the same lower and upper limits of flammabilit y – in other words, both will have identical physical and chemical properties because both products consist of 100% ethanol. On the other hand, the corn ethanol made fr om the Midwest will have different carbon intensity than the sugar cane et hanol from Brazil. Thus, the relevant inquiry with carbon intensity is not so much what is contai ned in a fuel, but how was that fuel made,

distributed and used.

An additional complication is that a regulated party’s carbon intensity is not only reflective of its fuels’ carbon intensities, but also whether any credits that are used or traded are also reflected in the party’s over all carbon intensity. Thus, from the above example, even if the corn ethanol and sugar ethanol were to have identical carbon intensity, one regulated party using corn et hanol would almost certainly have a differentV-31 overall carbon intensity than another party with sugar ethanol, simply because each party would have different rates of credit generation and usage.

The above considerations strongly suggest t hat the LCFS regulation, unlike other existing California regulations, does not establish prescriptive 43 fuel specifications. Instead, the nature of the LCFS regulation points to a rule t hat is much more akin to a performance 44 requirement, one that establishes an enforceable goal but does not dictate the process for how to achieve comp liance with that goal. As such, ARB staff believes the LCFS regulation, by itsel f, does not establish motor vehicle fuel specifications; therefore, t he LCFS rule should not be subject to the multimedia evaluation requirement.

c. The LCFS Regulation Do es Not Affect Existing Fuel Specifications

It is important to note that, by its terms, the LCFS regulat ion does not modify any other existing State or federal specifications for mo tor vehicle fuels. Section 95480.1(e) of the proposed regulation includes a saving clause providing, in pertinent part, that:

“ Nothing in this LCFS regulat ion (17 CCR §95480 et seq.) may be construed to amend, repeal, modify, or change in any way the California Reformulated Gasoline regulations (CaRFG, 13 CCR §2260 et seq.), the California Diesel Fuel regulations (13 CCR §2281-2285 and 17 CCR §93114), or any other applic able State or federal requirements. Any person, including but not limited to t he regulated party as that term is defined in the LCFS regulation, subjec t to the LCFS regulation or other State and federal regulations shall be responsible for ensuring compliance with all applicable LCFS require ments and other State and federal requirements, including but not lim ited to the CaRFG requirements and obtaining any necessary approvals, exem ptions, or orders from either the State or federal government.”

This provision was included to reflect staff’ s intent that the LC FS regulation, by itself, neither establishes a fuel spec ification nor amends any other State or federal requirements that apply to the a ffected fuels, including other requirements that constitute fuel specifications.

This provision also reflects staff’s understanding of what will likely occur to gasoline and diesel under the LCFS r egulation. To comply with the LCFS

43 "Prescriptive standard" means a regulation that sp ecifies the sole means of compliance with a performance standard by specific actions, measur ements, or other quantifiable means. (Gov. Code §11342.590.)

44 "Performance standard" means a regulation that de scribes an objective with the criteria stated for achieving the objective. (Gov. Code §11342.570.)V-32 regulation, it is unlikel y that fuel produc ers will change the composition and makeup of gasoline and dies el, since these are relatively mature technologies that still would need to meet applicable Stat e and federal specifications. Instead, fuel producers are likely to choose less carbon-intensive blendstocks, such as cellulosic ethanol, to help meet their LCFS obligations.

d. There are Practical Difficulties in Conducting a Multimedia Evaluation for the LCFS Rulemaking

Even if, for the sake of argument, one were to conclude that the LCFS rule itself somehow triggers the mult imedia evaluation requirement, conducting such an

evaluation for the overall rule would make it practically very difficult, if not impossible, to conduct such an evaluatio n. Because the LCFS establishes a performance-based requirement (see above) rather than a pre scriptive standard, it is very difficult for ARB to predict with certainty how regulated parties will comply with the LCFS requirement. Fo r instance, there has been substantial

mention of the use of genetically engineer ed algae to provide feedstock for making renewable diesel or other lower ca rbon intensity fuels. However, such technology is, at best, in its infan cy, and no meaningful discussion of the pathways (and, by extension, the associ ated carbon intensity) can be made until the technology is better developed and ARB has adopted fuel specifications for

such fuels.

Given these difficulties, the best that ARB staff can provide at this time is the “functional equivalent” of a mu ltimedia evaluation. Such an equivalent can, to the extent feasible, identify and evaluate the potential adverse impacts on public

health or the environment that may result from the producti on, use, or disposal of motor vehicle fuels that are likely to be us ed to meet the LCFS requirements. As fuels are developed and produced to co mply with the LCFS, ARB can adopt new specifications or amend exis ting specifications for such fuels as needed. At that time, ARB staff plan to conduct new multimedia evaluations pursuant to H&S §43830.8.

3. Applicability of H&S §43830.8 to Post-LCFS Regulations Establishing Vehicular Fuel Specifications

Based on the above discussion, ARB staff believe s that the LCFS regulation itself does not establish motor vehicle fuel specificat ions that trigger the multimedia evaluation requirement. However, it is clear that post-LCFS rules a dopted by ARB would certainly require multimedia evaluations to the extent su ch rules establish new fuel specifications or modify existing ones. The LCFS regulation incorporates th is principle as a pre-sale prohibition applied to fuels that are subject to an ARB specification that is modified or adopted after adoption of the LCFS regulation. 45 In such cases, regulated parties would be prohibited from selling the affected fuels in California to comply with the LCFS

45 See proposed LCFS regulation section 95487(a).V-33 requirements until a multimedi a evaluation is approved for those fuels pursuant to H&S §43830.8.

Fuels that would not be subject to this pre- sale prohibition incl ude the following (until such time as ARB adopts a new specification or modifies the existing specification for these fuels):

• Those fuels that were "g randfathered” in before July 1, 2000, pursuant to H&S §43830.8(h), or have not had their specif ications amended since SB 529 was enacted – these include CaRFG, diesel, E85, E10, CNG, LNG;

• Those fuels for which ther e are no existing ARB specifications but are permitted for sale in California pursuant to regul ations promulgated by the Division of

Measurement Standards -- this incl udes biodiesel and renewable diesel; and

• Those fuels for which the Californi a Environmental Policy Council has determined no significant adverse impac ts would result from the Board’s adoption of a fuel specificati on (under H&S §43830.8(i)).

For the 2009 rulemaking calendar, ARB sta ff is currently planning to propose a new motor vehicle specification for biodiesel and renewable diesel. Staff may also propose rulemakings for E85 and CNG later in the year. To the extent those rulemakings establish new specifications, multimedia evaluations may be needed pursuant to H&S §43830.8.

To comply with the requirements for multimedia evaluations that is applicable to the Low
Carbon Fuel Standard:

• Staff recognizes that a full and comp rehensive multimedia evaluation, in accordance with H&S §43830.8, is neither required nor practical to conduct for the LCFS rulemaking itself;

• Nevertheless, to implement the “spirit” of H&S §43830.8, staff intends to conduct the functional equivalent of a multimedia evaluation for the LCFS rulemaking to

the extent feasible.

• Staff will conduct full multimedia evaluations, pursuant to H&S §43830.8 and

consistent with the California Envir onmental Protection Agency (Cal/EPA) Guidance Document(74), prior to ARB adopt ion of a new fuel specification for motor vehicle fuels subject to the LC FS rule. The first of these will be rulemakings in 2009 to adopt motor vehicle fuel specifications for biodiesel and renewable diesel, which will require a multim edia evaluation. To the extent future rulemakings involving CNG, E85, or other fuels may involve the establishment of motor vehicle fuel specifications, a multimedia evaluation may be required for those rulemakings as well.V-34 K. Cap and Trade Under the LCFS Regulation (Reserved)

Under the AB 32 Scoping Plan(6) (Scoping Pl an), the Air Resources Board plans to incorporate transportation fuel s into the AB 32 cap-and-trade(6) 46 program in 2015. This will require that the LCFS regulation cont ain provisions to facilitate the integration of the LCFS with the AB 32 cap-and-trade program. Because the AB 32 cap-and-trade program itself is currently under developm ent, most elements of the related LCFS provision are still conceptual at this stage. For this reason, the proposed LCFS regulation contains a placeh older section in which the cap-and-trade provisions will eventually be specified.

With that said, staff believes there is meri t in beginning the dial ogue on how best to structure the LCFS provision. To this end, we provide in this chapter a broad overview of major elements of a LCFS cap-and-trade related provisio n. This discussion will necessarily be brief and general, reflecting the si gnificant work that must be undertaken in the next few years to flesh out the co mplex issues involved and develop these and related concepts into regulatory text. Accord ingly, we will focus on two issues: (1) the interchangeability of cap-and-tr ade allowances and credit trades, and (2) ARB’s role in credit trading.

Interchangeability of Cap-and-Trade Allowances and Credit Trades

An issue that staff is proposing to address at this point is the extent to which LCFS credits and tradable cap-and-trade allowances can be used interchangeably to comply
with LCFS and/or cap-and-trade.

On the one hand, staff pr oposes to allow the export of LCFS credits to other AB 32 programs. The LCFS credits , which will be denominated in metric tons of carbon dioxide equivalent (MT-CO2e), are based on an anal ysis of the transporta tion fuel’s full, lifecycle carbon intensity. As such, the LC FS credits can be clearly documented for each step in a fuel’s well-to-wheels lifecycl e. This could enhance the LCFS credits’ fungibility vis-à-vis other programs under AB 32. The pr oposed LCFS regulation does

not set forth conditions on how those credi ts can be used in other AB 32 programs. This is because other AB 32 programs, when developed, presumably will specify their own conditions for imported credits (e.g., from the LCFS program).

On the other hand, staff proposes to prohibit the import of cap-and-trade allowances into the LCFS program. Tradable allowances generated under California regional capand-trade program requirements may be based on emissions reporting and compliance obligations different from t hat used in the LCFS. Thus, any importing of cap-and-trade allowances into the LCFS program would need to account for the differences in the two methodologies. To this end, some discount ing or other adjustm ents may be needed in order to place LCFS credits and cap-and- trade allowances on an equal footing.

46 A cap-and-trade program establishes an enforceable limit (or cap) on the aggregate total emissions for those entities covered by the program. The cap is set for each co mpliance period of the program by the State, and emission reductions increase as the cap declines over time.V-35 Until regulatory provisions of a Calif ornia cap-and-trade progr am are proposed(75) 47

, staff believes it would be premature to incl ude regulatory provisions for importing of cap-and-trade allowances into the LCFS progra m. As part of the rulemaking process on the California cap-and-trade pr ogram, staff will evaluate the feasibility of making cap-and-trade allowances and LCFS progr am credits interchangeable and, if appropriate, the conditions that shoul d apply to such transactions.

ARB’s Role in Credit Trading

Successful credit trading depends, in part, on what role ARB wi ll play. In this regard, ARB can play a number of ro les, each of which can have pros and cons, such as: (1) “hands off” regulator, (2) clear inghouse, and (3) trade facilitator.

Hands Off Regulator

As the term implies, a “hands off” role c ould have ARB serve no transactional role other than to issue LCFS credits, enforce the regul atory requirements, an d track credit trades without publishing extensive information on such trades. This role has the benefit of imposing the least amount of administrat ive burden on both ARB and the regulated parties. Because of this, there would be fe wer barriers to credit transactions, which presumably would help minimize transactional costs.

Among the downsides to this role would be a lower level of transparency in the credit market. The lack of such transparency can impede credit transactions because the regulated parties would have less information with regard to current market prices and market participants with av ailable credits for sale.

Clearinghouse

As a clearinghouse, ARB could serve in both the enforcement role (noted in “Hands Off” above) and as a source of publicly available, credit-related information. Such information might include identification of r egulated parties that have credits available for trades, the amounts of credits available, and the prices fo r such credits. This role would help fill in the trans parency need noted above.

However, the need for transparency should be balanced with the need to avoid market manipulations that could be harmful to credi t trading. For exampl e, linking a specific regulated party with a specific amount of credits available may have an adverse effect a credit seller and buyer’s negotiations. Similarl y, a regulated party in need of credits may be placed in a disadvantageous position, depending on how much information is available from the clearinghouse (e.g., pub lication of credit balances). Further,

confidential business informa tion (e.g., sales volumes) might be gleaned from a clearinghouse if the data are not sufficiently delinked from the specif ic regulated parties.

47 The AB 32 cap-and-trade rulemaking is tentatively scheduled for the Board’s consideration in November 2010, with the launch of the California and WCI cap-and- trade programs scheduled for January 1, 2012.V-36 Based on the above reasons, we believe carefu l consideration of these and other issues is warranted before designing any AR B clearinghouse for LCFS credits.

Trade Facilitator

This concept would take the clearinghouse role to the next level. In other words, ARB could serves as an intermediary between a credit seller and credit buyer, since ARB would have information on which parties have cr edits available and whic h need credits. This role has the advantage of helping to r educe transactional costs by providing the market with a known entity (A RB) that can connect sellers with buyers at little or no

additional administrative cos t. However, the benefits of reducing such transactional costs may be reduced if ARB cannot get buyers and sellers t ogether more quickly or in effective numbers than a privat e, third-party facilitator, broker, agent, or similar entity

can achieve.

Summary

It is clear that the above issues and concept s warrant a thorough evaluation in order to make the LCFS successfully integrate wit h the AB 32 cap-and-trade program. These and other cap-and-trade related i ssues will be investigated as staff develops the LCFS cap-and-trade related provisi ons in the short term.

L. Regulation Review

The Executive Officer will conduct a review of the implementation of the LCFS program by January 1, 2012. The review ma y cover areas impacting the design and
enforcement of the LCFS r egulation, such as the gasoline and diesel average carbon-intensity requirements; data and other information used for the carbon intensity lookup table and vehicle energy economy ratios ; availability of biofuels and advanced vehicle technologies; and lifecycle and land- use change models, methods, and data. Special attention will be focused on indirect land use change. The review may also cover the logistics of complying with the LC FS such as the method, frequency, timelines of report submission, and the overall effe ctiveness and usability of the web-based Compliance and Reporting Tool. The exact scope and content of this review will be determined by the Executive Officer. Although not specified in the proposed regulation, staff intends to review the LCFS regulat ion approximately every three years after January 1, 2012.VI-1 

### VI. Compliance Scenarios

A. Summary

The LCFS is a performance-based standard: it neither mandates nor prohibits the use of specific fuels. Regulated fuel providers are free to make available any mix of fuels, so long as that mix complies with current car bon intensity limits. As such, a wide variety of compliance paths are possible. This Chapt er describes seven such paths. Its goals are twofold: first, it demons trates that compliance is possible, given what is currently known about the future availability of alte rnative fuels and vehicles; second, it shows that compliance is not contingent upon the availability of only a limited number of

alternative fuel-vehicle combinations. T he seven compliance paths described in this Chapter achieve these goals by demonstrating that compliance is possible under a wide range of fuel-vehicle scenarios.

Four of the scenarios described in this Chapt er pertain to gasoline and fuels that can substitute for gasoline, and three pertain to diesel and its substitute fuels. Each scenario describes a compliance path involving a different combination of advanced renewable fuels, and advanced electr ic and hydrogen-powered vehicles.

Chapter IV also describes three supplemental scenarios. The first illustrated the effects of allowing light-duty diesel vehicles to earn compliance credits under the gasoline standard—a practice that is not permitted un der the proposed Regulation. The second illustrates the extent to which compliance paths might be altered if no carbon intensity values included an indirect land use chang e component. The third supplemental scenario examines the carbon intensity reduc tions that could be expected if the LCFS were not implemented, but all Federal Renewable Fuel Standard production requirements were met in California.

The Chapter ends with a discussion of a likel y compliance path for the decade following the current LCFS compliance year of 2020. Because th e State’s long-term climate change goals call for continued GHG reductions through 2050, it is probable that the LCFS will be renewed with revised post-2020 carbon intensity redu ction requirements

B. Primary Scenarios



### 1. Establishing the Baseline

The LCFS baseline consists of baseline carbon intensity levels for gasoline and diesel, and a baseline year.

a. LCFS Baselines

ARB staff proposes that 2010 serve as the LC FS baseline year. In 2006, California reformulated gasoline contained an average of six percent ethanol by volume. As a result of the implementation of the Feder al Energy Independence and Security Act ofVI-2 2007 and California’s reformulated gasoline r egulations, the amount of ethanol in California reformulated gasoline is expected to increase to ten percent by volume.

The vast majority of ethanol used during the fi rst three to five years of the LCFS is expected to be produced from corn. The ca rbon intensity of California reformulated gasoline (CaRFG) depends in part upon the carbon intensity of the et hanol with which it
is blended. Because corn ethanol and Calif ornia reformulated gasoline blendstock for oxygenate blending (CARBOB) have almost identical carbon in tensities, the influence of

the ethanol fraction on the car bon intensity of reformulated gas oline is insignificant.

Staff expects the carbon intensity of diesel fuel to remain essentially constant through the 2010 baseline year. Significant volumes of alternative blendstocks that would affect the carbon intensity of the baseline diesel fuel are not expected in the California Market by 2010.

b. Baseline Carbon Intensities of Gasoline and Diesel

The 2010 carbon intensities for gasoline and dies el were calculated using version 1.8b of the CA-modified GREET model.(47) The ca rbon intensity of gasoline is based on an assumed ethanol content of 10 percent by volume. Table VI-1 shows the assumed composition of average corn ethanol, as us ed in California reformulated gasoline. Twenty percent of the ethanol was assumed to come from the wet milling process, and 80 percent from the dry milling process. Of the dry milling process, 80 percent of the plants were assumed to dry their distiller’s grain co-p roduct, and 20 percent were assumed to sell their co-product as wet distille r’s grain. Gasoline, including 10 percent ethanol by volume, has a ca rbon intensity of 95.85 gCO 2 e/MJ. The carbon intensity of diesel in 2010 is estimated to be 94.71 gCO 2 e/MJ. Details for both gasoline and diesel carbon intensity calculations can be found in the lifecycle analyses that are posted on the ARB website (http://www.arb.ca .gov/fuels/lcfs/lcfs.htm).

Table VI-1 Assumed Composition of the Ethanol Fraction of 2010 E10 Dry DGS, CI = 98.4: 80% Dry

Mill:

80% Wet DGS, CI = 90.1: 20% Ethanol: 10%

Wet Mill, CI = 105.10: 20%; E10

CARBOB: 90% CI = 95.86

2. Standards for 2020VI-3 To achieve a 10 percent reduction from 2010 levels, the standard for gasoline and fuels that substitute for gasoline will need to achieve a CI of 86.27 gCO 2 e/MJ by the year

2020.

With a 10 percent reduction in the carbon intens ity of diesel fuel, the carbon intensity of the diesel fool including the fuels that substitute for diesel will be 85.24 gCO 2 e/MJ by

2020.



### 3. Compliance Schedules

Table VI-2 summarizes the proposed LCFS regulatory compliance schedules for gasoline and fuels that substitute for gaso line, and for diesel fuel and fuels that substitute for diesel fuel. These schedules apply to these fuels as they will exist in 2010, as well as to the various substitutes and blends that will become available over the compliance period. As Table VI-2 shows, implementation of the regulation begins in

2010.

Table VI-2 LCFS Compliance Schedules

Year CI for Gasoline

and Fuels Substituting for

Gasoline 1
(gCO 2 e/MJ) Gasoline and

Fuels Substituting for

Gasoline

% Reduction CI for Diesel

and Fuels Substituting for

Diesel (gCO 2 e/MJ) Diesel and

Fuels Substituting for

Diesel

% Reduction

2010 Reporting Only Reporting Only

2011 95.61 0.25 94.47 0.25

2012 95.37 0.5 94.24 0.5

2013 94.89 1.0 93.76 1.0

2014 94.41 1.5 93.29 1.5

2015 93.45 2.5 92.34 2.5

2016 92.50 3.5 91.40 3.5

2017 91.06 5.0 89.97 5.0

2018 89.62 6.5 88.55 6.5

2019 88.18 8.0 87.13 8.0

2020 86.27 10.0 85.24 10.0

1 The use of 10.0 percent reduction is discus sed in the baseline discussion found in the previous section.VI-4 The carbon intensity reductions shown in Table VI-2 are displayed graphically in Figures VI-1 and VI-2.

Figure VI-1 Figure VI-2

Compliance Schedule from 2010 to 2020 for Gasoline and

Gasoline Substitutes

80 82 84 86 88 90 92 94 96 98

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

YearCarbon Intensity (gCO2e/MJ) Compliance Schedule for 2010 to 2020 for Diesel Fuel and

Diesel Fuel Substitutes

80 82 84 86 88 90 92 94 96 98

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

YearCarbon Intensity (gCO2e/MJ)



### 4. Compliance Scenarios

a. Introduction

The LCFS does not specify which combinat ion of fuels the r egulated parties must provide to comply with the standards. In stead, the LCFS requires producers and importers of transportation fuels to meet an ov erall carbon intensity fo r the fuel mix they supply to California. Regulated entities may meet the LCFS by using a combination of fuel blends, alternative fuels, and LCFS cr edits. Based on current and developing fuel and vehicle technologies, feedstock availabilit ies, and other factors, ARB staff has analyzed a number of possible compliance scenarios.

In this analysis, staff presents seven possi ble compliance scenarios—four for gasoline

and its substitute fuels and three for diesel fuel and its substitute fuels. Each of these

scenarios includes a mix of fuels that sati sfy the LCFS. The purpose of describing compliance scenarios at this time is to demonstrate how the draft carbon intensity reductions are achievable, given prevailing and foreseeable future conditions. The compliance scenarios are not intended to predict or forecast the actual combination of

fuels and vehicles that will be used.

The rate of future fuel and vehicle technol ogical development is still uncertain. The technologies which currently appear to be most likely to produce marketable quantities

of low-carbon fuels and vehicles to utilize thos e fuels over the near- to mid- term could encounter delays. The development of other, currently less well developedVI-5 technologies, could achiev e breakthroughs. Also, sinc e the proposed regulation is performance based, fuel producers and importers can decide on how to achieve compliance. One or more of these outcomes could resu lt in a set of compliance

scenarios that is different from those described below.

b. Basis for Developing the Scenarios

The scenarios developed below are based on the following information and assumptions about fuel availability over the LCFS compliance period:

• Recent improvements in corn ethanol production processes have led to carbon intensity reductions for that fuel. In this analysis, these improvements are reflected in two additional types of impr oved corn ethanol: (1) Ethanol produced in the latest generation of California plant s, which has a carbon intensity that is about 15 percent below that of CARB OB, and (2) Ethanol meeting the performance standard specified in the 2007 EI SA: a 20 percent carbon intensity

reduction over CARBOB. These fuels ar e referred to as California low-CI

ethanol and Federal New Renewable Biofuels.

• For each gasoline-related scenario, the st aff assumed that t here was a baseline of approximately 300 million gallons of California low-CI ethanol available beginning in 2010 and that this volume w ould remain available in the California market through 2020.

• There are feedstocks available to pr oduce sufficient quantities of cellulosic ethanol, advanced renewable ethanol, sugar cane ethanol, biodiesel, renewable diesel, and other renewable fuels, as necessary. These feedstocks include, but

are not limited to cellulosic waste material s from agricultural, sugarcane, forestry wastes, municipal wastes, wa ste oils, and animal fats.

• Flexible fuel vehicles (FFVs) and/or advanced technology vehicles will be

available in sufficient numbers to consume the quantities of E85, electricity, or hydrogen, assumed in each scenario. For ethanol, staff assumed that the gasoline blends consist of the maximum allowable 10 percent (E10) in the gasoline fleet and E85 in the FFV fleet.

• Each gasoline-related scenario includes a number of advanced technology

vehicles that enable vehicle manufacturers to gain credits under the ARB’s zeroemission vehicle program. These vehicles could be battery electric vehicles (BEVs), plug-in hybrid vehicles (PHEVs), or fuel cell vehicl es (FCVs). For the purposes of this analysis, we have assum ed that the percentage of vehicles in

each class of these vehicles is the same as that project ed for compliance with the 2008 ARB Zero Emission Vehicle (ZEV) regulation.

• The estimate of the carbon intensity of electricity is based on the California marginal electricity mix, where 79 perc ent of the electricity comes from highly efficient natural gas plants and 21 percent comes from renewable sources. Both electricity and hydrogen when used in adv anced vehicles result in significant

reductions in the carbon intens ity of the fuel/vehicle system.VI-6 • The LCFS baseline for the gasoline and related fuels st andard was projected based on the expected California fuel mix in 2010. The baseline gasoline blend

is assumed to be E10. The number of light duty vehicle miles traveled is assumed to increase by 1.5 percent annually under the business as usual case. For this analysis, staff adjusted the am ount of fuel consumed to reflect the implementation of ARB’s GHG standards for light-duty vehicles, which results in

a reduction of the to tal amount of E10 used in 2020 compared to 2010.

• The LCFS baseline for the diesel and related fuels standard was projected based on the expected California fuel mix in 2010. Staff assumed about a 2.2 percent annual increase in demand fo r diesel fuel between 2010 and 2020. This should be on the high side, as the dies el growth rate for the past two years has been negligible.

• For each scenario, staff assumes that there is no banking of credits. That is, all credits are used in the year that they are generated.

Tables VI-3 and VI-4 list the carbon intens ities of the fuels us ed in the compliance scenarios developed below. These carbon intensities are deriv ed from the carbon intensities presented in Chapter IV, “Determi nation of Carbon Intensity”. Chapter IV presents a discussion of the bas is for the carbon intensity values used in this report, including staff’s current land use change impact estimates.

A very small portion of the diesel that will be available in 2010 will be blended with biodiesel. Biodiesel produc ed from waste fats and oils have no identified lifecycle emissions from indirect land use change im pacts. Crop-based bi odiesel, however, do have land use change impacts. Current estimates of these impacts appear in Chapter IV.VI-7 Table VI-3 Descriptions and Carbon Intensities of Fuels Included in the Compliance Scenarios for Gasoline and Fuels that Substitute for Gasoline

Carbon Intensity (grams CO 2 e/MJ) Status Gasoline,

Gasoline Blendstock, or Replacement Pathway Description Direct

Emissions Land Use

or Other

Effect Total Proposed

for Adoption Under Development

CARBOB CARBOB – based on the average crude oil
delivered to California refineries and average California refinery

efficiencies 95.86 0 95.86 X

CaRFG – 2010

Baseline Fuel CaRFG - CARBOB and

a blend of 80%

Midwestern corn ethanol
and 20% California corn

ethanol to 10% ethanol 95.85 --- 95.85 1 X

Midwestern Average Corn

Ethanol Midwest average; 80% Dry Mill; 20% Wet Mill; Dry DGS 69.40 30 99.40 X

California Low

CI Ethanol California; Dry Mill; Wet DGS; NG 50.70 30 80.70 X

Cellulosic

Ethanol Farmed poplar trees using a fermentation

process 2.40 18.00 20.40 X

Advanced

Renewable

Ethanol Forest waste 22.20 0 22.20 X

Sugarcane

Ethanol Brazilian sugarcane using average production processes 27.40 46 73.40 X

Federal New

Renewable

Biofuels 20% reduction in the carbon intensity of

CARBOB 76.69 --- 76.69 1 X

Federal
Cellulosic

Biofuels 60% reduction in the carbon intensity of

CARBOB 38.34 --- 38.34 1 X

Federal

Advanced

Biofuels 50% reduction in the carbon intensity of
CARBOB 47.93 --- 47.93 1 X

Electricity California marginal electricity mix of natural gas and renewable

energy 104.70 0 34.90 2 X

Hydrogen SB 1505 Scenario; gaseous hydrogen from on-site reforming with

renewable feedstocks 76.10 0 33.09 3 X

1 Calculated value; land use assumed to be part of the value

2 Adjusted for by an Energy Economy Ratio of 3.0 to ac count for differences in power train efficiency of electric vehicles and plug-in electric vehicles over gasoline-powered vehicles

3 Adjusted for by an Energy Economy Ratio of 2.3 to acc ount for differences in power train efficiency of fuel cell vehicles over gasoline-powered vehiclesVI-8 Table VI-4 Descriptions and Carbon Intensities of Fuels Included in the Compliance Scenarios for Diesel and Fuels that Substitute for Diesel

Carbon Intensity (grams CO 2 e/MJ) Status Diesel, Diesel Blendstock,

or Replacement Pathway Description Direct

Emissions Land Use

or Other

Effect Total Proposed

for Adoption Under Development

ULSD Diesel

– 2010

Baseline ULSD – based on the average crude oil
delivered to California refineries and average California refinery

efficiencies 94.71 0 94.71 X

BiodieselSoybeans Midwest soybeans to soy oil (Fatty acid methyl esters-FAME)

for conversion to

biodiesel 26.93 42 68.93 1 X

Biodiesel or

Renewable

Diesel –

WasteDerived Tallow conversion using co-fed streaminto refinery or biorefinery, or yellow grease, fats, and

waste oils for

conversion to biodiesel

or renewable diesel 15.00 0 15.00 1 X

Compressed

Natural Gas North American natural gas delivered via pipeline; compressed
in California 68.00 0 75.56 1 X

Federal

BiomassBased Diesel 50% reduction in the carbon intensity of
ULSD Diesel 47.36 --- 47.36 2 X

Electricity California marginal electricity mix of natural gas and renewable energy 104.70 0 38.78 3 X

1 Preliminary estimate

2 Calculated value; land use assumed to be part of the value

3 Adjusted for by an Energy Economy Ratio of 2.70 to account for differences in power train efficiency of electric vehicles and plug-in electric v ehicles over diesel-pow ered heavy-duty vehiclesVI-9 The renewable fuel requirem ents of the Energy Independence and Security Act of 2007 (EISA) set federal mandates for the development of low carbon fuels. EISA increased

the amount of renewable fuels that gasoline and diesel fuel s must contain under the U.S. EPA’s Renewable Fuels Standard previously established in 2005. In 2008, 9 billion gallons of renewable fuel must be used, increasing to 36 billion gallons per year by 2022. In 2010, EISA require s that 0.95 billion gallons of federal advanced biofuel and 0.1 billion gallons of f ederal cellulosic biofuel be used, while in 2022, these requirements increase to 21 billion gallons and 16.0 gallons. These requirements are
shown in further detail in C hapter II: Table II-3. In e ffect, EISA established minimum renewable fuel production levels and car bon reduction performance metrics at the

national level.

The difference between total advanced biofuels and total renewable fuel is allowed to be ethanol from corn with up to 13 billion gallons of conventional corn to ethanol and about 2 billion gallons Federal New Renewable Biofuels corn to ethanol that has a CI 20% less than base gasoline.

c. Compliance Scenarios for Gasoline and Gasoline Substitutes

The purpose of the scenarios was to estima te the amounts of low-carbon gasoline and diesel fuel substitutes, and the number of FFVs and advanced vehicles, that would be needed in future years to meet the proposed ca rbon intensity values of the LCFS. The starting point for these estimates was to esti mate the total amount of both on-road and off-road transportation fuels t hat would be used in California in future years. The basis

of these estimates was the ARB’s EMFA C motor vehicle emissions model, data on

taxable sales of motor vehicles fuels in California, published by the State Board of Equalization (BOE), and data on fuels production published by the U.S. Department of Energy Information Administrati on (EIA). On-road motor vehi cle fuel use was estimated by using EMFAC estimates of vehicle m iles traveled for the year 2008, and by incorporating assumptions on fuel economy that resulted in fuel use estimates

consistent with the State Board of Equalization’s estimate of taxable on-road fuel use.

Off-road diesel fuel use was estimated so that total diesel fuel use would be consistent

with the EIA’s estimate of total fuel use in California for 2008.

Estimates of fuel use in future years were made by applying to the 2008 estimates assumed annual VMT growth rates of about 1. 5 percent for gasoline motor vehicles, and about 2.2 percent for heavy-duty diesel vehicl es. In estimating fuel use in future years, the staff also accounted for measures that result in a decrease in the amount of

motor vehicle fuel used. These measures are listed below:

• The regulations (both adopted and planned) by the ARB pursuant torequirements of AB 1493 (Pavley) which have the result of increasing the fleetwide fuel average fuel economy of gasoli ne motor vehicles by about 24 percent (the equivalent of about 31.7 MMT/y r of greenhouse gases) in 2020;VI-10 • The effects of the implem entation of regional transporta tion-related GHG targets, required by SB 375, which will reduce fuel use by an amount equivalent to about 5 MMT/yr of greenhouse gases;

• The effects of measures being consider ed and proposed by the ARB to increase vehicle efficiency, such as the rule to maintain adequate tire pressure, which will reduce fuel consumption by an amount equivalent to abut 4.5 MMT/yr of greenhouse gases;

• The effects of measures to be adopted by the ARB which will increase the aerodynamic efficiency of heavy-duty vehicles, and which will reduce fuel use by an amount equivalent to about 1. 4 MMT/yr of greenhouse gases;

• The use of about 560,000 advanced technol ogy (BEV, PHEV, and FC) vehicles in 2020 required under the Zero Emission Vehicle Regulations adopted by the ARB; and

• The use of about 500,000 light and medium- duty diesel vehicles in 2020, which results in a slight shift in fuel use from gasoline to diesel.

Table VI-5 lists the measures that will signi ficantly decrease the amount of fuel used in the future along with their corresponding CO 2 E emission reductions.

From the total amount of fuel estimated to be used in future years, a total energy demand was estimated. Using the total ener gy demand and the carbon intensities of gasoline, diesel, and gasoline and diesel fuel substitutes, the total amounts of lower carbon intensity gasoline and diesel fuel substitutes were estimated.

Table VI-5

Measures to Reduce GHG Emissions

Measure Description Emission Reductions
Counted Towards 2020 Target (MMTCO 2 E)

California Light-Duty

Vehicle Standards Implement adopted Pavley standard and planned second phase of the program. Align zero-emission vehicle, alternative and renewable fuel and vehicle technology program with climate change goals. 31.7

Regional TransportationRelated GHG Targets Develop regional GHG emissions reduction targets for passenger vehicles pur suant to Senate Bill 375. 5

Vehicle Efficiency

Measures Implement light-duty vehicle efficiency measures including properly inflated tires, consideration of minimum fuel-efficient tire standards, and reducing engine load via lower friction oil and reducing the

need for air conditioner use. 4.5

Medium/Heavy Duty

Vehicles Adopt medium and heavy-duty vehicle efficiency measure including retrofits to improve the fuel efficiency of heavy-duty trucks by reducing aerodynamic drag and rolling resistance and hybridization of medium-and heavy-duty vehicles. 1.4VI-11 Staff developed four compliance scenarios for gasoline and gasoline substitutes. These

scenarios differ in the volumes of corn -based ethanol, cellulosic ethanol, sugarcane ethanol, and advanced renewable ethanol. T he number of FFVs assumed to be using E85 and the number of advanced vehicles ( BEV, PHEV, FCV) using electricity or hydrogen also change significantly in several scenarios.

In general, the four scenarios can be characterized as follows:

Scenario 1 : Increasing volumes of Feder al New Renewable Biofuels (ethanol)(10) 48 through 2015, then gradual decli ne of higher CI crop-based biofuels through 2020 as advanced renewabl e ethanol fuels become available. Conventional corn ethanol gradually dec reases to zero in 2017, but lower intensity corn ethanol remains. There would be gradual increases in the number of FFVs using E85. The number of adv anced technology vehicles (BEV, PHEV, FCVs) using electricity or hydrogen as a fuel increases to about 560,000 by

2020. This number is consistent wit h the penetration schedule in the 2008 ARB ZEV regulation.

Scenario 2 : Similar to Scenario 1 except t hat a wider mix for cellulosic ethanol, advanced renewable ethanol, and sugarcane ethanol is used.

Scenario 3 : Similar to Scenario 2 except that the number of advanced technology vehicles is increased from 560, 000 vehicles to 1 million vehicles in 2020. In turn, the number of FFVs us ing E85 in 2020 and the amount of cellulosic ethanol, advanced renewabl e ethanol, and sugarcane ethanol are

reduced.

Scenario 4 : Similar to Scenario 3 except the number of advanced technology

vehicles is increased to 2 million v ehicles in 2020 and biofuel amounts are

reduced.

The year-by year assumptions used in each scenario are presented in Appendix E. In general, the LCFS can be met through about 2015 with a combination of somewhat lower-carbon corn derived ethanol or through the use of ethanol from sugarcane. For these years, almost all of the needed biofuels can be used in E10 and very little E85 is needed. However, as the LCFS (and c oncurrently the federal RFS) become increasingly more stringent, the scenarios tr ansition to higher volumes of very low carbon ethanol, with higher numbers of FFV s using E85, and hi gher numbers of advanced vehicles. In all cases, once a s pecified volume of lower-carbon biofuel is produced, that volume is maintained throughout 2020. In addition, the scenarios retain

48 The Federal Renewable Fuels Standard (RFS2), whic h is discussed in Chapter II of this report) specifies that ethanol derived from corn starch pr oduced at new facilities that commence construction after the date the act was signed, must achieve at le ast a 20 percent reduction in lifecycle greenhouse gas emissions compared to baseline lifecycle greenh ouse gas emissions. The baseline is defined as the average 2005 lifecycle GHG emissions for gasoline.VI-12 about 300 million gallons of lower-carbon intens ity ethanol from corn expected to be produced at existing or planned Californi a ethanol production facilities.

The results for 2020 are summarized in Tabl es VI-6, VI-7, and VI-8. Table VI-6 presents a summary of the amou nt of fuel used in 2020 for biofuels, electricity, and hydrogen. Table VI-7 presents a breakdown of the types of ethanol used for each

scenario in 2020. Table VI-7 also shows t he amount of ethanol used as a percent of the

total amount of E85 and E10 and the amount of ethanol used as a perc ent of gasoline. For each gasoline-related scenario, Table VI-8 shows the percent contribution that each fuel type plays in reducing GHG emissions as part of the LCFS for gasoline in 2020.

Table VI-6 Summary of Fuels and Vehicles Used in Each Scenario to Meet the

2020 Standard for Gasoline and Fuels that Substitute for Gasoline*

Scenario 1 Scenario 2 Scenario 3 Scenario 4

Total Volume of Ethanol (Million Gallons) 2.9 3.1 2.8 2.2

Total Amount of Electricity (Gigawatt Hours) 1,210 1,210 2,240 4,470

Total Amount of Hydrogen (Megagrams) 10,500 10,500 16,500 33,000

Number of Advanced Vehicles (Battery Electric, Plug-in Electric, and Fuel Cell Vehicles) (Million of Vehicles) 0.56 0.56 1.0 2.0

Number of Flexible Fuel Vehicles Operating on E85 (Millions) 3.0 3.4 2.9 1.8

* Numbers are rounded.

1 Baseline gasoline consists of 90% CARBOB and 10% Ethanol by volume.VI-13 Table VI-7 Summary of Ethanol Use in the Various Scenarios

for Fuels that Substitu te for Gasoline in 2020

Ethanol Scenario 1 Scenario 2 Scenario 3 Scenario 4

Midwestern Average Corn Ethanol (Millions of Gallons) 300 0 0 0

California Low CI Ethanol (Millions of Gallons) 0 300 300 300

Cellulosic Ethanol

(Million Gallons) 1,290 1,240 1,100 790

Advanced Renewable Ethanol (Million Gallons) 1,290 1,240 1,100 790

Sugarcane Ethanol

(Million Gallons) 0 300 300 300

Total Volume of Ethanol (Million Gallons) 2,880 3,080 2,800 2,180

Overall Percent of Ethanol in

Gasoline 19.6 20.2 19.3 15.7

Volume of E85 (Million Gallons) 1,980 2,250 1,920 1,190

1 2010 starting-year gasoline consists of 90% CARBOB and 10% Ethanol by volume.

Table VI-8 Contribution to Reducing GHG Emissions in the LCFS For Fuels Substituting for Gasoline Fuel in 2020

Percent of Reductions Provided by Each Fuel Type Substituting for Gasoline in 2020 1 Fuel Type

Scenario 1 Scenario 2 Scenario 3 Scenario 4

CA Low-CI Ethanol 2 2 2 2

Cellulosic Ethanol 44 43 38 28

Advanced

Renewable Ethanol 43 41 36 27

Sugarcane Ethanol 0 3 3 3

Electricity 9 9 18 35

Hydrogen 2 2 3 5

1 Baseline gasoline consists of 90% CARBOB and 10% Ethanol by volume.

d. Compliance Scenarios for Diesel Fuel and Substitutes for

Diesel Fuel

Staff developed three possible compliance scenarios for the diesel fuel group as

summarized below:VI-14 Scenario 1 : The first scenario is based on a diversification of the liquid fuel pool using available low-car bon-intensity fuels.

Scenario 2 : The second scenario includes not only a variety of liquid fuels, but also significant numbers of CNG v ehicles penetrating the fleet.

Scenario 3 : The third scenario increases t he compliance options by expanding
Diesel Scenario 2 to include additional advanced technology vehicles, including PHEVs used to replace conventional diesel vehicles.

The three scenarios require the availability of two categories of non-petroleum diesel:

• Biomass-based diesel includes the following:

o Conventional biodiesel, made from o il derived from crops using the fatty acid to methyl ester (FAME) proc ess. Conventional biodiesel has a carbon intensity of 68.93 gCO 2 e/MJ.

• Advanced renewable diesel is a fuel made from non-crop-based feedstocks. These include wood waste, municipal wast es, algae, waste oils and fats from animals processed to meats. T hese fuels do not have a land use change impact. These waste-derived biodiesel/ renewable diesels were assumed to have carbon intensities of 15 gCO2e/MJ.

The year-by year summaries are present ed in Appendix E. In general, as the penetration of CNG vehicles and advanced tec hnology vehicles increases, the need for

biodiesel and advanced renewable biodiesel decreases. The increased vehicle penetration also reduces the amount of biodiesel and advanced renewable biodiesel needed for blending into conventional diesel. Ev en in Scenario 1, where liquid fuels are providing all of the necessary reductions, the amount of alter native fuels needed for blending is less than 20%.

The results for 2020 are summarized in Tables VI-9, VI-10, and VI-11. Table VI-9 presents a summary of the amou nt of fuel used in 2020 for biofuels, electricity, and natural gas. Table VI-9 also shows the amount of biodiesel and advanced renewable biodiesel used as a percent of the total amount of dies el. Table VI-10 presents a breakdown of the types of biodiesel and adv anced renewable biodiesel used for each

scenario in 2020. For each diesel-relat ed scenario, Table VI-11 shows the percent

contribution that each fuel makes to reduce t he deficits that result from a business as usual case of using conventi onal diesel in 2020.VI-15 Table VI-9 Contribution to Reducing GHG Emissions in the LCFS

for Diesel Fuel and Fuels that Substitute for Diesel Fuel*

Scenario 1 Scenario 2 Scenario 3
CNG (mmscf) 0 14,210 17,050 Total Amount of Electricity (Gigawatt Hours) 0 0 387

Number of CNG Vehicles 0 20,900 25,100 Number of PHEV Vehicles 0 0 8,367

Volume of Biodiesel and

Advanced Renewable Diesel (Million Gallons) 838 822 788

Overall Percent of Biodiesel and

Advanced Renewable Diesel in
Conventional Diesel 15.4 15.4 14.9

* Numbers have been rounded

.

Table VI-10 Summary of Biofuel Use in the Various Scenarios

for Fuels that Substitute for Diesel Fuel *

Summary of Biofuel Volumes Used in

2020 For Each Scenario Potential Fuels

Scenario 1 Scenario 2 Scenario 3

Conventional Biodiesel (Million Gallons) 4,607 4,530 4,517

Advanced Renewable Biodiesel (Million Gallons) 281 276 264

Volume of Biodiesel and

Advanced Renewable Diesel (Million Gallons) 557 546 524

* Numbers have been rounded

.

Table VI-11 Contribution to Reducing the Deficits for Fuels Substituting for Diesel Fuel in 2020

Percent of Reductions Provided by Each Fuel Type Substituting for Diesel in 2020 Potential Fuels

Scenario 1 Scenario 2 Scenario 3

CNG 0 2 2

Electricity 0 0 3

Conventional

Biodiesel 14 14 13

Advanced

Renewable

Biodiesel 86 84 81VI-16 C. Supplemental Scenarios

1. Light-Duty Diesel Credit Scenario

The Low Carbon Fuel Standard (LCFS) specif ies two carbon intensity levels, one for gasoline and its substitute fuels, a second for diesel and its substitutes. Gasoline and fuels used as substitutes for gasoline must meet a carbon intensity target of 86.27 gCO 2 e/MJ by 2020, while the corresponding ta rget for diesel and fuels used as substitutes for diesel is 85.24 gCO 2 e/MJ.

For the most part in the proposed LCFS, fuel s used in light duty passenger vehicles and trucks are measured against the gasoline standard, the fuel used by the overwhelming majority of these vehicles. However, this does not apply for t he small portion (about 1 percent) of the current light duty fleet that uses diesel fuel. A number of parties have urged ARB to allow diesel fuel to be used to earn LCFS compliance credits against the gasoline compliance standards when it is used in light-duty vehicles 49 . If permitted to comply with the gasoline standards in the LCFS , suppliers of fuels to light-duty diesel

vehicles could earn credits under the gasoline standard.

Achieving even this modest contribution toward the 2020 LCFS gasoline standard, however, would require the California light-d uty diesel fleet to grow to one million vehicles by 2020 50 . An increase of this magnitude appears to be unlikely. As Table VI-12 shows, light- and medium-duty diesel vehicles have not gained significant acceptance with California consumers.

Table VI-12 Composition of the 2008 California Vehicle Fleet*

DieselPowered Total Fleet Diesel Percentage

Passenger Vehicles 49,150 13,000,000 0.4%
Light-Duty trucks weighing <= 3,750 lbs 156,400 2,800,000 5.6%

Light-Duty trucks weighing > 3,750 lbs 16,580 5,400,000 0.3%

Medium Duty Vehicles 11,100 2,400,000 0.5%

Source: Emfac 2007 v2.3 (November 1, 2006)

* Numbers have been rounded

.

There have not been many diesel passenger cars and diesel light-duty trucks certified in California in recent years. More medium-duty diesel tr uck models have been California-

49 Because the compression-ignited diesel engine cycl e is more efficient than the spark-ignited gasoline engine cycle, diesel vehicles have lower GHG ex haust emissions than comparable gasoline-powered vehicles. As a result of this efficiency advant age, diesel-powered vehicles are currently between 15 and 20 percent lower emitting on a per mile travelled basis than their gasoline powered counterparts.

50 Diesel fleet estimates are from tax data supplied to the California Bureau of EqualizationVI-17 certified. Despite this avai lability, they continue to comp rise under 0.5 percent of the medium-duty vehicle fleet. Additional factors likely to influence the size of the future

vehicle fleet are:

• The increasing efficiency of gasoline vehicles will continue to close the efficiency gap separating gasoline from diesel vehicles; and

• The price of diesel fuel may not drop si gnificantly below the price of gasoline.

If the assumption is made that one million light duty vehicles will enter the fleet by 2020, these one million light-duty dies el vehicles running on fuel that complied with the 2020 LCFS carbon intensity standard of 85.24 gCO 2 e/MJ would emit 3.9 million metric tons of

CO 2 per year. The difference between t hat and the comparabl e gasoline-powered

vehicle emission level of 4.7 million metric tons would yield t he number of credits generated, about 0.8 million metr ic tons per year.

One million diesel vehicles running on fuel which met the 2010 baseline fuel carbon standard of 94.71 gCO 2 e/MJ would emit higher volumes of CO 2 : 4.3 million metric tons per year. The credit earned by these vehicl es would be the difference between this emission rate, and the corresponding emission rate for the same number of gasoline vehicles, about 0.4 million metric tons per year.

Table VI-13 puts these light duty diesel credi t figures into perspective by comparing them with the credits that would be earned by various other fuel-vehicle combinations. Although the 0.8 credits that would be earned by diesel vehi cles that comply with the 2020 standard would be significant, it is well below the number of cr edits that the two

electric vehicle classifications would ear n, and only half of what hydrogen fuel cell vehicles would earn. Also, as noted, it i gnores the improvements in the gasoline engine technology that would close the gap in engine efficiencies and eliminate most, if not all,

of the credits.VI-18 Table VI-13 Comparison of LDV Diesel Credits Scenario with Comparable Scenarios for Other Vehicle-Fuel Combinations (All Comparisons Based on 1,000,000 vehicles)

Fuel-Vehicle Combination Credits Earned (MMT/yr CO2)

LDV/MDV Diesel Vehicles Meeting

2020 Std. 0.8

LDV/MDV Diesel Vehicles Meeting

Baseline Std. 0.4

FFVs Using E85 containing 100%

Advanced Renewable Ethanol 0 *

Battery Electric Vehicles 2.8

Plug-in Hybrid Vehicles 2.1

Fuel Cell Vehicles 2.9

*E85 earns no LCFS credits because it is used in vehicles with an Energy Efficiency Rating of 1 (equivalent to standard gasoline-powered vehicles).

2. No Indirect land-Use Change Scenario

The carbon intensities of the crop-based biofuels used in the gasoline scenarios 1 through 4 (see Section VI-4c, above) incl ude an indirect land use change component, which ranges from zero for adv anced renewable ethanol to 46 gCO 2 e/MJ for sugarcane ethanol, as shown in Table VI-3. The suppl emental scenarios developed in this section demonstrate the effects of removing that increment from the gasoline scenarios and contain no indirect land use change increment.

Reducing the carbon intensitie s of crop-based ethanols by t he amount of the indirect land use change increment has two effects on the four gasoline co mpliance scenarios.

The first is to lower the car bon intensity of baseli ne gasoline from 95.85 to 93.39. This

reduction results from a reduction in the av erage carbon intensity of corn ethanol in baseline gasoline from 95.7 to 65.7, and t he assumption that the baseline gasoline contains 10 percent (by volume) corn et hanol. The second effect of excluding the

indirect land use effect is to reduce the average carbon intensity of gasoline that will be used to meet LCFS carbon intensity reduction requirements. However, the reduction in the carbon intensity of the complying gasoline is not the same for all scenarios. This variability results from the fact that the magnitude of the land use effect varies by ethanol type, and the fact that different scenarios call for different proportions of ethanol types.

As shown in Table VI-3, the land use effect ranges from 46 for sugar cane ethanol to 30 for midwestern average corn ethanol and Ca lifornia low-carbon intensity ethanol, to 18 for cellulosic ethanol, and to zero for advanced renewable ethanol. The proportion of total carbon intensity attributable to indirect land use change varies from 63 percent forVI-19 sugar cane ethanol to zero percent for adv anced renewable ethanol. As a result, the effect of excluding the land us e component from ethanol carbon intensities will vary with scenario, due to the relative amounts of each ethanol type assumed under each

scenario.

Table VI-14 shows the variable effects on 2020 gasoline carbon intensities of excluding indirect land use change effects from the ca rbon intensity ratings of ethanol. The

carbon intensities shown incl ude the reduction in carbon in tensity resulting from the number of plug-in hybrid electr ic vehicles, battery electric vehicles, and fuel cell vehicles

called for under each scenario.

Table VI-14 Effect of Excluding Land Use Emissions on Gasoline Carbon Intensity in Year 2020

Scenario Baseline AFCI (gCO 2 e/MJ) 2020 Average AFCI (gCO 2 e/MJ) % Reduction

Scenario 1 93.39 84.2 9.8

Scenario 2 93.39 83.6 10.5

Scenario 3 93.39 83.7 10.4

Scenario 4 93.39 84.0 10.1

The above table shows t hat the exclusio n of the indirect land use component from the carbon intensities of the various types of f uels used to achieve a 10 percent reduction in the gasoline carbon intensity in 2020 has very little effect on the percent reduction in carbon intensity achieved in 2020. The per cent reduction in carbon intensity remains very close to 10 percent after the indirect land use component is excluded. Therefore,

the amounts of the various f uels needed in 2020 to achieve a 10 percent reduction in carbon intensity change very little. This is illustrated in the table below, which compares

the number of FFVs and the amounts of the f uels needed to be used to achieve a 10 percent reduction in carbon intensity if the indirect land use components are included, to the number of FFVs and the am ounts of fuels that w ould be needed in 2020

if the indirect land us e components are excluded.VI-20 Table VI-15 Effect of Excluding Indir ect Land Use Effects on the

Amounts of EtOH Blendstocks Needed to Achieve

10 Percent Reduction in Carbon Intensity in 2020 (Billions of Gallons)

Scenario 1 Scenario 2 Scenario 3 Scenario 4

With
ILUC Without
ILUC With
ILUC Without
ILUC With
ILUC Without
ILUC With
ILUC Without
ILUC MW Avg.Conv. Corn

EtOH 0 0 0 0 0 0 0 0

CA Low CI Corn EtOH 0.30 0.30 0.30 0.30 0.30 0.30 0.30 0.30

Cellulosic EtOH 1.29 1.32 1.24 1.19 1.10 1.06 0.79 0.77

Adv. Renew. EtOH 1.29 1.32 1.24 1.19 1.10 1.06 0.79 0.77 Sugar Cane EtOH 0 0 0.30 0.30 0.30 0.30 0.30 0.30
No. of FFVs (millions) 3.0 3.1 3.4 3.2 2.9 2.73 1.8 1.7

The table above shows that, in Scenarios 2, 3, and 4, t he 10 percent reduction in carbon intensity can be achieved in 2020 with s lightly less volumes of cellulosic ethanol

and advanced renewable ethanol if the indirect land use co mponent of carbon intensity

is excluded. It should be noted that in Sc enario 1 more cellulosic ethanol and advanced

renewable ethanol is needed if the indirect land use component of carbon intensity is

excluded. This is due to the need to achi eve a 10% reduction in CI from a lower

number.

It is important, however, to include the indi rect land use component in the LCFS to account for significant effects and to ens ure that the market signals are correct.

3. Federal “RFS Only” Scenario

A reduction in the average car bon intensity of California f uels would be expected from the implementation of the federal Energy Independence and Security Act of 2007 (EISA) even in the absence of a California LCFS . This section provides an estimate of

the benefits of the f ederal program alone.

EISA requires that of 30 billion gallons of renewable fuel be produced nationwide in 2020. Of these 30 billion gallons, up to 15 billion gallons of corn derived biofuel is allowed and 10.5 billion gallons of cellulosi c biofuel and 4.5 billion gallons of other advanced biofuel and are required. If Califor nia were to receive 11.3 percent of the renewable fuels required under EISA, the California gasoline pool would receive in 2020 about 1.19 billion gallons of cellulosic biof uel (ethanol) designated under the Act to have a 60 percent reduction in carbon intens ity and about 340 million gallons of advanced biofuel designated by the Act to have a 50 per cent reduction in carbon intensity. The

use of these volumes of cellulosic and advanced biofuel, in combinat ion with 1.17 billion gallons of mid-west corn ethanol and 300 mill ion gallons of lower-carbon intensity cornVI-21 ethanol from California dry mill facilities with wet distiller grain solubles (DGS), would reduce the average carbon int ensity of California gasolin e by about 4 percent.

Under EISA, about 100 million gallons of biom ass-based diesel fuel designated by the Act to have a 50 percent reduction in carbon intensity would be used in the California diesel pool in 2020. The use of this biom ass-based diesel fuel would achieve about a one percent reduction in the carbon intensity of California diesel fuel in 2020. Overall, compliance with EISA would achieve about a three percent reduction in emissions and the carbon intensity of the combined Californ ia gasoline and diesel fuel pool in 2020.

This translates into an emissions reduction of 7.3 million metric tons per year of greenhouse instead of about 23 milli on metric ton per year from implementation of the

LCFS.

Additional details are provided in Appendix E.

D. Fuel Carbon Reductions in the Post-2020 Period

Fuel carbon intensity reductions beyond t hose required under the LCFS in 2020 will be needed to meet the greenhouse gas emission reduction goals beyond the 2020 target set pursuant to AB32. The LCFS will need to be periodically revisited and updated. Staff anticipates that a major revision would be needed in the 2015 timeframe to establish the appropriate LCFS annual standards for the 2021 through 2030 timeframe. This effort will draw upon the real world progress that is made over the next five years in the development of very low carbon fuel s and the deployments of highly efficient vehicles capably of operating on advanced fuels.

It is vital that fuel suppliers look beyond 2020 in their assessments of the types and quantities of transportation fuels that might be used in Califor nia over the next 20 years. The 2030 Scenario presents an assessment of what that future might be, and provides

estimates of how the lower carbon intensit y fuels might be deployed to achieve very significant greenhouse gas reductions by 2030. The scenario for gasoline is shown in Table VI-16, while the assumptions for t he 2030 diesel scenario are shown in Table

VI-17.VI-22 Table VI-16 2030 Gasoline Scenario Assumptions

Total Number of LD/MD Vehicles (millions) 36.0 Total Number of LD/MD FFVs (millions) 4.5 Total Number of LD/MD PHEVs (millions) 3.6 Total Number of LD/MD FCVs (millions) 1.8 Total Number of LD/MD BEVs (millions) 1.8 Total Number of LD/MD Diesels (millions) 2.5 Carbon Intensity of Electricity (gCO2e/MJ) 90.0 Carbon Intensity of Hydrogen (gCO2e/MJ) 76.1 Carbon Intensity of CA Low-Carbon Intensity Corn EtOH (gCO2e/MJ) 80.7 Carbon Intensity of Cellulosic EtOH (gCO2e/MJ) 20.4 Carbon Intensity of Advanced Renewable EtOH (gCO2e/MJ) 22.2 Carbon Intensity of Sugar Cane EtOH (gCO2e/MJ) 73.40 Amount of CA Low-AFCI Corn EtOH Used (billion gal/year) 0.34

Amount of Cellulosic EtOH Used (billion gal/year) 1.25

Amount of Advanced Renewable EtOH Used (billion gal/year) 1.25 Amount of Sugar Cane EtOH Used (billion gal/year) 0.34

Table VI-17 2030 Diesel Scenario Assumptions

Percent of HD Vehicles are PHEVs (percent) 10 Percent of HD Vehicles are CNG (percent) 10 Carbon Intensity of Electricity (gCO2e/MJ) 90.0 Carbon Intensity of CNG (gCO2e/MJ) 75.56 Carbon Intensity of Conventional Biodiesel (gCO2e/MJ) 68.93 Carbon Intensity of Advanced Renewable Diesel (gCO2e/MJ) 15.00 Amount of Conventional Biodiesel Used (million gal/year) 250

Amount of Advanced Renewable Diesel Used (million gal/year) 1,000

On the basis of the assumptions in T ables VI-16 and VI-17, the average carbon intensity of gasoline would be reduced by about 25 percent, while the average carbon intensity of diesel would be reduced by about 17 percent in 2030. The greenhouse gas

emissions reductions would be about 49 million metric tons per year (CO2 equivalent) in 2030 compared to the estimated 23 million metric tons in 2020.VII-1 

### VII. Environmental Impacts

This Chapter presents the env ironmental benefits and impacts that are associated with meeting the LCFS. The LCFS is a perfo rmance-based standard. Consequently, the specific pathways chosen by fuel producers to comply with the LCFS are uncertain. However, the GHG benefits (addressed on Sect ion B of this chapter) can be estimated based on the projected energy requirements needed over time. In addition, potential air quality impacts can be evaluated based on vari ous compliance scenarios. As part of the air quality analysis (as addressed in Sect ion C of this chapter), the staff has

estimated the emissions that could result fr om the production, dist ribution, and use of alternative fuels in California, evaluated potential mitigation options, and estimated the public health risks associated with individual and multiple co-located biofuel production

facilities.

In addition to the GHG emission benefits and air quality analyses, the staff has evaluated other potential envir onmental impacts (address ed in Section D of this Chapter). These include potent ial impacts on water; aestheti cs; agricultural, biological and cultural resources; geology and soils; hazards and hazardous materials; mineral resources; housing and populat ion; public services; recr eation; solid waste; and transportation and traffic.

The last three sections of this Chapter addr ess staff’s approach to addressing the long term sustainable production of low carbon f uels, the multimedia analysis, and the environmental justice imp lications of the LCFS.

Appendix F presents supporting in formation for this Chapter.

A. Summary of the Environmental Analysis

The environmental analysis of the proposed LCFS regulation focuses on significant

decreases in the GHG emissions that would re sult from the proposed regulation. These reductions would result from production and us e of lower carbon transportation fuels in California and changes in the vehicle fleet composition due to new, lower carbon fuels being available to the transportation fuel pool. Staff has estimated the GHG emissions

reductions for the combustion of tr ansportation fuels to be about 16 MMT CO 2 e by
2020. Staff has also estimated GHG reductions for the full fuel lifecycle, including fuel production through combustion, of 23 MMT CO 2 e in 2020. These reductions account for a 10 percent reduction of the GHG emissi ons from the use of transportation fuel. These reductions compare to the expected 3 percent reduc tion in GHG emissions if only the federal RFS 2 requirements were met.

The proposed LCFS regulation is also expec ted to result in no additional adverse impacts to California’s air quality due to emi ssions of criteria and toxic air pollutants. Based on the best available data, there may be a benefit in fu rther reducing criteria air pollutants from the 2020 pr ojected vehicle fleet.VII-2 To meet the proposed LCFS and the federal RFS 2, new biof uel production facilities will likely be built in California. Staff estimate s a total of thirty facilities producing corn ethanol (6), cellulosic ethanol (18), and biodi esel (6) could be operational by 2020 based on an assessment of the availability of feedstock material. Biofuel production on a commercial scale will require development of new technologies as well as the continued use of conventional technolog y with crop-derived feedstocks. Non-crop

feedstocks could include biomass wastes fr om municipal solid wastes, agriculture wastes, waste oils, and forestry . Criteria pollutant emissi ons were estimated for the production of biofuels, the colle ction of feedstock, and deliver y of the finished biofuel.

The emissions estimated for the biofuel prod uction facilities reflect the use of the cleanest energy conversion technologies and ai r pollution control technologies. ARB

staff recommends that the emissions associ ated with the production of low carbon fuels be fully mitigated consistent with loca l district and CEQA requirements.

For cellulosic ethanol facilities, the energy r equirements are typically greater than that

for conventional ethanol facilities based on the conversion of corn st arch. To provide

additional information for local districts and to inform the CEQA process, ARB staff is committed to developing a guidance document to provide information on the best practices available to reduce emissions from these types of facilities. This effort will commence immediately; ARB staff plans to have a draft available by the end of

December 2009.

The major criteria pollutant emissions are associated with the ad ditional biorefinery truck trips. On a statewide basis, these emissions may be offset by reductions in motor vehicle emissions. However, there may still be localized diesel PM impacts and localized facility emissions impacts.

A health risk assessment was conducted to estimate the potential cancer risk associated with newly establis hed biorefineries based on the facility specific emission inventory and air dispersion m odeling predictions. The esti mated potential cancer risk

levels are associated with onsite diesel PM emissions from three co-located prototype biorefinery facilities. The area with gr eatest impact was estimated to be the area surrounding the facility fence lines with a potent ial cancer risk of over 0.4 chances in a

million. The health risk assessment also examined combined onsite and offsite emissions of the three protot ype biofuel facilities. The area with the greatest impact was estimated with a potential cancer risk of over five chances in a million.

Staff also quantified seven non-cancer health impacts associated with the change in exposure to PM2.5 emissions due to the oper ation of biofuel facilities. The analysis shows that the statewide health impacts of the emissions associated with the LCFS are approximately 24 premature deaths; 8 hospi tal admissions; and 367 cases of asthma,

acute bronchitis and other lo wer respiratory symptoms.

Staff does not anticipate either a decrease or increase in t he emissions from petroleum refineries, power plants, or corn ethanol facilities over t he 2010 baseline. The capacityVII-3 of the State’s electric system in 2020 will be sufficient to support 1.8 million electric vehicles due to the 33 perc ent renewable portfolio standard and off-peak charging.

Also included in the environmental analysis is an examination of other environmental impacts of the LCFS on water quality and us e, agricultural resources, biological resources, geology and soils, hazardous material s, mineral resources, and solid waste, among others.

Sustainability provisions will ensure that the LCFS regulat ion does not adversely impact the ability to continue the use of biofuels and other low ca rbon intensity fuels in the

future. The most critical sustainability component, addre ssing land use change, is part of the LCFS regulation. To addre ss other sustainability components, both environmental and socioeconomic, will require international cooperation and the development of enforceable cert ification standards. ARB is committed in the short term to develop a plan to address other sustainabi lity components, and within two years of adoption of the LCFS will develop proposed sustainability criteria.

The ARB is committed to making the achievem ent of environmental justice an integral part of the LCFS. As such, staff seeks to develop tools to ensure that the proposed regulation does not dispropor tionately impact low-income and minority communities,

does not interfere with the atta inment and maintenance of am bient air quality standards,

and considers overall societal be nefits (such as diversificatio n of energy resources). As part of ongoing AB 32 analysis, ARB staff is developing a screening method for geographically representing em ission densities, air quality exposure metrics, and indicators of vulnerable populations, as an evaluation aide for already adversely impacted communities.

B. Greenhouse Gas Emission Benefits

In this section, ARB staff presents esti mates of the GHG benefit s associated with the LCFS. GHGs include, but are not limited to carbon dioxide (CO 2 ), methane (CH 4 ) and nitrous oxide (N 2 O). In addition, staff has eval uated the contribution of various compliance options to the ov erall GHG emission benefits.

1. Determination of GHG Emission Reductions

In the AB 32 Scoping Plan, the LCFS is estimated to provide 15 MMT CO 2 e emissions reduction in the year 2020. This value was derived by considering the baseline and projected business as usual case emissions in 2020, subtracting out the measures that

would reduce the amount of fuel used, and then making an adjustment to ensure that

the emissions reductions from electric vehicl es are not double-counted. In that analysis,
staff assumed that the LC FS would achieve a 10 perc ent reduction in the carbon intensity of the fuel used in California, wh ich translated to a 10 percent reduction in
emissions from fuel used in California. In effect, that analysi s represented only the

emissions from combustion and not t he full lifecycle emission reductions.VII-4 In this analysis, we evaluated the benefits of the LCFS in two ways. In the first analysis, staff evaluated the fuel energy required to meet the LCFS standard in each year using only the “tank-to-wheel” carbon intensity. Th e “tank-to-wheels” analysis means that only the emission reductions seen at the tailpipe of the vehicles combusting low carbon fuels are considered. This analysis reasonably represents the emissions that would occur in California and is similar to the analysis us ed in the Scoping Plan. In addition, these reductions are the estimates of targeted emissions that would be compared to the targeted emissions in the Scoping Plan. In the second analysis, staff used the full lifecycle carbon intensity to estimate the overall CO2 emission reductions associated

with the LCFS.

In general, the energy requirements necessary to meet the LCFS are a function of the estimates of fuel use required each year fo r transportation fuels. These estimates are projected from 2010 to 2020 using a business as usual scenario for both gasoline and diesel fuel. The fuel use is expressed in terms of gasoline gallon equivalent (gge) to account for the different types of fuel used ( gasoline, diesel, CNG, el ectricity, hydrogen, etc.) In addition, the estimates are then adj usted by the other di screet early actions presented in the Scoping Plan. Chapter VI discusses these adjustments in more detail and presents a baseline case. The emissi ons estimates for each year are then projected by multiplying the respective baseline carbon intensities for gasoline and diesel fuel by the total energy required each year. Details of the analysis are presented in Appendix F1.

Table VII-1 presents the results for the tank-t o-wheel analysis. As shown in the table,
the total GHG emission reductions are 17.6 MMT CO 2 e in 2020. About 70 percent of the emissions are associated with the gasoli ne pathway; the remainder from the diesel pathway. Table VII-2 presents the results fo r the full lifecycle basis. As expected, the GHG benefits are higher than just the “tank-to- wheel” estimates as they account for the

full benefits of the LCFS. Howeve r, not all of these benefits are realized in California. Therefore, for purposes of tracking compliance with AB 32, staff recommends that the

“tank-to-wheel” estimates be used.VII-5 Table VII-1
GHG Emission Benefits of the LCFS

“Tank-to-Wheel” Basis

GHG Emission Reductions (MMT CO 2 e) Year

Gasoline Diesel Total

2010 --- --- ---

2011 0.3 0.1 0.4

2012 0.7 0.2 0.9

2013 1.3 0.5 1.8

2014 1.9 0.7 2.6

2005 3.2 1.3 4.5

2016 4.4 1.7 6.1

2017 6.3 2.5 8.8

2018 8.1 3.4 11.5

2019 9.7 4.3 14.0

2020 12.1 5.5 17.6*

*Please note that this does not include a 1.8 redu ction to eliminate the double counting of the ZEV mandate. If this is included, the estimated total “tank-to-wheel” GHG benefits would be closer to 15.8
MMT CO 2 e in 2020.

Table VII-2
GHG Emission Benefits of the LCFS Full Lifecycle Basis

GHG Emission Reductions (MMT CO 2 e) Year

Gasoline Diesel Total

2010 --- --- ---

2011 0.4 0.1 0.5

2012 0.9 0.3 1.2

2013 1.7 0.6 2.3

2014 2.5 0.9 3.4

2005 4.2 1.6 5.8

2016 5.8 2.2 8.0

2017 8.3 3.2 11.5

2018 10.6 4.3 14.9

2019 12.8 5.4 18.2

2020 15.9 7.0 22.9

2. Contribution of Low Carbon Fu els to GHG Emission Reductions

As discussed in Chapter VI, staff developed various compliance scenarios for meeting the LCFS. In these scenarios, staff pres ented examples of how producers can use a variety of fuels to achieve an average 10 percent reduction in the carbon intensity of the gasoline and diesel fuel. The following s ubsections discuss the contribution of the various fuels to achieving the overall GHG emission benefits.VII-6 a. Benefits from Gasoline Scenarios

Staff anticipates, as demonstrated in the sc enarios discussed in Chapter VI, that various types of renewable biofuels, electricity, and hydrogen will be necessary to achieve the required GHG reduction goals for gasoline. Table VII-3 summarizes two potential scenarios. The first scenario emphasizes the use of renewable liquid fuels and the second uses an optimistic penetration of advanced technology vehicles, in combination

with renewable fuels. These v ehicles include plug-in hybrid vehicles, battery electric vehicles, and fuel cell vehicles. The table presents the percent c ontribution of each low

carbon fuel to the total emi ssions reductions in 2020, as well as the actual MMT CO 2 e. These contributions are based on the complete lifecycle of the fuel s, with an overall reduction from the gasoline pathw ay of approximately 16 MMT CO 2 e.

Table VII-3
GHG Reductions from Low Carbon Fuels Substituting for Gasoline

Scenario 1 High Volume of Renewable Liquid Fuels Scenario 2 Large Number of Advanced

Vehicles Fuel

Percent
Contribution MMT CO 2 e Percent
Contribution MMT CO 2 e

CA Low-CI Ethanol 2 0.3 2 0.3

Cellulosic Ethanol 43 6.8 28 4.4

Advanced Renewable

Ethanol 41 6.6 27 4.3

Sugarcane Ethanol 3 0.5 3 0.5 Electricity 9 1.4 35 5.6 Hydrogen 2 0.3 5 0.8

Totals 100 15.9 100 15.9

b. Benefits from Diesel Scenarios

Staff anticipates, as demonstrated in the sc enarios discussed in Chapter VI, that various types of renewable biofuels, natural gas, and electricity will be necessary to achieve the required GHG reduction goals for diesel. St aff anticipates advanced renewable and advanced biodiesel to provide the majority of the GHG benefits for the heavy-duty fleet. Advanced electric, fuel cell, and compressed natural gas vehicles are not expected to result in significant GHG benefits by 2020. Therefore, Table VII-4 provides only one scenario. As with gasoline, T able VII-4 presents the percent contribution of each low

carbon fuel to the total emi ssions reductions in 2020, as well as the actual MMT CO 2 e. The total tons were calculated based on an overall reduction of 7 MMT of CO 2 e and are based on the complete lifecycle anal ysis of the fuels.VII-7 Table VII-4
GHG Reductions from Low Carbon Fuels Substituting for Diesel

Scenario 1 High Volume of Renewable Liquid Fuels Fuel

Percent
Contribution MMT CO 2 e

Conventional Biodiesel 13 0.9

Advanced Renewable

Biodiesel 82 5.7

Compressed Natural Gas 2 0.2 Electricity 3 0.2

Totals 100 7.0

C. Air Quality Impacts

This section discusses the potential air qualit y impacts and public health risks related to potential sources and types of ai r emissions of identified lo wer-carbon fuel that may be used in the implementation of the LCFS. Low carbon fuels that may be used to comply with the LCFS include, but are not limited to, low-carbon ethanol, biodiesel, renewable diesel, electricity, hydrogen, and natural gas.

Below are descriptions of the pollutants of inte rest in this Chapter.

• Criteria Air Pollutants : Criteria air pollutants ar e determined to be hazardous to human health and are regulated under U.S. EPA's National Ambient Air Quality

Standards. The 1970 amendments to the Clean Air Act require U.S. EPA to describe the health and welfare impacts of a pollutant as the "criteria" for inclusion in the regulatory regime. Both the California and federal governments have adopted health-based standards for the criteria pollutant s that include ozone, particulate matter (PM 10 , PM 2.5 ), carbon monoxide (CO), oxides of nitrogen (NO
x ), oxides of sulfur (SO
x ), and volatile organic compounds (VOC).

• Toxic Air Pollutants : Toxic air pollutants (als o referred to as toxic air contaminants (TAC), or air toxics) ar e those pollutants which may cause or contribute to an increase in mortality or serious illness, or which may pose a

hazard to human health. Air toxics are usual ly present in minute quantities in the ambient air. However, their high toxici ty or health risk may pose a threat to public health even at very low concentrati ons. The toxic air pollutant of most concern in this analysis is the particula te matter from diesel-fueled heavy-duty trucks (diesel PM).VII-8 1. Overview of the Air Quality Analysis

The analysis of the potential air quality impacts of the proposed LCFS regulation was conducted in the same manner as the analysi s of the GHG benefits. This “well-towheels” lifecycle analysis examines all poten tial air emissions from the production, transportation, and distribution of biofuels feed stocks; the actual production of biofuels; the transportation and distributi on of biofuels (including dispensing to vehicles); and, finally the combustion biofuels in vehicles.

In this section, staff first presents an anal ysis of the number and lo cation of biofuels facilities the State could support, as far as feedstock availability is concerned. Next, staff presents the various air quality regulatory requirements that apply to any biofuels facilities built in California. Following th is discussion, the st aff presents baseline emissions from the current production and use of transportation fuels in California. Then, staff presents the emi ssions that are estimated for the various cycles of production, distribution, and use of biofuels. Finally, staff compares the baseline

emissions with those that are estimated to be associated with the implementation of the

LCFS.

2. California Biofuel Production Facilities

Currently, there are two commercial scale corn ethanol facilities operating (approximately 100 MM gal/year), one sm all cellulosic ethanol facility under construction, and 9 small biodiesel facilities operating in California. Three additional

commercial scale ethanol facilities are constr ucted, but are not cu rrently operating for

economic reasons. Construction was starte d on one additional commercial scale corn but construction was recently halted. Two ot her commercial scale corn ethanol facilities have been permitted, but are not currently under construction. For purposes of this analysis, we assumed that six corn ethanol facilities would be operating in 2010. Table VII-5 summarizes the capacity of thes e facilities in addition to the volume of gasoline and diesel produced in California.

Table VII-5 Production Capacity of Transportation Fuels in California

2010

Sources (# of facilities) MMgal/year MMgal(gge)/year Petroleum Refineries (15) 18,400 18,960 Corn Ethanol Facilities (6) 310 440 Cellulosic Ethanol Facility (1) 3 2 Biodiesel Facilities (9) 63 73 TOTAL --- 19,475

The federal RFS2 and the pr oposed LCFS regulation will su bstantially increase demand
for biofuels in California. T herefore, there may be incentives for bringing some of theVII-9 existing and permitted corn ethanol facilities back on line, as well as incentives for constructing other biofuel facilities. For purpos es of this analysis, staff estimated that there could be 30 large, commercial-scale biofuel production facilities (biorefineries) in

California in 2020. This includes six commerc ial scale corn ethanol facilities. For this analysis, commercial-scale facilities are those facilities that produce approximately 50 million gallons per year. Table VII-6 shows the potential number of facilities in 2020, indicating which ones already exist and which ones might be built in order to meet the
demands of RFS2 and the LCFS.

Table VII-6
Potential Number of Commercial-Scale

Fuel Production Facilities in California*

2020

Type of Facility Existing New Total

Corn Ethanol 6 0 6

Cellulosic Ethanol 0 18 18

Biodiesel/Renewable Diesel 0 6 6

* Commercial-scale facilities are assumed to produce 50 MMgal/year each in 2020.

The analysis of the number and size of new biofuel production facilities is based on:

• The projected volume of biofuel needed to meet RFS2 requirements and the

estimated volume of biofuel that coul d be used to meet LC FS requirements (see Chapter VI for an explanation of possible scenarios); and

• A report prepared by the University of California, Davis, for the Western Governors’ Association (WGA)(76). The WGA report examines the potential for growth in the number, capacity, and loca tion of biorefineries based on economic parameters.

Production facilities would be located in clos e proximity to local feedstocks. Biofuel production on a commercial scale will require development of new technologies as well

as the continued use of conventional technology with crop- derived feedstocks. Non-crop feedstocks could include biomass wa stes from forestry, municipal solid wastes, agriculture wastes, and waste oils.

Biodiesel production plants also tend to be located close to their feedstocks and secondarily close to rail yards or freeways for distribution to retail sites. Ethanol

facilities tend to be located near rail or tr uck terminals. Ethanol facilities may also consider proximity to users of ethanol co-products during site determination.

Biofuels will be available to replace both gasoline and diesel with the split between the two fuel types difficult to quantify at this ti me. Based on the staff’s analysis, the volume of biofuels that might be produced in Calif ornia in 2020 could be 1.5 billion gallons of ethanol and 0.8 billion gallons of biodiesel. Potential locations in 2020 are listed inVII-10 Table VII-7 and shown on a map in Figure VII- 1. Additional detai ls on the number and location of biorefineries and petroleum refineries is presented in Appendix F2.

Table VII-7
Location of Potential California Bi ofuel Production Facilities by 2020 (New Facilities are 50 MMgal/year)

Air Basin Corn Ethanol Ce llulosic Ethanol Biodiesel

North Coast 2 Sacramento Valley 3 San Francisco Bay 2 2 a San Joaquin Valley 6 c 4 2 a

South Central Coast 2

South Coast 1 1 b

Salton Sea 1 San Diego County 3 1 a

a Fischer-Tropsch process

b Non-esterified renewable diesel (hydrotreatment)

c Plants currently exist and are incl uded in the baseline calculationsVII-11 Figure VII-1 Map of Potential Biorefinery Locations in 2020VII-12 3. Permitting and Other Requirements

Under State law, the air pollution contro l and air quality managemen t districts (local districts) have the primary responsibility for controlling ai r pollution from non-vehicular sources, including stationary s ources such as biorefineries. 51 Each local district has a program designed to address new stationary sources of air po llution. For most local districts, these programs ar e referred to as new source review (NSR) programs.(77) 52
NSR programs provide mechanisms to: (1) reduce emission increases up-front through the use of clean technology, and (2) achi eve a no net increase in emissions of nonattainment pollutants or thei r precursors for all new or modified sources that exceed particular emission thresholds. This is a ccomplished through two major requirements in
each district NSR rule: best av ailable control technology (BACT) 53 and offsets. The local districts also develop rules to reduce emissions from specific sources and govern the overall permitting process. Also, the lo cal districts enforce their local rules and prepare local air quality plans to achi eve ambient air quality standards.

In addition to meeting local district NSR rule s, new biorefineries must meet California Environmental Quality Act (CEQA) 54 requirements as part of the permitting process. As these biorefineries are large industrial fa cilities, an environmental impact report (EIR) must be prepared. To comply with CEQA requirements, the EI R must identify any significant environmental impacts, identify feas ible alternatives, and incorporate feasible mitigation measures to minimize the si gnificant adverse environmental impacts

identified in the envir onmental impacts analysis. CEQA requires that no project, which may have significant adverse environmental impacts, may be adopted as originally proposed if feasible alternatives or mitigati on measures are ava ilable to reduce or eliminate such impacts, unless specific ove rriding considerations are identified that outweigh the potential adverse cons equences of any unmitigated impacts.

The emissions estimates used for this air quality impact analysis reflect the use of the cleanest energy conversion technologies and ai r pollution control technologies. Even the use of the cleanest technologies can resu lt in unmitigated emissions. However,

ARB staff recommends that the emissions a ssociated with the produc tion of low carbon fuels be fully mitigated consistent with local district and CE QA requirements. For cellulosic ethanol facilities, the energy r equirements are typically greater than that

for conventional ethanol facilities based on the conversion of corn st arch. To provide

additional information for local districts and to inform the CEQA process, ARB staff is committed to developing a guidance document to provide information on the best practices available to reduce emissions from these types of facilities. This effort will commence immediately; ARB staff plans to have a draft available by the end of

December 2009.

51 Health and Safety Code section 39002.

52 See, e.g., Bay Area Air Quality Management District Regulations 2-1 through 2-6. A few local districts,

because of their federal attainment status for cert ain pollutants, implement a Prevention of Significant Deterioration (PSD) program.

53 In California, BACT is synonymous with the feder al term Lowest Achievable Emission Rate (LAER) for nonattainment area permit requirements.

54 Public Resources Code section 21000 et seq.VII-13 Based on the data currently avai lable, there are several stra tegies that can be used to mitigate emissions and these have been g enerally incorporated into the analysis presented in this Staff Report. These include:

• Requiring the use of the best available control technologies;

• Requiring the use of the most efficient conversion technologies for the production of low carbon fuels;

• Requiring the maximum recovery of wa ste heat and other marketable products from energy conversion processes;

• Requiring the use of energy effici ent air pollution control strategies;

• Eliminating, except for emergency purposes, the flaring or combustion of process waste fuels; and

• Requiring the use of vapor recovery to capture and re-use process evaporative

emissions.

Appendix F3 contains additional informati on on mitigation and permitting requirements.

4. Emissions Estimates for Producing Low Carbon Fuels

The emission estimates are based on compar ing the baseline emissions that would occur in 2020 versus the changes that might o ccur as a result of the LCFS. There are several assumptions that have been made in making this comparison. For petroleum production and refining, power generation, nat ural gas production, hydrogen production, and corn ethanol facilities, staff assumed that no significant changes in emissions

between 2010 and 2020 would occur due to the LCFS. The major changes are due to the increased production of cellulosic and biodi esel facilities in California. These changes include feedstock and biofuel distri bution and transportation and biofuel production facility emissions. For purposes of this analysis, we have assumed that the facility emissions are offset, although we present the cumulative emissions later in this

section. We also evaluate the local and regional emissions for an individual and multiple co-located facilities.

In addition, the analysis present s a comparison of the emi ssions benefits that would

result from the use of 2 million advanced vehicles versus the 1 million advanced

vehicles.

a. Baseline Emissions

In order to determine the effe cts of the LCFS on Californi a air quality, it is first necessary to determine the baseline emissions that currently exist from the production and use of transportation fuels in California . Table VII-8 present s the 2020 baseline
without consideration of the LCFS. More det ails regarding the regional impacts of these facilities can be found in Appendices F2, F4, F5, and F6.VII-14 Table VII-8 Estimated 2020 California Transportati on Fuel Baseline Emissions (tons/day)

Emissions (tons/day) Sources VOC CO NO X PM 10 PM 2.5 Petroleum Production, Refining, and Marketing(78) 104.5 40.0 43.9 7.8 7.4

Corn Ethanol Production 55 0.28 0.39 0.92 0.13 0.12

Cellulosic Ethanol Production 2 0.06 0.06 0.06 0.02 0.02

Biodiesel Production 56 0.17 0.10 0.07 0.02 0.01 Electricity Production 57

-- -- -- -- -- Hydrogen Production 4

-- -- -- -- -- Natural Gas Production 4

-- -- -- -- -- On- and Off-road Gasoline

Vehicles 58 636.04 4947.58 334.56 -- 46.87

On- and Off-road Diesel Vehicles 7 73.18 514.85 558.60 -- 19.73

TOTAL 814.23 5502.98 938.11 7.97 74.15

b. Emissions from Feedstock Production, Transportation, and

Distribution

Transportation fuels included in the LCFS ar e produced from a variety of feedstocks. These feedstocks include crude oil, natural gas , biomass material, biowaste material, waste grease, or munici pal solid waste. In some cases, criteria pollutants are emitted during the process of feedsto ck production. Waste feedsto ck is considered to have no production criteria pollutant emissions. Estimates of fe edstock production criteria pollutant emissions for the year 2020 are pr esented in Table VII-9. These estimates were calculated using a 2015 fleet average of diesel vehicles and includes the control measures put forth in the Scoping Plan. Appr oximately two-thirds of emissions from the 2020 fleet come from pre-2010 trucks; air dist ricts could require facilities to mitigate associated truck emissions by requiring t he use of 2020 or newer vehicles as a condition of permitting. A ssumptions for these analyses can be found in Appendix F4.

55 Based on permit values reported for California facilit ies (for complete list, see Appendix F) and includes transportation and distribution of feedstocks and finished fuels.

56 Based on American Biodiesel permit, scaled linearly from 6.1mmgal/yr to 63 mmgal/yr and includes transportation and distribution of feedstocks and finished fuels.

57 Electricity, hydrogen, and natural ga s production contribute negligibly to the criteria pollutant emissions in 2010 because they are not currently being used in large enough quantities as transportation fuel

58 On-road emissions based on EMFAC, includes Pavley I and II. Off-road emissions calculated using the

Off-road Vehicle model.VII-15 Table VII-9 Projected 2020 Criteria Pollutant Em issions from Feedstock Production, Transportation, and Distri bution above the Baseline

2020 Emissions Changes (tons/day) Feedstock VOC CO NO
x SO
x PM 10 PM 2.5 Crude Oil -- -- -- -- -- -- Electricity -- -- -- -- -- --

Natural Gas -- -- -- -- -- --

Corn Ethanol a

-- -- -- -- -- -- Cellulosic Waste

Feedstock b 0.02 0.33 0.80 0.02 0.02 0.02

Biodiesel Feedstock c 0.01 0.09 0.20 0.005 0.006 0.006

a No emissions are attributed to corn ethanol as no new facilities are expected to be built.

b Forest waste, orchard and vineyard waste, corn stover, straw, and/or municipal landfill waste.

c Beef tallow, pork lard and/or municipal landfill waste.

c. Emissions from Fuel Production Facilities

Criteria pollutants in 2020, above the 2010 basel ine, for transportation fuel production

facilities are shown in Table VII-10 below. Detailed calculations of cellulosic ethanol and biodiesel facility emissions can be found in Appendix F5. It should be noted that staff do not anticipate either a decrease or increase in the emissions from petroleum refineries, power plants, or corn ethanol facilities. In the ca se of petroleum, staff does not anticipate that refineries would operate at a lower capacity and any excess fuel above and beyond California’s needs would be exported to neighboring states or

elsewhere.

For electricity, the additional 1.8 million elec tric vehicles by the year 2020 assumed for this report are expected to increase the St ate’s electric system load demand by 4.6 terawatt hours (TWh) by 2020. Since mo st of this addition al demand would be supplied by off-peak power, electric vehi cles would not create an adverse impact on California’s supply of available electric pow er within the 2020 time frame. Also, staff

does not consider corn ethanol facilities to change by 2020, as they are currently using the best control technology currently availabl e. Again, it shoul d be noted that these facilities will be subject to permitt ing and mitigation requirements.

These estimates reflect:

• The most recent data gathered from permits and engineering evaluations for existing in-state facilities;

• Use of the cleanest energy conversion technologies and air pollution control technologies available;

• Emissions from stationary source s that do not require a permit; and

• Emissions from electric al back-up generators.VII-16 These emissions estimates do not reflect offs ets, which we expect to be required.

Table VII-10 Projected 2020 Criteria Pollu tant Emissions Changes

from Fuel Production Facilities a

2020 Emissions Changes (tons/day) Sources VOC CO NO X PM 10 PM 2.5 Petroleum Refineries b

-- -- -- -- -- Electricity Production b

-- -- -- -- -- Natural Gas Production b

-- -- -- -- -- Corn Ethanol Facilities b

-- -- -- -- -- Cellulosic Ethanol Facilities c 12.39 2.49 4.76 4.83 0.65

Biodiesel Facilities c 7.82 3.21 0.95 0.66 0.25

TOTAL 20.21 5.70 5.71 5.49 0.90

a Does not include offsets, which should be required in most cases.

b No additional emissions above the 2010 baseline.

c See Appendix F5 for details on how these estimates were made.

d. Emissions from Fuel Tran sportation and Distribution

Criteria pollutant emissions for the transpor tation and distribution of finished fuels were estimated for the year 2020. These emissions result in the movement of fuel in heavy duty-diesel trucks and railcars.

Production capacity of biorefiner ies in California in 2020 is not expected to supply the total volume of biofuels necessary for Calif ornia transportation use. To acquire the necessary volume of biofuels, they will be imported from the Midwest. Ethanol is currently transported by unit train from the Midwest through Needles; Yuma; or Reno. The unit trains deliver ethanol to Selby an d Carson. Ethanol is then delivered to CARBOB blending facilities or to storage facili ties by heavy-duty diesel truck. In the future, biodiesel fuel is also expected to be imported in significant quantities into California. Biodiesel will likely be delivered from rail yard to vehicle fueling site by heavy-duty diesel truck. Finished transportati on fuel is then delivered by tanker truck to fueling stations th roughout the State.

Criteria and toxic emissions were estimat ed for the rail and tru ck transportation of ethanol and biodiesel fuels, shown in Table VII-11.VII-17 Table VII-11 Projected 2020 Criteria Pollutant Emission Changes from Fuel Transportation and Distribution a

2020 Emissions Changes (tons/day) Fuel VOC CO NO
x SO
x PM 10 PM 2.5 Finished Petroleum

Products -- -- -- -- -- --
Electricity -- -- -- -- -- -- Compressed Natural Gas -- -- -- -- -- --

Corn Ethanol -- -- -- -- -- -- Cellulosic Ethanol b 0.04 0.05 3.58 0.001 0.069 0.063

Biodiesel b 0.011 0.047 0.61 0.002 0.004 0.003
Hydrogen -- -- -- -- -- --

a Based on hypothetical optimized locations for cellulo sic ethanol, corn ethanol, and biodiesel facilities.

b These transportation emissions include the rail emissions from imported cellulosic ethanol and biodiesel once they enter the state.

e. Emissions from Ports

Staff has considered the effect of the LCFS on port emissions. We anticipate that there would be little to no change to emissions at ports from feedstock delivery or finished fuel. Although we anticipate a decreas e in demand for both crude and finished CARBOB from overseas, we expect Californi a refinery production to remain constant. Therefore, surplus finished gasoline, which will be above and beyond our needs as our reliance decreases, will be shipped overseas.

f. Motor Vehicle Emissions

In order to meet the goals of the LCFS, staff has two bas ic approaches: (1) introducing lower carbon fuels and (2) employing vehicles t hat can use these lower carbon fuels. In this section, there is a discu ssion of several different vehicl e technologies and how they compare to their appropriate gasoline or diesel vehicles. Table VII-12 shows the overall reductions in criteria pollutants staff antic ipates from our projected 2020 fleet.

The criteria pollutant emission impact from Zero Emission Vehicle (ZEV) program is

based on the benefit difference between the 2 million market-driven advanced technology vehicle (fuel cell, battery or plug- in hybrid electric vehicles) and the improved ZEV regulation of up to 1 milli on advanced technology vehicles.

The impact from the use of E85, B20, and CNG bio/renewab le diesel assumes 15% of petroleum diesel will be displaced by renewabl e alternative diesel fuels (biodiesel 5% and renewable diesel 10%). It covers the criteria pollutants emissions changes from

both on-road and off-road vehicles in 2020.VII-18 The criteria pollutant emissions impact from CNG is obtained by assuming 35,000 heavy-heavy-duty diesel vehicles will be repl aced by CNG vehicles in 2020.

For E85, the vehicles are required to meet emission standards equivalent to those for gasoline vehicles. Therefore there are no em ission increases from E85 versus gasoline vehicles. Staff estimated slight increase in refueling emissions due primarily to the larger number of refills. Since E85 has lower energy content than gasoline, people would have to fill up more often.

Table VII-12 Projected 2020 Criteria Pollutant Emission Changes

Due to an Increased Number of Advanced Vehicles

2020 Emissions Changes (tons/day) Vehicle VOC CO NOx SOx PM10 PM2.5

ZEV -4.11 -38.36 -6.03 -1.21 -0.71 -0.41

B20 -- -- -2.20 -- -0.75* -0.71

CNG -- 15.08 -1.64 -- -0.67 -0.63*

E85 0.23 -- -- -- -- --

Total -3.88 -23.28 -9.87 -1.21 -2.13 -1.75

*: Number is obtained by assuming 94.7% of diesel PM is PM2.5.

E85 vs. Gasoline Vehicles:

One potential avenue to reduced greenhouse gas emissions is expanded use of E85 in place of gasoline. E85, however, must be used in flexible fuel vehicles (FFVs). Upgrades to the fuel distribut ion system are also required. This section examines the potential impacts to emissions of criteria pollutants and toxic air contaminants from switching from gasoline to E 85. Given that bot h conventional gasoline and flexible fuel

vehicles must meet the same emissions standards, it is reasonable to expect that the

emissions levels will be similar. The following discussion present s aspects which are

essential to examine E85’s f easibility and environmental impact.

The number of vehicles and the emissions per vehicle on each fuel can be used to determine the change in emissions in switching from gasoline to E85. The population of FFVs is expected to increase between 2005 and 2020.

Staff estimates a maximum increase of 84 ton/year VOC evaporative emissions from refueling results in switching to scenario 2 volumes of E10 and E85 in 2020, as opposed to not switching from an energy equivalent volume of CaRFG3 fuel (E10). The other

scenarios offer somewhat smaller increases.

Emission standards for vehicles which use E85 are the same as for vehicles which use gasoline. Therefore, staf f does not expect to see a significant difference in the

emissions.VII-19 A cursory review of Californi a certification data for 2008 m odel year FFVs indicates that they are all compliant on both E85 and gasoli ne for all pollutants. While differences were slight, emissions of CO and NOx tende d to be less on E85 than on gasoline, while emissions of VOC tended to be greater on E85 than on gasoline. Emissions of formaldehyde (HCHO) were also greater on E85 than on gasoline, showing a much larger difference, although there was only one pair of test values (DaimlerChrysler).

A literature search was conducted for E 85 and FFV emissions. Results turned up mostly dated (1990s) publications and low-to-int ermediate ethanol concentration fuels. Since that time, reformulated gasoline has emerged and vehicle technologies have changed considerably. Fewer recent publicati ons are available. Emissions studies yielded mixed results; there does not appear to be a clear consensus as to whether E85 or gasoline has greater emissions.

At least two other vehicle studies are in t he works, the Coordinati ng Research Council E-80 project, and the US EPA Co mprehensive Gasoline Light Duty Exhaust Fuel Effects Test Program to Cover Multiple Fuel Pr operties and Two Ambient Test Temperatures.

Criteria pollutant and toxic emi ssions from motor vehicles us ing all fuels were estimated with the CA Modified GREET version 1.8b( 47). Emissions data are located in Appendix F6.

Biodiesel and Renewable Di esel vs. Diesel Vehicles:

The main factors that will affect changes in emission rates from biodiesel as compared to diesel are feedstock composition, changes in engine technologies, and regulatory action. Biodiesel feedstocks can have a sign ificant effect on emissions of ROG, PM, and NOx. NOx is of particular interest bec ause biodiesel has been reported to increase
NOx emissions. ARB staff has assumed that there will be no increase in the emissions
of NOx. This is because staff is current ly conducting an extensive test program for

biodiesel and renewable diesel and will follow that effort with a rulemaking to establish specifications to ensure ther e is no increase in NOx.

For renewable diesel, the main factors are changes in engine technologies and regulatory action; however feedstock composit ion is not expected to affect changes in

renewable diesel emission rates. Because r enewable diesel is a high Cetane, ultra-low aromatic fuel, renewable diesel is expected to have lower emission rates of ROG, PM,

and NOx than diesel fuel.

Another factor is the lack of data on how biodiesel and r enewable diesel will affect emissions from 2010 on-road engines. The 2010 engine technologies are significantly different from current engines since they control both NOx and PM and emit lower emissions than uncontrolled engines. Staf f expects that PM and NOx benefits from renewable diesel, and PM benefits from biodi esel, would be mainly from pre-2010 onroad, and uncontrolled off-road diesel engines. As the on-road and off-road diesel fleet regulations control more of the in-use flee t, the criteria pollutant benefits of renewableVII-20 and biodiesel will decrease over time. For mo re details on the emissions from vehicles using biodiesel and renewable di esel, refer to Appendix F7.

Electricity and Hydrogen vs. Ga soline and Diesel Vehicles:

An analysis of three different deployment scenar ios for light duty electric drive vehicles was performed to determine possible emissions reductions from various populations. The potential emissions reductions for t he year 2020 range from 1.6 to 6.9 million tons/year of GHGs and 11,430 to 36,000 tons /year of criteria pollutants depending on deployment scenario.

Currently a limited number of zero emission hydrogen fuel ce ll buses (ZBus) are being used by transit fleets in demonstration projec ts. The number of vehicles is limited and expected to increase as the technology is validated and regulations facilitate the adoption of cleaner fleets. Future heavy duty vehicle populations have the potential to

reach over 7300 units in 2020 due to emission reduction requirements placed on transit agencies. These vehicles demonstrate t he potential for emissi ons of GHGs to be reduced by 16,200 tons/year and criteria pollutants by 1000 tons/year.

For detailed information regarding Z EV benefits, refer to Appendix F8.

CNG vs. Diesel Vehicles:

Staff analyzed the impacts of switching a nu mber of diesel fuel ed HHDD trucks to CNG fuel to compare the change in PM and NOx emi ssions. This analysis was performed for 4,600 conversions by 2015 and 23,300 conversions by 2020. This analysis shows that switching from diesel fuel to CNG would resu lt in a slight decrease in PM emissions, as well as a slight decrease in NOx emissions . Staff did not estimate any change in

emissions of CO and NMHC. For mo re details, please see Appendix F9.

g. Summary of Impacts

The total criteria pollutant emissions fo r the production (after mitigation and offsets), transportation, and distribution of biofuels from the potential 24 new biorefineries listed

above are summarized in Table VII-13. This summary is an overall estimate of the criteria pollutant impacts. The potential public health risks are discussed separately.

Clearly the major impact is associated with t he additional truck trip s. On a statewide basis, these emissions may be offset by re ductions in motor vehicle emissions. However, there may still be localized diesel PM impacts and localized facility emissions impacts. These impacts are discussed in the next section.VII-21 Table VII-13 Summary of 2020 Changes from the Production and Use of Low Carbon Fuels above the Baseline (tons/day)

Criteria Pollutants Emissions VOC CO NOx SOx PM10 PM2.5

Petroleum Refining, Production, and Marketing -- -- -- -- -- --

Electricity Production -- -- -- -- -- -- Natural Gas Production -- -- -- -- -- -- Cellulosic Ethanol Facilities -- -- -- -- -- --
Biodiesel Facilities -- -- -- -- -- -- Impact from ZEV -4.11 -38.36 -6.03 -1.21 -0.71 -0.41

Impact from Bio/Renewable Diesel -- -- -2.20 -- -0.75 a -0.71

Impact from CNG Vehicles -- 15.08 -1.64 -- -0.67 -0.63 a

Impact from E85 Vehicles 0.23 -- -- -- -- --

Impact from In-State Bio-Refinery Truck and Rail Trips -- 0.52 5.19 0.03 0.11 0.10

Total Impact -3.88 -22.76 -4.67 -1.18 -2.02 -1.65

a Number is obtained by assuming 94.7% of diesel PM is PM2.5.

Emissions from biofuel facilities could co me from the facilities themselves and associated truck trips. Staff assumes the in state biofuel facilities would have no facility emissions, because such emissions are requi red to be offset as a condition of permitting. Staff assumes the trucks to transport biomass to and biofuel from the facilities to be the 2020 fleet average, in wh ich about 2/3 of the emissions come from the pre-2010 trucks. These emissions could be reduced if the air districts require the use of only 2010 or newer vehicles.

5. Analysis of the Potential Public Heath Risks

This section presents an analys is of the potential public health risks associated with the construction and operation of individua l and co-located biofuel facilities.

a. Health Risk Assessment for Biofuel Facilities

The staff conducted a health risk assessment (HRA) study to evaluate the health impacts associated with toxic air contaminan ts emitted from typical biofuel facilities

within California. The HRA focused on the potential cancer risk associated with diesel particulate matter (diesel PM) emissions caused by the biofuel facilities.

In order to estimate the potential cancer risk associated with a newly established biorefinery, ARB staff devel oped a prototype biofuel faci lity with 50 million gallon per year capacity. The protot ype facility was located on a 200 meter by 200 meter square

fence line. The emission source s from the facility include nat ural gas or biomass boilersVII-22 and turbines. Diesel PM emissions are caus ed by the heavy duty trucks that are used to transport feedstocks and finished biofuel. Staff estimates an average of about 110 daily truck trips would be made to transpor t feedstock in and finished fuel out for a facility.

For the most conservative anal ysis, staff assumed that one main truck route connects a major freeway and three prototype biofuel facilities. The tota l diesel PM emissions from three facilities, including truck movements and idling, are about 0.004 tons per year. Staff defines this portion of emissions as “ onsite”. The diesel PM emissions from the

main and three individual truck routes are also directly caused by the biofuel facilities, although these routes ar e outside of the facility boundar ies. The total diesel PM

emissions from these routes are about 0.12 tons per year. Staff defines this portion of

emissions as “offsite”.

The Health Risk Assessment (HRA) follows The Air Toxics Hot Spots Program Risk

Assessment Guidelines (OEHHA, 2003) published by t he California Office of Environmental Health Hazard Assessment (O EHHA). The HRA is based on the facility specific emission inventory and air dispersion modeling predictions.

As a result, the potential cancer risks leve ls associated with t he onsite diesel PM

emissions from the three collo cated prototype biofuel facilities are displayed by using isopleths, based on the 80 th percentile breathing rate and 70 year exposure duration for

residents. The area with the greatest impact has an estimat ed potential cancer risk of over 0.4 chances in a million, su rrounding the facility fence lines.

Staff also estimated the health impact asso ciated with the combined onsite and offsite

emissions of the three prototype biofuel facilities. T he area with the greatest impact has an estimated potential cancer risk of over 5 chances in a million. For more details regarding this modeling, see Appendix F10.

b. Ambient Ozone Impacts

National ambient ozone levels are regulated under the U.S. EPA nat ional ambient air quality standards (NAAQS). To ensure attainment of the national standards in each state within specified time frames, U.S. EPA requires states to submit State Implementation Plans (SIPs) t hat show how each air basin within a state plans to meet
the ozone NAAQS in the future. In t he more populated and polluted areas, U.S. EPA requires that photochemical computer models be used to demonstrate the effectiveness of future regulatory em ission controls on ambient ozone air quality.

The SIP air quality modeling process begins with replicating field measurements of hourly ozone concentrations for a period of days using a modeling system that is comprised of: (1) an EPA-approved photoc hemical model; (2) representative meteorological- and boundary condition i nputs; and (3) a base case emissions inventory. After the modeling system has demonstrated the ability to reasonably replicate measured concentrations (i.e . based on regulatory model performanceVII-23 guidelines), it can be used to assess potential SIP control strategies for attaining- or maintaining ambient ozone levels prescribed in the NAAQS. In general, this attainment demonstration step is accomplished through a process of applying control strategy

emission reductions to the baseline emission s inventory, then determining whether the corresponding model response at ozone fiel d monitoring locations would yield the needed percentage reduction in measured ozone at those same locations to achieve

attainment.

In theory, modeling systems us ed for SIP purposes can be used to assess air quality impacts for other regulatory purposes, such as the LCFS. However, due to the relatively small magnitude of emissions associated with LCFS (which are much less than the ~5% inventory delta that is an a ccepted minimum for grid-based modeling to avoid numerical artifacts), it is not practica l to expect the air quality model to reasonably predict the impact on ozone air quality.

c. Health Impacts

A substantial number of epidem iologic studies have found a strong association between exposure to ambient PM2.5 and a number of adverse health effects (CARB, 2002). For this report, ARB staff quant ified seven non-cancer health impacts associated with the change in exposure to PM2.5 emissions. This analysis shows that the statewide health impacts of the emissions associated with this regulation in year 2020 are approximately:

• 24 premature deaths (7 – 43, 95% CI)

• 3 hospital admissions due to respiratory causes (1 – 4, 95% CI)

• 5 hospital admissions due to cardio vascular causes (3 – 7, 95%CI)

• 340 cases of asthma-related and other lo wer respiratory sympt oms (130 – 530, 95% CI)

• 27 cases of acute bronchitis (0 – 57, 95% CI)

• 2,200 work loss days (1,900 – 2,600, 95% CI)

• 13,000 minor restricted activity days (11,000 – 15,000, 95% CI)

Details on the health impacts assessm ent are included in Appendix F11.

d. Contribution to Impacts Assessment Method

As part of ongoing AB 32 analysis, ARB staf f is developing a screening method for geographically representing em ission densities, air quality exposure metrics, and indicators of vulnerable populations, as an evaluation aide for already adversely impacted communities. This work is not ant icipated to be complete by the adoption of the LCFS. However, LCFS sta ff will continue to track this work and its applicability to
future LCFS evaluations and is committed to conducting an analysis as methods develop.

The screening method under development is based on an ARB contract in progress

with a team of academic researchers. The screening method uses geographicVII-24 information system (GIS) tools and data to c haracterize a suite of parameters across census tracts for a region. The method wil l utilize measures of ambient air quality and

emissions data derived from ARB’s various cr iteria and toxic air pollutant programs, in order to provide indicators of current emi ssions and exposures to air pollution. Various measures may include, for example, particulate matter (PM) exposures and PM mortality, ozone exposures and adverse health e ffects, diesel and other toxic exposures and health effects, traffic densit ies, and other indicators of proximity to hazards. The screening approach would then c ouple these environmental indicators with another assessment for identifying indicators of vu lnerable communities. Examples of these types of indicators include socio-economic census data such as poverty, ethnicity, housing and education, m easures of linguistic isolation or lack of participation in the voting process, and representation of sens itive populations and land use, such as schools, day care centers, and hospitals.

Once areas have been characterized using th is screening method, this information can be used in the future to help guide regul atory approaches that minimize community impacts, and to inform local decisions r egarding siting and permitting alternatives.

D. Other Environmental Impacts

1. Water

This section briefly describes the water quality issues, water use impacts, and current regulatory requirements for the production and use of various low carbon “fuel” candidates. Eight candidate “fuels” were evaluated based on feedstocks, conversion technology and scale of conversion, resulting in a combination of seventeen scenarios without regard to the extent to which any of t hose fuels would be a part of a LCFS mix.

Additional details can be found in Appendix F12.

a. Water Quality

Water quality issues include spills in tr ansport, unauthorized releases during production or storage, unlawful disposal to storm sewe rs or even to WWTP. Releases of ethanol, biodiesel, and butanol blends to groundwater potentially cont aminate drinking water with highly toxic petrochemicals (alkanes, BTEX and aliphatic com pounds). Ethanol and

biodiesel blends released to surface wate r may increase the likelihood and degree of fish kills compared to CARB gasoline and petroleum diesel because they deplete oxygen more rapidly.

Wastewater discharge volume from the produc tion facilities range from none to high as described below, but regardless of the volume these facilities will need permits. With the exception of wastewater fr om pyrolysis operations that may be highly toxic, most wastewater discharges from the proposed LCFS facilities are not expected to be "toxic" per se, but may be high in salinity and BOD and therefore prohibite d from discharge to

land or water. In some cases the lim itations on water discharge from production facilities may limit the development of the LCFS options in California.VII-25 b. Water Use

Water supply and consumption is a major issue in California and the State Water Board is responsible for surface water rights adjudications and the protection of their “beneficial uses”. Ownership of virtually every drop of su rface water in California has

been established. Surface water is neither free nor easily available. Even when water supplies can be acquired, the Water Boards ma y limit use if the removal of fresh water from a watershed basin adversely impacts t he environment, ecology, or other beneficial

uses.

Groundwater is not adjudicated statewide, but is limited in some areas. The Water Boards instead encourage the use of treated wastewater to produce fuels and irrigate feedstock crops where possible.

The production of fuels that consume very large quantities of water may be limited by available local supply and impac ts on beneficial uses, and further limited to specific supplies such as Waste Water Treatm ent Plant (WWTP) ocean discharges.

Table VII-14 below estimates the worse case water consumption scenario of the LCFS

mix.

Table VII-14 Water Consumption During Biofuel Production

Fuel # plants gWater/ gFuel Total Fuel

Production

(mmgal) Total Water (mmgal) a

Cellulosic EtOH 18 6 900 5400

Corn EtOH b 6 3.5 300 1050

Biodiesel 6 0.5 300 150

Total 6600

a Recycled water can be used for these processes

b The estimate for water use for corn ethanol does not include the impacts of irrigating the corn crop, as it seems unrealistic to assume that any corn for fuel would be planted in the state. For more information regarding the corn irrigation, please see Appendix F12.

Proponents of ethanol production fa cilities should consult with the Region Water Boards and the State Water Board, Division of Water Rights prior to committing to a location in

order to confirm that sufficient water is available and that the State and Regional Boards have no objections to the use of that water.

Groundwater supply is not adjudicated or regu lated by the State Water Board per se, but there is often competi ng local demand for groundwater.

Although recycled wastewater from a local wa stewater treatment plant (WWTP) may be available for irrigation and process water, proponents of ethanol plants in the CaliforniaVII-26 Central Valley and other water scarce areas ar e advised to confirm the availability of such water especially during periods of low surface water flow.

Ocean discharge from coastal WWTPs is a more reliable source of process water than WWTP discharge to land and the available vo lume easily exceeds the water supply requirements of the entire LCFS scenario ab ove by several orders of magnitude. In fact, WWTP discharge to the ocean in Calif ornia could supply enough water to support a 100% hydrogen economy. The available annual ocean discharge from WWTP can supply sufficient water ‘feedstock’ to produce enough hydrogen to supply over 1000% of California’s 2007 gasoline consumption on a Btu basis.

Thus the proposed LCFS candidate fluid fuel production schemes should not create a water consumption problem if sited near large coastal WWTP and use ocean discharge.

c. Regulatory Requirements

The Water Boards regulate water discharges fr om any fuel production facility including electric power plants, as well as, the st orage of any fuel in underground storage tanks UST. The Water Boards also protect and re gulate the “beneficial use” of California’s water including the impact on beneficial uses posed by water consumption in the production of energy.

Water related environmental and regulatory issues which fall entirely or in part within the authority of the State Water Board includ e water use, wastewater discharge from production facilities, toxicity of wastewater discharges, water quality related to ecology and other beneficial uses, permits required for production and storage of these fuels, and other regulatory limits on st orage of fuels which do not nece ssarily require a permit.

2. Aesthetics

Any impacts associated with aesthetics, siti ng and construction of facilities supporting

the LCFS would be assessed on a lo cation and project-specific basis.

3. Agricultural Resources

The LCFS result in significant impacts to agricultural resources. The conversion of prime farmland, unique farmland or farmland of statewide importance due to siting of new facilities and its associated supporting in frastructure, or conflict with an existing Williamson Act contract may be significant. Further, the loss of food and fiber for fuel may increase the cost of food if the acreage had formerly been us ed to grow food crops. With mitigation measures such as avoidanc e of siting facilities on prime farmland, supporting the California Farml and Conservancy Program, working cooperatively with the landowners, and ensuring conformity with ex isting Williamson Act contracts, impacts would be substantially mitigated. Existing stationary source locations are presently, and would continue to be, pr imarily designated as heavy industrial land uses.VII-27 While future facilities that support the LCFS may be sited on prime agricultural lands, this is unlikely as prime agricultural land is too valuable to be used to grow crops for biofuel production. If siting of facilities resu lts in the conversion of agricultural land, this would be subject to the CEQA process and appr oval by the city or county on a projectby-project basis. Siting of new stationary sources that convert biomass to fuel may convert prime farmland to other uses – the degree of which would be determined locally, and may conflict with an existing Willia mson Act contract. Facilities associated
with the LCFS measure would re quire local approval of conditional use permits, local air permits and possibly waste discharge require ments and would be subject to projectspecific compliance with CEQA. Such conversion could be mitigated via a financial throughput mechanism that supports the Calif ornia Department of Conservation’s California Farmland Conservancy Program. Av oidance of siting a facility on Williamson Act contracted land would alleviate potential im pacts associated with contract conflicts.

4. Biological Resources

The LCFS may adversely impact biological resources when new facilities are sited and constructed or existing facilities are expa nded. Project and site-specific analysis and coordination with federal, st ate and local agencies would be necessary to obtain pertinent information regarding sensitive spec ies within and surrounding a project area. Mitigation measures would be dependent upon t he site survey and analyses. Projectlevel compliance with CEQA, and if appropr iate, NEPA would be necessary. Until the proposed locations of the facilities are known, it is not possible to determine significance of impact.

When converting natural lands or farmlands to industrial or a utility-scale facility, such as an ethanol facility, any adverse impacts are required to be addressed and mitigated through CEQA. These impacts could be to terrestrial, riparian, or aquatic habitat, natural communities, or to any species iden tified as a candidate, sensitive or special status species in local or regional plans, policies or regul ations, or by the California Department of Fish and Game or U.S. Fish and Wildlife Service, or §404 of the Clean Water Act. A facility may interfere with the movement of any native resident or migratory fish or wildlife species with establ ished migratory corridors, or it may conflict with the provisions of an adopted Habitat Conservati on Plan or other approved local, regional or state habitat conservation plan.

In addition, the refining, marketing and dist ribution of petroleum fuels may adversely impact water quality due to leaks, spills, and wa stewater discharge. These water quality impacts can also impair important habitat, or interfere with critical life-cycles of native species. Any reduction in petroleum fuel use would reduce the opportunity for such

occurrences.

Some biofuels feedstocks have the potential to affect native species and biological resources, if feedstocks ar e produced though conversion of important habitat to agriculture or increase agricultural activities in species’ corridors.VII-28 Hydrogen production and use should have little or no affect on native species and biological resources outside of any potential e ffects from its energy and water source.

Specific information will be evaluated as t he measures and regulations are further developed; each regulation is required to have its own environmental evaluation. CEQA and possibly NEPA compliance would be requir ed for each facility with its projectspecific environmental evaluation. Figur e J-1 depicts known and proposed locations of

biofuel facilities.

5. Cultural Resources

Site-specific significant adverse impacts to cultural resources are not expected because the LCFS would not require destruction or alteration of any buildings or sites with prehistoric, historic, archeological, religious or ethnic significance. However, siting, grading, construction or expansion of facilitie s or buildings on lands that have not been surveyed for cultural significance, may result in adverse impacts to cultural resources if

inadvertent disturbance occurs at the time of construction.

Location and project-specific compliance wi th CEQA and/or NEPA would be required for individual projects. The l ead and implementing entit ies would be required to contact the appropriate agencies and department s to ensure that potentia l impacts to cultural

resources would be minimized or avoided. As ARB staff cannot speculate on the locations of these resources, it is not po ssible to ascertain the impacts on cultural

resources at this level.

6. Geology and Soils

At this time, implementation of the LCFS is not expected to expose people or structures to potential substantial adverse effects that involve risk of loss, injury or death from rupture of a known earthquak e fault, strong seismic ground shaking, seismic-related ground failure, landslides, or result in soil erosion or be located on a geologic unit or soils that is unstable. The LCFS may invo lve siting, grading, cons truction or expansion of facilities or buildings and may require disruption or over covering of soil during construction of facilities. There may be changes in topography or surface relief features, the erosion of beach s and, or a change in existing siltat ion rates. At this time, ARB cannot speculate on the significance, as any future facility siting, construction or expansion would be required to be evaluat ed on a project specific basis, and would need to comply with state and local require ments that would mitigate impacts.VII-29 7. Hazards and Hazardous Materials

Impacts from the hazardous wast e associated with the LCFS are not expected to be of major significance because the hazardous materials produced from biofuels production can generally be recycled, reprocessed, and reus ed. Additionally, facility operators will want to minimize generated wastes to mi nimize operational costs. They will be encouraged to create zero-waste facilities th rough sale of all products and co-products (ethanol, carbon dioxide, and wet distiller grai ns, etc.) for offsite use. Any hazardous waste generated (e.g., during a “process ups et”) that cannot be reused would require appropriate transport and disposal at a permitted facility.

Current state-of-the-art dry milling ethanol plants generate mini mal waste. Much of the material resulting from ethanol production is actually co-product that can be used for other purposes. For example, distillers gr ains (DGs), someti mes called mash, and syrup which is called evaporated thin stilla ge can be mixed and used for feed. Any waste materials (e.g., waste hydraulic oil) that is generated woul d require appropriate disposal if the materials cannot be reused or reprocessed.

The production of biodiesel uses sodium hydroxi de, hexane, sulfuric acid, and methanol. These will be present in any waste generated. Glycerol is a co-product that contains unused catalyst, salt, water, methanol, and soaps, and may be recycled as it
has economic value. Stearates are likely generated during the esterification process as

well. Hazardous waste materials that c annot be reused or reprocessed would require appropriate disposal.

Automobile manufacturers have indicated plans to incorporate lithium-ion battery technology for electricity storage in future PHEVs, BEVs and FCVs vehicles. It is expected that lithium automotiv e batteries will not be disposed of in landfills. This is due to the economic value of the lithium along with regulations prohibiting disposal. If the

lithium batteries obtained from vehicles ar e not placed in service for other energy storage or other power applicat ions, they will likely be recycled prior to the disposal of

the vehicle.

There are numerous alternativ e production methods being propo sed for hydrogen fuels. In the production of hydr ogen fuels there is minimal generated wast e. Hydrogen production is actually being pr oposed using various waste st reams. Other production methods use metals as catalysts. These metals can generally be recycled minimizing

residual waste.

The operation of biofuel fa cilities will involve the transportation of hazardous materials that could be released on roadways. These materials could include ethanol, biodiesel, unleaded gasolin e, sulfuric acid, aqueous ammonia, and urea. Although these materials are currently carried on r oadways, there will be an increase in the use and transportation of these materials. T here should be no impact to public or the environment through the routine transport, use, or disposal of hazardous materials. The biofuel facility operators will be expected eliminat e any significant hazard to the public orVII-30 the environment through reasonably fore seeable upset and accident conditions involving the release of hazardous materials into the environment.

Additional information on hazardous wa ste is presented in Appendix F13.

8. Mineral Resources

The LCFS is not expected to cause any adv erse impacts on mineral resources. The measures are not expected to deplete non -renewable mineral resources at an

accelerated rate or in a wasteful manner. There are no anticipated significant adverse impacts to mineral resources. It s hould be noted that an in creased ZEV population might have some effect on the lithium s upply. This is discussed in detail in Appendix F8.

9. Housing and Population

The LCFS is not expected to cause any adver se impacts to population or housing. The proposed measures are not expect ed to result in the creation of any industry that would significantly affect population growth, or direct ly or indirectly induce the construction of single- or multiple-family units. No si gnificant population relocation or growth inducement is expected.

10. Public Services

The LCFS is not expected to cause any adver se impacts to public services. Any need for an unforeseen public service would be subjec t to project-specific CEQA analysis or NEPA analysis by federal agencies.

11. Recreation

The LCFS is not expected to affect recreationa l opportunities in the St ate. To the extent that specific industries propose to construct faci lities in protected l ands to meet statutory or regulatory requirements, these projects would be required to go through NEPA and CEQA review prior to approval.

12. Solid Waste

Solid waste consists of residential wa stes (garbage and rubbish produced by households), construction wastes, commercia l and industrial wastes, home appliances and abandoned vehicles, and sludge residues (was te remaining at the end of sewage treatment process). CCR Title 14, Division 7, provides the State standards for the management of facilities that handle and /or di spose of solid waste. CCR Title 14, Division 7 is administered by the Califo rnia Integrated Waste Management Board (CIWMB) and the designated Local Enforcem ent Agency (LEA). The LEA for each county is the County Department of Environmental Health, and some cities have LEAs.VII-31 CCR Title 14, Division 7, establishes general standards to provided required levels of performance for facilities that handle and /or di spose of solid waste. Other Title 14 requirements include operational plans, clos ure plans, and post-closure monitoring and maintenance plans. Title 14 covers various solid waste facilities including but not limited to landfills, material recovery fac ilities (MRF), transfer stations, and composting

facilities.

Potential adverse waste impac ts are not expected to be significant. The proposed measures are not anticipated to result in a s ubstantial increase in the generation of solid waste or require that any permitted fac ility to expand its capacity to accommodate increased quantities of wa ste. For more deta ils, see Appendix F14.

13. Transportation and Traffic

The LCFS is not expected to cause signifi cant adverse impacts to transportation or traffic. Construction related impacts a ssociated with the LCFS are expected to be temporary. During construction of facilitie s, traffic impacts can be mitigated through ingress and egress controls to mitigate for congestions, and facility design should include appropriate traffic cont rols such as turn lanes, tra ffic lights, and reduced speed zones to ensure safety.

E. Sustainability

From an LCFS perspective, sust ainability implies that curr ent production and use of

biofuels to meet the LCFS mu st not adversely impact the abi lity to continue its use in the future. Sustainability encompasses a variety of environmental, economic, and social components. These include GHG em issions, conservation of high carbon stock land, conservation of high biodiversity land, air quality, water use, water quality, soil conservation, genetically modified organisms, labor rights, (working conditions, worker rights, child labor, forced labor), land ri ghts (displacement of indigenous people), environmental justice, food price and food security.

The U.S. and several other governments (U nited Kingdom, Germa ny and Netherlands) have either passed laws, proposed policies, or implemented policies for the sustainable production of biofuels. The proposed policie s by the United States, United Kingdom, Germany, and Netherlands have key similari ties: they address common environmental and social principles, they use existing st andards to certify sustainability, and they intend to tighten sustainability policy over ti me. Additionally, various other government organizations have committed to developing lo w carbon fuel standards. These include the Northeastern/Midwestern states, as well as the Canadian provinces British

Columbia and Ontario.

Supra-national (European Unio n) and international organizations (United Nations Environment Prohramme(79) , Roundtable on Sust ainable Biofuels(80), Food and Agriculture Organization of the United Na tions(81)) are also addressing sustainable biofuels production. These organizations are in the process of developing sustainabilityVII-32 criteria, as well as certification standar ds, that could be used to evaluate the sustainability of biomass production. T he Roundtable on Sustain able Biomass (RSB) has released its draft ‘generic ’ standard (‘Version Zero’) that can be applied to any

feedstock.

The Energy Commission is developing sustainability goals (and their associated sustainability characteristics) as part of it s role in administering AB 118-funded projects. The sustainability characteristics will form the basis of a set of evaluation criteria that will be used to assess how well each propos ed project can meet the sustainability goals. ARB and the Energy Commission ar e working together to ensure that sustainability principles developed fo r the LCFS and AB118 are consistent.

Sustainability, as it pertains to the LCFS, is complex. Currently, there is not enough information available to develop relevant and detailed sustainability strategy or standards. The most likely method for establ ishing sustainability in the production of biofuels on a global scale is the adoption of certification standards. Such standards will have to address universally accepted sust ainability components, have well developed criteria and criteria indicators, and be verifiabl e by certified third parties (which will in turn have to be certified by accrediting bo dies). The components of a universally accepted certification standard might include but are not limited to:

• Well defined sustainability criteria and thei r associated indicators on a plantation level;

• Methods for assessing the cumulative im pacts of many “sustainable” operations on a regional or global level;

• Certification process to establish whether t he standard has been met; this

i ncludes defining the auditor’s qualificat ions & training, the audit process, consultation, reporting of the info rmation, mechanism for dealing with complaints;

• Accreditation requirements: an accreditation body accredits certification bodies (certifiers) based on systems, records, and/or processes. ISO 17011 provides the general requirement for bodies provid ing assessment and accreditation of conformity assessment bodies. The IS O 17021 is more specific for bodies providing audit and certificat ion of management systems. ISO 65 is used in case of product certification. The accredi tation body may demonstrate competencies either by adhering to the appropriate In ternational Accreditation Forum (IAF) Multilateral Recognition Arrangement (MLA) or thr ough membership of the

International Social and Environment al Accreditation and Labeling Alliance (ISEAL); and

• Chain of custody rules.

The ARB will work together with other St ate agencies, national and international organizations, non-government or ganizations, and other intere sted parties to develop an appropriate sustainability strategy. By De cember 2009, ARB staff intends to develop a strategic plan for addressing overall sust ainability provisions for the LCFS, forVII-33 consideration by the Board at its first formal public revi ew scheduled for the end of

2011.

F. Multimedia Evaluation

Senate Bill 529, enacted in 1999 and set forth in Health and Safety Code (H&S) section 43830.8 (“the statute”), 59 generally prohibits ARB fr om adopting a regulation establishing a specification for motor vehicl e fuel unless the regulation is subject to a multimedia evaluation by the California Environmental Poli cy Council (CEPC). (Stats. 1999, ch. 813; SB 529, Bowen.) Pursuant to Public Resources Code section 71017(b),

the CEPC was established as a seven-mem ber body comprised of the Secretary for Environmental Protection; the Chairpersons of the ARB, State Water Resources Control Board, and Integrated Waste Ma nagement Board; and the Direc tors of the Office of

Environment Health Hazard Assessment, the Department of Toxic Substances Control, and the Department of Pestic ide Regulation. Key co mponents of the evaluation process are the identification and evaluation of significant adverse impacts on public

health or the environment and the use of best available scientific data.

“Multimedia evaluation” means the identification and eval uation of any significant adverse impact on public health or the environm ent, including air, water, or soil, that may result from the production, use, or disposal of the mo tor vehicle fuel that may be

used to meet the state board’s motor vehicl e fuel specifications. H&S §43830.8(b).

Notwithstanding the general pr ohibition noted above, the stat ute provides that ARB may adopt a regulation establishing a specificat ion for motor vehicle fuel without the proposed regulation being subject to a multim edia evaluation if the CEPC, following an initial evaluation of the propos ed regulation, conclusively det ermines that the regulation will not have any significant adverse impact on public health or the environment. This raises three issues, all of which ar e addressed in this Staff Report:

(1) whether the proposed LCFS regulation establishes a motor-vehicle fuel specification in the first place that would require a multimedia evaluation;

(2) whether the proposal is expect ed to have any significant adverse environmental impacts on public heal th or the environment; and

(3) whether the multimedia evaluat ion requirement applies to subsequent rulemakings to implement the LCFS regulation, even if the multimedia evaluation requirement does not apply to the LCFS regulation itself.

As discussed below, ARB staff has determined t hat the proposal itse lf neither triggers the multimedia evaluation requi rement nor is it expected to have significant adverse impacts on public health or the environment. But the multimedia ev aluation requirement may apply to subsequent rulemakings to impl ement the LCFS regulation to the extent such rulemakings establish motor-vehicle fuel specifications.

1 All statutory references in this chapter are to H&S §43830.8 unless otherwise noted.VII-34 1. Does the Proposal Establish a Motor-Vehicle Fuel Specification?

With regard to the first i ssue, Chapter V (Summary of the Proposed Regulation), Section J (Requirements for Mult imedia Evaluation) contains the staff’s legal rationale for its determination that the proposal does not trigger the multimedia evaluation requirement in the first place. As noted in that discussion, t he proposed regulatory action does not establish any motor-vehicle fuel specifications. This is because the proposal contains no requirements that dict ate the exact composition of compliant transportation fuels under the LCFS regulation. By its terms, t he proposed regulation does not in any way amend, repeal, modify or otherwise change in any way any existing
State or federal fuels regulations or any othe r applicable regulations. 60 Because the proposal does not establish a motor-vehicle f uel specification in the first place, the multimedia evaluation requirement under H&S 43830.8 is not triggered.

To illustrate, the proposal does not establis h any specifications for CaRFG3 gasoline and will not require a gasoline ingredient to be added or removed beyond what is already used to produce gasoline for sale in Ca lifornia. Similarly, the proposal does not change any specifications for CARB diesel and will not require a diesel ingredient to be added or removed beyond what is already used to produce diesel for sale in California. Further, the proposal does not change or adopt any specifications for natural gas, liquefied petroleum gas, biodiesel, renewable dies el, hydrogen, or electr icity. Therefore, as discussed more extensively in Chapter V, staff believes that the proposed rulemaking is not subject to the requi rement for a multimedia evaluation.

2. Is the Proposal Expected to Have Significant Adverse Environmental and Public Health Impacts?

While we believe the proposal is not form ally subject to the multimedia evaluation requirement, staff believes there is merit in conducting a functional equivalent of a multimedia evaluation, as not ed in Chapter V. Such a functional equivalent would evaluate the expected environmental and public health impacts from the proposal to the

extent feasible and based on the best available data.

To this end, staff believes the environmental impacts analysis in this Chapter VII amply serves the role of a functional equivalent analysis. Thus, with regard to the second issue noted above, the staff has determined t hat the proposal will not have significant adverse environmental impacts on public heal th or the environment. This determination is based on our environmental impacts analysis contained in this Chapter VII.

3. Does the Multimedia Evaluation Requirement Apply to Post-LCFS Rulemakings?

We should note that subsequent rulemaking s establishing specifications for motor vehicle fuels will be subject to H&S §43830.8. Future rulemakings planned by ARB that

60 See section 95480.1(e) of the proposed LCFS regulation.VII-35 may establish such motor-vehicle fuel specifications include proposals to adopt new specifications for biodiesel, compressed nat ural gas, E85, and biobutanol. To the extent such future rulemakings establish sp ecifications for motor vehicle fuels, the provisions of H&S sect ion 43830.8 would apply.

G. Environmental Justice

As the Scoping Plan is implemented and s pecific measures are developed, ARB and other implementing agencies w ill also conduct further analyses, including cumulative and multi-media impacts. ARB must design equitable regulations that:

• Encourage early action;

• Do not disproportionately impact lo w-income and minority communities;

• Ensure that AB 32 programs complement and do not interfere with the attainment and maintenance of ambient air quality standards;

• Consider overall societal benefits (such as diversification of energy resources);

• Minimize the administrative burden; and

• Minimize the potential for leakage.

AB 32 requires that, to the ext ent feasible and in furtheranc e of achieving the statewide greenhouse gas emission limit, ARB must consider the potential for direct, indirect and cumulative emission impacts from mark et-based compliance mechanisms, including localized impacts in communities that are already adversely impacted by air pollution, design the program to prev ent any increase in emissi ons, and maximize additional

environmental and economic benefit s prior to the inclusion of market-based compliance mechanisms in the regulations. As ARB fu rther develops its approach for consideration of these issues in future rulemakings , and updates needed analytical tools and data sets, we will consult with outside experts and the Environmental Justice Advisory
Committee.

ARB already conducts robust environmental and environmental justice assessments of our regulatory actions. Many of the requirements in AB 32 overlap with ARB’s

traditional evaluations. In adopting regulations to implement the measures recommended in the Scoping Plan, or including in the regulations the use of marketbased compliance, mechanisms to comply with the regulations, ARB will ensure that the measures have undergone the af orementioned screenings and meet the requirements established in HSC §38562 (b) (1-9) and §38570 (b) (1-3).

The ARB is committed to making the achievem ent of environmental justice an integral part of the LCFS. As such, staff seeks to develop tools to ensure that the proposed regulation does not dispropor tionately impact low-income and minority communities,

does not interfere with the atta inment and maintenance of am bient air quality standards,

and considers overall societal be nefits (such as diversificati on of energy resources). As part of ongoing AB 32 analysis, ARB staff is developing a screening method for geographically representing em ission densities, air quality exposure metrics, andVII-36 indicators of vulnerable populations, as an evaluation aide for already adversely impacted communities.

To provide additional information for local districts and to inform the CEQA process, ARB staff is committed to developing a guid ance document to provide information on the best practices available to reduce emissions from these types of facilities. This effort will commence immediately; ARB staff plans to have a draft available by the end

of December 2009.VIII-1 

### VIII. Economic Impacts

In this chapter, staff presents the estima ted costs and economic impacts associated with the implementation of the proposed regulation. The economic analysis includes estimated costs for fuel providers of pot ential compliance pathways, an analysis of the cost-effectiveness of the proposed regulat ion, and the costs and associated economic impacts on businesses, consumers, and gov ernment agencies. Additional cost information is included in Appendix G.

A. Summary of the Economic Impacts

For the economic analysis of the LCFS, staf f estimated the costs of producing the petroleum-based fuels—gasoline and diesel— and the costs of producing the lowercarbon-intensity transportation fuels that could be used in combination with petroleum

fuels to meet the LCFS. St aff applied these costs to po ssible compliance scenarios for both diesel fuel and gasoline. Each of these possible scenarios includes an assumed

mix of fuels that satisfies the LCFS reduction targets.

Staff estimated that the displacement of petroleum-based fuels with lower-carbonintensity fuels will result in an overall savings in the State, as much as $11 billion from 2010 -2020. These savings may be realized by the biofuel producers as profit, or some of the savings may be passed on to the cons umers. Should the savings be entirely passed on to consumers, it would represent le ss than three percent of the total cost of a typical gallon of transporta tion fuel ($0 - $0.08/gal).

Staff understands that the economic analysis of the LCFS is gr eatly affected by future oil prices and the actual production co sts and timing of lower-carbon-intensity alternative fuels. Economic factors, such as tight supplies of lower-carbon intensity fuels or a lengthy economic downturn k eeping crude demand and hence prices down, could result in overall net costs, not savings, for the LCFS.

Staff determined that approximat ely 25 new biorefineries coul d be built in California based on an assessment of potential feedsto cks. Biofuel producers are expected to eventually recoup their costs through the sale of lower-car bon-intensity fuels, while consumers should see no significant changes in fuel prices to some savings. In addition to liquid fuels, such as ethanol and bi odiesel, other lower carbon-intensity fuels, including electricity, hydrogen, and compre ssed natural gas (CNG) may be used to meet the requirem ents of the LCFS.

The proposed regulatory action would not affect small businesses because: (1) most, if not all, regulated parties are expected to be relatively large businesses, and (2) small businesses (generally the fueling stati on owners and operators) would presumably invest in equipment that dispenses LCFS-c ompliant fuel with the expectation that the costs of such an investment would be recouped through sales of such fuels.VIII-2 Staff conducted the economic analyses cons idering all costs of production and

distribution of alternative tr ansportation fuels, which, as mentioned above, resulted in overall savings to the State. Staff then recognized that the federal Renewable Fuel Standard (RFS2) will bring sign ificant quantities of ethanol to California, and that the infrastructure required to meet the mandates of RFS2 is essentially the same infrastructure necessary to meet the potential ethanol require ments of the LCFS; therefore, nearly all of the ethanol-related infrastructure co sts can be attributed to RFS2.

RFS2 and the proposed LCFS regulation will result in a shift of capital from the petroleum sector to the agricul tural, chemical, electricity, and natural gas sectors. This redistribution of capital among these sectors is essential to the success of the LCFS

and RFS2. The diversification of California’s transportation fuels, which requires a shift of capital from the petroleum sector, is consistent with well-e stablished national and State policies.

The regulation would create cost s to the State in the form of lost transportation-fuel taxes, including excise taxes and sales ta x. Although there would be no estimated fiscal impact for the first th ree years of the pr oposed regulation, staff estimates the potential loss of annual state tax revenue to be $80 million to $370 million in 2020—the year of greatest impact—depending on comp liance path(s) chosen. For local government, the impact of sales tax on tr ansportation fuels from implementing the potential compliance scenarios co uld either create revenue or result in a revenue loss, depending on the complianc e path(s) chosen. The impacts to local sales taxes would be location specific. Although t here would be no fiscal impact fo r the first three years of the proposed regulation, staff estimates a po tential range of impa cts in annual local sales tax revenue of -$51 million to +$2 million from 2013 – 2020.

B. Legal Requirements

This section explains the l egal requirements that must be satisfied in analyzing the economic impacts of the regulation.

Section 11346.3 of the Government Code requires State agencies to assess the potential for adverse economic impacts on California business enterprises and individuals when proposing to adopt or am end any administrative regulation. The

assessment shall include a c onsideration of the impact of the proposed regulation on California jobs, business expansion, eliminati on or creation, and the ability of California businesses to compete with businesses in other states.

Also, State agencies are required to estimate t he cost or savings to any State or local agency and school district in accordance with instructions adopted by the Department of Finance (DOF). The estimate shall include any non-discretionary cost or savings to local agencies and the cost or savings in federal fundi ng to the State.

Finally, Health and Safety Code section 57005 requires the Air Resource Board (ARB or Board) to perform an economic impact analysis of submitted alternatives to a proposedVIII-3 regulation before adopting any ma jor regulation. A major regulation is defined as a regulation that will have a potential cost to Ca lifornia business enterprises in an amount exceeding ten million dollars in any single year.

The following is a description of the methodology used to estimate costs as well as ARB staff’s analysis of the economic impacts on California businesses, consumers, and government agencies.

C. Methodology for Estimating Costs

This section provides the general methodolog y and assumptions used to estimate the

costs associated with t he proposed regulation.

The proposed regulation requires producers, importers, and some other providers of transportation fuels to meet an overall carbon intensity (CI) for the fuel mix they supply

to California. The standards are set on an annual basis and become more stringent from 2011 to 2020, ultimately resulting in an average 10 percent reduction in the carbon intensity of most transportation fuel sold in California by 2020. T he proposal does not specify which combination of transportation fuels the regulated parties must provide to comply with the standards, and it does not limit the CI of any particular fuel. However, to meet the LCFS, the fuel mix will need to include alternat ive fuels that have lower CI

than traditional fuels.

For the economic analysis of the LCFS, staf f estimated the costs of producing the petroleum-based fuels—gasoline and diesel— and the costs of producing the lower carbon-intensity (lower-CI) transportation f uels that could be used in combination with petroleum fuels to meet the LCFS. The cost s for the lower-CI fuels included the capital costs for building new fuel production facilitie s, the operating costs associated with the facilities, and the distribution co sts of the products. In addition al to liquid fuels, such as ethanol and biodiesel, lower-CI fuels that were assessed included electricity, hydrogen, and compressed natural gas (CNG).

Once staff estimated the over all production and distribution co sts of the lower-CI fuels, staff applied them to eight compliance scenarios—illustrative examples of possible compliance pathways. They include five scenar ios for gasoline and its substitute fuels,

and three for diesel fuel and its substitute fu els. Each of these scenarios includes an

assumed mix of lower-CI fuels that satisfies the LCFS reduction targets for the overall fuel mix. Chapter VI discusses the scenarios in more detail.

Staff then evaluated the savings that would occur in each scenario due to the avoided cost of buying the traditional fuels that were displaced by the lower-CI transportation fuels. Next, for each of the compliance sc enarios, staff estimat ed the net cost and/or savings, and calculated the cost effectivene ss, defined as net LCFS regulation costs (or savings), in dollars, divided by the carbon dioxide equivalent emissions reduced, in metric tons. Finally, staff estimated how t he fuel procurement costs or savings incurred by fuel providers under the pr oposed LCFS might be reflected in fuel prices and thereby affect businesses, consumer s, and government agencies.VIII-4 1. Gasoline and Diesel Costs

To perform a cost analysis of the proposed regul ation, staff first pr ojected the cost of producing and distributing (i.e., getting the fuel to the station) the traditional petroleum-based fuels that would be displace d by alternative fuels needed to comply

with the LCFS. Estimates of the future co st of producing gasoli ne and diesel are highly dependant on the future price of crude oil.

For this analysis, staff used forecasts of pric es for crude, gasoline, and diesel that are included in the Energy Commission’s docum ent “Transportation Energy Forecasts for the 2007 Integrated Energy Policy Report (I EPR)(82).” To be consistent with the assumptions used in preparing the AB 32 Scoping Plan, approved by the Board in December 2008, staff used the “high case” va lues in the report. To estimate the production and distribution cost of gasoline and diesel fuels, staff subtracted the appropriate federal, state, and local taxes from the retail prices.

Table VIII-1 presents the referenced esti mates for crude prices and ARB staff’s estimates of the cost of producing and dist ributing gasoline and diesel, based on those crude prices. The crude prices forecast s were based on the Energy Information Administration’s (EIA) crude price estimates at the time. Rec ently, EIA published an updated forecast of crude prices: for the period of 2010 – 2020, EIA estimates crude prices at $78 - $116/bbl for their reference ca se, which is their mid-range estimate of future prices. This is much higher than the $66 - $88/bbl “high ca se” estimate included in EIA’s previous estimate.

Currently, Energy Commission st aff is estimating crude pric es and associated California retail fuel prices for their 2009 IEPR, taking in to account this recent EIA forecast. For the purpose of the LCFS economic analysis, staff used the 2007 IEPR estimates to be consistent with the AB 32 Scoping Plan. St aff recognizes that the higher, more recent crude price estimates would enhance the cost effectivene ss of the proposed LCFS regulation.VIII-5 Table VIII-1
Estimated Crude Prices and As sociated Costs to Produce and Distribute Gasoline and Diesel (2007 dollars)

Year Crude Price ($/bbl) Cost of Gasoline Production and

Distribution 1 ($/gal) Cost of Diesel Production

and Distribution 1 ($/gal)

2010 $66 $2.42 $2.48 2011 $68 $2.46 $2.53 2012 $70 $2.51 $2.57 2013 $73 $2.57 $2.63 2014 $76 $2.65 $2.71 2015 $79 $2.70 $2.77 2016 $81 $2.76 $2.82 2017 $83 $2.80 $2.86 2018 $84 $2.84 $2.90 2019 $86 $2.88 $2.95 2020 $88 $2.92 $2.99
1 Cost excludes federal, state, and local taxes.

2. Lower-CI Fuel Production and Distribution Costs

a. General Discussion

The next step in the economic analysis of the LCFS was to estimate the production and

distribution cost of the lowe r-CI fuels, including liquid bi ofuels (ethanol and biodiesel) and other lower-CI fuels (hydrogen, electricit y and CNG) that will displace the traditional petroleum-based fuels.

Lower-CI Liquid Biofuels:

The production and distribution costs for the lo wer-CI liquid biofuels included the capital costs for building the fuel-manufacturing fac ility, the operating or production costs to produce the specific fuel, the costs for purch asing the feedstock material for the fuel, and the costs for storing, trans porting, and distributing the fuel . Staff adjusted the costs, where applicable, with a co-product credit if the fuel-production process had other economic benefits, such as creating material for other products or providing steam for electrical generation at the facility.

While some of these liquid biofuels ar e commercially available—corn ethanol, sugarcane ethanol, biodiesel from crops, ani mal fats, and grease—other lower-CI liquid fuels are in an earlier stage of development. Si gnificant examples of this are cellulosic ethanol and hydrocarbons fr om algae and green wastes.

To estimate the overall production cost for these biofuels, staff relied on documentation from several sources, including: the National Renewable Energy Laboratory (NREL); the United States Department of Agriculture (USDA); the An tares Group (Antares); IowaVIII-6 State University; Kansas State University; Biomass and Bioenergy Journal; Bioresource Technology Journal; and Sparks Companies Inc. Staff discusses the specific utilization of these resources within the cost subcategor ies below. In order to compare the lowerCI fuel costs to traditional fuel costs, staff converted cost estimates of ethanol biofuels to gallons of gasoline equivalent (gge), which took into account the lower energy content of ethanol as compar ed to gasoline. The energy content of biodiesel was assumed to be approximately equal to that of traditional diesel, so staff made no adjustments to those cost estimates. (See Appendix G for gge conversion calculations.)

Other Lower-CI Fuels:

In addition to the liquid biofuels, staff esti mated the cost of producing and distributing

three other lower-CI fuels: hydrogen, electricity, and CNG. As with the liquid biofuels,

staff converted these costs to gge. In addition, staff adjust ed those values to recognize the difference in energy efficiency of the cars in which these fuels are used. This was done by dividing the gge-adjusted cost num bers by the applicable Energy Economy Ratio (EER), which compares the energy econom y of an alternative fuel vehicle to a conventional gasoline or diesel vehicle.

For example, an electricity cost of $0.09/ kilowatt-hour (kW-hr) converts to $2.89/gge on an energy content basis. The EER for an electric vehicle is estimated to be 3.0 (i.e., an

electric vehicle is three times more effici ent than a conventional ga soline-fueled vehicle in converting the energy in the fuel into energy used to power the vehicle). The gge value would then be adjusted by dividing $2.89 by three— $0.96/gge, EER adjusted.

Electricity costs were based on electricity ta riffs from Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and t he Los Angeles Department of Water and Power (LADWP). Hydrogen costs were based on data provided by the Committee on

Assessment of Resource Needs for Fuel Cell and Hydrogen Technologies. CNG cost estimates were based on available data pr ovided by the Energy Commission in the 2007 State Alternative Fuels Plan(1), which was required by AB 1007 (Pavley, 2005).

b. Capital Costs

Staff estimated the capital costs of co mmercial biofuel produc tion plants based on available information. For some biofuels, staff relied on capital cost estimates conducted by NREL, Antares(18), T ijmensen(83), Haas(84), Zhang(85) and Gallagher(86). For example, NREL, Ti jmensen(83), and Haas(84) , using the ASPEN Plus model, conceptually designed lignocellu losic, FAME, and Fischer-Tropsch (F-T) biodiesel facilities. ASPEN Plus is a pr ocess modeling program tool for conceptual design, optimization, and performance monito ring for specialty chemicals, metals, minerals, and coal power industries. T he NREL studies also engaged engineering firms that have expertise in this subject matter.

Also, the NREL Processing Engineering Te am developed a database of primary information on the equipment needed for such facilities. This database containsVIII-7 information on anticipated costs, reference y ear, scaling factor, design information, and back-up cost referencing. Table VIII-2 pres ents an example of some of the specific pieces of equipment and the estimated costs in the NREL ASPEN Plus database needed for a biofuel plant producing 25 million gallons per year (MGY).

Table VIII-2 Estimated Costs for Some Biofuel Plant Equipment from NREL Using ASPEN-Plus Database (NREL, 1999)

Equipment Cost
Hopper Feeder $41,700

Pretreatment Feeder $122,000

Beer Column Reflux Drum $22,400

Aerobic Digester $600,000

Sulfuric Acid Storage Tank $54,400

Cooling Tower System $1,630,000

For dry-mill corn ethanol, Gallagher(86) used a mathematical model to estimate the capital costs. The wet-mill corn ethanol c apital cost is based on data from Whims(87), while the fatty acid to hydrocarbon (FA HC) biodiesel is based on current and planned facilities for ConocoPhillips, Neste Oil, and Pe trobras. (See Chapter III for more details on these facilities.)

When estimating the capital cost of various size s of biofuel production facilities, the size of the individual equipment c an be scaled up or down usi ng published scaling factors. These scaling factors take into account economy of scale, which asserts that an increase in processing capacit y can be achieved with a smaller percentage increase in capital cost.

The economy of scale is expressed as follows(88):

New Capital Cost = Original Capital Cost x (New Capacity Size/Old Capacity size) scaling factor

As an example, if a 25 MGY facility cost s $174 million to build, a 50 MGY plant would cost $240 million to build, applying an economy-of -scale factor of 0. 6. Scaling factors typically range from 0.6 to 0.8. For our analyses, staff used a scaling factor of 0.6,

which is consistent with the st udies that staff analyzed.

To estimate the annual capital recovery cost, staff used a capital recovery factor of 14.90 percent, based on an eight percent real discount rate per year with a capital recovery period of 10 years. The economic analysis for this regulation evaluates the private compliance costs that companies would face, so these assumptions are

intended to reflect the risk in investing in new biorefin ery technologies—the “cost of financing.” The economic anal ysis for the AB 32 Scoping Plan was designed to reflectVIII-8 societal costs, and used a five percent real discount rate and the expected life of the equipment, which was typically assumed to be 20 years. Sensitivity analyses for

several of the scenarios have also been conduc ted using a five percent and ten percent real discount rate. (See Section E.)

The associated annualized capital recovery co st can be determined according to the following equation:

Capital Recovery Cost ($/Gal) = (Capital Cost x Capital Recovery Factor)/Plant Capacity

For the 25 MGY biofuel facility above, its c apital cost of $174 million will result in an annual capital recovery of $26 million (eight percent interest for 10 years). For the 25 million gallons per year, that translate s into $1.04/gal of fuel produced.

The estimated capital costs for ethanol varies between $0.31/gge and $1.37/gge. The corn dry-mill facility has the least esti mated capital costs because the process is straightforward and highly commercial; the wood chips lignocellulosic ethanol facility has the highest estimated capital cost s due to feedstock-handling and multistep processing. Because there are no lignocellulo sic ethanol facilities in operation, the

estimated costs for these facilities in t he documents on which ARB relied (e.g., NREL reports) include some level of uncertainty.

For biodiesel, the range of estimated capita l costs per gallon varies between $0.09/gal and $2.43/gal. The estimated capital cost is l east for a fatty acid methyl esters (FAME) biodiesel plant because the process operates at relatively lower temperatures and pressures with high conversion rates and low reaction times. Conversely, the highest estimated capital cost is for the F-T diesel plant due to multistep processing, including gasification of solid feedstocks and catalytic conversion to hydrocarbons. In general, the more processing that is necessary to produce the biofuel, the higher the capital costs. (See Chapter III for a di scussion on the biofuel technologies.)

Staff also included the cost of best availabl e control technology (BACT) to reduce air

emissions from these biorefi neries. Staff estimated the cost for BACT at approximately $2 million per plant. Using a capital recovery fa ctor of 14.90 percent, this translates to $0.006/gal for a 50 MGY plant. (See Chapte r VII for a more detailed discussion.)

c. Production Costs

The costs to produce the biofuels include fixe d and variable costs. Fixed costs include annual operating and maintenance labor, taxes, and insurance, while variable costs include utilities, non-feedstock raw materials (sulfuric acid, lime, nutrients, etc.), and waste disposal. To estimate the fixed and va riable costs for the va rious biofuels, staff analyzed studies that utilized ASPEN Plus, a United States Department of Agriculture ethanol cost-of-production survey(89) , and a compilation of studies.

For ethanol, the production cost of lignocellulo sic ethanol from corn stover is higher than wood chips because of assumed higher labor expense. For biodiesel, the range ofVIII-9 estimated production costs per gallon vari es between $0.27/gal and $1.66/gal. The estimated production cost is least for a fatty acid to hydrocarbon (FAHC) biodiesel plant because the hydrotreating process result s in a product that needs little further processing. Conversely, the highest estima ted production cost is for the F-T diesel plant due to the multistep processing described above.

Based on an Aspen Plus analyses conducted by NREL(90) and Haas(84), energy input accounts for 15 to 20 percent of the total production cost. These fuel-related costs include gasoline used as denaturant for ethanol, diesel, and electricity. For the LCFS economic analysis, staff raised the production costs of the liquid biofuels by 20 percent in the scenarios when higher crud e prices are assumed. For example, if crude prices were to double, staff would raise the pr oduction costs of the liquid biofuels by 20 percent.

For CNG, staff used Energy Commission reta il price estimates for 2010-2020(91), subtracting a 10 percent profit margin to estimate production costs. Staff did not adjust electricity costs.

d. Feedstock Costs

The feedstock cost per gallon of ethanol is calculated as follows:

Feedstock Cost per Gallon = Price of Feedstock/ Ethanol Yield of Feedstock

For example, if the cost of corn is $4.00 per bushel ( approximately the average 2009 future prices listed in February 2008) and the dry-mill ethanol yield is 2.72 gallons of ethanol per bushel, then the feedstock cost is $1.47/gal, or $2.18/gge. This cost does not take into account the co-product credit which is discussed in the next section.

The estimated feedstock costs for ethanol vary between $0.00/gge and $2.13/gge. Staff estimated the cost of municipal solid waste (MSW) as a feedstock at zero. (MSW here refers to the grass, wood, and paper por tion of municipal soli d waste.) Whereas some reports that staff reviewed asserted a negative cost for MSW because of avoided tipping fees at the landfills, most of California’s green wast e does not go to landfills. AB 939(92) required a 50 percent reduction of ma terial being sent to California landfills by 2000, which resulted in segregation of paper and plant materials. Typically the plant material is used to make compost, and the paper is recycled. Staff assumes these

materials can be delivered to biorefineries fo r the same cost as delivering them to recycling or compost facilities, hence the cost -neutral feedstock price. Conversely, the highest estimated feedstock cost is for wet-mill corn ethanol due to the higher commodity prices of corn and a lesser yield than with the dry-mill process.

Similarly, for biodiesel, the range of esti mated feedstock costs varies between $0.68/gal and $2.62/gal. The feedstock cost is least for F-T diesel since relatively inexpensive wood chips are used as feedstock. The highes t estimated biodiesel feedstock cost is for an FAME process using soybean oil.VIII-10 As with the production costs at the biorefineries, the cost of crude oil also affects the cost of biorefinery feedstocks. Acco rding to “Ethanol Production Using Corn, Switchgrass, and Wood; Biodiesel Produc tion Using Soybean and Sunflower” (93), 20 to 35 percent of the cost of growing corn or soybeans is related to fuel costs. These costs include diesel, gasoline, fertilizer, el ectricity, and transport costs. Labor, most nonpetroleum chemicals, and capital recovery for machinery are fixed production costs not affected by crude prices.

To be conservative, staff raised the feedstock costs of the liquid bi ofuels by 35 percent in the LCSF economic analysis when higher crude prices are assumed. For example, if crude prices were to double, staff would rais e the feedstock costs of the liquid biofuels by 35 percent.

The cost of transporting a feedstock to a bior efinery is included in the feedstock prices. Staff assumed a feedstock is transported within 50 miles of a biorefinery.

In addition to the liquid biofuels, staff eval uated the feedstock costs for other non-liquid lower-CI fuels that are expected to be used in greater quantities to meet the LCFS. Hydrogen may be produced in a variety of wa ys, currently the most common by steammethane reforming (SMR). The methane can be produced from natural gas or biogas from landfills. Furthermore, hydrogen and methane for SMR can be co-produced from pyrolysis or gasification of solid waste, such as biomass or coal. Hydrolysis is another technology for producing hydrogen. Although a net energy consumer, hydrolysis can be powered by renewable sources of energy, such as wind and solar. Staff estimated the feedstock cost of hydrogen production, based on steam-methane reforming of natural gas, to be $0.70/gge, EER adjusted 61

.

According to the Energy Commission, the reta il price of CNG is estimated to follow a range of $1.81 to $2.04/gge over the 2010 – 2020 compliance periods. Staff assumed a 10 percent profit margin; ther efore, staff calculated the av erage cost of CNG at $1.81 to $2.04/gge, EER adjusted. These values were converted to diesel gallon equivalent (DGE) in the diesel scenario calculations.

Table VIII-3 summarizes the commodity prices and yields that staff used to determine the per-gallon feedstock cost s for the liquid alternativ e transportation fuels.

61 Senate Bill 1505 (Lowenthal, 2006) directed the ARB to develop a regulation to set environmental standards for hydrogen fuel produced/dispensed for tr ansportation use in California; therefore, hydrogen production cost estimates may be impacted by future regulatory requirements.VIII-11 Table VIII-3 Commodity Prices (2007 Dollars) and Yields

Commodity Price Reference Yield Reference

Corn (dry mill) $3.77/bu CN NMoney, 2008(94) 2.72 gal/bu CA-GREET, 2009(47)

Corn (wet mill) $3.77/bu CNNMoney, 2008(94) 2.62 gal/bu CA-GREET, 2009(47)

Corn Stover $38/ton LafayetteOnline, 2008(95) 80.6 gal/ton Antares(b), 2008(18)

Wood Chips (Cellulosic) $29/ton NREL, 2008(96) 90.2 gal/ton Antares(b), 2008(18)

Wood Chips (FT) $29/ton NREL, 2008(96) 42 gal/ton Antares(b), 2008(18)
Soybean Oil $0.34/lb CBOT, 2009(97) 7.6 lbs/gal biodiesel Antares, 2008(18)

Yellow Grease (FAME) $0.11/lb Tribe, 2008(98) 249 gal/ton Antares(b), 2008(18)

Yellow Grease (FAHC) $0.11/lb Tribe, 2008(98) 250 gal/ton Antares(b), 2008(18)
Municipal Solid Waste (vegetation and paper) $0.00/ton Staff Estimated Cost 86 gal/ton – paper 70 gal/ton - vegetation Antares(b), 2008(18)

e. Co-Product Credits

The production of some biofuels generates significant co-product benefits. For example, with a dry-mill corn ethanol plant, the solids remaining after distillation are called distiller’s grains and solubles (DGS). These can be dried (DDGS) or used wet (WDGS) with minimal energy to prepare for us e as feed. Both DDGS and WDGS are used as an animal feed supplement, typically for cattle and swine. This DDGS and WDGS in effect displaces a portion of the corn that, if not us ed for ethanol production,

could have been used as animal feed.

The price of DGS prices varies with corn pric es; however, the cost is also influenced by the cost of soybean meal, a competitive livestock feed suppl ement. According to the CA-GREET model, a bushel of corn produces 2.72 gallons of ethanol and 14.5 pounds of DDGS. Recent prices for corn and DDGS were $3.58/bushel (99) and $150/ton(100), respectively, which would value the DDGS at $1.09/bushel, a 30 percent cost recovery of the purchased corn. To simplify the ec onomic analysis, staff assumed a 30 percent cost recovery for corn proce ssed at dry-mill ethanol plants.

A wet-mill corn ethanol plant produces a number of valuable by-products, including corn gluten, corn gluten meal, and corn oil. For this reason, the co-product credit for a wet mill is higher than for a dry mill. According to Whims(87), the co-product value is estimated to represent about 53 percent of the purchase price of corn.

According to an NREL study, a co-product credit for lignocellulosic ethanol can be realized by using excess steam to generate electricity, which may be sold to the grid.VIII-12 This is also true for Fischer-Tropsch (F-T ) diesel, which also produces naphtha as a co-benefit(18).

For the lignocellulosic ethanol process, staf f relied on an NREL analysis in which the plant operates 8,000 hours per ye ar, generating approximately 18 MW of electricity, of which half is consumed on site(90). The excess electricity equates to 70,400 MW-Hr, which is then sold to the grid at a wholesale price of $0.054/kW-Hr.

For the F-T diesel process, the electr icity generated is approximately 560 kW-Hr per barrel of F-T liquids produced, with the exce ss sold to the grid at a price of $0.054/kW-Hr. Naphtha repres ents about 30 percent of the total liquid product and for this analysis is sold at a pr ice of $1.50 per gallon(18).

The FAME biodiesel co-product is crude glycerin, which can be sold to a chemical manufacturer. FAHC co-products are light hy drocarbons that can be further processed to produce gasoline. Staff estimated the value of glycerin at approximately seven percent of the feedstock cost(84), which is sold at a price of $0.17 per gallon. The light hydrocarbons from the FAHC pr ocess represent approximately 3.5 to 4.4 weight percent of the feedstock, which is sold at $1.04 per gallon.

Table VIII-4 lists the co-products that c an be created from producing certain biofuels and the estimated values for these co-products that staff used in the lower-CI fuel cost

calculations.

Table VIII-4
Co-Products from Biofuel Produc tion and Their Estimated Values

Process Feedstock Co-Product(s) Yield Estimated Value

Dry Mill Fermentation Corn DDGS 14. 5 lbs/bushel 30% of corn price

Wet Mill Fermentation Corn Corn Gluten

Corn Gluten Meal

Corn Oil 11.4 lbs/bushel

3 lbs/bushel

1.6 lbs/bushel 53% of corn price

for all co-products

Lignocellulosic

Fermentation Corn Stover Wood Chips MSW (Grass,

Wood, and

Paper) Electricity Varies Wholesale price

estimated at $0.054/kW-hr

Fischer-Tropsch

Diesel Wood Chips Electricity Naphtha Varies 30% liquid yield $0.054/kW-hr $1.50/gal

FAME Biodiesel Yellow Grease Glycerin 7% of feedstock $0.17/gal

FAHC Diesel Yellow Grease Light Hydrocarbons 3.5 – 4.4 wt % of

feedstock $1.04/galVIII-13 f. Storage, Transport, and Distribution Costs

Staff used the U.S. EPA document entitled “Im pact Analysis: Renewable Fuel Standard Program(19),” an analysis of the first federal RFS, to esti mate the storage, transport,

and distribution costs of the biofuels. According to the RFS document, the average state-by-state freight cost for ethanol is approximately $0.21/gal (from the Midwest to California by rail). Furthermore, U.S. EPA estimated that the ethanol distribution and storage infrastructure under RFS1 will be ap proximately $350 million for 2.77 billion gallons of ethanol. This equates to an annual c apital cost recovery of $45.6 million, which in turn translates to approximately $0.02/ gal for storing and distributing ethanol.

Therefore, staff estimated the cost for storage, transpor t, and distribution of ethanol

biofuels from out-of-state at $0.23/gal, or $0.34/gge fo r ethanol. According to a California biorefinery, the co st to transport ethanol within Ca lifornia (Northern California to Southern California) by truck is es timated to be $0.20/gal to $0.30/gal(101). Therefore, staff used the same cost for storage, transport, and distributing for both outof-state ethanol biofuels and ethanol produced wit hin the State. Staff assumed similar infrastructure and cost for biodiesels, but did not convert them to gges.

According to data provided by the Committe e on Assessment of Resource Needs for Fuel Cell and Hydrogen Techno logies the storage, transpor t, and distribution costs for hydrogen is $0.57/gge, EER adjusted(102).

g. Fuel Dispensing Costs

Conventional gasoline or RFG can contain up to 10 percent ethanol (E10) by volume and be used in any gasoline vehicle. E10 needs no infrastructure as all storage tanks and dispensing equipment can accommodate up to E10. However, E85 (nominally 85 percent ethanol and 15 percent gasoline) c an only be used in vehicles designed for its use. Today, these are fl exible-fuelled vehicles (FFVs) which can accommodate from E0 (gasoline with no ethanol) to E85. Current gasoline equipment at service stations

cannot accommodate E85.

The estimated storage, transport, and distribution costs account ed for getting the fuel to the retail station. To complete a “well-to -wheels” analysis, staff es timated the cost of installing the infrastructure at the retail stations required to fuel the vehicles. Staff is assuming there will be two gasoline products on the market: E10 and E85. E85 will become more prominent when the total volume of ethanol needed to meet the average CI levels set by the proposed LCFS in 2015 and beyond cannot be satisfied by E10

alone. Should U.S. EPA allow E15 or E20 fuels, the additional volume of ethanol needed to meet the LCFS may be provided by these products instead, which will reduce

the need for E85.VIII-14 E85:

The necessary E85 infrastructure at an exis ting gasoline dispensing facility or service station includes a 10,000 gallon tank, one dispenser with two nozzles, and other piping.

The estimated costs in Table VIII-5 are based on a recent E85 installation at an existing service station(103).

Table VIII-5 Cost of Installing E85 Dispensing Infrastructure per Existing Service Station (2007 dollars)

Equipment

& Parts Installation Permits Soil Disposal & Testing Total

$72,000 $87,000 $5,000 $8,000 $172,000

Hydrogen:

The capital cost of a hydrogen stat ion ranges from $250,000 for a 10 kg H 2 /day mobile refueling unit to $5 million for a 1,000 kg H 2 /day steam-methane reformer station(104). For the economic analysis, staff used a 1,000 kg H 2 /day liquid delivery system for public fleets, with an estimated capital cost of $2.7 million per fueling station. Assuming annual sales of 173,000 kg H 2 (47 percent capacity factor), staff estimated that the cost of a hydrogen station adds $3.60/per kg sold, or $1.57/gge, EER adjusted.

CNG:

Staff assumed increased throughput of CNG would require both expanding existing CNG fueling stations (adding infrastructu re for increased capacity) and building new

stations. Staff assumed the new CNG stat ions would be added to existing truck stops along major freeways. Staff assumed one new station would be built for every five existing stations retrofitted, resulting in 20 percent mo re stations equipped for CNG fueling. New infrastructure at an ex isting CNG station includes a dispenser, compressor, and dryer. Staff assumed an addi tional dispenser an d compressor at the

new stations so that two vehicles could be services simultaneously. A new station includes storage tanks, two dispensers, tw o compressors, and a dryer(105, 106). The costs in Table VIII-6 are based on estimates from a gas utility company 62

.

62 Phone calls with Sempra and equipment manufacturing company, December 2008.VIII-15 Table VIII-6 Estimated Cost of Upgrading Existing or Creating New CNG Fueling Station (2007 dollars)

Facility Type Dispenser

with two

hoses 400 CFM Compressor

with

Installation New Dryer (Storage, dispensing, compressing) Total

Existing CNG Station $57,400 $239,100 $76,500 $373,000

New CNG Dispenser at

Existing Truck Stop $57,400 $239,100 $717,500 $1,014,000

Electricity:

For electricity, staff estima ted the costs based on electricit y tariffs from Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and the Los Angeles Department of Water and Power (LADWP). Table VIII-7 present s the specific tariff schedules that staff

referenced.

Table VIII-7 Electricity Tariffs Used in LCFS Economic Analysis

Load-Serving Entity Tariff Schedule Description

R: E-9 (PGE9) Experimental Residential Time-of-Use Service for Low

Emission Vehicle Customers PG&E C: E-19 (PGE19) Medium General Demand-Metered TOU Service

R: TOU-EV-1

(SCEEV1) Domestic Time-of-Use Electric Vehicle Charging

SCE C: TOU-EV-4 (SCEEV4) General Service Time-Of-Use Electric Vehicle Charging -

Demand Metered

R: R-1 Rate B

(LADWPR1) Residential TOU with Electric Vehicle Credit

LADWP C: A-2 Rate B (LADWPA2) General Service TOU with Electric Vehicle Credit

R = Residential, C = Commercial

Staff assumed that the owner s of the plug-in hybrid electric vehicles (PHEVs) and battery electric vehicles (BEVs) would predom inately recharge their vehicles during offpeak times. Therefore, for residential cust omers (light-duty vehi cles), staff assumed $0.09 per kilowatt-hour (kW-hr ). For commercial custom ers (medium-duty and heavyduty vehicles), staff assu med $0.12/kW-hr. Converti ng to gges based on energy content, these rates are $2.89/gge ( $0.96/gge, EER adjusted) and $3.85/gge ($1.28/gge, EER adjusted), respectively. To account for mete ring charges, staff rounded up these costs to $1.00/gge, EER adjusted, for gasoline scenarios and $1.33/gge, EER adjusted, for diesel scenarios.VIII-16 h. Summary of Lower-CI Fuel Costs

The costs for each fuel are presented below in Table VIII-8. Staff assumed that these

are 2010 costs in 2007 dollars. Tax credits were not included in this table, but are included in the economic analysis as discuss ed in the next subsection. Furthermore, research and development costs for the lower-c arbon-intensity alternat ive transportation

fuels are not included in these costs.VIII-17 Table VIII-8 Lower-CI Fuel Costs ($/gge, except for biodiesel [$/gal])

1 Imported ethanol transported by rail; intrastate ethanol transported by truck.

2 Assumed the conversion of sugarcane to ethanol is th e same process as conversion of corn (dry mill) to ethanol but more capital intensive due to grinding sugarcane into flour.

3 Co-benefit of using bagasse as fuel is included in the production cost.

4 Assumed transportation cost from plant to port $0.21 /gal (RFS), port cost $0.10/gal and transportation from Brazil to U.S. $0.14/gal.

5 Added tariff of $0.54/gal and 2.5% ad valorem tax.

6 Local dispensing costs not included for hydrogen, CNG, an d electricity. These costs are addressed in 2. g. Values take into account the Energy Economy Ratio (EER) of the vehicles into which the fuels are dispensed (FCVs = 2.3; PHEVs and BEVs = 3.0; CNG HD vehicles = 0.9) g = gge cost of electricity for gasoline scenarios; d = gge cost of electricity for diesel scenarios

For the gasoline scenarios, staff used seve ral corn-based ethanol sources, such as “Midwest corn,” California low-CI,” and “fede ral new renewable.” “Midwest corn” is based on existing corn ethanol facilities—85 percent from dry milling and 15 percent Fuel Feedstock Capital

Cost Production

Cost Feedstock
Cost CoProduct
Credit Storage Transport

Distribution 1 Total Reference

Ethanol Corn (Dry Mill) 0.31 0.81 2.05 -0 .61 0.34 2.90 USDA 2002(89), and

Gallagher, 2005(86)

Ethanol Corn (Wet Mill) 0.65 0.89 2.13 -1 .14 0.34 2.87 Whims, 2002(87)

Brazilian

Ethanol Sugarcane 2 0.77 0.75 0.44 0.00 3 0.67 4 3.26 5 USDA, 2006(107)

Lignocellulosic

Ethanol Corn Stover 1.22 1. 15 0.70 -0.22 0.34 3.19 NREL, 2000(90)

Lignocellulosic

Ethanol Wood Chips 1.37 0.66 0.47 -0.14 0.34 2.70 NREL, 1999(88)

Lignocellulosic

Ethanol Municipal
Solid Waste 1.35 0.62 0.00 0.34 2.31 Fulcrum, 2008 (108) Tomkinson(109 )

FischerTropsch

Biodiesel Wood Chips 2.43 1.66 0.68 -1.25 0.22 3.74 Tijmensen, 2002(83), and Antares, 2008(18)

FAME

Biodiesel Soybean Oil 0.12 0.36 2.62 -0 .17 0.22 3.15 Haas, 2006(84)

FAME

Biodiesel Yellow
Grease 0.09 0.67 0.85 -0 .17 0.22 1.66 Zhang, 2003(85)

FAHC

Biodiesel Yellow
Grease 0.30 0.27 0.84 -0 .06 0.22 1.57 Antares, 2008(18)

Hydrogen Natural Gas 0.70 6 0.57 6 1.26 6 Hydrogen, 2008(102)

CNG Natural Gas 1.81 6 CEC, AB-1007 (92)

Electricity Grid 1.00 g 6

1.33 d 6 PG&E, SCE, LADWP, 2008VIII-18 from wet milling—and is assumed to hav e a carbon intensity of 99.4 g CO2/MJ.

“California low-CI” ethanol assumes a dr y-mill process with a carbon intensity of 80.7 g CO2/MJ. “Federal new renewable” et hanol also assumes a dry mill process and

has a carbon intensit y of 76.7 g CO2/MJ.

As discussed above, staff adjusted the pr oduction costs and feedstock costs of the liquid biofuels as crude prices varied. Tabl e VIII-9 below shows the cost impacts of those adjustments.

Table VIII-9 Estimated Impact of Ch anges in Crude Prices on Lower-CI Fuel Costs ($/gge, except for biodiesel [$/gal]) 1

Ethanol Biodiesel

Year Projected
Crude

Price ($/bbl) Midwest
Corn (dry mill) Midwest
Corn (wet mill) Lignocell. (wood chips) Sugarcane (Brazil) Lignocell. (corn stover) Green

Wastes FAME (Soybean Oil) FAME,

Yellow
Grease (waste grease) F-T (Wood chips) FAHC (Yellow Grease) CNG 2

2010 $66 $2.87 $2.87 $2.70 $3.25 $3.19 $2.31 $3.15 $1.66 $3.74 $1.57 1.81

2011 $68 $2.89 $2.90 $2.71 $3.26 $3.20 $2.31 $3.18 $1.67 $3.76 $1.58 1.83

2012 $70 $2.91 $2.92 $2.72 $3.27 $3.22 $2.32 $3.21 $1.68 $3.77 $1.59 1.86

2013 $73 $2.94 $2.96 $2.73 $3.28 $3.23 $2.32 $3.24 $1.70 $3.79 $1.60 1.87

2014 $76 $2.97 $3.00 $2.74 $3.29 $3.26 $2.33 $3.29 $1.72 $3.82 $1.62 1.90

2015 $79 $2.99 $3.03 $2.75 $3.30 $3.27 $2.33 $3.32 $1.73 $3.84 $1.63 1.92

2016 $81 $3.01 $3.05 $2.76 $3.31 $3.28 $2.33 $3.35 $1.75 $3.85 $1.64 1.96

2017 $83 $3.03 $3.07 $2.77 $3.32 $3.29 $2.34 $3.37 $1.75 $3.87 $1.65 1.97

2018 $84 $3.04 $3.09 $2.77 $3.32 $3.30 $2.34 $3.39 $1.76 $3.88 $1.65 1.99

2019 $86 $3.06 $3.11 $2.78 $3.33 $3.31 $2.34 $3.41 $1.77 $3.89 $1.66 2.02

2020 $88 $3.07 $3.13 $2.78 $3.34 $3.32 $2.35 $3.43 $1.78 $3.90 $1.67 2.04
1 All lower-CI fuel costs increase annually; however , slight annual differences may not be apparent due to

rounding. 2 $/gge, EER adjusted. CNG cost increases we re based on retail price estimates in Energy

Commission’s 2007 State Alternative Fuels Plan and are not directly related to crude prices.

i. Alternative-Fuel Tax Incentives

There are a number of tax incentives for al ternative fuels to encourage their production by making them more economical ly competitive with petroleu m-based fuels. Increasing production of domestically-supplie d lower-CI fuels will assist the U.S. with improving energy independence and security and with im proving the environment. Blenders, producers, and sellers of some biofuels will receive tax cr edits, which will affect the profit margin or the selling price of biofuels. Staff reduced the over all cost of production of the lower-CI fuels that were presented in Table VIII-8 by the amount of the tax incentives, where applicable. The credits are assessed on a gallon of ethanol or biodiesel blended or produced an d on the volume of CNG sold. Although some incentives could expire in the near futu re, staff assumed the incentives would beVIII-19 extended, as has been the case with incentives that had rec ently expired. A discussion

of the tax credits is presented below.

Ethanol and Biodiesel Blenders:

The American Jobs Creation Act of 2004 created a new excise tax credit system for

ethanol and biodiesel blenders. As of January 1, 2005, the federal tax credit was $0.51 per gallon of pure ethanol blended, $1.00 per gallon of agricultural biodiesel (derived from virgin oils), and $0.50 per gallon of “waste grease” biodiesel (derived from vegetable oils and animal fats)(110). The Food, Conservation, and Energy Security Act of 2008 (2008 Farm Bill) reduced the ethanol cr edit to $0.45 per gallon of ethanol blended, effective January 1, 2009(111). Th e Emergency Economic Stabilization Act of 2008 eliminated the disparity in credit for bi odiesel and agri-biodie sel (now providing $1.00 per gallon of biodiesel blended), and extended the credit through the end of 2009(112).

Cellulosic Ethanol Producers:

The 2008 Farm Bill created a new cellulosic bi ofuels production tax credit of $1.01 per gallon produced. This credit is effe ctive January 1, 2009, through December 31, 2012(111).

Small Ethanol and Agri-Biodiesel Producer:

The Omnibus Budget Reconciliation Act of 1990, revised by the American Jobs Creation Act of 2004 and the Energy Policy Act of 2005, provides a tax credit to small ethanol producers of $0.10 per gallon for the first 15,000,000 gallons produced. A small producer is defined as a facility that produces less than 60 million gallons of ethanol per year(113). The 15 million gall on limitation does not apply to cellulosic ethanol. Thus, the credit may be claimed for cellulosic ethanol produced in excess of 15 million gallons(111).

The small agri-biodiesel producer credit was part of the Energy Policy Act of 2005 and has similar credits, facility size restrictions , and production limitations as those imposed on the small-ethanol-producer ta x credit(113). Staff did not include any tax credit for

either the small ethanol or agri-biodiesel blenders in the cost analysis because it is uncertain how many future ethanol plants in the State would qualif y for these credits.

Ethanol Tariff:

To keep from incenting the production and importation of foreign ethanol, ethanol imported into the United States is subject to a 2.5 percent ad valorem tariff (a duty levied on an imported item based on the item’s value) as well as a secondary tariff of 54 cents per gallon of ethanol import ed from non-Caribbean Basin countries (approximately 60 cents/gallon total for s ugarcane ethanol). The secondary tariff wasVIII-20 first placed on foreign-produced ethanol by Congress in 1980. The 2008 Farm Bill extended this tariff through 2010.

CNG Sellers:

The Safe, Accountable, Flexible , Efficient Transportation E quity Act, signed in 2005, created a 50 cents per gasoline- gallon-equivalent tax credit for CNG sold as a motor vehicle fuel(114).

3. Baseline Determination for the Compliance Scenarios

Staff created a baseline scenario for the LC FS regulation from which the emission

reductions and cost effectiveness of the LC FS regulation can be estimated. The

baseline scenario reflects the successful implementation of the Scoping Plan measures that impact the amount of tr ansportation fuels and resultant GHG emissions expected in

California between 2010 and 2020. These regulations and program s include: the ARB Zero Emission Vehicle (ZEV) regulation, t he federal Corporate Average Fuel Economy (CAFE) program, the Pavley regulation, and the federal Renewable Fuel Standard (RFS). For the purpose of determining comp liance with the LCFS, the initial year is considered 2010; staff extrapolated the baseline for years 2011 – 2020.

The ARB ZEV regulation will impa ct the State’s future mix of transportation fuel. The Board first adopted the ZEV regulation in 19 90 as part of the Low Emission Vehicle Program. Since then, the B oard has made modifications to the regulation, the most recent in March 2008. The goal has been to have zero-emission technologies on the roads on a mass scale as soon as possible, c onsidering the state of technology, market factors, economic impact, and environmental benefits. ARB staff estimates that the number of advanced-technology vehicles using electricity or hydrogen as a fuel— battery electric vehicles (BEVs), plug-in hybr id vehicles (PHEVs), or fuel cell vehicles (FCVs)—will increase to about 560,000 vehicles by 2020. This volume is consistent with the penetration schedule in the 2008 ARB Z EV regulation. St aff considered the deployment of this number of ZEV vehicles as part of the baseline analysis. Staff also considered other scenarios with up to two mi llion advanced-technology vehicles of all types in place by 2020.

The ARB’s GHG vehicle emission standards will also affect the future mix of transportation fuels. In August 2005, purs uant to AB 1493 (Pavley, 2002), the Board adopted greenhouse gas emissions standards fo r new passenger vehicles, beginning with 2009 models (Pavley I). Ma nufacturers have flexibility in meeting these standards through a combination of reducing tailp ipe emissions of carbon dioxide (CO 2 ), nitrous oxide (N 2 O), and methane (CH 4 ) and receiving credit for systems demonstrated to mitigate fugitive emissions of hydrofluoroc arbons (HFCs) from vehicle air conditioning systems. The emission standards become incr easingly more stringent through the 2016 model year. ARB is also committed to fu rther strengthening thes e standards to obtain an estimated 45 percent greenhouse gas reduc tion from 2020 model year vehicles (Pavley II). Federal approval of the Pavley I regulation is anticipated, and this analysisVIII-21 considers the impacts of this regulation as part of the baseline fuel forecast case for the

LCFS.

The Emission Factors (EMFAC) model is used to calculate emission rates from motor vehicles operating on highways, freeways, and local roads in California. For the AB 32 Scoping Plan, staff used EMFAC to estimate vehicle miles traveled (VMT), fuel use, emissions, and emission reduction s for transportation measures identified in the Plan. Gasoline demand in California is expected to decrease slightly between 2010 and 2020.

Another important statute that affects the analysis of the proposed LCFS regulation is the Energy Independence and Security Act of 2007 (EISA). Among other requirements, the EISA enhanced the original federal Rene wable Fuel Standard (RFS)—established by the Energy Policy Act of 2005—by requi ring the use of 36 billion gallons of renewable fuels annually in 20 22, of which only 15 billion gallons can be “conventional biofuel,” principally ethanol derived from corn starch. The remaining 21 billion gallons are to be from sources other than corn starch and are labeled
“advanced biofuels.” Sixteen billion gallons must meet a minimum 60 percent reduction in carbon intensity; the remaining five billion gallons must achieve a 50 percent reduction. If EISA is successfully implem ented, these federal RFS requirements, referred to as RFS2, will result in changes in U.S. and California transportation fuels.

ARB staff has considered the impact of RF S2 on the proposed LCFS regulation. To that end, staff assessed two alternative cases: one without RFS2 and one with the mandates of RFS2 fully realized. (For a full discussion on how staff addressed RFS2 impacts on the proposed LCFS re gulation, see Section F below: “Impact of RFS2 on LCFS.”)

4. Comparison of Fuel Production a nd Distribution Costs for Gasoline Compliance Scenarios

Staff evaluated costs based on five possible compliance scenarios for gasoline. (See Appendix G for printouts of the gasoline scenario anal yses spreadsheets.) The gasoline scenarios differ in the volume of corn-based ethanol, cellulosic ethanol, sugarcane ethanol, and advanced renewable ethanol used; the num ber of flexible fuel vehicles (FFVs) assumed to be using E8 5; and the number of advanced vehicles (ZEVs) using electricity or hydrogen

.

The least costly means of achieving the LC FS reductions in carbon intensity would be accomplished by using an optimal mix of very -low-CI and lower-cost fuels to the extent

that there is sufficient cons umer demand for these fuels. Table VIII-8 shows that the least costly compliance, in te rms of fuel costs, would re ly heavily on electricity and hydrogen. Therefore, maximi zing the use of BEVs, PHEVs, and FCVs would result in the lowest compliance cost in terms of fuel. However, in the 2020 timeframe it is not reasonable to expect that there will be suffici ent numbers of these v ehicles to provide the 10 percent CI reduction proposed for t he LCFS; other lower-CI fuels will be needed in significant quantities.VIII-22 The gasoline scenarios vary ZEV deployment from 560,000 vehicles to two million vehicles. The degree of ZEV deployment wil l be determined by future ZEV mandates and the market acceptance of ZEVs by consum ers, especially when consumers realize the fuel savings provided by PHEVs and BE Vs. Since the proposed LCFS regulation

does not mandate additional Z EV deployment, staff did not assign the costs of these vehicles to the LCFS regulat ion. Rather, staff focus ed on the fuels necessary to accommodate the number and types of Califor nia’s vehicles on the road, including

ZEVs.

For the five gasoline scenarios, staff address ed ZEVs on a “what if” basis—that is, what if there were 560,000 ZEVs on the road, how might this affect compliance with the

LCFS? Or what if there were one million or two million ZEVs on the road? Staff then considered the transportation f uel mixtures necessary to achieve compliance with the proposed LCFS regulation for the various scenar ios as more electricity or hydrogen is used as a transportation fuel.

a. Common Assumptions

• RFS2 impacts are addressed later in Se ction F; therefore, they are excluded from the following gasoline scenarios.

• Taxes and biofuel incentives are incl uded in both the petroleum-based fuels and

the biofuels and assumed effective throughout 2010-2020. Credits include $0.45 per gallon of ethanol blended and $1.01 per gall on of cellulosic ethanol produced. (See previous subsection i, “Alter native Fuel Tax Incentives,” for more information.)

• Based on existing corn ethanol facilitie s, conventional corn ethanol includes 85 percent from dry mill operation and 15 per cent from wet milling process. (All new corn ethanol facilities assumed to be dry-mill facilities.)

• Cost of producing one gallon of “Calif ornia low-CI corn et hanol” and “federal new renewable ethanol” is the same as dry -mill corn ethanol ($2.83 to $3.08/gge, 2007 dollars) during the compliance period.

• Wood chips, green waste, and corn stover are the common feed stock sources for

both cellulosic and advanced r enewable ethanol fuels.

• Based on a UC Davis analysis of availabl e biomass in California, green waste, paper, and wood waste could provide 50 percent of feedstock for advanced renewable; wood chips could provide 44 percent; and corn stover and straw would provide the other six percent.

• Ethanol products are E10 and E85. At this time, there are no other ethanol blends, such as E15 or E20, etc.

• There are no new fueling stations for E85, only upgrading a portion of existing gasoline service stations to dis pense E85 (one tank and dispenser).

• For any given year:

Total Costs or Savings = Scenario Total Co sts - Base Case Total Costs

b. Number of E85 Facilities RequiredVIII-23 As discussed previously, all five gasoline scenar ios contain a certain number of flexible fuel vehicles (FFVs) penetrating the mark et that varies depend ing on the compliance year for a given scenario. Table VIII-10 s hows the existing number of public accessible (retail) gasoline dispensing facilities ( gasoline stations) in California, based on information in ARB’s 2008 report, “Gasoline Dispensing Facility (GDF) Vapor Recovery Hose Population Report”(115).

Table VIII-10
Gasoline Stations in Calif ornia by Air District

South

Coast Bay

Area San Joaquin San Diego Other

Districts Total

Number of Gasoline

Stations (as of Oct 2008) 5,298 2,581 2,720 1,080 4,493 16,172

Statewide % 33% 16% 17% 7% 27% 100%

If E85 is introduced into the market as par t of meeting the LCFS and RFS2, staff believes that larger retail stations (great er than two million gall ons a year throughput)

will invest first in the E85 infrastructure . As the demand for E85 increases, other gasoline stations will invest.

To determine the number of gasoline stat ions needed to accommodate various volumes of E85, staff started with an annual throughput of E85 of 180, 000 gallons per year per gasoline station when E85 first enters t he market, increasing the average annual throughput by 20 percent every year until 2020, when the estimated average annual E85 throughput per station would be almost 450, 000 gallons. Staff believes that this is a reasonable approach: the in itial gasoline stations will not generate significant E85

business until more FFVs are on the road. When the FFVs become more prevalent, the stations investing in E85 will have more business and higher annual throughputs. For the economic analysis, staff expects 100, 000 to 350,000 FFVs in 2015 and 1.8 to

3.4 million FFVs in 2020.

c. Scenario 1

(1) Description

This scenario models an increase in ethanol us e to 10 percent of gasoline volume by 2010, a steady use of ethanol at that level until 2014, then an increasing use of ethanol in FFVs between 2015 and 2020. Early year compliance is achieved through a gradual

decrease in the volume of conventi onal corn-based ethanol between 2011-2015 as these fuels are replaced with ethanol from low ca rbon production methods. From 2015 – 2020, California low-carbon-intens ity corn ethanol, federal new renewable ethanol, and advanced renewable fuels replace most conventional corn-based ethanol. (See Chapter VI for complete descriptions of the scenarios.) When the volume ofVIII-24 ethanol (all types) needed to meet lower-CI va lues cannot be provided by E10 alone, E85 becomes a product available in the marketplace. For Scenario 1, this occurs in 2015. Staff assumes that there will be an adequat e number of FFVs on the road to use this E85. From 2015 -2020, the volume of E85 and number of FFVs increase.

The number of advanced vehicles (BEVs, PHEVs, and FCVs) using electricity or hydrogen as a fuel increases to about 560,000 vehicles in 2020. This volume is consistent with the penetration schedule in the 2008 ARB ZEV regulation.

(2) Assumptions

• Annual E85 dispensing per station is based on the ascending throughput discussed earlier (180 ,000 – 450,000 GPY).

• Number of gasoline stations that will provide E85 is estimated at approximately 4,400 stations by 2020.

(3) Results

Relative to the base case, the total vo lume of both ethanol and CARBOB remains unchanged until 2015, although the carbon intensity of the ethanol fraction begins to change in 2011. A modest savings occurs in these early years due to the gradual penetration of non-conventional-based corn ethanol (California low-CI, cellulosic, federal new renewable biofuel, and advanc ed renewable). Staff estimated the production cost of these fuel s (except CA low-CI ethanol which has a slightly higher capital cost) to be equivalent to the cost of dry-mill corn ethanol, which is $0.03/gal higher than the ethanol from the wet-mill process that makes up 15 percent of the conventional corn ethanol. E85, and its associ ated infrastructure costs, arrives on the market in 2015, increasing in volume th rough 2020. For these years, as ethanol displaces CARBOB in the overall transportation fuel mix, savings are realized due to the lower production cost of ethanol relative to CARBOB. The additional infrastructure costs of E85 marketing contribute to the cost of the greater volumes of ethanol in the market; however, those costs do not overco me the cost differential between producing

ethanol and CARBOB. The cost results for Scenario 1 are pr esented below in

Table VIII-11.

The total cost of this scenar io and its base case includes the costs of electricity and hydrogen consumption, resulting fr om 560,000 ZEVS on the road in 2020.VIII-25 Table VIII-11
Cost Results for Gasoline Fuel Scenario 1

EtOH (billion gallons/yr) CARBOB (billion gallons/yr) Additional Non-Liquid

Fuel Volume (billion gge/yr) Total Cost (Billion Dollars) Year

B S1 B S1 Electricity Hydrogen Baseline S1

2010 1.45 1.45 13.97 13.97 0.00026 0.00009 $35.90 $35.95

2011 1.44 1.44 13.88 13.88 0.00035 0.00017 $36.33 $36.38

2012 1.43 1.43 13.82 13.86 0.00225 0.00035 $36.85 $36.94

2013 1.43 1.43 13.77 13.77 0.00406 0.00052 $37.60 $37.49

2014 1.42 1.42 13.69 13.69 0.00588 0.00061 $38.48 $38.25

2015 1.41 1.47 13.66 13.62 0.01012 0.00164 $39.18 $38.71

2016 1.40 1.65 13.49 13.34 0.01410 0.00242 $39.49 $38.79

2017 1.39 1.84 13.39 13.09 0.01808 0.00320 $39.79 $38.65

2018 1.37 2.18 13.22 12.67 0.02370 0.00588 $39.89 $38.27

2019 1.35 2.46 13.04 12.30 0.03174 0.00830 $39.95 $37.89

2020 1.33 2.88 12.89 11.84 0.03762 0.01090 $40.07 $37.31

B = Baseline
S1 = Gasoline Scenario 1

d. Scenario 2

(1) Description

This scenario is similar to Scenario 1 exc ept that federal new renewable ethanol is replaced with sugarcane ethanol. Also, there is more total ethanol, which on average has a higher CI than the bi ofuels used in Scenario 1. The additional ethanol in Scenario 2 requires more E85 and FFVs.

(2) Assumptions

• Annual E85 dispensing per facility is based on the ascending throughput discussed earlier (180 ,000 – 450,000 GPY).

• Number of gasoline stations that will provide E85 is estimated at approximately 5,000 stations by 2020.

(3) Results

The introduction of ethanol from Brazilian sugarcane makes Scenario 2 more expensive than the base case in the early years. Br azilian sugarcane, although less expensive to produce than conventional corn-b ased ethanol, is subject to a tariff and an ad valorem tax. Therefore, unlike in Sc enario 1, the displacement of federal new renewable cornbased ethanol in 2011 -2020 comes with an additi onal cost, not a savings. The other major difference between the two scenario s is the need for a much higher FFV penetration from 2018 – 2020, resulting in an increase in E85 and an additional number of gasoline stations (5,000 st ations vs. 4,400 stations in Scenario 1). The reduction inVIII-26 CARBOB reaches approximately 1.2 billion gallons in 2020 due to more E85 in the
market. The cost results for Scenario 2 are presented below in Table VIII-12.

The total cost of this scenar io and its base case includes the costs of electricity and hydrogen consumption, resulting fr om 560,000 ZEVS on the road in 2020.

Table VIII-12
Cost Results for Gasoline Fuel Scenario 2

EtOH (billion gallons/yr) CARBOB (billion gallons/yr) Additional Non-Liquid

Fuel Volume (billion gge/yr) Total Cost (Billion Dollars) Year

B S2 B S2 Electricity Hydrogen Baseline S2

2010 1.45 1.45 13.97 13.97 0.00026 0.00009 $35.90 $35.95

2011 1.44 1.44 13.88 13.88 0.00035 0.00017 $36.33 $36.48

2012 1.43 1.43 13.82 13.86 0.00225 0.00035 $36.85 $37.09

2013 1.43 1.43 13.77 13.77 0.00406 0.00052 $37.60 $37.65

2014 1.42 1.42 13.69 13.69 0.00588 0.00061 $38.48 $38.39

2015 1.41 1.47 13.66 13.62 0.01012 0.00164 $39.18 $38.85

2016 1.40 1.64 13.49 13.34 0.01410 0.00242 $39.49 $38.90

2017 1.39 1.84 13.39 13.09 0.01808 0.00320 $39.79 $38.78

2018 1.37 2.22 13.22 12.63 0.02370 0.00588 $39.89 $38.37

2019 1.35 2.62 13.04 12.19 0.03174 0.00830 $39.95 $37.99

2020 1.33 3.08 12.89 11.71 0.03762 0.01090 $40.07 $37.49

B = Baseline
S2 = Gasoline Scenario 2

e. Scenario 3

(1) Description

This scenario is similar to Scenario 2 except that the number of advanced vehicles (ZEVs) is increased from 560,000 vehicles to 1,000,000 vehicles in 2020. In turn, the number of FFVs using E85 in 2020 and the amount of cellulosic ethanol, advanced renewable ethanol, and sugar cane ethanol are reduced.

(2) Assumptions

• Annual E85 dispensing per facility is based on the ascending throughput discussed earlier (180 ,000 – 450,000 GPY).

• Number of gasoline stations that will provide E85 is approximately 4,300 stations.

• Electricity and hydrogen to supply the additi onal ZEVs are taken into account, as well as the necessary infrastructure fo r dispensing into vehicles. (See discussion below.)VIII-27 (3) Results

In Scenario 3, Brazilian sugarcane continues to add cost for the years 2011 – 2020.

The total amount of CARBOB starts decreasi ng in 2014, reaching 1.2 billion gallons less in 2020. Conventional corn endures a gr adual decrease through 2017, zeroing out in 2018. Similar to Scenario 2, federal new renewable ethanol is absent; however, staff projects the same share of sugarcane with a maximum of 300 million gallons in 2020. Starting in 2014, the cost savings of di splacing CARBOB with ethanol overcomes the cost impact of the Br azilian sugarcane, resulting in net savings.

The total cost of this scenario includes the costs of electricity and hydrogen consumption, resulting from one million ZEVS on the road in 2020. (Scenarios 1 and 2 have 560,000 ZEVs) Because of the relative ly small amount of energy supplied by electricity and hydrogen (0.52 percent and 0.13 percent, respectively, of the total energy required by the fleet), t he economic impact of these fuels and their associated dispensing infrastructure is minimal. The cost results for Scenario 3 are presented

below in Table VIII-13.

Table VIII-13
Cost Results for Gasoline Fuel Scenario 3

EtOH (billion gallons/yr) CARBOB (billion gallons/yr) Additional Non-Liquid

Fuel Volume (billion gge/yr) Total Cost (Billion Dollars) Year

B S3 B S3 Electricity Hydrogen Baseline S3

2010 1.45 1.45 13.97 13.97 0.0003 0.0001 $35.90 $35.95

2011 1.44 1.44 13.88 13.88 0.001 0.0002 $36.33 $36.48

2012 1.43 1.43 13.82 13.86 0.002 0.0003 $36.85 $37.09

2013 1.43 1.43 13.77 13.77 0.004 0.0005 $37.60 $37.63

2014 1.42 1.54 13.69 13.61 0.006 0.0006 $38.48 $38.39

2015 1.41 1.65 13.66 13.32 0.014 0.002 $39.18 $38.38

2016 1.40 1.73 13.49 13.22 0.022 0.004 $39.49 $38.83

2017 1.39 1.87 13.39 12.98 0.030 0.006 $39.79 $38.70

2018 1.37 2.06 13.22 12.65 0.040 0.009 $39.89 $38.36

2019 1.35 2.40 13.04 12.23 0.053 0.012 $39.95 $38.02

2020 1.33 2.80 12.89 11.70 0.070 0.017 $40.07 $37.37

B = Baseline
S3= Gasoline Scenario 3

f. Scenario 4

(1) Description

This scenario is similar to Scenario 3 except the number of advanced vehicles (ZEVs) is increased to 2,000,000 vehicles in 2020.VIII-28 (2) Assumptions

• Annual E85 dispensing per facility is based on the ascending throughput discussed earlier (180 ,000 – 310,000 GPY).

• Number of gasoline stations that will provide E85 is approximately 3,800 stations.

• Electricity and hydrogen to supply the additi onal ZEVs are taken into account, as well as the necessary infrastructu re for dispensing into vehicles.

(3) Results

The total cost of this scenario includes the additional costs of electricity and hydrogen consumption, resulting from two million ZEVS on the road in 2020 which lessens the need for liquid fuels. Conseq uently, there are less FFVs on the road, less E85 on the market, and fewer gasoline stations needed to sell it. Conventional corn ethanol is absent again from 2017 - 2020, replaced by lower CI ethanol. The cost results for Scenario 4 are presented bel ow in Table VIII-14.

Table VIII-14
Cost Results for Gasoline Fuel Scenario 4

EtOH (billion gallons/yr) CARBOB (billion gallons/yr) Additional Non-Liquid

Fuel Volume (billion gallons/yr) Total Cost (Billion Dollars) Year

B S4 B S4 Electricity Hydrogen Baseline S4

2010 1.45 1.45 13.97 13.97 0.0003 0.0001 $35.90 $35.95

2011 1.44 1.44 13.88 13.88 0.001 0.0002 $36.33 $36.47

2012 1.43 1.43 13.82 13.85 0.004 0.0003 $36.85 $37.10

2013 1.43 1.43 13.77 13.75 0.006 0.0005 $37.60 $37.62

2014 1.42 1.42 13.69 13.65 0.013 0.0008 $38.48 $38.38

2015 1.41 1.41 13.66 13.55 0.029 0.004 $39.18 $38.78

2016 1.40 1.40 13.49 13.31 0.044 0.008 $39.49 $38.81

2017 1.39 1.42 13.39 13.09 0.061 0.013 $39.79 $38.61

2018 1.37 1.66 13.22 12.67 0.079 0.018 $39.89 $38.28

2019 1.35 1.84 13.04 12.20 0.110 0.026 $39.95 $37.76

2020 1.33 2.18 12.89 11.68 0.139 0.034 $40.07 $37.16

B = Baseline
S4 = Gasoline Scenario 4

g. Scenario 5

(1) Description

This scenario is similar to Scenario 3 fo r the number of ZEVs (1,000,000); however,

staff assumes less E85 in 2020 and lower amounts of non-conventional ethanol.VIII-29 (2) Assumptions

• Annual E85 dispensing per facility is based on 16 percent annual increase.

• Number of gasoline stations that will provide E85 is approximately 4,100 stations.

• Electricity and hydrogen to supply the additi onal ZEVs are taken into account, as well as the necessary infrastructu re for dispensing into vehicles.

(3) Results

The total cost of this scenario includes the costs of electricity and hydrogen consumption, resulting from one million ZEVS on the road in 2020 (Scenarios 1 and 2 have 560,000 ZEVs, while Scenario 3 ant icipates one million ZEVs in 2020). Scenario 5 is more expensive than Scenario 3 (even though the total ZEVs are the same) because staff assumes slightly higher vo lumes of Midwest corn in the early years due to a one-year delay in penetration of cellulosic and advanced ethanol. The economics improve in 2013 because of penetration of cellulosic and advanced renewable ethanol which is less expens ive than Midwest and sugarcane ethanol.

Penetration of E85 begins in 2014, a year earlier than with the ot her scenarios. The higher demand for ethanol is provided by a la rger volume of cellulosic and advanced renewable ethanol, which surpasses t he sugarcane volume between 2015 – 2020. Also, compared to Scenario 3, there is a lar ger volume of total transportation fuel. The cost results for Scenario 5 are pr esented below in Table VIII-15.

Table VIII-15
Cost Results for Gasoline Fuel Scenario 5

EtOH (billion gallons/yr) CARBOB (billion gallons/yr) Additional Non-Liquid

Fuel Volume (billion gallons/yr) Total Cost (Billion Dollars) Year

B S5 B S5 Electricity Hydrogen B S5

2010 1.45 1.45 13.97 13.97 0.0003 0.0001 $35.90 $35.95

2011 1.44 1.44 13.88 13.88 0.001 0.0002 $36.33 $36.44

2012 1.43 1.43 13.82 13.86 0.002 0.0003 $36.85 $37.11

2013 1.43 1.43 13.77 13.77 0.004 0.0005 $37.60 $37.67

2014 1.42 1.50 13.69 13.64 0.006 0.0006 $38.48 $38.42

2015 1.41 1.62 13.66 13.50 0.014 0.002 $39.18 $38.83

2016 1.40 1.73 13.49 13.22 0.022 0.004 $39.49 $38.83

2017 1.39 1.89 13.39 12.96 0.030 0.006 $39.79 $38.66

2018 1.37 2.08 13.22 12.64 0.040 0.009 $39.89 $38.35

2019 1.35 2.36 13.04 12.23 0.053 0.012 $39.95 $37.99

2020 1.33 2.72 12.89 11.76 0.070 0.017 $40.07 $37.48

B = Baseline
S5 = Gasoline Scenario 5VIII-30 5. Comparison of Fuel Production a nd Distribution Costs for Diesel

Fuel Scenarios

(See Appendix G for print outs of the diesel scenario analyses spreadsheets.)

a. Common Assumptions

• Biodiesel incentive of $1.00/gal is included and assumed effective throughout 2010-2020. (See previous subsection i, “A lternative Fuel Tax Incentives,” for more information.)

• Conventional renewable biodies el is derived from soybeans.

• Advanced renewable biodiesel is der ived from 85 percent wood chips (F-T) and 15 percent yellow grease (FAHC).

• All biodiesels have about the same ener gy content of conventional diesel.

• No additional infrastructure for fueling stations are required, assuming biodiesel in the fuels mix remains compatib le with the dispensing equipment.

• Sufficient number of CNG fueling stati ons exists to accommodate increased volumes; however, staff assumed additiona l dispenser, compressor, and dryer at majority of existing facilities to proce ss additional throughput. In addition, due to the lack of CNG fueling st ations along the major freeways, staff projected installing new CNG fueling dispensing syst ems at existing truck stops. Staff

assumed one new station would be built for ev ery five existing stat ions retrofitted, resulting in 20 percent more stat ions equipped for CNG fueling.

• For any given year:

Total Costs or Savings = Scenario To tal Costs - Base Case Total Costs

b. Scenario 1

(1) Description

The first scenario is based on a diversificati on of the liquid fuel pool using available lower-carbon-intensity fuels.

(2) Assumptions

• See “Common Assumptions” above.

(3) Results

Since only liquid fuels are involved for this scenar io and they all contain the same amount of energy, replacing conventional diesel with its biodiesel counterparts does not affect the total volume for any of the ten years during the compliance period. However, staff projects a much higher volume of advanced renewable biodiesel (CI =15) than conventional biodieselVIII-31 (CI =69) in order to achieve the 10 percent reduction in carbon intensity. The cost results for Diesel Fuel Scenario 1 are pr esented below in Table VIII-16.

Table VIII-16
Cost Results for Diesel Fuel Scenario 1

Conventional Diesel

(million gallons/yr) Biodiesel (million gallons/yr) CNG Electricity Total Cost (Billion Dollars) Year

B S1 B S1 S1 S1 Baseline S1 2010 4,393 4,393 0 0 0 0 $10.89 $10.89
2011 4,484 4,467 0 17 0 0 $11.32 $11.32
2012 4,577 4,542 0 35 0 0 $11.77 $11.76
2013 4,672 4,600 0 72 0 0 $12.30 $12.28
2014 4,768 4,660 0 108 0 0 $12.92 $12.89
2015 4,866 4,676 0 190 0 0 $13.45 $13.39
2016 4,977 4,710 0 267 0 0 $14.04 $13.94
2017 5,091 4,696 0 395 0 0 $14.57 $14.42
2018 5,207 4,688 0 519 0 0 $15.12 $14.91
2019 5,325 4,674 0 651 0 0 $15.69 $15.40
2020 5,445 4,607 0 838 0 0 $16.26 $15.87

B = Baseline
S1 = Diesel Scenario 1

c. Scenario 2

(1) Description

The second scenario includes not only a variet y of liquid fuels, but heavy-duty vehicles using compressed natural gas (CNG ) vehicles penetrate the fleet.

(2) Assumptions

• Annual CNG throughput of 180,000 gallons per year per station in 2011, increasing the average annual throughput by 10 percent every year until 2020, when the estimated average annual throughp ut per station would be almost 425,000 gallons.

• In year 2020, upgrading 280 existing CNG stat ions plus installing CNG fueling at approximately 60 existing truck stops along major freeways.

• CNG has a lower fuel economy than conventional diesel.

(3) Results

Scenario 2 introduces HD CNG vehicles in 2011, with increasing numbers the following years. Compared to the base case, the total volume of transportation fuel will increase by one million gallons in 2013, reaching a maxi mum of eleven million gallons in 2020.VIII-32 Since the advanced biodiesel for this scenario comes from F-T diesel from wood chips and FAHC diesel from renewable yellow grea se, there are overall savings for this scenario. The cost results for Scenario 2 are presented below in Table VIII-17.

Table VIII-17
Cost Results for Diesel Fuel Scenario 2

Conventional

Diesel (million gallons/yr) Biodiesel (million gallons/yr) CNG (million gallons

of diesel equivalent/yr) Electricity (million gallons of

diesel equivalent/yr) Total Cost (Billion Dollars) Year

B S2 B S2 S2 S2 Baseline S2 2010 4,393 4,393 0 0 0 0 $10.89 $10.89
2011 4,484 4,465 0 17 2 0 $11.32 $11.32

2012 4,577 4,538 0 35 4 0 $11.77 $11.76
2013 4,672 4,593 0 71 9 0 $12.30 $12.28
2014 4,768 4,648 0 108 13 0 $12.92 $12.88
2015 4,866 4,663 0 183 22 0 $13.45 $13.38

2016 4,977 4,686 0 262 32 0 $14.04 $13.92

2017 5,091 4,661 0 388 47 0 $14.57 $14.38

2018 5,207 4,638 0 511 64 0 $15.12 $14.85

2019 5,325 4,610 0 642 81 0 $15.69 $15.33

2020 5,445 4,530 0 822 104 0 $16.26 $15.78

B = Baseline
S2 = Diesel Scenario 2

d. Scenario 3

(1) Description

The third scenario increases the compliance opt ions by expanding Scenario 2 to include Heavy Duty PHEVs (HD PHEVs).

(2) Assumptions

• CNG has a lower fuel economy than conventional diesel

• In year 2020, upgrading 330 existing CNG stat ions plus installing CNG fueling at approximately 70 existing tru ck stops along major freeways.

• Electricity offers a more efficient fuel economy than diesel.

(3) Results

With combined CNG HD and PHEV HD penetration in this scenario, the reduction in total volume of non-liquid fuel becomes greater than the former scenario (from 15 million diesel gallons equivalent (DGE) in 2014 up to 141 million gallons DGE in 2020). Compared to the base case, the total vo lume of transportation fuel will decrease by one million gallons in 2014, reaching a maxi mum of five million gallons in 2020.VIII-33 Similar to the previous two scenarios, advanc ed renewable biodiesel plays a major role in driving down the costs. Sc enario 3 is the least costly of all three cases. The cost results for Scenario 3 are pres ented below in Table VIII-18.

Table VIII-18
Cost Results for Diesel Fuel Scenario 3

Conventional

Diesel (million gallons/yr) Biodiesel (million gallons/yr) CNG (million gallons

of diesel equivalent/yr) Electricity (million gallons of

diesel equivalent/yr) Total Cost (Billion Dollars) Year

B S3 B S3 S3 S3 Baseline S2 2010 4,393 4,393 0 0 0 0 $10.89 $10.89
2011 4,484 4,465 0 17 3 0 $11.32 $11.32

2012 4,577 4,536 0 35 5 0 $11.77 $11.76

2013 4,672 4,592 0 68 11 1 $12.30 $12.28
2014 4,768 4,645 0 104 16 1 $12.92 $12.88
2015 4,866 4,657 0 177 28 2 $13.45 $13.37

2016 4,977 4,679 0 254 39 3 $14.04 $13.90

2017 5,091 4,652 0 373 58 5 $14.57 $14.36

2018 5,207 4,627 0 491 79 6 $15.12 $14.83

2019 5,325 4,580 0 635 97 8 $15.69 $15.29

2020 5,445 4,517 0 788 124 10 $16.26 $15.74

B = Baseline
S3= Diesel Scenario 3

D. Cost-Effectiveness

This section discusses the cost-effectivene ss of the proposed regulation. AB 32 requires the Board to cons ider cost effectiveness of each greenhouse gas control measure it adopts. The values must be ex pressed in dollars per metric ton of CO 2 equivalent. AB 32 does not specify what should be included in the cost calculations nor does it provide criteria to assess if a r egulation is or is not cost-effective.

Staff calculated cost-effectiveness values for each compliance scenario developed for the proposed regulation. The values were calculated for each compliance year for 2010 to 2020 and were determined by dividing the net compliance cost for the year by

the total metric tons of CO 2 equivalent expected to be reduc ed for the same year. (See Chapter VII for a discussion of annual CO 2 reductions.) To determine an overall cost effectiveness for each scenario, staff divi ded the cumulative costs from 2010-2020 by the cumulative emission reductions during that same period. All costs were calculated

in 2007 dollars.

As Table VIII-19 shows, the net cost effect iveness, based on the cost of producing or otherwise procuring the needed amounts of lo wer-CI fuels, for all five gasoline scenarios was negative—the net savings from reduced gasoline production orVIII-34 importation was greater than t he net costs of supplying t he lower-CI transportation fuels (ethanol, electricity, and hydrogen) that displaced the petroleum-based fuels.

For the five gasoline analyses, the cumulati ve net cost effectiveness ranged from ($121) to ($142)/MT CO 2 E reduced, which, for the period of 2010 – 2020, is a cumulative savings of $8 to $9 billion. T he possible distribution of these savings is

discussed later in Section G.

Table VIII-19 Summary of Cost-Effectiveness for the LCFS Regulation for Each Gasoline Fuels Compliance Scenario

Gasoline
Scenario 1 Gasoline
Scenario 2 Gasoline
Scenario 3 Gasoline
Scenario 4 Gasoline
Scenario 5
(Dollars per Metric Tons of CO 2 Reduced)

($141.58) ($120.71) ($132. 31) ($136.86) ($130.54)

Similarly, as Table VIII-20 shows, the cumu lative net cost effectiveness for all three diesel scenarios was negative—the net savi ngs from reduced diesel production or importation was greater than t he net costs of supplying t he lower-CI transportation fuels (biodiesel, alternative renewable diesel, CNG, and electricity) that displaced the petroleum-based fuels.

For the three diesel scenarios, the co st effectiveness r anged from ($49) to ($67)/MT CO 2 E reduced, which, for the period of 2010 – 2020, is a cumulative savings of $1.3 billion to $1.7 billion. The possible distribution of these savings is discussed

later in Section G.

Table VIII-20 Summary of Cost-Effectiveness for the LCFS Regulation for Each Diesel Fuels Compliance Scenario

Diesel Scenario 1 Diesel Scenario 2 Diesel Scenario 3

(Dollars per Metric Tons of CO 2 Reduced)

($49.17) ($61.00) ($67.11)

E. Sensitivity Analysis

To conduct the economic analyses of the ei ght scenarios, staff used the petroleumbased costs of Table VIII-1, the lower-CI fuel costs of Table VIII-8, the appropriate tax credits for the alternative transportation fuel s, the costs of the necessary dispensing infrastructure (e.g., E85, hydrogen, CNG), and a real interest rate of eight percent forVIII-35 10 years. Staff then conduct ed a sensitivity analysis by varying crude prices, feedstock prices, and interest rates.

1. Crude Oil Prices

With the tax incentives in place for et hanol production and blendi ng, staff dropped the price of crude until the cost of making a gal lon of gasoline was the same as making a gge of corn ethanol from corn starting at $3.75/bu (2007 dollars). The cost of corn declines as crude prices decline due to the energy/feedstock and energy/production cost relationships discussed above. The breakeven crude price occurred at $45/bbl.
Without the tax incentives, t he breakeven price was $110/bbl.

For cellulosic ethanol from wood chips at $30/ton, the breakeven price was $82/bbl

without tax incentives. With the $1.01/gal tax credits in place for cellulosic ethanol production, the breakeven price of crude w ould be less than $10/bbl, so low that the value of the ethanol produced would decline to t he point that very little cellulosic ethanol would actually be produced.

For alternative diesel fuels, staff cons idered the breakeven crude price for biodiesel made from soybeans and Fischer-Tropsch dies el produced from wood chips. Starting out at $0.34/lb for soybean oil, the breakeven crude price was estimated at $30/bbl with incentives and $142/bbl without incentives. For Fischer-Tropsch diesel, starting with $30/ton for wood chips, the breakeven pr ice for crude was less than $10/bbl with
incentives, much like with cellulosic ethanol. Without the tax credi t, the breakeven price was estimated at $150/bbl.

2. Feedstock Prices

Staff set the crude price at $66/bbl (about t he estimated 2010 price) and raised the cost

of the ethanol feedstock to find a breakev en feedstock price. For corn ethanol, the breakeven price was $4.15/bu with tax incentives. Without tax incentives the breakeven corn price was $2.90/bu. For cellulosic et hanol from wood chips, the breakeven price was $12/ton without incentives. At this price, there would be insufficient biomass to supply the States biorefiner ies with feedstock. With incentives, the calculated breakeven point is calculated to be $103/t on, although this hypothetical figure essentially indicates that sufficient bioma ss would be available to produce cellulosic

ethanol at the 18 cellulo sic ethanol plants(18).

For alternative diesel fuels, the breakeven price for soybean oil is $0.39/lb with incentives and $0.26/lb without in centives at $66/bbl crude price. For Fischer-Tropsch diesel, the breakeven price for wood chip s is $18/ton with incentives, and without

incentives F-T diesel made fr om wood chips is not cost-effe ctive at any crude price.VIII-36 3. Real Interest Rates

Because of the increased risks of investing in biorefineries, especially cellulosic ethanol plants that have only been built on a pilot-project scale, staf f used a real interest rate of eight percent for a 10-year proj ect life. A mature chemical industry might attract capital

at a real interest rate of five percent, perhaps over a 20-y ear period. Staff maintained the 10-year project life and look ed at the sensitivity of adjus ting the real interest rate downward to five percent and upward to 10 perc ent. For this sensitivity analysis, staff

chose Gasoline Scenario #2 and Diesel Sce nario #1, the two scenarios that require more liquid biofuels than the other gaso line and diesel scenarios, respectively. Table VIII-21 shows the impact on cost effectiv eness by adjusting real interest rates.

Table VIII-21 Impact of Real Interest Rates on Cost Effectiveness

Real Interest Rate (%) Gasoline Scenario #2 Diesel Scenario #1 (Dollars per Metric Tons of CO 2 Reduced) 5 ($139.51) ($71.56) 8 ($120.71) ($49.17) 10 ($106.06) ($32.75) 13.9 - ~$0 24.1 ~$0 -

The breakeven interest rate for diesel is abo ut 13 percent. The Fischer-Tropsch diesel process is capital-intensive; t herefore, it would be more affe cted by interest rates than other processes. (See Table VIII-8.) Conv ersely, cellulosic ethanol— with a tax credit of $1.01/gal ($1.50/gge)—can endure a much higher interest ra te before the cumulative savings from 2010-2020 is driven to zero. Nevertheless, under such a scenario, the
LCFS would result in overall costs from 2010-2016 of $1.3 billion and overall savings from 2017-2020 of $1.3 billion.

F. Impacts of RFS2 on LCFS

Staff conducted the LCFS economic analyses c onsidering all costs associated with the use of lower-carbon-intensity alternative tr ansportation fuels, including capital costs, operating costs, and distributi on costs. All of the illust rative compliance scenarios showed that when these lower-CI fuels displa ce petroleum-based fuels in the market— with tax credits in place and crude prices at $66-$88/bbl—there is estimated overall savings to the State.

Even with overall estimated savings, the Energy Independence and Security Act of 2007 (EISA), which established additional f ederal renewable fuel standards, known as RFS2, will result in significant changes in California’s transportation fuels and require

ethanol-related infrastructure to be construct ed in the State even without the LCFS. Table VIII-22 below shows the RFS2 require ments explicitly out lined in the EISA.VIII-37 Table VIII-22 RFS2 Requirements Nati onally (Billion Gallons)

Billion

Gallons Renewable

Volume Requirements Advanced

Biofuel Cellulosic

Biofuel * BiomassBased

Diesel Other

Advanced

Biofuel Starch

Derived Biofuel (Corn EtOH)

2008 9.00 0.00 0. 00 0.00 0.00 9.00

2009 11.10 0.60 0. 00 0.50 0.00 10.35

2010 12.95 0.95 0. 10 0.65 0.00 11.88

2011 13.95 1.35 0. 25 0.80 0.00 12.50

2012 15.20 2.00 0. 50 1.00 0.00 13.20

2013 16.55 2.75 1. 00 1.00 0.25 13.80

2014 18.15 3.75 1. 75 1.00 0.50 14.40

2015 20.50 5.50 3. 00 1.00 1.00 15.00

2016 22.25 7.25 4. 25 1.00 1.50 15.00

2017 24.00 9.00 5. 50 1.00 2.00 15.00

2018 26.00 11.00 7. 00 1.00 2.50 15.00

2019 28.00 13.00 8. 50 1.00 3.00 15.00

2020 30.00 15.00 10. 50 1.00 3.00 15.00

2021 33.00 18.00 13. 50 1.00 3.00 15.00

2022 36.00 21.00 16. 00 1.00 3.50 15.00
Staff highlighted 2010 -2020, the period of time addressed by the proposed LCFS regulation.

* Cellulosic Biofuel is a subset of Advanced Biofuel. For example, of the 15 billion gallons of Advanced

Biofuel required in 2020, 10.5 billion gallons must be Cellulosic Biofuel.

The RFS2 volumetric requirements apply nati onwide; where the volumes of renewable

fuels are consumed is not mandated. If California were to receive its proportional share of RFS2 fuels, based on historical fuel cons umption (11.3 percent of the nation’s total),

the amount of these fuels in the State is estimated in Table VIII-23 below.VIII-38 Table VIII-23 California RFS2 Proportional Share (Billion Gallons)

Billion

Gallons Renewable

Volume Requirements Advanced

Biofuel Cellulosic

Biofuel BiomassBased

Diesel Other

Advanced

Biofuel Non-Adv Biofuel (Corn EtOH)

2008 1.02 0.00 0. 00 0.00 0.00 1.02

2009 1.25 0.07 0. 00 0.06 0.00 1.17

2010 1.46 0.11 0. 01 0.07 0.00 1.34

2011 1.58 0.15 0. 03 0.09 0.00 1.41

2012 1.72 0.23 0. 06 0.11 0.00 1.49

2013 1.87 0.31 0. 11 0.11 0.03 1.56

2014 2.05 0.42 0. 20 0.11 0.06 1.63

2015 2.32 0.62 0. 34 0.11 0.11 1.70

2016 2.51 0.82 0. 48 0.11 0.17 1.70

2017 2.71 1.02 0. 62 0.11 0.23 1.70

2018 2.94 1.24 0. 79 0.11 0.28 1.70

2019 3.16 1.47 0. 96 0.11 0.34 1.70

2020 3.39 1.70 1. 19 0.11 0.34 1.70

2021 3.73 2.03 1. 53 0.11 0.34 1.70

2022 4.07 2.37 1. 81 0.11 0.40 1.70 Staff highlighted 2010 -2020, the period of time addressed by the proposed LCFS regulation.

* Cellulosic Biofuel is a subset of Advanced Biofuel. For example, of the 1.7 billion gallons of Advanced

Biofuel required in 2020, 1.19 billion gallons must be Cellulosic Biofuel.

Table VIII-23 shows that the total RFS2 et hanol volume for the State, assuming proportional share, is 3.39 bill ion gallons in 2020. Scenar io 2 had the highest amount of ethanol required for compliance at 3.08 billion gallons. Therefore, the total RFS2- mandated volumes of ethanol would satisfy the total volumes required by LCFS. On the other hand, the carbon intens ity of the RFS2-mandated et hanol does not meet the requirements of the proposed LCFS; staff es timates that RFS2 will achieve about 30 percent of the GHG emission r eductions as the proposed LCFS.

The impact of RFS2 on the proposed LCFS regulat ion is significant, however, in that the vast majority of the infrastr ucture costs related to importi ng, storing, distributing, and dispensing ethanol in California will occu r under RFS2, independent of California’s adoption of the LCFS. The proposed LCFS regul ation would achieve significantly more GHG emissions reduction over RFS2, as discu ssed in Chapter II, wit h little additional costs—essentially requiring the biofuels to hav e a lower carbon intensity than RFS2- compliant fuels. (See discussion in section G.2. below for specific RFS2 impacts on the capital costs of the proposed LCFS.)

The marginal cost of meeting LCFS require ments instead of RFS2 mandates is related

to the amount of advanced and cellulosic ethanol used in California’s transportation

fuels in lieu of corn-based ethanol that w ould be imported into the State under RFS2. As shown in Table VIII-8, cellulosic et hanol produced from waste products, when the technology is proven on a commercial scale, is estimated to be less costly to produceVIII-39 than corn-based ethanol. C onsidering the $1.01/gal tax credit for cellulosic ethanol producers, this cost different ial is more evident. Theref ore, there would be a market incentive to produce more cellulosic ethanol than RFS2 requires.

Should the State’s estimated 18 cellulosi c ethanol plants be constructed and provide 0.9 billion gallons per year of lower-CI ethanol, then California would have to import about 2.2 billion gallons of lower-CI cellulo sic ethanol to meet t he requirements of

Gasoline Scenario 2. This cellulosic volu me should be available nationally, and the LCFS may attract more of it to the State in lieu of Midwest corn ethanol. Furthermore, the cellulosic ethanol required by RFS2 ma y be lower-CI than the minimum required (a 60 percent reduction from baselin e) if sufficient waste cellulosic feedstock can be used.

Staff estimates that, when cellulosic ethanol production is proven on a commercial scale, market forces will result in wast e-derived cellulosic ethanol being more costeffective than corn-based ethanol nationally; t he LCFS will attract more volume to the State; and, despite achievin g additional GHG emission reduct ions, the LCFS will not result in incremental costs or savings relative to RFS2.

G. Potential Costs and Savings to California Consumers, Including

Businesses

In this section, staff estimates the compli ance costs and potential savings for California businesses for the proposed LC FS regulation. The analysis estimates the overall total statewide impact to businesses, the impact to a typical business, and impacts to industry sectors.

1. Possible Distribution of Savings

As summarized in Section D, all of the scenari os resulted in overall savings relative to fuel production, procurement and delivery, as less expensive alternative fuels displaced the more expensive petroleum-based fuels. These savings can be distributed several ways, including:

a. Increased Profits for Lower-CI Fuel Suppliers

The estimated gasoline and diesel producti on and distribution costs in Table VIII-1 included Energy Commission-estimated “refiner y-to-rack” and “rack-to-retail” margins, which contain some profit margin. Theref ore, at least some of the estimated net savings will be realized as profit s for the lower-CI fuel suppliers.

Given the technical challenges of scaling up pilot-project size biorefineries and the high capital costs of some of the lower-CI-fuel technologies—such as Fischer-Tropsch diesel (at nearly a billion dollars for a 50 MGY pl ant)—potential investors may require a more attractive rate-of-return before risking capi tal. Therefore, the lower-CI fuel industry reaping all of the savings as pr ofits is a reasonable scenario.VIII-40 b. Lower Fuel Prices for Consumers

This estimated savings for the scenarios tr anslates into $0.02 to $0.08/gge for the entire California gasoline market, and $0.03 to $0. 04/DGE for the entire California diesel market. Given that gasoline and diesel retail prices have been volatile over the last couple of years, a savings of one to five cents per gallon of fuel would not seem

remarkable for most consumer s. Nevertheless, some of the savings could be shared with consumers through lower prices at the pump.

c. Lower Fuel Prices fo r Specific Consumers

A third option could be a shared savings with consumers for only some lower-CI fuels, such as electricity and hydrogen. An example of this is lower electricity tariffs for recharging electric vehicles during off-peak hours. The power is readily available and provided to the consumer at a reduced rate.

d. Use of Lower-CI Fuels Has Broad Economic Impact on Transportation Fuel Pricing

An increased use of lower-CI fuels may have a broader, more complex impact on the overall transportation fuel market. Ex amples of these impacts might be:

Lower California gasoline and diesel pric es due to lower in-state demand and less pressure on refinery production: The proposed LCFS could reduce demand for petroleum-based transportation fuels in the Stat e, alleviating the pressure on California refineries to produce greater amounts of thos e fuels. The historic Energy Commission outlooks expected the State refining capacity to increase by about 0.5 percent annually to keep up with increased fuel demands. Howe ver, the State’s effo rts to reduce GHGs from transportation and to di versify the mix of transportation fuels are expected to reduce in-state consumption of petrol eum products. Refineries would have less incentive to modify their operations (e.g ., debottleneck processes, install additional processing equipment) to produc e continually higher amounts of transportation fuel.

With sufficient decline in consumption of petroleum-based transportation fuels, the need for importing fuel blendstocks would dec line and price shocks caused by temporary disruptions in refinery capacity would be lessened.

Moderated price increases for crude oil and pet roleum products because of greater use

of biofuels and other alternative fuels: Lower-CI fuels will compete with petroleumbased products in the market. This com petition may have a dampening affect on crude price increases.

Higher overall prices if lower-CI fuels end up costing more than the fuels they replace: Staff understands that the economic analyses of the LCFS is greatly affected by future oil prices and the actual pr oduction costs and timing of lower CI alternative fuels. Economic factors, such as tight supplies of lower-CI fuels or a lengthy economicVIII-41 downturn keeping crude demand down, could result in overall net costs, not savings, of the LCFS. The proposed LCFS allows several years—until 2014 or so—for the introduction of second- and third-generation lo wer-CI fuels into the market. ARB staff recognizes that RFS2 fuels will have to be available in significa nt quantities for the proposed LCFS to succeed.

Once adequate quantities of lower-CI fuels are available, disruptions in supply can create temporary price hikes for transportation fuels. The transportation fuel industry in the State should consider potent ial supply disruptions of liquid biofuels when designing and building the necessary infrastructure to transport and st ore these fuels.

2. Overall Expenditures and Investments

The total costs that would be associated with the proposed LCFS regulation, absent RFS2, would be the cost of the constructi on and operation of the biofuel refineries described in Chapter VII, the capital cost of the additional st orage capacity of the biofuels, and the cost of t he infrastructure necessary to dispense the lower-CI fuels (E85, CNG, hydrogen, and electricity). Capi tal costs, including installation, are

discussed below.

a. Biorefinery Capital Cost

Chapter VII discusses the potential construction of biorefineries in California: eighteen

cellulosic ethanol and six corn ethanol plants built by 202 0 with a total annual capacity of 1.2 billion gallons, and five F-T diesel and one FAHC diesel plants built by 2020 with a total annual capacity of 300 million gallons. The estimated capital investment for these new businesses is approximately $8.5 bill ion (five corn ethanol plants are already built). However, because of the requirements of RFS2, staff expects these facilities to be constructed without the proposed LCFS.

According to a UC Davis research paper developed for the Western Governors Association(18), 300 million gallons is the ma ximum volume of biofuels that can be produced in California. Based on Gasoline Scenario 2, the scenario with the highest overall ethanol demand, and Die sel Scenario 1, the scenario with the highest biodiesel demand, staff estimates that additional biofuels will have to be imported into the State to meet these two illustrative compliance exam ples. Staff assumes that RFS2 mandates

will make these fuels available.

b. Ethanol Storage Tanks

Staff estimates that 35 new ethanol storage tanks with a capacity of one million gallons per tank would have to be built to handle the required volumes of ethanol. The capital investment for installing these new tan ks is approximately $1. 4 million dollars per storage tank, or $50 million total(88).VIII-42 c. E85 Dispensers

For E85 dispensing infrastructure, Scenario 2 has the most E85 stations at 5,000. Assuming $172,000 per installation, t he total cost would be $860 million.

d. Hydrogen Dispensing

For hydrogen fueling stations, Scenario 4 has the most FCVs. To provide hydrogen for these vehicles, staff estimates that 200 fue ling stations would need to be built. At $2.7 million apiece, the total cost would be $540 million.

e. CNG Dispensing

For CNG dispensers, Scenario 3 has the most upgrades to existing CNG stations (330) and new CNG stations (70). Assuming $373,000 for upgrading an existing CNG stations (to increase capacit y) and $1 million for a new CNG station at an existing truck stop, the total cost w ould be nearly $200 million.

f. Electricity

The cost of the electrical infrastructure for PHEVs and BEVs is included in the cost of electricity charged to the customers.

The potential capital cost for the new bi orefineries, ethanol storage tanks, and alternative-fuel dispensing ar e presented in Table VIII-24.

Table VIII-24 Potential Capital Costs

Infrastructure Capital Cost (million dollars)

25 Biorefineries 8,500 1

35 Ethanol tanks 50 1

E85 dispensers 860 1

CNG dispensers 200 2

Hydrogen fueling stations 540 2

Electricity Not applicable 3

1 Cost attributable to RFS2 2 Although infrastructure not specifically required to comply with the regulation, it is a possible compliance route 3 Metering cost included in tariff rate

The total potential capital cost of the propos ed LCFS regulation—in the absence of the overlapping RFS2 requirements—is estimated at $10 billion over the next decade. However, if the RFS2 mandates are met an d California receives its proportional share of RFS2 fuel, virtually all of the capital co sts associated with the liq uid fuels (ethanol andVIII-43 alternative diesel) would be borne by RFS2 , not the LCFS. These would include the biorefineries, the et hanol storage tanks, and the E85 dispensers.

Regarding operating costs, staf f assumes that these will include transportation costs of feedstock and product, the routine operationa l costs of the biorefineries, and maintenance of the new equipment. For the bi orefineries, those costs are included in the production-cost estimates in Table VIII-8. For the other infrastructure, including the dispensers, staff assumes maintenance costs of two percent of annual capital recovery, which, at a real interest rate of eight perc ent for 10 years, is estimated at 14.90 percent of the capital cost, or about $2 million dollars.

3. Costs to Businesses

As discussed above, to accommodate the lowe r-CI fuels in the market, businesses will have to invest in the necessary infrastructu re to produce, distribute, and dispense those

fuels.

a. Biorefineries

The costs associated with the expected bior efineries in the St ate are borne by the

investors of those facilities. These invest ors have risked capital with the expectation of being rewarded with profits co mmensurate with the risk.

b. Refiners and Fuel Distributors

A refinery or independent blender may have to install an additional storage tank for the
increased ethanol volumes. Staff estimated t hat cost at $1.4 milli on for a million-gallon (24,000 barrel) tank, including installation. As mentioned previously, RFS2 mandates may require the installation of th is tank, regardless of the LCFS.

These same refineries and independent blenders would have to acquire the alternative fuels for blending. These costs are in cluded in the storage, transportation, and

distribution costs of the fuels in Table VIII-8. C onversely, these blenders would not receive as much petroleum-based blending stocks, which would offset some of the impact of acquiring the alternative fuels. (Section H below discusses a general overall impact on California businesses.)

Staff assumes that the refineries in the State will conti nue to operate at capacity. The displaced petroleum-based fuels will come at the expense of imported blendstocks. The importers of these blendstocks, typica lly oil companies, wil l be impacted by the proposed LCFS, as these imported blendstocks ar e used in the California transportation fuel market, which receives a pr emium price over other markets.VIII-44 c. Service Station Owners

Since the proposed LCFS regulation does not m andate the installation of E85, CNG, or hydrogen dispensers at any specific facility, facility owners who choose to invest in these fuels will do so with the expectation of recovering the costs and increasing profits.

d. Other Businesses

Electrical utilities, natural gas providers, and hydrogen providers who would wish to optin to the LCFS to generate credits would do so voluntarily. Businesses for which transportation fuels are a significant expense (taxis, trucking firms, etc.) should not be impacted by the proposed LCFS, as overall tr ansportation-fuel costs are estimated to

decline or be unaffected for the consumer.

If RFS2 or the LCFS induces the utilizati on of the vegetative and paper fractions of municipal solid waste for biofuel production, compost companies that currently receive green MSW and recycling companies that rece ive paper would be adversely impacted.

e. Recordkeeping and Reporting Costs

The most obvious additional cost to a business will be recordkeeping and reporting costs. The regulation require s affected parties to submit quarterly progress reports and annual account-balance reports by specified dates using a Web-based, interactive form that ARB staff will establish prior to the impl ementation of the regul ation. The quarterly progress reports are intended to ensure that r egulated parties keep track of their ability to comply with the allowable carbon int ensity at the end of the annual compliance period. The reports are required to contain a specified set of information and data, such as carbon intensities, fuel volumes sold or dispensed, fuel transfer information, and

other information.

The annual account-balance reporting includes the information required for the quarterly reporting, along with additional information re lating to the total credits and deficits generated during the year or carri ed over from the previous year; total credits acquired from another party; total credits transferr ed to other parties; credits generated and banked in the current year; and any defic its to be carried into the next year.

Records must be kept for three years on the product transfer documents, data and reports submitted to the ARB fo r this program, records relate d to each fuel transaction, and records used for compliance or credit calculations.

Staff estimated that it would take one person-year (PY) per affected company to comply with the recordkeeping and reporting require ments. There ar e 15 refineries in California, four importers of CARBOB/diesel (in 2008), four in-state ethanol producers, and four ethanol importers. Assu ming $170,000 per PY, annual reporting and recordkeeping costs would equal $4. 6 million for all affected industry.VIII-45 4. Impact by Industry Sector

The combination of the RFS2 and the proposed LCFS regulation will result in a shift of capital from the petroleum sect or to the agricultural, chemic al, and electricity sectors. The agricultural sector includes the sources of raw feedstock, such as corn, corn stover, other planted crops, and forest residues. The chemical sector includes the biorefineries, while the elec tricity sector includes the l oad-serving entities and other businesses promoting electricity use.

This redistribution of capital among these sectors is essential to the success of the LCFS and RFS2. In fact, RFS2 mandates are part of the Energy Independence and Security Act of 2007, a statute with the ex plicit goal of reducing petroleum use. Furthermore, in response to AB 1076 (Pavle y, 2000), the Energy Commission and ARB prepared and adopted a joint agency report, Reducing California’s Petroleum Dependence . Thus, the diversification of Cali fornia’s transportation fuels, which requires a shift of capital from the petroleum sector is consist ent with well-establish national and State policies.

H. Other Potential Impact s to California Businesses

In this section, staff analyzes the potentia l impacts of the estimated costs of the proposed regulation on busine ss enterprises. Section 11346. 3 of the Government Code requires that, in proposing to adopt or am end any administrativ e regulation, State agencies shall assess the potential for adverse economic impact on California businesses to compete with businesses in ot her states, the impac t on California jobs, and the impact on California business expa nsion, elimination, or creation.

1. Potential Impact on Employment, Business Creation, Elimination or Expansion

RFS2 mandates will displace traditional petroleum-based fuels with biofuels. The proposed LCFS will reduce the carbon intensit y of those biofuels and promote the use of other alternative fuels, such as electricity, hydrogen, and natural gas.

Staff expects the overall impact of the proposed LCFS regulation on California’s economy to be neutral to slightly positive, with some fiscal benefits realized locally in the

State. The 2007 State Alter native Fuels Plan—required by AB 1007 (Pavley, 2005)— evaluated three illustrative examples of alter native fuel use in California: 1) ethanol and hydrogen fuel cell vehicles (FCVs), 2) biofuel s and plug-in hybrid electrical vehicles, and 3) biofuels and hydrogen FC Vs. The report stated:

The Energy Commission and the ARB used a macroeconomic model to evaluate the statewide impacts of the three examples. The examples all assume significant government incentives to partially offset the costs of alternative vehicles, fuel production, and fueling stations. Overall, considering both public and private sectors, all three examples result in small costs or even net savings (decreased expenditures) in the early years, followed by increased expe nditures in later years. The privateVIII-46 sector experiences savings in nearly all y ears. These savings are due to the fact that the private sector saves more in avoided petroleum costs than it spends in

additional vehicle and infrastructure costs.

An earlier Energy Commi ssion study(116), entitled Costs and Benefits of a Biomass-toEthanol Production Industry in California , concluded that state wide economic benefits of a California biomass-to-ethanol industry exc eed the cost of State support for such an industry. Since that report, RFS2 m andates will require ethanol to enter the transportation fuel market in significant am ounts, so the required level of State support for the industry should be less.

While macroeconomic modeling was conducted for these previously analyses, no similar modeling was done for the LCFS r egulation. Staff considered using an equilibrium model, such as the Envir onmental-Dynamic Revenue Analysis Mode (E-DRAM), to conduct a macroeconomic analysi s of the proposed regulation. A model

such as E-DRAM is most useful when it is used to evaluate the economic impacts of a large-scale policy on the Stat e economy. The model can be informative at the sector level with the understanding that some details that may be important in characterizing how producers will respond to a policy change may not be fully reflected in the model.

Because the economic effects of this regulation depend in large part on those responses by the producers, staff determi ned that this type of macroeconomic analysis would not provide useful additional information.

Generally, the following impacts of the proposed LCFS are assumed:

• Biofuels will displace some percent of petroleum-based transportation fuels.

• The displaced fuels will first be import ed blendstocks for transportation fuels, as
the State’s refineries cannot meet the current demand for these fuels.

• Reducing the volume of transportation fuel s that are imported from other states will reduce foreign imports of oil into the U.S.

• State’s refineries will cont inue to operate at capacity duri ng this period. If State demand for fuel declines below this capacity, staff assumes refi neries will export
fuels at some loss in value since Ca lifornia RFG3 has a premium value.

• The biorefineries expected to be bu ilt in the State will provide needed employment, an increased tax base for the State, and value added to the

biomass used as feedstock. These benefits will be more important in rural areas
of the State that are short on employment but ri ch in natural resources.

• Displacing imported transportation f uels with biofuels produced in the State keeps more money in the State.

2. Potential Impact on Business Competitiveness

The proposed LCFS regulation will not adversely affect the competitiveness of

California businesses. Staff has estimated th at the price at the pum p will likely be either a small savings of unaffected, so transporta tion-related businesses will not be harmed. To the extent that California can produce more of its own transportation fuel, lower theVIII-47 amount of money spent on imported oil or petroleum products, and lower dependence on out-of-state biofuels, business competit iveness should be improved overall in the
State.

I. Potential Costs to Local, State, and Federal Agencies

1. Impact to Government Revenue

In this section, staff discusses the impac t of the LCFS regulation on government revenue. The impacts on each level of government are discussed below and

summarized in Table VIII-23. It should be no ted that if RFS2 ma ndates are met and California receives its proportional share of liquid biofuels (as discussed earlier in section F), the revenue impacts from Ca lifornia’s share of the biofuels will be attributable to the RFS2 regulat ion and not the LCFS regulation.

a. Federal

Impacts on federal government revenues ar e based on federal biofuels subsidies sugarcane ethanol tariffs, and the federal excise taxes on transportation fuels sold in California. These impacts vary among the eight compliance scenarios.

In the gasoline scenarios, the lower energy cont ent of a gallon of ethanol will result in more total volume of transportation fuel sold in California, resulti ng in greater excise

taxes collected. The federal motor fuels ex cise tax on gasoline is 18.4 cents per gallon sold, regardless of the blend of the gasoli ne(117). In addition, the 54 cents per gallon and 2.5 percent ad valorem tariffs on imported ethanol (estimated at a total of 60 cents per gallon for sugarcane ethanol) will result in an increase in revenue. Nevertheless, as more biofuels displace traditional transporta tion fuels, the federal government will spend much more on ethanol subsidies ($0.45/gallo n of ethanol blended and $1.01/gallon of cellulosic ethanol produced).

In the diesel scenarios, shifting a portion of traditional diesel fuels to electricity and CNG

will result in less federal excise tax collec ted on transportation fuels sold in California because the tax does not apply to electricity and is less for CNG than for diesel fuels.

The federal excise tax on diesel and biodiese l fuels is 24.4 cents per gallon sold(117) and 18.3 cents per gallon equivalent for CNG( 114). In addition, th e federal government will spend more on subsidies for biodiesel fu els and CNG ($1.00/gallon of biodiesel fuel blended and $0.50/gge of CNG sold).

The regulation would create costs to the Feder al government primarily from biofuel tax credits. Staff estimates the potential loss of federal tax revenue to be $1.3 billion to $1.6 billion in 2020—the year of great est impact—depending on compliance path(s)

chosen.VIII-48 b. State

Impacts on State revenue will be based on State biofuels subs idies, State excise tax and sales tax on transportation fuels sold in California, and the underground storage tank (UST) fee for stored petroleum products. The State biofuel subsidy is in the form

of a reduced excise tax for E85. Californ ia’s excise tax for gasoline and diesel is 18 cents per gallon sold, nine cents per gallon of E85 sold, and seven cents per 100 cubic feet of CNG sold(118). The California state sales tax rate is 6.25 percent(119). The UST fee is 1. 4 cents/gallon of fuel stored(120).

As discussed earlier under federal impacts, in the gasoline scenarios, more volume of

fuel will be sold in California because of t he lower energy content of ethanol. However, some of the volume of traditional gasoline will be displaced by E85, which has a State

excise tax of half the value of traditional fuels, resulting in less excise taxes collected. E85 has 25 percent less energy per gallon than E10. To make E85 more affordable for fueling FFVs, staff assumes the retail price of E85 will be 25 percent less than E10. The lower retail price of E85 will result in less State sales tax collected.

In the diesel scenarios, shifting a portion of traditional diesel fuels to electricity and CNG

will result in less State excise tax collected on transportation fuels sold in California as well as less UST fees collected. In addition, the retail price of CNG in gallons of diesel equivalent will be less than dies el fuels, resulting in le ss State sales tax collected.

The regulation would create cost s to the State in the form of lost transportation-fuel taxes, including excise taxes and sales ta x. There would be no fiscal impact for FY 2009/2010, FY 2010/2011, or FY 2011/2012. Staff estimates t he potential loss of annual state tax revenue to be $80 million to $370 million in 2020—the year of greatest impact—depending on compli ance path(s) chosen.

c. Local Tax Revenue

The local sales tax rate varies among cities and counties. For the LCFS economic analysis, staff assumed 1.75 percent. As was discussed earlier, more volume of transportation fuel will be sold in California under the gasoline scenarios. However, as E85 accounts for more of the volume sold, its lower retail price will result in less local sales tax collected. Similar to the State impac ts, shifting a portion of traditional diesel fuels to electricity and CNG wil l result in less local sales tax collected on transportation

fuels.

The impact of sales tax on transportation fuels from implem enting the potential compliance scenarios could either create rev enue or result in a revenue loss to local government, depending on the compliance path(s) chosen. The impacts to local sales taxes would be location specific. Ther e would be no fiscal impact for FY 2009/2010, FY 2010/2011, and FY 2011/2012. Staff estima tes a potential range of impacts in annual local sales tax revenue of -$51 m illion to +$2 milli on from 2013 – 2020.VIII-49 2. Other Fiscal Effects on Government

The ARB will need resources to implement and enforce the regulation and to contract with third parties to certify particular as pects of a regulated par ty’s claimed fuel pathways. There will be no impact in FY 2009/2010. Staff estimates that three new positions will be needed for FY 2010/2011 and FY 2011/2012—funded at $170,000 per position per year, or $510,000 annually

. These annual costs are necessary to enforce the proposed regulation on an ongoing basis. This includes field inspections, reviewing records and reporting, and tracking regulat ed party compliance with the annual

standards. ARB is considerin g a fee program that would reimburse ARB for costs to implement certain provisions of the proposed regulation related to the review and approval of alternative carbon intensit y values for low carbon fuels.

Staff does not anticipate cost to other state agencies to comp ly with or implement this regulation.

J. Consideration of Alternatives

Staff considered an economic assessment of two alternative approaches to the proposed regulation: 1) impl ement only the federal RFS2 , and 2) implement only a gasoline standard.

1. Implement Only the Federal RFS2

RFS2 achieves only about 30 percent of the GHG reductions projected with the proposed LCFS. (See Chapter X for a discussion of alternatives.) As discussed in Section F above, the margi nal cost of meeting LCFS requirements instead of RFS2

mandates is related to the amount of advanced and cellulosic ethanol used in California’s transportation fuels in lieu of corn-based ethanol that would be imported into
the State under RFS2.

Staff estimates that, when cellulosic ethanol production is proven on a commercial scale, it will be more cost-effective than co rn-based ethanol; therefore, under the most conservative assumption, the LCFS will not increase costs relative to RFS2. With significantly more GHG emi ssion reductions, the proposed LC FS is preferred over the RFS-only alternative.

2. Implement Only a Gasoline Standard

Staff analyses of the three illustrative dies el scenarios estimates that, with the tax incentives in place, lower-CI alternative diesel fuels result in an overall savings relative to the base case of strictly petroleum-based f uels. Excluding diesel from the LCFS will

forgo 20 percent of the GHG emission reductions from th e proposal (see Chapter X), but will also forgo possible overall savings to the State. Theref ore, the LCFS is preferred over the gas oline-only alternative.VIII-50 This Page Left Intentionally BlankIX-1 

### IX. Compliance and Enforcement

The success of the LCFS program depends , in large part, on ARB’s ability to account for credits and deficits generated during a compliance period. This will require the reporting and tracking of a r egulated party’s credit balance during a compliance year, credits bought and sold, credits retained, and other key information required under the regulation. With a few exceptions, the proposal would require reporting to the State to be done electronically to minimize the administrative burden and for efficiency.

To this end, ARB staff is developing a secure on-line LCFS Reporting Tool and Credit Tracking System, a suite of app lications that will support the LCFS reporting and tracking requirem ents. Staff is planning to have both applications available by the end of December 2009. Because these applications are under development, the exact details for these app lications remain subject to change. Thus, this Chapter provides a general di scussion of these tools, as well as the approach towards overall enfor cement of the LCFS.

A. LCFS Reporting Tool

The proposed LCFS mandates that all r egulated parties repor t fuels and other data electronically and on a quarterly and annual basis. The LCFS Report Tool (LRT) will provide a secure, web-bas ed data collection and report-generation application to help regulated parties meet the reporting requirements. Judicious use of these tools can help a regulat ed party maintain compliance with the regulation and determine if a shortfall is im minent before a violat ion of the LCFS

occurs.

An accompanying step-by-step user gui de will be available online. The establishment of the user pr ofile will occur at the point of initial user registration when an account is created and approved. The user account may be the “regulated party” for a fuel(s ) or a person responsible for reporting for one or more regulated parties. The linkage betwe en a user and regulated parties will be integrated into the user profile. Along wit h unique login information, the use of an electronic signature that complies with applicable State law should help deter fraudulent reporting.

1. Identification of Regulated Parties

The identification of the regulated parti es will be based upon section 95484 of the LCFS Regulation, “Requirements for Regul ated Parties.” Depending on the fuel category and whether a transfer of ownersh ip has occurred, the regulated party may be a “producer or importer,” a “person” , an “entity”, “recipi ent of ownership,” or some other party as set forth in the proposal. In cases of transfer of ownership, the LRT will be designed to expect submittal of accompanyingIX-2 documentation of the specific transfer. The different types of regulated parties will incorporated into the LRT.

2. Reporting Requirements

As part of each quarterly and annually r eport, regulated parties will identify and report fuel carbon intensity values for their fuels, along with the total energy

content of each low carbon fuel component replacement for either gasoline or diesel. The general and specific informa tion required for reporting are specified in section 95484(c), which includes the fo llowing information from Table 3 of that

subsection:

• “Company ID” (linked to specific Regulated Party);

• Reporting period;

• Type of fuel;

• Blended fuel (Y/N);

• If blended, the number of blendstocks;

• Type(s) of blendstock;

• Federal renewable fuel identificati on (RIN) numbers that are retired for facilities in California (for gasoline and diesel fuel);

• Blendstock type;

• Blendstock feedstock;

• Amount of each blendstock (MJ);

• Feedstock origin;

• Production process;

• Fuel carbon intensity from the Lookup Table;

• Amount of each fuel as gas oline replacement (MJ); and

• Amount of each fuel as dies el fuel replacement (MJ).

This input, along with others specified in the proposal, will be stored in the LRT database. The “unadjusted” (i.e., befor e adjustment with the Energy Economy Ratio or EER) carbon intensity for the fuel, along with the “compliance” average fuel carbon intensity from Table 1 or 2 in the regulation (whi chever applies) will be used in the credit balancing calculation. This calculation will be implemented as part of the credit tracking system described later.

Quarterly progress reporting will begin for calendar year 2010 and continue each year thereafter. This reporting to the LRT is required for all regulated parties, including those that voluntarily opt into the LCFS program sole ly to generate only credits. The LRT will provide a syste m-generated online reporting form each quarter for this purpose. Quarterly repor ts (for the most recently completed quarter) will be required to be in system by May 31 st , August 31 st , November 30 th
and February 28 th (or 29 th ) of each year.

The LCFS requires regulated parties to s ubmit an Annual Compliance Report by April 30 th (starting in 2012 for calendar year 2011) . This reporting is required forIX-3 each year thereafter. For convenience, staff plans to design the LRT application to remind each regulated party in advanc e of its annual reporting obligation via

email near the end of each reporting period. All r eport submittals will be date stamped and late reports will be flagged. Thos e regulated parties that are out of compliance with the quarterly reporting requirements will be notified by the system within 2-3 days of a late submittal.

Only electronically uploaded reports in a sp ecified format will be accepted, rather than hardcopies. As noted, the LRT wi ll require an electronic signature, along with each submitted report, which meets the requirement of Title 2, CCR, section

22000 et al. The LRT will facilitate the uploading of additional scanned information in a PDF file to accompany t he online report submittal, if required.

This would be in cases where there is a transfer of compliance obligation by written contract and the regul ated party must provide the Executive Officer with the “product transfer document” or other written instrument and report the applicable information identif ied in section 94584(a)(1)(B ), (a)(1)(C), (a)(1)(D), (a)(2)(B), (a)(2)(C), (a)(4)(B), (a)(4)(C), (a)(5)(D), or (a)(7)(C), whichever applies.

Output reporting tools will provide regulat ed parties with access to their data. Our goal is to provide public access to summary reports of LCFS data and related information without disclosing conf idential business information or trade

secrets.

3. Fuel Carbon Intensity

As noted in Chapter V, t he LCFS allows regulated parties to use Method 1, Method 2A or Method 2B, under specifi ed conditions (both 2A and 2B require Executive Officer approval), for determini ng carbon intensity values for their

fuels. These values will reflect the mu lti-step pathways for producing each fuel. The LRT database will incorporate car bon intensity values from the Lookup Table, which will be accessible online to support LRT users, as well as being accessible to the general public via ARB’s in ternet site. Those regulated parties using Method 1 will identify t he carbon intensity value for a finished fuel directly from the Lookup Table after identifying the fuel and specific feedstock.

As noted in Chapter V, Method 2A will in volve customization of the CA-GREET inputs for the fuel pathways in the Lookup Table. Further, Method 2B allows for new fuel pathways to be documented and approved by the Executive Officer. Upon approval by the Executive Officer of a fuel pathway and carbon intensity pursuant to the requirements in Method 2A or 2B, the result ing carbon intensity value will be placed in the Lookup Table and can be selected from the corresponding drop down list.IX-4 To account for indirect effects, incl uding land-use changes, regulated parties using Method 2A or 2B would need to petition the Executive Officer to conduct the appropriate modeling analysis as set forth in the LCFS regulation. The results of these analyses will be added to the applicable carbon intensity values in the Lookup Table. The resulting adj usted carbon intensity will be shown in a column in the Lookup Table for use in the credit balancing calculations.

B. Credit Tracking System (CTS)

As an adjunct to the LRT, ARB staff is developing the Credit Tracking System (CTS) as an online application that will en able regulated parties to track their LCFS credit balance and credit trades. The CTS will securely maintain and report credit/deficit status as well as a credit trading history for each regulated party. The user interface will inclu de detailed annotations and online help to facilitate reporting. The S ystem will handle all fuels calculations required to
establish the “Credit” or “Deficit” value fo r each regulated party. This will facilitate

the LCFS credit balance determination.

The CTS will compare the over all yearly credits/deficits to the LCFS target value for the compliance period and determine wh ether the regulated party meets the required credit balance. A positive val ue will represent “Credits Generated” and a negative value will represent a “Deficit”. A zero or positive total credit value will indicate that the regulated party has met its credit balance requirement for that compliance period. A negative value will indicate that the regulat ed party has not met its credit balance requirement.

The CTS will derive or tra ck the following from input provided by the regulated parties through the companion LCFS Reporting Tool:

• Total credits or deficits generated per reporting quarter;

• Total credits or deficits gener ated per annual compliance period;

• Carryover credits from the prev ious annual compliance period used for compliance;

• Credits acquired from another LCFS regulated party during the compliance period;

• A deficit carried over from the previous annual compliance period;

• Credits sold to another LCFS regulated party during the compliance period;

• Credits exported to another progr am during the compliance period; and

• Credits retired.

The CRT credit/deficit value will be recalculated and updated as new quarterly carbon intensity data are submitted by a regulated party to the CTS through the LCFS Reporting Tool. This will provide up-to-date results for a given annual compliance period. Previously generated compliance values will be saved and maintain as part of the credit tracking hi story for previous compliance periods.IX-5 The system will also maintain a complete history of “transactions” associated with the purchasing, selling, and exporting of credits. This information will be secured and available only to each regulated par ty that submitted the data, ARB enforcement and program staf f, or as otherwise set forth under State law.

C. Description of Enforcement Approaches

Enforcement of the LCFS r egulation will generally involv e the following activities:

• receiving quarterly and annual reports from the regulated parties;

• reviewing the reports for completeness and accuracy;

• evaluating the data in the reports to determine if the regulated party is in compliance with the requirem ents of the regulation;

• conducting field investigations and audits of the regulated parties to verify

and validate the information s ubmitted in the reports;

• preparing and issuing not ices of violation;

• meeting with violators for the pur pose of mutual settlement; and

• participating in litigation, if necessary.

It is anticipated that a new database may need to be developed in order to handle the reporting and auditing functi ons for enforcement purposes.

All these activities are necessary to provide an adequate enforcement presence to maintain a level playing field among the regulated parties, incentivize compliance, and deter noncompliance.

D. Penalties and Other Remedies for Violations of the LCFS

The proposal contains enforce ment provisions that aut horize the imposition of penalties and other forms of relief for viol ations of any LCFS provision. The enforcement provisions provide a systemat ic basis for assessing penalties that are fair, consistent, and effective at maintaining compliance and deterring noncompliance. These provis ions are summarized below.

Consistent with Health and Safety C ode (H&SC) section 38580 – a State law enacted by AB 32 – the proposed regulation provides that the following remedies are available for a violation of any LCFS provision:

(1) Injunctive relief under H&SC section 41513; (2) Civil and criminal penaltie s under H&SC section 42400 et seq. 63 ; and (3) Civil and criminal penalties under H&SC section 43025 et seq.

63 H&SC Division 26, Part 4, Chapter 4, Article 3, section 42400 et seq. (also referred to as “Part 4”).IX-6 The proposed regulation additionally provides that any LCFS violation is also subject to all other penalties and re medies permitted under State law.

Under H&SC section 41513, any violation of an ARB regulation may be enjoined by a court in a civil action brought in the name of the peopl e of the State of

California. There is no need for the Stat e to show the lack of an inadequate remedy at law, or irreparable damage or loss – showings that are required under some other injunction statutes. Injuncti ve and other forms of relief may also be

available under Business and Professions Code section 17200 et seq. (i.e., for unfair business practices), as we ll as other applicable State law.

H&SC sections 42400 et seq. provide fo r criminal, civil, and administrative penalties for violations generally involvin g nonvehicular sources of air pollutant emissions. It provides a tiered penalty system, with the penalti es increasing in severity based on the violator’s degree of culpability (i.e., regulated party). Penalties are most severe if the noncompl iance results in a specified injury, and under some provisions, if the violator is a corporation. 64 Each day of the violation constitutes a separate offense. As an alternative to civil penalties, ARB may under specified conditions seek administr ative penalties as specified in section

42410. 65

H&SC sections 43025 et seq. 66 set forth penalty provisions specific to ARB’s fuel regulations, which are adopted pursuant to AR B’s authority to regulate vehicular sources of air pollution. These Part 5 provisions generally parallel the tiered penalty structure for violations set forth in Part 4 (H&SC section 42400 et seq.). 67
Similarly, administrative penalties are authorized as an alternative enforcement mechanism under specified conditions. 68

Unlike the provisions in Part 4, H &SC section 43029 provides for additional incremental penalties, which are designe d to eliminate t he economic benefits gained from a regulated party ’s noncompliance. Ther e are additional penalties for excess emissions based on a per ton multiplier: $9,100 per ton of excess emissions for violations of gasoline r equirements, and $5,200 per ton of excess

emissions for violations of diesel fuel requirements. These values may be periodically adjusted for inflation.

64 Under the tiered penalty system in Part 4 (H&S se ction 42400 et seq.), stri ct liability offenses, negligent offenses, and knowing offenses are a ll misdemeanors punishable by progressively higher fines and/or jail terms. For example, t he fine is up to $1,000 per day for a strict liability offense, $25,000 per day when negligence is in volved, and $40,000 per day when the offense is committed knowingly. A violation committed willfully is a public offense with a penalty of up to $125,000 per day. All violations have considerably hi gher penalties when actual injuries resulted. Corporations are generally subject to higher penalties.

65 See Cal. Code Reg. title 17 sections 60065.1-60065.45.

66 H&SC Division 26, Part 5, Chapter 1.5, sections 43025 et seq. (also referred to as “Part 5”).

67 H&SC section 43027 sets maximum penalties for different levels of offenses: $250,000 per day for willful and intentional violations, $50,000 per day when negligence is involved, $35,000 per day for strict liability violations, and $25, 000 per day for falsification of records.

68 See Cal. Code Reg. title 17 sections 60075.1-60075.45.IX-7 For penalties under both Part 4 and Part 5, State law provides for potential mitigating factors to be taken into acc ount in assessing the appropriate penalties for a violation, including: the extent of harm caus ed, the nature and persistence of the violation, the magnitude of excess emissions, the compliance history of the defendant, preventive efforts taken by t he defendant, the effort required to comply and accuracy of available test me thods, the cooperat ion of the defendant during investigations, and business size. 69

69 See H&SC sections 42403 and 43031.IX-8 This Page Left Intentionally BlankX-1 

### X. Analysis of Alternatives

In this Chapter, we provide an analysis of the alternatives to the proposed regulation. The Chapter is divided into two sections. The first section addresses alternative approaches to the proposed regulation. The second section addresses various specific alternatives to s pecific provisions of the regulation. A

detailed discussion of each alternative considered follows in the subsections

below.

A. Alternative Approaches to the Regulation

The staff analyzed four different appr oaches to the regulation; these are

summarized below:

• Only implement the federal renewable fuels program;

• Implement a gasol ine standard only;

• Delay LCFS Pending Possible National Regulation; and

• Delay LCFS Pending Development of Regional GHG Programs.

ARB staff evaluated these four potential al ternative approaches to the regulation

and found that none was more effective in carrying out the purpose of the proposed regulation, or would be as effective and less burdensome than the proposed regulation. The following sections discuss each alternative.

1. Implement Only the Federal RFS2

The U.S EPA has adopted its Renewable Fuel Standard (R FS2) regulation—title 40, Code of Federal Regulations (CFR), part 80, section 1100 et seq.— that mandates the blending of specific volume s of renewable fuels into gasoline and diesel sold in the U.S. each year. As defined, “renewable fuels” under the RFS superficially resembles the list of liquid tr ansportation fuels subject to the LCFS. However, there are a number of reasons why the RFS2 is not comparable to the

LCFS.

Congress adopted a renewable fuels st andard in 2005 and strengthened it in December 2007 as part of the Energy Independence and Security Act (EISA). The RFS2 requires that 36 billion gallons of biofuels be sold annually by 2022, of which 21 billion gallons must be “advanced” biofuels and the other 15 billion gallons can be corn ethanol. The advanced biofuels are required to achieve at least 50 percent reduction from base line lifecycle GHG emissions, with a subcategory required to meet a 60 perc ent reduction target. These reduction targets are based on lifecycle emissions , including emissions from land use changes. Additional information on the RFS2 is presented in Chapter II.

Although the RFS2 is a step in the right direction, the RFS2 volumetric mandate alone will not achieve the objectives of the LCFS. The RFS2 targets onlyX-2 biofuels and not other alter natives; therefore, the potential value of electricity, hydrogen, and natural gas are not consider ed in an overall progr am to reduce the carbon intensity of transportati on fuels. In addition, t he targets of 50 percent and 60 percent GHG reductions only estab lish the minimum requirements for

biofuels. It forces biofuels into a sm all number of fixed categories and thereby stifles innovation. Finally, it ex empts existing and planned corn ethanol production plants from the GHG requirement s, thus providing no incentive for reducing the carbon intens ity from these fuels.

By contrast, the LCFS regulates all tr ansportation fuels, including biofuels and non-biofuels, with a few narrow and specif ic exceptions. Thus, non-biofuels, such as compressed natural gas, electric ity, and hydrogen, play important roles in the LCFS program. In addition, the LCFS encourages much greater

innovation than the federal program by providing important incentives to continuously improve the carbon intensity of biofuels and to deploy other fuels with very low carbon intensities.

If California were to rely solely on the RF S2 (i.e., the “No LCFS” alternative), the

State would not achieve the GHG emission reductions called for in AB 32 Scoping Plan and Executive Order S-01-07. The RFS2, by itself, achieves only approximately 30 percent of the GHG reductions pr ojected under the LCFS program. Additional deta ils on this analysis are presented in Chapter VI. Therefore, this alternat ive was deemed to be not as effective as the proposed

action.

Furthermore, as discussed in Chapter VII I, the marginal cost of meeting LCFS requirements instead of RFS2 mandates is related to the amount of advanced

and cellulosic ethanol used in California’s transportation fuels in lieu of cornbased ethanol that would be impo rted into the State under RFS2.

Staff estimates that, when cellulos ic ethanol production is proven on a commercial scale, it will be more cost-effective than corn-based ethanol; therefore, under the most conservative assumption, the LCFS will not increase

costs relative to RFS2. With significantly more GH G emission reductions, the proposed LCFS is preferred over the RFS-only alternative.

2. Implement a Gasoline Standard Only

The LCFS includes two separate standards for gasoline and the alternative fuels that can replace it, and for diesel fuel and its replacements. A gasoline standard only approach has been advocated by various stakeholders to allow for a simpler implementation of the regulat ion in the early years. ARB staff does not support this approach as discussed below.

Staff believes that a comprehensive approa ch from the beginning will allow for the development of a more robust credit market and will provide greater certaintyX-3 on future expectations. Fuel producers will need to consider overall approaches to providing low carbon transportation fuel s. Given the fact that the compliance requirements are substantially less in the early years should provide fuel producers adequate time to develop appropriate compliance options. In addition, because diesel accounts for approximat ely 20 percent of the total liquid transportation pool of California, failure to include diesel will result in a loss of approximately 20 percent of t he LCFS benefits. Therefore, this alternative would not meet the requirement s of AB 32 and was deemed to be not as effective as the proposed action.

From an economic perspective, staff analyse s of the three ill ustrative diesel scenarios estimate that, with the tax inc entives in place, lower-CI alternative diesel fuels result in an overall savings relative to the base case of strictly petroleum-based fuels. (See Chapter VIII.) Excluding diesel from the LCFS will not only forgo 20 percent of the GHG em ission reductions from the proposal, but will also forgo possible overall savings to the State. Theref ore, the LCFS is preferred over the gaso line-only alternative.

3. Delay LCFS Pending Possible National Regulation

In taking positive steps toward reducing GHG emissions, ARB staff believes that California should not simply defer to t he federal government. Deferring to the federal government would conflict with the requirements of AB 32 and Executive Order S-01-07. As such, ARB is without authority to simply def er to the federal government. Moreover, the implementation of successful state-level programs can hasten the development of similar progr ams by other states, and, ultimately, by the federal government. Similarly, a single successful national program based

on California’s efforts can stimulate the development of related programs in other nations. In this respect, California seeks to implement an LCFS that will accelerate the adoption of similar measures nationally, and, possibly, internationally.

Even if ARB were to defer to the feder al government, doing so would not ensure

that effective action at the federal level would be taken in the near future to meet the requirements of AB 32. The U.S. EPA has not specified a timeframe by which it would develop a national LCFS-ty pe regulation. Ther efore, deferring to the federal government’s e fforts to develop a national LCFS program would be unacceptably open-ended. Based on the above reasons, staff deemed this alternative as

infeasible and not as effect ive as the proposed action.

4. Delay LCFS Pending Development of Regional GHG Programs

One potential regulatory alte rnative would be to delay the LCFS regulation pending development of regional GHG programs, like the one under development by the Wester n Climate Initiative (WCI). In the Western ClimateX-4 Initiative Design Recommendations doc ument, the Partners recommended the
WCI include direct emissions from gasoline and diesel combusted as transportation fuel. They also recommended that direct CO 2 emissions from the combustion of pure biofuels be excl uded from the cap-and-trade program.

ARB staff believes it is critical to incl ude full fuel-lifecycle GHG emissions and to

address both fossil fuels and biofuels. T herefore, California is moving forward with the development of the LCFS. We re cognize that combined state, national, and international efforts are necessary to solve the global warming crisis. We will

continue to coordinate our work with t he states and Canadian provinces in the Western Climate Initiative. We apprec iate their efforts to reduce greenhouse gases, and we will work with the WCI partner s in their future efforts to assess whether and how to include upstream em issions associated with bio and fossil fuels prior to the start of the cap and trade program.

At this time, ARB staff understands t hat the WCI is awaiting California’s development of the LCFS regulation bef ore the WCI establishes its regional regulation. Because of this, delayi ng the LCFS development while the WCI’s efforts are pending would make little s ense. Therefore, staff deemed this

alternative as infeasible.

B. Specific Proposed Modifi cations to the Regulation

1. Exclude Indirect Land Use Effects

Carbon intensities are calculated under t he LCFS on a full fuel lifecycle basis.

This means that the car bon intensity value assigned to each fuel reflects the

GHG emissions associated with that f uel’s production, transport, storage, and
use. In addition to these direct GHG emissions, some fuels create emissions due to indirect land use change effects. An indirect land-use change impact is initially triggered when an in crease in the demand for a crop-based biofuel begins to drive up prices for the necessary feeds tock crop. This price increase causes farmers to devote a larger proportion of their cultivated acreage to that feedstock crop. Supplies of the displaced food and feed commodities subsequently decline, leading to higher pric es for those commodities.

The lowest-cost way for many farmer s to take advantage of these higher commodity prices is to bring non-agricult ural lands into production. These land use conversions release the carbon seques tered in soils and vegetation. The resulting carbon emissions constitute the “indirect” land use change impact of increased biofuel production.

Efforts to model indirect land use impacts indicate that the full lifecycle carbon intensities of some biofuels may be sim ilar to or even higher than the carbon intensities of conventional petroleum- based fuels. ARB staff has been and will

continue to work with modelers at t he University of California and PurdueX-5 University to derive indirect land use change estimates that are empirically based, defensible, and fully open to public scrutiny and comment.

Based on the work done to dat e, crop-based biof uels contribute to some indirect land use impacts. However, the magni tude of this impact has been questioned by renewable fuel advocates. Land use change is driven by multiple factors. Because the tools for estimating land use change are few and relatively new, biofuel producers argue that land use change impacts should be excluded from carbon intensity values pending the development of better estimation techniques. Based on its work with university land use change researchers, however, ARB

staff has concluded that the land use impacts of crop-based biofuels are significant and must be included in LCFS fuel carbon intensities. To exclude

them would allow fuels with carbon intens ities that are sim ilar to gasoline and

diesel fuel to function as low-carbon f uels under the LCFS. This would delay the development of truly lo w-carbon fuels and jeopardize the achievement of a 10 percent reduction in fuel carbon intensity by 2020.

Additonal information on excl uding indirect land use fr om the proposed regulation is presented in Chapter VI.

Based on the reasons discussed above, ARB staff deemed this suggestion as

infeasible.

2. Include Light Duty Diesel Vehicles

This suggested modification would treat di esel-fueled, light-duty vehicles (diesel LDVs) as being alternative vehicles to gasoline LDVs and give them credit accordingly for reduced carbon intens ity as compared to gasoline.

Staff agrees that light-duty vehicles are more energy efficient than gasoline

vehicles. Staff estimates that there is about a 20 pe rcent improvement in the adjusted carbon intensity of light-duty diesel vehicles using conventional diesel fuel compared to gasoline vehicles. However, the focus of the LCFS is encouraging and promoting impr ovements in the carbon in tensity of conventional

fuels. The use of conventional diesel fuel would not achieve the objective of encouraging low carbon fuels. Furthermore , unlike electric vehicles or fuel cell vehicles, allowing light-duty diesel vehi cles in the LCFS does not provide any significant long term benefits of promoti ng significantly lower carbon fuels and more energy efficient vehicles.

In addition, the introduction of these vehi cles would already be credited under the vehicle GHG regulations 70 adopted pursuant to AB 1493 (P avley, Stats. 2002, ch. 200). Thus, assigning LCFS credits fo r diesel LDVs would amount to double crediting. This would result in a subst antial loss in GHG reductions due to the LCFS. Therefore, staff deemed this suggested modification as infeasible.

70 13 CCR §§1900, 1961, and 1961.1.X-6 Additional information on the impact of in cluding light-duty diesel vehicles is presented in Chapter VI.

3. Develop Oil Sands/Oil Shale-Specific Pathway

The methods used to extract, refine, and tran sport crude from oil sands, oil shale and other high carbon-intensity crude source s can result in a relatively high carbon-intensity rating for that feedsto ck. Staff is developing a pathway or pathways for petroleum fuels refined fr om high carbon-intensity crude oil, including crude oil from oil sands. The carbon intensity for those pathways will likely be higher for most pathways than the carbon intensity of fuels refined from conventional crude oils. However, t he proposed regulation generally requires accounting for these higher intensity crude oils that are not currently used in
California and sets forth alternatives , provided the regulat ed party establishes that the higher GHG emissions from thos e crude oils are substantially mitigated through carbon capture and sequ estration or similarly innovative technologies.

4. Electricity Accounting Met hods for Electric Vehicles and PlugIn Hybrid Electric Vehicles

ARB staff proposes to allow both electric vehicles and plug-in hybrid vehicles to generate LCFS credits, provided the electr icity used to charge the vehicle is directly metered and reported by the regulated party. Under a statewide Advanced Metering Initiative, utilities are replacing old meters with new, more sophisticated digital meters from 2009 through 2011-13 (depending upon the individual utility.)

Stakeholders recommended that the requirem ent of direct metering apply only

when customers receive advanced meters wi th sub-metering capability, or 2015 (whichever is earlier). They also suggested that, until the direct metering requirement is applied under their re commended schedule, the utilities be allowed to use an estimation technique to generate credits, possibly with discounting factors to account for uncer tainty. Stakeholders noted that, under the “cost of service” regulation by the California Public Utilities Commissions and the governing boards of muni cipal utilities, the cost of the second meter for transportation purposes is borne solely by th e electric transportation customer. Furthermore, they state that it will take 2-3 years for the development, testing, and verification of sub-metering capability to be incorporated into utility advanced meters and systems (2011-2012 timeframe).

Under the proposed regulation, ARB staff has determined that a requirement for direct metering is the most accurate me thod for determining electric vehicle or PHEV charging. However, staff is further investigating the te chnical challenges of sub-metering electric vehicle chargi ng and the timeframe for the technology roll-out. Staff will propose amendments to the proposed regulation if the analysisX-7 demonstrates an alternative method shoul d be used in the early years of the

program.

5. Alternative Marine Power

Electric alternative marine power, also known as cold ironing or port electrification, provides shore-side electr ical power to a ship at berth while its main and auxiliary engines are turned off. Alternative marine power replaces the use of petroleum fuels when a ship is at dock. Stakeholders have suggested that the use of alternative marine power s hould generate LCFS credits. However, subjecting the production of bunker and marine distillate fuels (i.e., those fuels used in ocean-going vessels) to the LCFS requirements would present jurisdictional challenges that are beyond the scope of the LCFS rulemaking. Such fuels are produced in countries outside the U.S., and subjecting the production of those foreign-made fuel s to the average carbon-intensity requirements of the LCFS would be probl ematic, at best. Therefore, the proposed regulation does not consider f uels used in marine vessels (other than commercial harborcraft) as transportati on fuels that would be eligible for generating LCFS credits.

6. Truck Stop Electrification

Truck stop electrificat ion provides electrical power fr om the grid for truckers to operate the trucks’ heater, air-conditioner an d electrical appliances while at the truck stop, rather than runni ng the truck engine to generate el ectricity. Electricity used by trucks at truck stops in California is consider ed a transportation fuel and could generate LCFS credits, provi ded the metering, reporting and other requirements of the regul ation are satisfied.

7. Electric Transpor t Refrigeration Units

Transport refrigeration units (TRU) are re frigeration systems typically powered by diesel internal combustion engines desi gned to refrigerate or heat perishable products that are transported in various containers, including semi-trailers, truck vans, shipping containers, and rail cars . Although TRU engines are relatively small, ranging from 9 to 36 horsepower , significant numbers of these engines congregate at distribution centers, truck st ops, and other facilities, resulting in the potential for health risks to those that live and work nearby. The ARB adopted an
Airborne Toxic Control Measure for transport refrigeration units and TRU generator sets, which requires owners and operators of such equipment to meet stringent PM emissions levels; to have them retrofitted with a PM control device; or to use an alternative technology (includi ng the use of electric standby or other approved technology).

The proposed LCFS regulation does not provide for the generation of LCFS

credits from the use of el ectric transport refrigerati on units. The incrementalX-8 benefits of using electric tr ansport refrigeration units beyond what is required or eligible for early credits in the transpor t refrigeration regulat ion are not expected to be large, and the benefits would be difficu lt to verify. T herefore, staff is proposing not to allow LCFS credits for electric transport refrigeration units.

8. Electric Forklifts

Forklifts are powered industrial trucks used to lift and transport materials, typically in manufacturing and warehousi ng operations. In a typical warehouse setting most forklifts used have load capacit ies between one to five tons. Larger machines, up to 50 tons lift capacity are used for lifting heavier loads. Forklifts are generally electric-, pr opane-, or diesel-powered, although some gasoline and natural gas models are available. El ectric forklifts are common in food warehouses and indoor applications w here CO2 emissions from internal combustion engine forklifts could cause food s poilage or worker safety issues.

In 2006, ARB approved a rule to reduce em issions from propane, gasoline, and natural gas forklifts and other large s park ignited equipment. The rule has two elements. The first requires forklift engi ne manufacturers to meet more stringent

emission limits for new forklifts sold in California. The second element requires operators of existing forklifts to reduce emissions by retrof it or replac ement of the engines or equipment with cleaner models, wh ich could include electric forklifts. a. Existing Forklifts and Similar Equipment

Stakeholders have proposed that existing electric forklifts and other off-road electric transportation equipment be incl uded in the 2010 baseline GHG level for

diesel and that all electric forklifts bot h existing and new be metered and allowed to generate LCFS credits. Under this s uggested modification, the stakeholders argue that the correction for existing equipm ent would already be included in the baseline standard. However, ARB staff is concerned that th is approach allows credits for new equipment that would have been electric anyway, in the absence

of the low carbon fuel st andard. Therefore, ARB staff proposes not to include existing electric equipment in the base line and not to subsequently allow all electric equipment to generate LCFS credits.

b. New Categories of Use

The above concerns notwithstand ing, new electric forklifts that displace internal combustion engines can provide signific ant emissions benefits. Hence, ARB staff proposes that electric forklifts in new applications or categories of use be eligible to generate LCFS credits. Electr ic forklifts required under regulation or used in common practice would not be eligible. A mechanism to allow generation of credits from new categories of electric forklifts needs to be developed before LCFS credi ts could be generated.X-9 9. Establish a Cap on Early Year Credits

A concern has been raised regarding the possibility of generat ing substantial excess credits by some alternative fuels in the early years of the LCFS program, which in turn might stifle the development of low carbon-intensity fuels in the

future. Staff has evaluated this concern and has determined that it is unlikely to occur. To illustrate, our analysis of sugarcane ethanol (the most likely scenario for generating excess credits) sh ows that, although this fuel is expected to have low GHG emissions in some respects, it will have large, offsetting land-use effects. Thus, the carbon in tensity for this fuel will be relatively high, thereby making it unlikely that excess credits in the early year s will be generated.

However, staff will continue to monito r the amount of credits generated and banked and will consider appropriate acti on based on the information available.

10. Establish Different Energy Economy Ratios for Vehicles

Some stakeholders have advocated for diff erent Energy Economy Ratios (EERs) different from those used by staff in t he Staff Report be used for vehicles with emerging, alternative fuel technologi es. Staff has determined that this suggestion cannot be implemented at this ti me due to the lack of data on such emerging technologies. Staff’s current analysis incorporates the best available data that are representative of alternative fueled vehicl es that are commercially available today or in the very near future.

With that said, the best available data on EERs are nevertheless based on limited fuel economy data available for emer ging alternative technology vehicles. For example, in the case of advanced te chnology or emerging vehicles such as battery electric vehicles (BEV), plug-in hy brid electric vehicles (PHEV), fuel cell vehicles (FEV), and heavy-duty compress ed natural gas (CNG) or liquefied natural gas (LNG) vehicles, the data ar e limited to one or two vehicles per category. Therefore, t he proposed regulation specifie s EER values for use until such time that there are more updated data available. As there will only be a

limited number of these advanced vehicles av ailable in the first few years of the LCFS, the amount of credits generated is not likely to be significantly affected.

Staff is committed to re view and update these and other EERs as better data

become available.

11. Use of External GHG credits

The proposed regulation disallows the us e of GHG credits that are generated outside the LCFS program. This is to ens ure that improvements in the LCFS fuel pool occur. However, staff will cont inue to evaluate the feasibility and effectiveness of allowing credits generated from marine and aviation transportation areas, which are not currently included in the LCFS fuel pool, to be used in the LCFS program. ARB staff will provide an update on the potential useX-10 of greenhouse gas credits from lower carbon marine and aviation fuels to be used in the LCFS program as part of the periodic reviews.R-1 

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Appendix B References:

1. California Board of Equalization. (2008) . "Fuel tax rates." Retrieved, from http://www.boe.ca.gov/s ptaxprog/spftrpts.htm

. 2. EIA. (2007). "U.S. Product S upplied for Crude Oil and Petroleum Products." Retrieved, from http://tonto.eia.doe.gov/dnav/pet /pet_cons_psup_dc_nus_mbbl_a.htm

. 3. CEC. (2009). "Calif ornia's Oil Refineries " Retrieved, from http://energyalmanac.ca.gov/ petroleum/refineries.html

. 4. ARB (2007). Emfac 2007. Air Resources Board. 5. Alexander E Farrell, Daniel Sperli ng, and et al. (2007). A Low-Carbon Fuel

Standard for California Part 1: Technical Analysis 6. Antares Group (2008). Strategic A ssessment of Bioenergy Development

in the West. 7. US EPA (2007). Regulatory Impact Analysis: Renewable Fuel Standard Program. O.o.T.a.A. Quality. 116-170. 8. RFA (2009). Renewable Fuels As sociation Biorefineries Locations.

Renewable Fuels Association.

9. Renewable Fuels Association. (2007). "Renewable Fuels Association Ethanol Industry Statistics. " Retrieved, from http://www.ethanolrfa.org/ industry/statistics/#E

. 10. (2007). Congressional Research Serv ice Report for Congress; Agriculture Based Renewable Energy Production. 11. (2008). Attachment E for Landf ill Methane as a Biomass Renewable Energy Source. 12. ARB (1998). Noncombustion Landfill Ga s Control Technologies. California

Air Resources Board. 13. GTI and Prometheus Energy Co mpany (2007). GTI and Prometheus Energy Company Grant Application Package. California Air Resources

Board. 14. Oregon. (2007). "Biomass Energy Homepage." Retrieved, from http://www.oregon.gov/ENERGY/RENE W/Biomass/biogas.shtml#Anaerob ic_Digestion

. 15. CEC. (2008). "Biomass - Anaerobic Digestion." Retrieved, from www.energy.ca.gov/research/renewab le/biomass/anaerobic_digestion/ind

ex.html

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. 28. Michael Kintner-Meyer, Kevin Schnei der, and Robert Pratt (2007). Impacts Assessment of Plug-in Hybrid Vehicles on Electric Utilities and Regional
U.S. Power Grids Part 1: Technical Analysis. Pacific Northwest National Laboratory. 29. Lucy Sanna (2005). "Driving the Solu tion: The Plug-In Hybrid Vehicle."

EPRI Journal. 30. Rolf Schreiber. (2008). "Vehicle to grid (V2G) overview." Retrieved, from http://rechargeit.blogspot.com/2008/09/ vehicle-to-grid-v2g-overview.html

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latissima for Bioethanol." Jour nal of Applied Phycology. 40. John R Benemann (2008). Microalgae Biofuels: A Brief Introduction. 41. NREL (2008). Photobiological Water Splitting. National Renewable Energy Laboratory. 42. Green Car Congress. (2008). "Sapphire Energy Introduces Algae-Derived Bio-Gasoline." Retrieved, from http://www.greencarcongress.co m/2008/05/sapphire-energy.html

. 43. CSR Wire. (2006). "Arizona Public Service and GreenFuel Technologies Corp. Successfully Recycle Power Plant Flue Gases into TransportationGrade Biodiesel and Ethanol." Retrieved, from http://www.csrwire.com/News/6959.html

. 44. Robert Buderi. (2007). "Metcalfe Takes Reins at GreenFuel After Key Setbacks; Company Lays Off Half its Staff, Seeks to Raise Cash." Retrieved, from http://www.xconomy.com/ boston/2007/07/01/metcalfetakes-reins-at-greenfuel-after-key-set backs-company-lays-off-half-its-staffand-seeks-to-raise-cash/

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number: DE-F-G02-00ER86106 for U.S. Department of Energy. US Department of Energy. 48. Jiri van Straelen (2008) . CO2 Capture for refinerie s, a practical approach.
ScienceDirect.com. 49. CEC (2007). WEST COAST REGIONAL CARBON SEQUESTRATION

PARTNERSHIP: SOURCE-SINK CHARACTERIZATION AND

GEOGRAPHIC INFORMATION SYSTE M-BASED MATCHING. California Energy Commission.R-4 Appendix C References:

1. TIAX (2007). Full Fuel Cycle Asse ssment Well to Tank Energy Inputs, Emissions, and Water Impacts. Ca lifornia Energy Commission. 2. Michael O'Hare and et al. (2009). Proper accounting for time increases crop-based biofuels’ GHG deficit versus petroleum. UC Berkeley. 3. S. Solomon and et al. (2007). Climate Change 2007: The Physical

Science Basis. Contribution of Work ing Group I to the Fourth Assessment Report of the Intergovernment al Panel on Climate Change. Intergovernmental Pa nel on Climate Change. 4. NASS (2009). Agricultural Prices . US Department of Agriculture. 5. R. Keeney and T. W. Hertel (2008) . Indirect Land Use Impacts of US

Biofuels Policies: The Im portance of Acreage, Yi eld and Bilateral Trade Responses. GTAP Working Paper 52. Purdue University. 6. USDA (2009). Agricultural Outlook: Statistical Indicators. US Department of Agriculture. 7. Salil Arora, May Wu, and Mic hael Wang (2008). Update of Distillers Grains Displacement Ratios for Co rn Ethanol Life-Cycle Analysis. Argonne National Laboratory. 8. Kent Tjardes and Cody Wright (2002). Feeding Corn Distiller’s CoProducts to Beef Cattle. San Diego State University. 9. R. Lemenager and et al. (2006). The Value of Dis tillers’ Grains as a Livestock Feed. Purdue University. 10. T. J. Klopfenstein (1991). "Efficie ncy of escape protein utilization." Proc.

Distillers Feed Res. Council 46: 77-82. 11. G. L. Cromwell, K. L. Herkelman, and T. S. Stahly ( 1993). "Physical, chemical, and nutritional characterist ics of distillers dried grains with solubles for chicks and pigs." J. Anim. Sci 71: 679-686. 12. F. M. Dong, B. A. Rasco, and S. S. Gazzaz (1987). "A protein quality

assessment of wheat and corn distillers dried grains with solubles." Cereal Chemistry 64: 327-332. 13. A. S. Chaudhry and A. J. F. W ebster (1993). "The true digestibility and biological value for rats of undegraded dietary nitrogen in feeds for

ruminants." 42: 209-221. 14. T. Nakamura, et al. (1994). "Growth efficiency a nd digestibility of heated protein fed to growing ruminant s." J. Anim. Sci. 72: 774-782. 15. S. Uwituze (2008). The effects of feedi ng dry distiller’s grains with solubles on ruminal metabolism, growth perform ance, and carcass traits of feedlot cattle. Kansas State University.

16. T. J. Vasconcelos and M. L. Galyean (2007). "Nutritional

recommendations of feedlot consulti ng nutritionists: The Texas Tech University survey." 85: 2772-2781. 17. F. J. Dooley (2008). Market analysis fo r dried distillers grains in Indiana. Purdue University.R-5 18. Michael R. Lehman and Kurt A. Rosentrater (2007). "Microbial development in distillers wet grai ns produced during fuel ethanol production from corn (Zea mays)." C an J. Microbiology 53: 1046-1052.

19. Kurt A. Rosentrater Ethanol Processing Co-Products: Economics, Impacts, Sustainability. US D epartment of Agriculture. 20. Mike Deering and Marri Carrow. (2009). "Global Update: February 19, 2009." Retrieved, from http://www.grains.org/global-update/1375-globalupdate-february-19-2009

. 21. CEC. (2008). "Energy Alm anac." Retrieved, from http://energyalmanac.ca.gov/

. 22. Argonne (2008). The Greenhouse Gase s, Regulated Emissions, and Energy Use in Transportation (GREET) Model. Argonne National Laboratory. 23. EPRI (1999). Enhanced Oil Recove ry Scoping Study. Electric Power

Research Institute. 24. DOC. (2009). "Oil, Gas & Geothermal - DOGGR Home Page." Retrieved,

from http://www.conservation.ca .gov/dog/Pages/Index.aspx

.R-6 Appendix E References:

1. Susanne Retka Schill (2008). "U.S . ethanol production." Ethanol producer magazine (October).R-7 Appendix F References

1. CEC. (2009). "Calif ornia's Oil Refineries " Retrieved, from http://energyalmanac.ca.gov/ petroleum/refineries.html

. 2. UC Davis (2008). Strategic Developm ent of Bioenergy in the Western

States. Western Gover nors’ Association. 3. ARB (2007). Emfac 2007. Air Resources Board. 4. ARB (2009). Emfac Screenshot T able F6-1. California Air Resources

Board. 5. ARB (2009). Emfac Screenshot T able F6-2. California Air Resources

Board. 6. ARB (2009). GREET Analysis Table F6 -3. California Air Resources Board. 7. ARB (2008). California-GREET Model version 1.8b. Air Resources Board. http://www.arb.ca.gov /fuels/lcfs/lcfs.htm

. 8. TIAX (2007). Full Fuel Cycle Asse ssment Well to Tank Energy Inputs, Emissions, and Water Impacts. Ca lifornia Energy Commission. 9. ARB (2007). CALIFORNIA EVAP ORATIVE EMISSION STANDARDS

AND TEST PROCEDURES FOR 2001 AND SUBSEQUENT MODEL

MOTOR VEHICLES. California Air Resources Board. 10. ARB (2008). The California Low-Emi ssion Vehicle Regulations. California

Air Resources Board. 11. MSCD (2008). E85 Spreadsheet F6-4. California Air Resources Board. 12. Lisa A. Graham, Sheri L. Belisle , and Cara-Lynn Baas (2008). "Emissions from Light Duty Gasoline Vehicl es Operating on Low Blend Ethanol Gasoline and E85." Atmospher ic Environment 42: 4498-4516. 13. Renewable Technology (2005). Renew able Diesel Subcommittee of the WSDA Technical Work Group. WSDA. 14. Aaron Williams, et al. (2006). Ef fect of Biodiesel Blends on Diesel

Particulate Filter Performance. SAE. 15. EPA (2002). A Comprehensive Analysi s of Biodiesel Impacts on Exhaust Emissions. US Environmental Protection Agency. 16. Thomas D. Durbin, J. Wayne M iller, Kent Johnson (2009). For the CeCERT Engine Testing portion fo r the CARB Assessment of the

Emissions from the Use of Biodiesel as a Motor Vehicle Fuel in California “Biodiesel Characterization Study ” Testing on 2006 Cummins ISM.

California Air Resources Board. 17. SAE (2004). Automotive Handbook. Society of Automotive Engineers. 18. William Tahil (2007). The Trouble with Lithium. Meridian International

Research. 19. Joyce A. Ober (2008). Lithium. US Geological Survey. 20. USCAR. (2007). "What’s recycled more than any other item in the U.S.? Here’s a hint -- USCAR’s VRP IS involved." Retrieved, from http://www.uscar.org/commands/files_download.php?files_id=125

. 21. Annette Hebert (2008) A-021-0479 Cummins 22. Annette Hebert (2008) A-021-0458-1 CumminsR-8 23. OEHHA (2003). Air Toxics Hot Spots Program Risk Assessment

Guidelines. Californa Office of Envir onmental Health Hazard Assessment. 24. ARB (1998). PROPOSED IDENTI FICATION OF DIESEL EXHAUST AS A

TOXIC AIR CONTAMINANT. Califo rnia Air Resources Board. 25. ARB (2002). Public Hearing to C onsider Amendments to the Ambient Air Quality Standards for Particulate Matter and Sulfates. California Air

Resources Board. 26. ARB (2007). Health Risk Assessm ent for the Union Pacific Railroad Commerce Railyard. California Air Resources Board. 27. ARB (2006). Emission Reduction Pl an for Ports and Goods Movement in

California. California Air Resources Board. 28. ARB (2000). Risk Reduction Plan to Reduce Particulate Matter Emissions from Diesel-Fueled Engines and Vehicles . California Air Resources Board. 29. SCAQMD (2000). MULTIPLE AIR TOXICS EXPOSURE STUDY. South Coast Air Quality Management District. 30. EPA (2004). USER'S GUIDE FOR THE AMS/EPA REGULATORY MODEL - AERMOD. US Environmental Protection Agency. 31. ARB (2007). Health Risk Assessm ent for the Union Pacific Railroad Commerce Railyard Stationary Source Division. California Air Resources

Board. 32. ARB (2006). ARB Almanac 2006. California Air Resources Board. 33. ARB and OEHHA (2002). Public Heari ng to Consider Amendments to the Ambient Air Quality Standards for Particulate Matter and Sulfates.

California Air Resources Board. 34. ARB (2006). Emission Reduction Plan for Ports and Goods Movement.

California Air Resources Board. 35. EPA (2004). Final Regulatory Impact A nalysis: Control of Emissions from Nonroad Diesel Engines. US Environmental Protection Agency. 36. EPA (1999). The Benefits and Costs of the Clean Air Act 1990 to 2010. US Environmental Protection Agency. 37. EPA (2005). Regulatory Impact Analysi s for the Final Clean Air Interstate Rule. US Environmental Protection Agency. 38. ARB (2008). Methodology for Es timating the Premature Deaths Associated with Long-term Exposures to Fine Airborne Particulate Matter
in California. California Air Resources Board. 39. Alan C. Lloyd and Thomas A. Cackette (2001). "Diesel Engines: Environmental Impact and Control. " Journal of the Air & Waste Management Association 51: 809-847. 40. F Diminici and et al. (2005). "Revised An alyses of the National Morbidity, Mortality, and Air Pollution St udy: Mortality Among Residents Of 90 Cities." Journal of Toxicology & Envi ronmental Health: Part A 68(13/14):

1071-1092. 41. MEREDITH FRANKLIN, ARIANA ZEKA, and JOEL SCHWARTZ (2007).

"Association between PM2.5 and all-caus e and specific-cause mortality in 27 US communities." Journal of Exposure Science and Environmental Epidemiology 17(3): 279-287.R-9 42. Michael Jerrett and et al. (2005). "S patial Analysis of Air Pollution and Mortality in Los Angeles." Epidemiology 16(6): 727-736. 43. C. Arden Pope III, et al. (2002). " Lung Cancer, Cardiopulmonary Mortality, and Long-term Exposure to Fine Particulat e Air Pollution." Journal of the

American Medical Associ ation 287(9): 1132-1141. 44. Mark A. Thayer (2003). The Economic Value of Respiratory and Cardiovascular Hospitalizations. UC San Diego. 45. EPA (2000). Guidelines for Preparing Economic Analyses. US Environmental Protection Agency. 46. Katherine Mrowka (2008). Divisi on of Water Rights, State Water

Resources Control Board. 47. Bart Christensen PE (2008). Divisi on of Water Quality, State Water

Resources Control Board. 48. Andy Aden (2007). Water Usage for Current and Future Ethanol

Production. National Renewab le Energy Laboratory.

49. Bureau of Reclamation. (2009). "Central Valley Project - Folsom and Sly Park." Retrieved, from http://www.usbr.gov/dat aweb/html/folsom.html

.This Page Left Intentionally BlankA-1 

## APPENDIX A

PROPOSED REGULATION ORDERThis Page Left Intentionally BlankA-2 PROPOSED REGULATION ORDER

Adopt new sections 95480, 95480.1, 95481, 95482, 95483, 95484, 95485, 95486, 95487, 95488,
and 95489, title 17, California Code of Re gulations (CCR), to read as follows:

(Note: The entire text of sections 95480, 95480.1, 95481, 95482, 95483, 95484, 95485, 95486, 95487, 95488, and 95489 is new language.)



### Subchapter 10. Climate Change Article 4. Regulations to Achieve Greenhouse Gas Emission

Reductions

Subarticle 7. Low Carbon Fuel Standard

Section 95480. Purpose

The purpose of this regulation is to impl ement a low carbon fuel standard, which will reduce greenhouse gas emissions by reducing the full fuel-cycle, car bon intensity of the transportation fuel pool used in California, pursuant to the California Global Warming Solutions Act of 2006 (Health & Safety Code (H&S), section 38500 et.seq.).

NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 39515, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).



### Section 95480.1. Applicability

(a) Applicability of the Low Carbon Fuel Standard.

Except as provided in this section, t he California Low Carbon Fuel Standard (the “LCFS”) applies to any transportation fuel, as defined in section 95481, that is sold, supplied, or offered for sale in California, and to any person who, as a regulated party defined in section 95481 and specified in section 95484(a), is responsible for a transportation fuel in a calendar year. The types of transportation fuels to whic h the LCFS applies include:

(1) California reformulated gasoline (“gasoline” or “CaRFG”); (2) California diesel fuel (“diesel fuel” or “ULSD”); (3) Fossil compressed natural gas (“Fossil CNG”) or fossil liquefied natural gas (“Fossil LNG”);A-3 (4) Biogas CNG or biogas LNG; (5) Electricity; (6) Compressed or liquefied hydrogen (“hydrogen”); (7) A fuel blend containing hydrogen (“hydrogen blend”); (8) A fuel blend containing greater than 10 percent ethanol by volume; (9) A fuel blend containing biomass-based diesel; (10) Denatured fuel ethanol (“E100”); (11) Neat biomass-bas ed diesel (“B100”); and (12) Any ot her liquid or non-liquid fuel.

(b) Credit Generation Opt-In Provision for Specific Alternative Fuels.

Each of the following alternative fuel s is presumed to have a full fuel-cycle, carbon intensity that meets the comp liance schedules set forth in section 95482(b) and (c) through December 31, 2020. With regard to an alternative fuel listed below, the regulated par ty for the fuel must meet the requirements of the LCFS regulation only if the regulated party elects to generate LCFS credits:

(1) Electricity; (2) Hydrogen; (3) A hydrogen blend; (4) Fossil CNG derived from North American sources; (5) Biogas CNG; and (6) Biogas LNG.

(c) Exemption for Specific Alternative Fuels. The LCFS regulation does not apply to

an alternative fuel that meets the criteria in ei ther (c)(1) or (2) below:

(1) An alternative fuel that:

(A) is not a biomass-based fuel; and (B) is supplied in California by a ll providers of that particular fuel for transportation use at an aggregated vo lume of less than 420 million MJ (3.6 million gasoline gallon equivalent) per year;

A regulated party that believes it is subject to this exemption has the sole burden of proving to the Executive Officer’s sati sfaction that the exemption applies to the regulated party.

(2) Liquefied petroleum gas (LPG or “propane”).

(d) Exemption for Specific Applications. The LCFS regulation does not apply to any transportation fuel used in the following applications:

(1) Aircraft; (2) Racing vehicles, as defined in H&S section 39048;A-4 (3) Military tactical vehicles, as defined in 13 CCR §1905(a); (4) Locomotives not subject to the re quirements specified in 17 CCR §93117;

and (5) Ocean-going vessels, as defined in 17 CCR §93118.5(d). This exemption does not apply to recreational and comme rcial harbor craft, as defined in 17 CCR §93118.5(d).

(e) Nothing in this LCFS regulation ( 17 CCR § 95480 et seq.) may be construed to amend, repeal, modify, or change in any wa y the California reformulated gasoline regulations (CaRFG, 13 CCR §2260 et s eq.), the California diesel fuel regulations (13 CCR §2281-2285 and 17 CCR §93 114), or any other applicable State or federal requirem ents. A person, includi ng but not limited to the regulated party as that term is defined in the LCFS regulation, who is subject to the LCFS regulation or ot her State and federal regul ations shall be solely responsible for ensuring compliance wit h all applicable LCFS requirements and
other State and federal r equirements, including but not limited to the CaRFG requirements and obtaining any necessary approvals, exemptions , or orders from

either the State or federal government

.

NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 395 15, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).



### Section 95481. Definitions and Acronyms

(a) Definitions. For the purposes of sections 95480 through 95489, the definitions in Health and Safety Code sections 39010 through 39060 shall apply, except as otherwise specified in this section, section 95480.1, or sections 95482 through

95489:

(1) “Alternative fuel” means any transpor tation fuel that is not CaRFG or a diesel fuel, including but not limited to, those fuels specified in section 95480.1(a)(3) through (a)(12).

(2) “B100” means biodiese l meeting ASTM D6751-08 ( Standard Specification

for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels ), which is incorporated herein by reference.

(3) “Biodiesel” means a diesel fuel substitute produced from nonpetroleum

renewable resources that meet the registration r equirements for fuels and fuel additives established by the En vironmental Protection Agency underA-5 section 211 of the Clean Air Act. It includes biodiesel meeting all the following:

(A) Registered as a motor vehicle f uel or fuel additive under 40 CFR part 79; (B) A mono-alkyl ester; (C) Meets ASTM D 6751-08 ( Standard Specification for Biodiesel Fuel Blendstock (B100) for Middle Distillate Fuels ); (D) Intended for use in engines that are designed to run on conventional diesel fuel; and (E) Derived from nonpetroleum renewable resources.

(4) “Biodiesel Blend” means a blend of biodiesel and diesel fuel containing 6% (B6) to 20% (B20) biodie sel and meeting ASTM D7467-08 ( Specification for Diesel Fuel Oil, Biodiesel Blend (B6 to 20) ), which is incorporated herein by reference.

(5) “Biogas (also called biomethane)” means natural gas that meets the requirements of 13 CCR §2292.5 and is derived from anaerobic digestion of agricultural waste, animal waste, or other biomass.

(6) “Biogas CNG” means CNG consisti ng solely of compressed biogas.

(7) “Biogas LNG” means LNG cons isting solely of liquefied biogas.

(8) "Biomass" has the same meani ng as defined in "Renewable Energy Program: Overall Program Guidebook ," 2nd Ed., California Energy Commission, Report No. CEC-300-2007-003-ED2-CMF, January 2008, which is incorporated herein by reference.

(9) “Biomass-based diesel” means a biodiesel (mono-alkyl ester) or a renewable diesel that complies with ASTM D975-08ae1 ( Specification for

Diesel Fuel Oils ), which is incorporated herein by reference. This includes a renewable fuel derived from co-pro cessing biomass with a petroleum

feedstock.

(10) “Blendstock” means a component that is either used alone or is blended with another component(s) to produce a finished fuel used in a motor vehicle. Each blendstock corresponds to a fuel pathway in the Californiamodified GREET. A blendstock that is used directly as a transportation

fuel in a vehicle is considered a finished fuel.

(11) “Carbon intensity” means the amount of lifecycle greenhouse gas emissions, per unit of energy of fuel delivered, expressed in grams of carbon dioxide equivalent per megajoule (gCO2E/MJ).A-6 (12) “Compressed Natural Gas (CNG)” means natural gas that has been compressed to a pressure greater than ambient pressure and meets the requirements of 13 CCR §2292.5.

(13) “Credits” and “deficits” means the measures used for determining a regulated party’s compliance wit h the average carbon intensity requirements in sections 95482 and 95483. Credits and deficits are

denominated in units of metric tons of CO2E, and are ca lculated pursuant to section 95485(a).

(14) “Diesel Fuel” (also called conventi onal diesel fuel) has the same meaning as specified in 13 CCR §2281(b).

(15) “Diesel Fuel Blend” means a blend of diesel fuel and biodiesel containing no more than 5% (B5) biodiesel by weight and meeting
ASTM D975-08ae1.

(16) “E100,” also known as “Denatur ed Fuel Ethanol,” means nominally anhydrous ethyl alcohol meeting ASTM D4806-08 ( Standard Specification

for Denatured Fuel Ethanol for Ble nding with Gasolines for Use as Automotive Spark-Ignition Engine Fuel ), which is incorporated herein by

reference.

(17) “Executive Officer” means the Ex ecutive Officer of the Air Resources Board, or his or her designee.

(18) “Final Distribution Facility” means t he stationary finished fuel transfer point

from which the finished fuel is tran sferred into the cargo tank truck, pipeline, or other delivery vessel for delivery to the facility at which the finished fuel will be dispensed into motor vehicles.

(19) “Finished fuel” means a fuel that is used directly in a vehicle for transportation purposes without requiring additional chemical or physical processing.

(20) “Fossil CNG” means CNG that is derived solely from petroleum or fossil sources, such as oil fields and coal beds.

(21) “HDV” means a heavy-duty vehicle that is rated at 14,001 or more pounds gross vehicle weight rating (GVWR).

(22) “Home fueling” means the dispensing of fuel by use of a fueling appliance

that is located on or within a resident ial property with access limited to a single household.

(23) “Import” means to bring a product from outside Ca lifornia into California.A-7 (24) “Importer” means t he person who owns an impor ted product when it is received at the import fa cility in California.

(25) “Import facility” means, with res pect to any imported liquid product, the storage tank in which the product was first delivered from outside California into California, including, in the case of liquid product imported by cargo tank and delivered directly to a facility for dispensing the product into motor vehicles, the cargo tank in which the product was imported.

(26) “Intermediate calculated value” means a value that is used in the calculation of a reported value but does not by it self meet the reporting requirement under section 95484(c).

(27) “LDV & MDV” means a vehicle ca tegory that includes both light-duty (LDV) and medium-duty vehicles (MDV).

(A) “LDV” means a vehicle that is rated at 8500 pounds or less GVWR. (B) “MDV” means a vehicle t hat is rated between 8501 and 14,000 pounds GVWR.

(28) “Lifecycle greenhouse gas emissi ons” means the aggregate quantity of greenhouse gas emissions (including di rect emissions and significant indirect emissions such as signific ant emissions from land use changes), as determined by the Executive Officer, related to the full fuel lifecycle, including all stages of fuel and feedst ock production and di stribution, from feedstock generation or extraction th rough the distribution and delivery

and use of the finished fuel to t he ultimate consumer, where the mass values for all greenhouse gases are adjusted to account for their relative global warming potential.

(29) “Liquefied Natural Gas (LNG)” m eans natural gas t hat has been liquefied and meets the requirement s of 13 CCR §2292.5.

(30) “Motor vehicle” has the same me aning as defined in section 415 of the

Vehicle Code.

(31) “Multi-fuel vehicle” m eans a vehicle that uses two or more distinct fuels for its operation. A multi-fuel vehicle (also called a vehicle operating in blended-mode) includes a bi-fuel vehicl e and can have two or more fueling ports onboard the vehicle. A fueling port can be an electrical plug or a receptacle for liquid or gaseous fuel. As an example, a plug-in hybrid hydrogen ICEV uses both electricity and hydrogen as the fuel source and can be “refueled” using two separat ely distinct fueling ports.A-8 (32) “Multimedia evaluation” has the same meaning as specified in H&S §43830.8(b) and (c).

(33) “Natural gas” means a mixt ure of gaseous hydrocarbons and other compounds, with at least 80 percent methane (by volume), and typically sold or distributed by utilities, such as any utility company regulated by the
California Public Utilities Commission.

(34) “Oil Sands” means sands that are nat urally occurring mixtures of sand or clay, water and an extremely dense and vi scous form of petroleum called bitumen. They are found in large am ounts in many countries throughout the world, but are found in ex tremely large quantities in Canada and

Venezuela.

(35) “Oil Shale” means fine-grained sedim entary rock that contains significant amounts of kerogen (a solid mixtur e of organic chemical compounds), from which liquid hydrocarbons can be extracted by distillation or other

means.

(36) “Private access fueling facility” means a fueling facility with access restricted to privately distributed electr onic cards (“cardlock”) or is located in a secure area not accessible to the public.

(37) “Producer” means, with respect to any liquid fuel, the person who owns the liquid fuel when it is supp lied from the pr oduction facility.

(38) “Production facility” means, with re spect to any liquid fuel (other than LNG), a facility in California at whic h the fuel is produced. "Production facility" means, with respect to natural gas (CNG, LNG or biogas), a facility

in California at which fuel is conv erted, compressed, liquefied, refined, treated, or otherwise proc essed into CNG, LNG, biogas, or biogas-natural gas blend that is ready for transportat ion use in a vehicle without further physical or chemical processing.

(39) “Public access fueling facility” means a fueling facility that is not a private access fueling dispenser.

(40) “Regulated party” means a person who, pursuant to section 95484(a), must meet the average ca rbon intensity requirem ents in section 95482 or

95483.

(41) “Renewable diesel” means a motor vehi cle fuel or fuel additive which is all the following:

(A) Registered as a motor vehicl e fuel or fuel additive under 40 CFR part 79;A-9 (B) Not a mono-alkyl ester; (C) Intended for use in engines that are designed to run on conventional diesel fuel; and (D) Derived from nonpetroleum renewable resources.

(42) “Single fuel vehicle” means a vehicl e that uses a single external source of fuel for its operation. The fuel can be a pure fuel, such as gasoline, or a

blended fuel such as E85 or a dies el fuel containing biomass-based

diesel. A dedicated fuel vehicle ha s one fueling port onboard the vehicle. Examples include BEV, E85 FFV, v ehicles running on a biomass-based diesel blend, and grid-independent hy brids such as a Toyota Prius.®

(43) “Transportation fuel” means any fuel used or intended for use as a motor vehicle fuel or for transportation purposes in a nonvehicular source.

(b) Acronyms. For the purposes of secti ons 95480 through 95489, the following acronyms apply.

(1) “ASTM” means ASTM International. (2) “BEV” means battery electric vehicles. (3) “CARBOB” means California reform ulated gasoline blen dstock for oxygenate blending (4) “CaRFG” means Californ ia reformulated gasoline. (5) “CEC” means California Energy Commission. (6) “CFR” means code of federal regulations. (7) “CI” means carbon intensity. (8) “CNG” means compressed natural gas. (9) “EER” means energy economy ratio. (10) “FCV” means fuel cell vehicles. (11) “FFV” means flex fuel vehicles. (12) “gCO2E/MJ” means grams of car bon dioxide equivalent per mega joule. (13) “GREET” means the Greenhouse gases , Regulated Emissions, and Energy use in Transportation model. (14) “GVRW” means gross vehicle weight rating. (15) “HDV” means heavy-duty vehicles. (16) “ICEV” means internal combustion engine vehicle. (17) “LCFS” means Low Carbon Fuel Standard. (18) “LDV” means light-duty vehicles. (19) “LNG” means liquefied natural gas. (20) “LPG” means liquefied petroleum gas. (21) “MDV” means medium-duty vehicles. (22) “MT” means metric tons of carbon dioxide equivalent. (23) “PHEV” means plug-in hybrid vehicles. (24) “ULSD” means California ultra low sulfur diesel.A-10 NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 39515, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).



### Section 95482. Average Carbon Inte nsity Requirements for Gasoline

and Diesel

(a) Starting January 1, 2011 and for each year thereafter, a regulated party must meet the average carbon intensity requirem ents set forth in Table 1 and Table 2 of this section for its transportation gasol ine and diesel fuel, respectively, in each calendar year. For 2010 only, a regulat ed party does not need to meet a carbon intensity requirement, but it must meet the reporting requirements set forth in section 95484(c).

(b) Requirements for gasoline and fuels used as a substitute for gasoline

.

Table 1. LCFS Compliance Schedule for 2011 to 2020 for Gasoline and

Fuels Used as a Substitute for Gasoline.

Year Average Carbon Intensity (gCO2E/MJ) % Reduction 2010 Reporting Only

2011 95.61 0.25%

2012 95.37 0.5%

2013 94.89 1.0%

2014 94.41 1.5%

2015 93.45 2.5%

2016 92.50 3.5%

2017 91.06 5.0%

2018 89.62 6.5%

2019 88.18 8.0% 2020 and subsequent

years 86.27 10.0%A-11 (c) Requirements for diesel fuel and fuels used as a substitute for diesel fuel.

Table 2. LCFS Compliance Schedule for 2011 to 2020 for Diesel Fuel and

Fuels Used as a Substitute for Diesel Fuel.

Year Average Carbon Intensity (gCO2E/MJ) % Reduction 2010 Reporting Only

2011 94.47 0.25%

2012 94.24 0.5%

2013 93.76 1.0%

2014 93.29 1.5%

2015 92.34 2.5%

2016 91.40 3.5%

2017 89.97 5.0%

2018 88.55 6.5%

2019 87.13 8.0% 2020 and subsequent

years 85.24 10.0%

NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 39515, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).



### Section 95483. Average Carbon Intensity Requirements for

Alternative Fuels

(a) The requirements of this section apply to a regulated party that provides an alternative fuel as a transpor tation fuel in California.

(b) Carbon Intensity Requirements for an Alternative Fuel Other Than a BiomassBased Diesel Fuel -Intended for Use in a Single Fuel Vehicle.

(1) A regulated party must use the av erage carbon intensity value for gasoline set forth in section 95482( b) for its alternative fuel, other than biomassbased diesel fuel, if the alternative f uel is used or intended to be used in any single-fuel:

(A) light-duty vehicle, or

(B) medium-duty vehicle.A-12 (2) A regulated party must use the av erage carbon intensity value for diesel fuel set forth in section 95482(c) fo r its alternative fuel, other than biomass-based diesel fuel, that is used or intended to be used in any single-fuel applicati on not identified in section 95483(b)(1).

(c) Carbon Intensity Requirements for Biomass-Based Diesel Fuel Provided for Use in a Single Fuel Vehicle. A regulated party must use the average carbon intensity

value for diesel fuel set forth in secti on 95482(c) if its biom ass-based diesel fuel is used or intended to be used in any single-fuel:

(1) light-duty vehicle;

(2) medium-duty vehicle;

(3) heavy-duty vehicle;

(4) off-road transportation application;

(5) off-road equipm ent application;

(6) locomotive or commercia l harbor craft application; or

(7) non-stationary source application not otherwise specified in 1-6 above.

(d) Carbon Intensity Requirements for Transportation Fuels Intended for Use in

Multi-Fuel Vehicles.

(1) For an alternative fuel provided fo r use in a multi-fueled vehicle, a regulated party must use:

(A) the average carbon intensity value for gasoline set forth in section 95482(b) if one of the fuels used in the multi-fuel vehicle is gasoline; or

(B) the average carbon intensity value fo r diesel fuel set forth in section 95482(c) if one of the fuels used in t he multi-fuel vehicle is diesel

fuel.

(2) For an alternative fuel provided for us e in a multi-fueled vehicle (including a bi-fuel vehicle) that does not use gasoline or diesel fuel, a regulated party must use:

(A) the average carbon intensity value for gasoline set forth in section 95482(b) if that alternative fuel is used or intended to be used in:A-13 1. light-duty vehicle, or

2. medium-duty vehicle.

(B) the average carbon intensity value for diesel set forth in section 95482(c) if that alternat ive fuel is used or intended to be used in an application not i dentified in section 95483(d)(2)(A).

NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 395 15, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).



### Section 95484. Requirements for Regulated Parties

(a) Identification of Regulated Parties.

The purpose of this part is to establish the criteria by which a regulated party is determined. The regulated party is init ially established for each type of transportation fuel, but this part provides for the transfer of regulated party status and the associated compliance obligations by agreement, notification, or other means, as specified below.

(1) Regulated Parties for Gasoline

.

(A) Designation of Producers and Impor ters as Regulated Parties

.

1. Where Oxygenate Is Added to Downstream CARBOB.

For gasoline consisting of CARBOB and an oxygenate

added downstream from the Calif ornia facility at which the CARBOB was produced or import ed, the regulated party is initially the following:

a. With respect to the CARBOB, the regulated party is the producer or importe r of the CARBOB; and

b. With respect to the oxy genate, the regulated party is the producer or importe r of the oxygenate.A-14 2. Where No Separate CARBOB

.

For gasoline that does not include CARBOB that had previously been supplied from the facility at which was produced or imported, the regulated party for the gasoline is the producer or importe r of the gasoline.

(B) Effect of Transfer of CARB OB by Regulated Party.

1. Threshold Determination Whether Recipient of CARBOB is a Producer or Importer.

Whenever a person who is the regulated party for CARBOB transfers ownership of the CARBOB, the recipient must notify the transferor whether t he recipient is a producer or importer for purposes of this section 95484(a)(1)(B).

2. Producer or Importer Acqui ring CARBOB Becomes the Regulated Party Unless Spec ified Conditions Are Met.

Except as provided for in section 95484(a)(1)(B)3., when a person who is the regulated part y transfers ownership of the CARBOB to a producer or im porter, the recipient of ownership of the CARBOB (i.e., the transferee) becomes the regulated party for it. The transferor must provide the recipient a product transfer document that prominently

states:

a. the volume and average carbon intensity of the transferred CARBOB; and

b. the recipient is now t he regulated party for the acquired CARBOB and accordingly is responsible for meeting the requirements of the LCFS regulation with respect to the CARBOB.

3. Transfer of CARBOB or Gaso line to a Producer or Importer and Retaining Compliance Obligation.

Section 95484(a)(1)(B)2. notwit hstanding, a regulated party transferring ownership of CARBOB to a producer or importer may elect to remain the regulat ed party and retain the LCFS compliance obligation for the transferred CARBOB by providing the recipient at the time of transfer with a product transfer document that prominent ly states that the transferorA-15 has elected to remain the regul ated party with respect to the
CARBOB.

4. If Recipient Is Not a Producer or Importer, Regulated Party Transferring CARBOB Remains Regulated Party Unless Specified Conditions Are Met.

When a person who is the regulated party for CARBOB transfers ownership of the CARBOB to a person who is not a producer or importer, the trans feror remains the regulated party unless the conditions of section 95484(a)(1)(B)5. are

met.

5. Conditions Under Which a N on-Producer and Non-Importer Acquiring Ownership of CARBOB Becomes the Regulated Party.

A person, who is neither a producer nor an importer and who acquires ownership of CARBOB from the regulated party, becomes the regulated party for the CARBOB if, by the time ownership is transferred, the two parties agree by written contract that the person acqui ring ownership accepts the LCFS compliance obligation as t he regulated party. For the transfer of regulated party obli gations to be effective, the transferor must also provide t he recipient a product transfer document that prominently states:

a. the volume and average carbon intensity of the transferred CARBOB; and

b. the recipient is now t he regulated party for the acquired CARBOB and accordingly is responsible for meeting the requirements of the LCFS regulation with respect to the CARBOB.

(C) Effect of Transfer By Regulated Party of Oxygenate to Be Blended

With CARBOB.

1. Person Acquiring the Oxygenat e Becomes the Regulated Party Unless Specifie d Conditions Are Met.

Except as provided in section 95484(a)(1)(C)2., when a person who is the regulated party for oxygenate to be

blended with CARBOB transfers ownership of the oxygenate before it has been blended with CARBOB, the recipient of ownership of the oxygenate (i .e., the transferee) becomes the regulated party for it. The transferor must provide theA-16 recipient a product transfer document that prominently

states:

a. the volume and carbon in tensity of the transferred oxygenate; and

b. the recipient is now t he regulated party for the acquired oxygenate and accordingly is responsible for meeting the requirements of the LCFS with respect to the oxygenate.

2. Transfer of Oxygenate and Retaining Compliance Obligation.

Section 95484(a)(1)(C)1. notwiths tanding, a regulated party transferring ownership of oxygena te may elect to remain the regulated party and retain the LCFS compliance obligation for the transferred oxygenate by providing the recipient at

the time of transfer with a product transfer document that prominently states that the tr ansferor has elected to remain the regulated party with re spect to the oxygenate.

(D) Effect of Transfer by a Regulated Party of Gasoline to be Blended With Additional Oxygenate.

A person who is the sole regulated party for a batch of gasoline and is transferring ownership of the gasoline to another party that will be combining it with additional oxyg enate may transfer his or her obligations as a regulated party if all of the conditions set forth

below are met.

1. Blending the additional oxygen ate into the gasoline is not prohibited by title 13, California Code of Regulations, section 2262.5(d).

2. By the time ownership is tr ansferred the two parties agree by written contract that the per son acquiring ownership accepts the LCFS compliance obligati ons as a regulated party with respect to the gasoline.

3. The transferor provides the recipient a product transfer document that prominently states:

a. the volume and average carbon intensity of the transferred gasoline; andA-17 b. the recipient is now t he regulated party for the acquired gasoline and accordingly is responsible for meeting the requirements of the LCFS regulation with respect to the gasoline.

4. The written contract between the parties includes an agreement that the recipient of the gasoline will be blending additional oxygenate into the gasoline.

(E) Effect of Transfer by a Regulated Party of Oxygenate to be Blended

With Gasoline.

Where oxygenate is added to gasolin e, the regulated party with respect to the oxygenate is initiall y the producer or importer of the oxygenate. Transfers of the ox ygenate are subject to section 95484(a)(1)(C).

(2) Regulated Party for Diesel F uel and Diesel Fuel Blends.

(A) Designation of Producers and Impor ters as Regulated Parties.

1. Where Biomass-Based Diesel Is Added to Downstream

Diesel Fuel.

For a diesel fuel blend consisti ng of diesel fuel and biomassbased diesel added downstream fr om the California facility

at which the diesel fuel wa s produced or imported, the regulated party is initially the following:

a. With respect to the diesel fuel, the regulated party is the producer or importer of the diesel fuel; and

b. With respect to the biomass-based diesel, the regulated party is the produc er or importer of the

biomass-based diesel.

2. All Other Diesel Fuels.

For any other diesel fuel that does not fall within section 95484(a)(2)(A)1., the regulated party is the producer or importer of the diesel fuel.A-18 (B) Effect of Transfer of Diesel F uel and Diesel Fuel Blends by Regulated Party.

1. Threshold Determination Whether Recipient of Diesel Fuel or Diesel Fuel Blend is a Producer or Importer.

Whenever a person who is the re gulated party for diesel fuel

or a diesel fuel blend transfers ownership before it has been

transferred from its final distri bution facility, the recipient must notify the transferor whether the recipient is a producer or importer for purposes of this section 95484(a)(2)(B).

2. Producer or Importer Acquiring Diesel Fuel or Diesel Fuel Blend Becomes the Regulat ed Party Unless Specified

Conditions Are Met.

Except as provided for in section 95484(a)(2)(B)3., when a person who is the regulated party for diesel fuel or a diesel fuel blend transfers ownership to a producer or importer

before it has been transferred fr om its final distribution facility, the recipient of ownership of the diesel fuel or diesel fuel blend (i.e., the transferee) becomes the regulated party for it. The transferor must pr ovide the recipient a product transfer document that prominently states:

a. the volume and average carbon intensity of the

transferred diesel fuel or diesel fuel blend; and

b. the recipient is now t he regulated party for the acquired diesel fuel or diesel fuel blend and accordingly is responsible for meeting the requirements of the LCFS regulation with respect to it.

3. Transfer of Diesel Fuel or Diese l Fuel Blend to a Producer or Importer and Retaining Compliance Obligation.

Section 95484(a)(2)(B)2. notwit hstanding, a regulated party transferring ownership of diesel f uel or diesel fuel blend to a producer or importer may elect to remain the regulated party and retain the LCFS compliance obligation for the

transferred diesel fuel or diesel fuel blend by providing the recipient at the time of transfer with a product transfer document that prominently stat es that the transferor has elected to remain the regulat ed party with respect to the

diesel fuel or diesel fuel blend.A-19 4. If Recipient Is Not a Producer or Importer, Regulated Party Transferring Diesel Fuel or Diesel Fuel Blend Remains Regulated Party Unless Spec ified Conditions Are Met.

When a person who is the regulated party for diesel fuel or a

diesel fuel blend transfers owner ship of the diesel fuel or diesel fuel blend to a person who is not a producer or importer, the transferor remain s the regulated party unless the conditions of section 95484(a)(2)(B)5. are met.

5. Conditions Under Which a N on-Producer and Non-Importer Acquiring Ownership of Diesel Fuel or Diesel Fuel Blend Becomes the Regulated Party.

A person, who is neither a producer nor an importer and who acquires ownership of diesel fuel or a diesel fuel blend from the regulated party, becomes t he regulated party for the

diesel fuel or diesel fuel blen d if, by the time ownership is transferred, the two parties agree by written contract that the person acquiring ownership accepts the LCFS compliance obligation as the regulated par ty. For the transfer of regulated party obligations to be effective, the transferor must also provide the recipient a product transfer document that prominently states:

a. the volume and average carbon intensity of the

transferred diesel fuel or diesel fuel blend; and

b. the recipient is now t he regulated party for the acquired diesel fuel or diesel fuel blend and accordingly is responsible for meeting the requirements of the LCFS regulation with respect to

the diesel fuel or diesel fuel blend.

(C) Effect of Transfer By Regulated Party of Biomass-Based Diesel to

Be Blended With Diesel Fuel.

1. Person Acquiring the Biomass-Based Diesel Becomes the Regulated Party Unless Spec ified Conditions Are Met.

Except as provided in section 95484(a)(2)(C)2., when a person who is the regulated pa rty for biomass-based diesel to be blended with diesel fuel transfers ownership of the

biomass-based diesel before it has been blended with diesel fuel, the recipient of ownership of the biomass-based diesel (i.e., the transferee) becomes t he regulated party for it. TheA-20 transferor must provide the recipient a product transfer document that prominently states:

a. the volume and carbon in tensity of the transferred biomass-based diesel; and

b. the recipient is now t he regulated party for the acquired biomass-based diesel and accordingly is responsible for meeting the requirements of the LCFS with respect to the biomass-based diesel.

2. Transfer of Biomass-Based Diesel and Retaining Compliance Obligation.

Section 95484(a)(2)(C)1. notwiths tanding, the transferor may elect to remain the regulat ed party and retain the LCFS compliance obligation for the transferred biomass-based diesel by providing the recipient at the time of transfer with a product transfer document that prominently states that the transferor has elected to remain the regulated party with respect to the biomass-based diesel.

(3) Regulated Party For Liquid Alternativ e Fuels Not Blended With Gasoline

Or Diesel Fuel.

For a liquid alternative fuel, incl uding but not limit ed to neat denatured ethanol and neat biomass-based diesel, t hat is not blended with gasoline or diesel fuel, or with any other petrol eum-derived fuel, the regulated party is the producer or importer of the liquid alternative fuel.

(4) Regulated Party For Blends Of Liquid Al ternative Fuels And Gasoline Or

Diesel Fuel.

(A) Designation of producers and Im porters as regulated parties.

For a transportation fuel that is a bl end of liquid alternative fuel and gasoline or diesel fuel – but that does not itself constitute gasoline or diesel fuel – the regulated party is the following:

(1) With respect to the alternat ive fuel component, the regulated party is the person who produced the liquid alternative fuel in California or imported it into California; and

(2) With respect to the gasoline or diesel fuel component, the regulated party is the person who produced the gasoline or
diesel fuel in California or imported it into California.A-21 (B) Transfer Of A Blend Of Liquid Alternative Fuel And Gasoline Or Diesel Fuel And Comp liance Obligation.

Except as provided for in sect ion 95484(a)(4)(C), on each occasion that a person transfers ownership of fuel that falls within section 95484(a)(4) (“alternative liquid f uel blend”) before it has been

transferred from its final distribut ion facility, the recipient of ownership of such an alternativ e liquid fuel blend (i.e., the transferee) becomes the regulated party for that alternative liquid

fuel blend. The transferor sha ll provide the recipient a product transfer document that prominently states:

1. the volume and average carbon intensity of the transferred alternative liquid fuel blend; and

2. the recipient is now the r egulated party for the acquired alternative liquid fuel blend and accordingly is responsible for meeting the requirements of the LCFS regulation with respect to the alternative liquid fuel blend.

(C) Transfer Of A Blend Of Liquid Alternative Fuel And Gasoline Or

Diesel Fuel And Retaini ng Compliance Obligation.

Section 95484(a)(4)(B) notwithstanding , the transferor may elect to remain the regulated party and retain the LCFS compliance obligation for the transferred alternat ive liquid fuel blend by written contract with the recipient. T he transferor shall provide the recipient with a product transfer docu ment that identifies the volume and average carbon intens ity of the transferred alternative liquid

fuel blend.

(5) Regulated Parties for Natural Gas (Including CNG, LNG, and Biogas).

(A) Designation of Regulated Part ies for Fossil CNG and Biogas

CNG.

1. Where Biogas CNG is Added to Fossil CNG.

For fuel consisting of a fossil CNG and biogas CNG blend, the regulated party is in itially the following:

a. With respect to the fossil CNG, the regulated party is the person that owns the natural gas fueling equipment at the facility at which the fossil CNG and biogas CNG blend is dispensed to motor vehicles for their transportation use; andA-22 b. With respect to the biogas CNG, the regulated party is the producer or importer of the biogas CNG.

2 . Where No Biogas CNG is Added to Fossil CNG.

For fuel consisting solely of fossil CNG, the regulated party is the person that owns the natural gas fueling equipment at the facility at which the fossil CNG is dispensed to motor vehicles for their transportation use.

(B) Designation of Regulated Partie s for Fossil LNG and Biogas LNG.

1. Where Biogas LNG is Added to Fossil LNG.

For a fuel consisting of a fossil LNG and biogas LNG blend, the regulated party is in itially the following:

a. With respect to the foss il LNG, the regulated party is the person that owns the fossil LNG when it is transferred to the facility at which the liquefied blend is dispensed to motor vehicl es for their transportation use; and

b. With respect to the biogas , the regulated party is the producer or importer of the biogas LNG.

2. Where No Biogas LNG is Added to Fossil LNG.

For fuel consisting solely of fossil LNG, the regulated party is initially the person that owns the fossil LNG when it is transferred to the facility at which the fossil LNG is dispensed to motor vehicles for their transportation use.

(C) Designation of Regulat ed Party for Biogas CNG or Biogas LNG Supplied Directly to Vehicles for Transportation Use.

For fuel consisting solely of biogas CNG or biogas LNG that is produced in California and supplied directly to vehicles in California for their transportation use without first being

blended into fossil CNG or foss il LNG, the regulated party is initially the producer of t he biogas CNG or biogas LNG.A-23 (D) Effect of Transfer of F uel by Regulated Party.

1. Transferor Remains Regulated Party Unless Conditions Are

Met.

When a person who is the regulat ed party for a fuel specified in section 95484(a)(5)(A), (B), or (C) transfers ownership of the fuel, the transferor remain s the regulated party unless the conditions of section 95484(a)(5)(D)2. are met.

2. Conditions Under Which a Person Acquiring Ownership of a Fuel Becomes the Regulated Party.

Section 95484(a)(5)(D)1. notwithstanding, a person acquiring ownership of a fuel specified in section 95484(a)(5)(A), (B), or (C) from the regulated party becomes the regulated party for that fuel if, by t he time ownership is transferred, the two parties agree by written contract that the person acquiring ownership accepts the LCFS compliance obligation as the regulated par ty. For the transfer of regulated party obligations to be effective, the transferor must also provide the recipient a product transfer document that prominently states:

a. the volume and average carbon intensity of the transferred fuel; and

b. the recipient is now t he regulated party for the acquired fuel and accordingly is responsible for meeting the requirements of the LCFS regulation with respect to the acquired fuel.

(6) Regulated Parties for Electricity.

For electricity used as a transportation fuel, the regulated party is determined in the order specified below:

(A) The load-serving entity or other provider of electricity services,unless section 95484(a)(6)(B), (C), or (D) below applies. “Loadserving entity” has the same meani ng specified in Public Utilities Code (PUC) section 380. “Provider of electricity services” means a local publicly-owned utility, retail seller (as defined in PUC section 399.12(g)), or any other person t hat supplies electricity to the vehicle charging equipment;A-24 (B) The electricity services supplie r, where ”electricity services supplier” means any person or entity that provides bundled charging infrastructure and other electric tran sportation services and provides access to vehicle c harging under contract with the vehicle owner or operator;

(C) The owner and operator of t he electric-charging equipment, provided there is a contract between the charging equipment owner-operator and the provider of electricity services specifying that the charging equipment owner- operator is the regulated party;

(D) The owner of a home with elec tric vehicle-charging equipment, provided there is a contract between the homeowner and provider of electricity services specifyi ng that the homeowner may acquire

credits.

(7) Regulated Parties for Hydrogen Or A Hydrogen Blend.

(A) Designation of Regulated Party at Time Finished Fuel is Created.

For a volume of finished fuel c onsisting of hydrogen or a blend of hydrogen and another fuel (“finished hydrogen fuel”), the regulated party is initially the person who owns the finished hydrogen fuel at

the time the blendstocks are blended to make the finished hydrogen fuel.

(B) Transfer of Ownership and Reta ining Compliance Obligation.

Except as provided for in section 95484(a)(7)(C), when a person who is the regulated party trans fers ownership of a finished hydrogen fuel to another person, the transferor remains the regulated party.

(C) Conditions Under Which a Person Acquiring Ownership of Finished Hydrogen Fuel Becomes the Regulated Party.

Section 95484(a)(7)(B) notwithst anding, a person who acquires ownership of finished hydrogen fuel becomes the regulated party for the fuel if, by the time ownersh ip is transferred, the two parties (transferor and recipient) agree by written contract that the person acquiring ownership accepts the LCFS compliance obligation as the regulated party. For the transfe r of regulated party obligations to be effective, the transferor mu st also provide the recipient a product transfer document t hat prominently states:A-25 1. the volume and average carbon intensity of the transferred finished hydrogen fuel; and

2. the recipient is now the r egulated party for the acquired finished hydrogen fuel and accordingly is responsible for meeting the requirements of the LCFS regulation with respect to the acquired finished hydrogen fuel.

(b) Calculation of Credit Balance

(1) Compliance Period. Beginning in 2011 and every year thereafter, the compliance period is January 1 through December 31 of each year.

(2) Calculation of Credit Balance at the End of A Compliance Period.

A regulated party must calculate t he credit balance at the end of a compliance period as follows:

tired Exported Sold Gen Acquired r CarriedOve Gen

Credits Credits Credits Deficits Credits Credits Credits nce CreditBala

Re

− − − + + + =

where:

Gen Credits is the total credits generated pur suant to section 95485(a) for the current compliance period;

r CarriedOve Credits is the credits or deficits ca rried over from the previous compliance period;

Acquired Credits is the credits purchased or ot herwise acquired in the current compliance period;

Gen Deficits is the total deficits generated pursuant to section 95485(a) for
the current compliance period;

Sold Credits is the credits sold or otherwise transferred in the current compliance period;

Exported Credits is the credits exported to pr ograms outside the LCFS for the current compliance period; and

tired Credits Re is the credits retired within the LCFS for the current compliance period.A-26 (3) Deficit Carryover. A regulated party with a negative credit balance in a compliance period may carry over t he deficit to the next compliance period, without penalty, if both t he following conditions are met:

(A) the regulated party has a credit balance greater than or equal to zero in the previous compliance period; and

(B) the sum of the magnitude of Gen Credits

, r CarriedOve Credits , and

Acquired Credits is greater than or equal to 90 percent of the sum of the magnitude of Gen Deficits

, Sold Credits

, Exported Credits

, tired Credits Re and
for the current compliance period.

(4) Deficit Reconciliation.

(A) A regulated party that meets the conditions of deficit carryover, as specified in section 95481(b)(3), must eliminate any deficit generated in a given compliance period by the end of the next compliance period. A deficit may be eliminated only by retirement of an equal amount of retained credits ( r CarriedOve Credits ), by purchase of an equal amount of cr edits from another regulated party, or by any combination of these two methods.

(B) If the conditions of deficit ca rryover as specified in section 95481(b)(3) are not met, a regulat ed party must eliminate any deficit generated in a given comp liance period by the end of the next compliance period. A deficit may be eliminated only by
retirement of an equal amount of retained credits ( r CarriedOve Credits ), by purchase of an equal amount of credits from another regulated party, or by any combination of t hese two methods. In addition, the regulated party is subject to penalti es to the extent permitted under
State law.

(C) A regulated party that is reconc iling in the current compliance period a deficit from the previous comp liance period under (A) or (B) above remains responsible for meeting the LCFS regulation requirements during the current compliance period.

(c) Reporting Requirements.

(1) Reporting Frequency . A regulated party must s ubmit to the Executive Officer quarterly progress reports and annual compliance reports, as specified in sections 95484(c)(3) and 95484(c)(4). The reporting frequencies for these reports are set forth below:A-27 (A) Quarterly Progress Reports For All Regulated Parties. Beginning 2010 and each year thereafter, a regulated party must submit quarterly progress reports to the Executive Officer by:

1. May 31st – for the first cal endar quarter covering January through March;

2. August 31st – for the second calendar quarter covering April through June;

3. November 30th – for the thir d calendar quarter covering July through September; and

4. February 28th (29th in a leap year) – for the fourth calendar quarter covering October through December.

(B) Annual Compliance Reports. By April 30 th of 2011, a regulated party must submit an annual report for calendar year 2010. By April 30 th of 2012 and each year thereafter, a regulated party must provide an annual compliance report for the prior calendar year.

(2) How To Report. A regulated party must su bmit an annual compliance andquarterly progress report by using an interactive, secured internet webbased form.

The regulated party is solely responsib le for ensuring that the Executive Officer receives its progress and compliance reports by the dates specified in section 95484(c)(1). The Executive Officer shall not be responsible for failure of electronica lly submitted reports to be transmitted to the Executive Officer. The report mu st contain a statement attesting to the report’s accuracy and va lidity. The Executive Officer shall not deem an electronically submitted report to be valid unless the report is accompanied by a digital signature that meets the requirem ents of Title 2, California Code of Regulatio ns, section 22000 et seq.

(3) General and Specific Reporting Requirements for Quarterly Progress Reports . For each of its transportation fuels, a regulated party must submit a quarterly progress report that contains the information specified in Table 3 and meets the additional spec ific requirements set forth below:

(A) Specific Quarterly Reporting Requ irements for Gasoline and Diesel

Fuel.

1. For each transfer of gaso line or diesel fuel that results

in a tr ansfer of the compliance obligat ion or retention of the

comp liance obligation by writt en contract, the regulatedA-28 party must provi de to the Executive Officer the product

transfer document and report the applicable information

identified in sect ion 95484(a)(1)(B), (a)(1 )(C), (a)(1)(D), (a)(2)(B), (a)(2)(C), (a)(4)(B), (a)(4)(C), (a)(5)(D), or (a)(7)(C), whichever applies.

2. The carbon intensity value of each blendstock determined pursuant to section 95486.

3. The volume of each blendstock (in gal) per compliance period.

4. All Renewable Ident ification Numbers (RIN s) that are retired

for facilities in California.

(B) Specific Quarterly Reporting Re quirements for Natural Gas (including CNG, LNG, and Biogas).

For each private access, public access, or home fueling facility to which the regulated party supplies CNG, LNG or biogas as a transportation fuel:

1. For CNG, the regulated party must report the amount of fuel dispensed (in scf) per complianc e period for all light/mediumduty vehicles (“LDV & MDV”) and heavy-duty vehicles (“HDV”). For LNG, the regulat ed party must report the amount of fuel dispensed (in gal) per compliance period for all LDV & MDV and HDV;

2. Except as provided for in section 95484(c)(3)(B)3., the regulated party must report t he amount of fuel dispensed based on the use of separate fuel dispenser meters at each fuel dispenser;

3. In lieu of using separate mete rs at each fuel dispenser, the regulated party may report the amount of fuel dispensed at each facility using any other me thod that the regulated party demonstrates to the Executive Officer’s satisfaction as being equivalent to or better than the use of separate fuel meters at each fuel dispenser in each fueling facility;

4. The carbon intensity val ue of the CNG, LNG, or biogas determined pursuant to section 95486.A-29 (C) Specific Quarterly Reporting Requirements for Electricity

.

For electricity used as a transporta tion fuel, a regulated party must also submit the following:

1. For residential charging stations, the total electricity dispensed (in kWh) to all vehi cles at each residence based on direct metering, which distinguishes electricity delivered for transportation use;

2. For each public access char ging facility, the amount of electricity dispensed (in kW-hr);

3. For each fleet charging facility, the amount of fuel dispensed (in kW-hr).

4. The carbon intensity val ue of the electricity determined pursuant to section 95486.

(D) Specific Quarterly Reporting Requirements for Hydrogen or a Hydrogen Blend. For hydrogen or a hydrogen blend used as a transportation fuel, a regulated party must also submit the following:

1. For each private access fueli ng facility, the amount of fuel dispensed (in kg) by vehicle weight category: LDV & MDV

and HDV.

2. For each public access filling station, the amount of fuel dispensed (in kg) by vehicle weight category: LDV & MDV

and HDV.

3. The carbon intensity va lue of the hydrogen or the blendstocks used to produce the hydrogen blend determined pursuant to section 95486.

(4) General and Specific Reporting Requirements for Annual Compliance Reports

.

A regulated party must submit an annual compliance report that meets, at minimum, the general and specific r equirements specified in section 95484(c)(3) above and the additional requirements set forth below:A-30 (A) A regulated party must report the following:

1. The total credits and deficits generated by the regulated party in the current compliance period, calculated as per equations in section 95485(a);

2. Any credits carried over fr om the previous compliance period;

3. Any deficits carried over fr om the previous compliance period;

4. The total credits acquired from another party and identify the party from whom the cr edits were acquired;

5. The total credits sold or otherwise transferred and identify each party to whom those cr edits were transferred;

6. The total credits retired within the LCFS; and

7. The total credits export ed to programs outside the LCFS.

(5) Significant Figures

.

The regulated party must report t he following quantities as specified

below:

(A) carbon intensity, expressed to the same number of significant figures as shown in the carbon intensity lookup table (Method 1);

(B) credits, expressed to the neares t whole metric ton CO2 equivalent;

(C) fuel volume, expressed as follows:

1. a fuel volume greater than 1 million gasoline gallon equivalent (gge) must be ex pressed to the nearest 10,000 gge;

2. a fuel volume between 100,000 gge and 1 million gge, inclusive, must be expre ssed to the nearest 1,000 gge;

3. a fuel volume bet ween 10,000 gge and 99,999 gge, inclusive, must be expressed to the nearest 100 gge; and

4. a fuel volume less than 9, 999 gge must be expressed to the nearest 10 gge.A-31 (D) any other quantity not specifi ed in section 95484(c)(5)(A) to 95484(c)(5)(C) must be expresse d to the nearest whole unit applicable for that quantity.

(E) Rounding Intermediate Calculated Values.

A regulated party must use one of the following procedures for rounding intermediate calc ulated values for fuel quantity dispensed, blended, or sold in California; calculated carbon intensity values;

calculated LCFS credits and deficit s; and any other calculated or measured quantity required to be used, recorded, maintained, provided, or reported for the purpose determining a reported value under the LCFS regulation ( 17 CCR section 95480 et seq.):

1. ASTM E 29-08 ( Standard Practice for Using Significant Digits in Test Data to Determine Conformance with Specifications ), which is incorporated herein by reference; or

2. Any other practice that t he regulated party has demonstrated to the Executive Officer’s written satisfaction provides equivalent or better results as compared with the method specified in subsection 95484(c)(5)(E)1. above.A-32 Table 3. Summary Checklist of Quarterly and Annual Reporting Requirements for LCFS Transportation Fuels.

Parameters to Report Gasoline &

Diesel fuel CNG

&

LNG Electricity Hydrogen

Or Hydrogen

Blends Neat Ethanol or

Biomass-Based

Diesel Fuels

Company or organization

name x x x x x

Reporting period x x x x x Type of fuel x x x x x Blended fuel (yes/no) x x x x x If yes, number of

blendstocks x x n/a x x

Type(s) of blendstock x x n/a x x
RIN numbers x n/a n/a n/a x Blendstock feedstock x x n/a x x Feedstock origin x x n/a x x Production process x x x* x x Amount of each blendstock (MJ) x x n/a x x

**The CI of the fuel or blendstock ( XD reported CI ) x x x x x

Amount of each fuel used as gasoline replacement (MJ) x x x x x

Amount of each fuel used as diesel fuel replacement (MJ) x x x x x

**Credits/deficits generated per quarter (MT) x x x x x

For Annual Reporting (in addition to the items above)

**Credits and Deficits generated per year (MT) x x x x x

**Credits/deficits carried over from the previous year (MT), if any x x x x x

**Credits acquired from another party (MT), if any x x x x x

**Credits sold to another party (MT), if any x x x x x

**Credits exported to another program (MT), if any x x x x x

**Credits retired within LCFS (MT) , if any x x x x x

* Optional. However if qualifying the CI value of electr icity, under method 2A, that is different from CA Marginal electricity value, produ ction process must be reported.

**Value will be calculated or stored in the compliance tool.A-33 (d) Recordkeeping and Auditing.

(1) A regulated party must retain all of the following records for at least 3 years and must provide such records within 20 days of a written request

received from the Executive Officer or his/her designee before expiration of the period during which the reco rds are required to be retained:

(A) product transfer documents;

(B) copies of all data and reports s ubmitted to the Executive Officer;

(C) records related to each fuel transaction; and

(D) records used for compliance or credit calculations.

(2) Evidence of Physical Pathway.

A regulated party may not generate credits purs uant to section 95485 unless it has demonstrated a physi cal pathway, for each of the transportation fuels and blendstocks for which it is responsible under the LCFS regulation, and that physical pathway has been approved by the Executive Officer pursuant to this section 95484(d)(2).

“Physical pathway” means the applicable combination of actual fuel delivery methods, such as truck rout es, rail lines, gas/liquid pipelines, electricity transmission lines, and any other fuel distribution methods, through which the regulated party expects the fuel to be transported under contract from the entity that gener ated or produced the fuel, to any intermediate entities, and ending at the fuel blender, producer, importer, or provider in California.

The Executive Officer shall not approv e a physical pathway demonstration unless the demonstration meets the following requirements:

(A) Initial Demonstration of Delivery Methods.

The regulated party must provide an initial demonstration of the delivery methods comprising the physical pathway for each of the regulated party’s fuels. The in itial demonstration must include

documentation in sufficient detail fo r the Executive Officer to verify the existence of the physical pathway’s delivery methods.

The documentation must include a m ap(s) that shows the truck/rail lines or routes, pipelines, tr ansmission lines, and other delivery methods (segments) that, together, comprise the physical pathway. If more than one company is involv ed in the delivery, each segmentA-34 on the map must be linked to a specific company who is expected to transport the fuel through each s egment of the physical pathway. The regulated party must prov ide the name, mailing address, phone number, and company name for each such person.

(B) Initial Demonstration of Fuel Intr oduced Into the Physical Pathway.

For each blendstock or alternative fuel for which LCFS credit is being claimed, the regulated party must provide evidence showing that a specific volume of that bl endstock or fuel was introduced by its provider into the physical pathway identified in section 95484(d)(2)(A). The evidence may in clude, but is not limited to, a written purchase contract or tran sfer document for the volume of

blendstock or alternative fuel t hat was introduced or otherwise delivered into the physical pathway.

(C) Initial Demonstration of Fuel Removed From the Physical Pathway.

For each specific volume of blends tock or alternative fuel identified in section 95484(d)(2)(B), the regulated party must provide evidence showing that the same vo lume of blendstock or fuel was removed from the physical pathway in California by the regulated party and provided for transportati on use in California. The evidence may include, but is not lim ited to, a written sales contract

or transfer document for the volume of blendstock or alternative fuel

that was removed from or otherwis e extracted out of the physical pathway in California.

(D) Subsequent Demonstration of Physical Pathway.

Once the Executive Officer has appr oved the initial demonstrations specified in section 95484(d)(2)(A) through (C), the regulated party

does not need to resubmit the demonstrations for Executive Officer approval in any subsequent year, unl ess there is a material change to any of the information subm itted under section 95484(d)(2)(A) through (C).

“Material change” means any change to the initially submitted information other than a change in the name, phone number, mailing address, or company name for a person identified in section 95484(d)(2)(A).

If there is a material change to an approved physical pathway demonstration, the regulated party must submit for Executive Officer approval new initial demon strations, pursuant to section 95484(d)(2)(A) through (C), which in cludes the material change(s)A-35 to the physical pathway. For changes that are not material changes, the regulated party must notify the Executive Officer of the applicable change in the person’s name, phone number, mailing address, or company name.

(E) Submittal and Review of and Final Action on Submitted

Demonstrations

1. The regulated party may not re ceive credit for any fuel or blendstock until the Executive Officer has approved the regulated party’s submitted ph ysical-pathway demonstration pursuant to section 95484(d)(2). Upon receiving Executive Officer approval of a physical pathway, the regulated party may claim LCFS credits based on that pathway retroactive to the date use of the pathway began.

2. Within 15 business days of receipt of a physical pathway demonstration, the Executive Officer shall determine if the physical pathway demonstration is complete and notify the regulated party accordingly. If incomplete, the Executive Officer shall notify the regulated party and identify the information needed to complete the demonstrations identified in section 95484(d)(2 )(A) through (D). Once the Executive Officer deems the demonstrations to be complete, the Executive Officer shall, within 15 business days, take final action to either approve or disapprove a physical pathway demonstration and notif y the regulated party of the

final action.

(3) Data Verification. All data and calculations s ubmitted by a regulated party for demonstrating compliance or claiming credit are subject to verification by the Executive Officer or a third par ty approved by the Executive Officer.

(4) Access To Facility And Data. Pursuant to H&S section 41510, if necessary under the circumstances , after obtaining a warrant, the

Executive Officer has the ri ght of entry to any pr emises owned, operated, used, leased, or rented by an owner or operator of a facility in order to inspect and copy records relevant to the determination of compliance.

(e) Violations and Penalties.

(1) Pursuant to H&S section 38580 (par t of the California Global Warming Solutions Act of 2006), any violation of the provisions of the LCFS regulation (17 CCR §95480 et seq.) may be enjoined pursuant to H&S section 41513, and the violation is subj ect to those penalties set forth inA-36 Article 3 (commencing with Section 42400) of Chapter 4 of Part 4 of, and Chapter 1.5 (commencing with Section 43025) of Part 5 of, Division 26.

(2) Pursuant to H&S section 38580, any vi olation of the provisions of the LCFS regulation shall be deemed to result in an emission of an air contaminant for the purposes of t he penalty provisions of Article 3 (commencing with Section 42400) of C hapter 4 of Part 4 of, and Chapter 1.5 (commencing with Section 43 025) of Part 5 of, Division 26.

(3) Any violation of the provisions of the LCFS regulation shall be subject to all other penalties and remedies permitted under State law.

NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 39515, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).



### Section 95485. LCFS Credits and Deficits

(a) Calculation of Credits and Deficits Generated.

A regulated party must calc ulate the amount of credits and deficits generated in a compliance period for an LCFS fuel using the methods specified below in section 95485(a)(1) through (3). The total credi ts and deficits generated are used in determining the overall credit balance for a compliance period, pursuant to section 95484(b). All credits and deficits are denominated in units of metric tons (“MT”) of carbon dioxide equivalent.

(1) All LCFS fuel quantities used for credit calculation must be in energy units of megajoules (MJ).

Fuel quantities denominated in other units, such as those shown in Table 4, must be converted to MJ by multiplying by the corresponding energy density 71 :

71 Energy density factors are based on the lower heating values of fuels in CA-GREET using BTU to MJ

conversion of 1055 J/Btu.A-37 Table 4. Energy Densities of LCFS Fuels and Blendstocks.

Fuel (units) Energy Density CARBOB (gal) 119.53 (MJ/gal) CaRFG (gal) 115.63 (MJ/gal) Diesel fuel (gal) 134.47 (MJ/gal) CNG (scf) 0.98 (MJ/scf) LNG (gal) 78.83 (MJ/gal) Electricity (KWh) 3.60 (MJ/KWh) Hydrogen (kg) 120.00 (MJ/kg) Neat denatured Ethanol (gal) 80.53 (MJ/gal) Neat Biomass-based diesel (gal) 126.13 (MJ/gal)

(2) The total credits and deficits generated by a regulated party in a compliance period must be calculated as follows:

diesel

i n

i gasoline

i n

i Gen Credits Credits MT Credits 

# ∑ ∑ + = ) (

diesel

i n

i gasoline

i n

i Gen Deficits Deficits MT Deficits 

# ∑ ∑ + = ) (

where:

Gen Credits represents the total credits (a zero or positive value), in units of metric tons (“MT”), fo r all fuels and blendstoc ks determined from the credits generated under either or both of the gasol ine and diesel fuel average carbon intens ity requirements;

Gen Deficits represents the total deficits (a nega tive value), in units of metric
tons (“MT”), for all fuels and blen dstocks determined from the deficits generated under either or both of the gasoline and diesel fuel average carbon intensity requirements;

i is the finished fuel or blendstock index; and

n is the total number of finished fuels and blendstocks provided by a regulated party in a compliance period.

(3) LCFS credits or deficits for each f uel or blendstock supplied by a regulated party must be calculated accordi ng to the following equations:

(A) 

# ( ) C E CI CI MT Deficits Credits XD displaced XD reported XD

dard s XD

i XD

i × ×

− = tan ) ( /

where:A-38 XD

i Credits / XD

i Deficits (MT) is either the amount of LCFS credits
generated (a zero or positive value) , or deficits incurred (a negative value), in metric tons, by a f uel or blendstock under the average carbon intensity requirement for gasoline ( XD =”gasoline”) or diesel ( XD =”diesel”);

XD

dard s CI

tan is the average carbon intens ity requirement of either
gasoline ( XD = “gasoline”) or diesel fuel ( XD = “diesel”) for a given year as provided in section 9548 2 (b) and (c), respectively;

XD reported CI is the adjusted carbon int ensity value of a fuel or

blendstock, in gCO2E/MJ, calculat ed as per section 95485(a)(3)(B);

XD displaced E is the total amount of gasoline ( XD =”gasoline”) or diesel

( XD =”diesel”) fuel energy displaced, in MJ, by the use of an alternative fuel, calculated as per section 95485(a)(3)(C); and

C is a factor used to convert credit s to units of metric tons from gCO2E and has the value of:

C = 1.0 x 10

− 6 MT 

## ( )

gCO 2 E 

## ( )

(B)

XD i XD reported EER CI CI =

where:

i CI is the carbon intensit y of the fuel or bl endstock, measured in
gCO2E/MJ, determined by a Calif ornia-modified GREET pathway or a custom pathway and incorpor ates a land use modifier (if applicable); and

XD EER is the dimensionless Energy Economy Ratio (EER) relative

to gasoline ( XD =”gasoline”) or diesel fuel ( XD = “diesel”) as listed in

Table 5. For a vehicle-fuel comb ination not listed in Table 5,

XD EER =1 must be used.A-39 (C) XD

i XD displaced EER E E × =

where:

i E is the energy of the f uel or blendstock, in MJ , determined from
the energy density conversion factor s in Table 4.

Table 5. EER Values for Fuels Used in Light- and Medium-Duty, and Heavy-Duty Applications.

Light/Medium-Duty Applications (Fuels used as gasoline replacement) Heavy-Duty/Off-Road Applications (Fuels used as diesel replacement)

Fuel/Vehicle Combin ation EER Values

Relative to Gasoline Fuel/Vehicle Combin ation EER Values

Relative to Diesel

Gasoline (incl. E6 and E10)

or

E85 (and other ethanol blends) 1.0 Diesel fuel

or

Biomass-based diesel

blends 1.0

CNG / ICEV 1.0 CNG or LNG 0.9

Electricity / BEV, or PHEV 3.0 Electricity / BEV, or PHEV 2.7

H2 / FCV 2.3 H2 / FCV 1.9

(BEV = battery electric vehicle, PH EV=plug-in hybrid electric vehicle, FCV = fuel cell vehicle, ICEV = internal combustion engine vehicle)

(b) Credit Generation Frequency. Beginning 2011 and every year afterwards, a regulated party may generate credits quarterly.

(c) Credit Acquisition, Banki ng, Borrowing, and Trading.

(1) A regulated party may:

(A) retain LCFS credits without ex piration for use within the LCFS

market.

(B) acquire or transfer LCFS credits. A third party entit y that is not a regulated party or acting on behalf of a regulated party, may not purchase, sell, or trade LCFS credits.

(C) export credits for compliance with other greenhouse gas reduction initiatives including, but not limited to, programs established pursuant to AB 32 (Nunez, Stats. 2006, ch. 488), subject to the authorities and requirements of those programs.

(2) A regulated party may not:A-40 (A) use credits generated outside t he LCFS program in the LCFS, including, but not limited to, credits generated in other AB 32

programs.

(B) borrow or use credits from ant icipated future carbon intensity

reductions.

(C) generate LCFS credits from fuels exempted from the LCFS under section 95480.1(d) or are otherwise not one of the transportation fuels specified in section 95480.1(a).

(d) Nature of Credits.

LCFS credits shall not constitute instruments, securities, or any other form of property.

NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 39515, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).



### Section 95486. Determination of Carbon Intensity Values

(a) Selection of Method.

(1) A regulated party for CARBOB, ga soline, or diesel fuel must use Method 1, as set forth in section 95486(b)(2)(A), to determine the carbon intensity of each fuel or blendstock fo r which it is responsible (“regulated party’s fuel”).

(2) A regulated party for any other fuel or blendsto ck must use Method 1, as set forth in section 95486(b)(2)(B), to determine the carbon intensity of each fuel for the regulated party’s f uels, unless the regulated party is approved for using either Method 2A or Method 2B, as provided in section 95486(c) or (d).

(b) Method 1 – ARB Lookup Table.

(1) To generate carbon intensity val ues, ARB uses the California-modified GREET (CA-GREET) model (version 1. 8b), which is incorporated hereinA-41 by reference, and a land-use change (L UC) modifier (when applicable).

The CA-GREET model is available for downloading on ARB’s internet site.

Upon adoption of the LCFS, the Ex ecutive Officer will certify for use in meeting the requirements of this section an initial set of carbon intensity values for various fuel pathways. This initial set of carbon intensity values will be published in a Carbon Intensit y Lookup Table (hereinafter called “Lookup Table”), which will be available on ARB’s internet site. Thereafter, the Executive Officer will add to the Lookup Table any new carbon intensity values and their a ssociated pathways, either at the
Executive Officer’s initiative or Exec utive Officer approval of a new fuel and pathway proposed by a regulated party pursuant to Method 2A or 2B. Both the initial set of carbon intensity values and subsequently approved new carbon-intensity values will be published in the Lookup Table and

made available on ARB’s internet site for use as specified in this section.

(2) Use of Lookup-Table Car bon-Intensity Values.

(A) For CARBOB, Gasoline and Diesel Fuel.

For purposes of this section 95486( b)(2)(A), “2006 California baseline crude mix” means the total pool of crude oil supplied to California refiners in 2006; “included in the 2006 Califor nia baseline crude mix” means the

crude oil constituted at least 2.0% of the 2006 Californi a baseline crude mix, by volume, as shown by Califo rnia Energy Commission records for 2006; and “high carbon-intensity crude o il” means any crude oil that has a total production and transport carbon-in tensity value greater than 15.00 grams CO2e/MJ.

The carbon intensity for a regulated party’s CARBOB, gasoline or a diesel fuel is determined as specified in section 95486(b)(2)(A)1. or 2. below, whichever applies:

1. For CARBOB, Gasoline or Diesel Fuel Derived from Crude Oil That

Is Either Included in the 2006 Calif ornia Baseline Crude Mix or Is Not a High Carbon Intensity Crude Oil

.

If a regulated party’s CARBOB, gas oline or diesel fuel is derived

from crude oil that is either:

a. included in the 2006 Calif ornia baseline crude mix, or

b. not a high car bon-intensity crude oil,

the regulated party must use the average carbon intensity value shown in the Lookup Table for CARBOB, gasoline or diesel fuel.A-42 2. For All Other CARBOB, Gasoline or Diesel Fuel, Including Those Derived from High Carbon-Intensity Crude Oil.

Except as set forth in this prov ision, if a regulated party’s CARBOB, gasoline, or diesel fuel does not fall within section 95486(b)(2)(A)1. above (including those derived fr om high carbon-intensity crude oils), the carbon intensity for the regulated party’s crude oil must be

determined as follows in the order shown:

a. The carbon intensity value shown in the Lookup Table corresponding to the high carbon-intensity crude oil’s pathway;

b. Except as provided in c. bel ow, if there is no carbon intensity value shown in the Lookup Table corresponding to the crude’s pathway, the regulated party must propose a new pathway for its crude oil and obtain approval from the

Executive Officer for the result ing pathway’s carbon intensity pursuant to Method 2B as set forth in section 95486(d) and (f); or

c. The regulated party may, upon written Executive Officer approval pursuant to secti on 95486(f), use the average carbon intensity value in the Lookup Table for CARBOB, gasoline or diesel fuel, provi ded the GHG emissions from the fuel’s crude production and tr ansport steps are subject to control measures, such as carbon capture-and-sequestration (CCS) or other methods, which reduce the crude oil’s production and transport carbon- intensity value to 15.00 grams CO2e/MJ or less, as determined by the Executive

Officer.

(B) For All Other Fuels and Blendstocks.

Except as provided in section 95486( c) and (d), for each of a regulated party’s fuels, the regulat ed party must use the carbon intensity value in Lookup Table that most closely co rresponds to the production process used to produce the regulated party’s fuel. The Lookup Table carbon intensity value selected by the regulat ed party is subject to approval by the
Executive Officer.

For example, if one of the regulated party’s fuels is ethanol produced from

the fermentation of cellulosic feed stock derived from farmed trees, the regulated party would use the total carbon intensity value in the Lookup Table (i.e., the last column in Lookup Table) corresponding to theA-43 applicable Fuel (Ethanol) and Feedsto ck (Cellulosic, Farmed Trees, Fermentation).

(c) Method 2A – Customized Lookup Tabl e Values (Modified Method 1).

Under Method 2A, the regulated party may propose, for the Executive Officer’s written approval pursuant to section 95486(f) , modifications to one or more inputs to the CA-GREET model used to generate the carbon intensity values in the Method 1 Lookup Table.

For any of its transportation fuels subj ect to the LCFS re gulation, a regulated party may propose the use of Method 2A to determine the fuel’s carbon intensity, as provided in this section 95486(c). For each fuel subject to a proposed Method 2A, the regulated party must obtain wri tten approval from the Executive Officer for its proposed Method 2A before the r egulated party may use Method 2A for determining the carbon intensity of the fuel. The Executive Officer’s written approval may include more than one of a regulated party’s fuels under Method

2A.

The Executive Officer may not approve a proposed Method 2A unless the regulated party and its proposed Method 2A meet the scientif ic defensibility, “5-10” substantiality, and data submitta l requirements specified in section 95486(e)(1) through (3) and the following requirements:

(1) The proposed modified CA-GREET inputs must accurately reflect the conditions specific to the regulated party’s production and distribution

process;

(2) The proposed Method 2A uses on ly the inputs that are already incorporated in CA-GREET and d oes not add any new inputs (e.g., refinery efficiency); and

(3) The regulated party must reques t the Executive Officer to conduct an analysis or modeling to determine t he new pathway’s impact on total carbon intensity due to indirect effect s, including land-use changes, as the Executive Officer deems appropriate. The Executive Officer will use the GTAP model, which is incorporated by reference, or other model determined by the Executive Officer to be at least equivalent to the GTAP

model.

(d) Method 2B – New Pathway Generated by California-Modified GREET (v.1.8b).

Under Method 2B, the regulated party proposes for the Executive Officer’s written approval the generation of a new pathway using the CA-GREET as provided for in this provision. The Exec utive Officer’s approval is subject to the requirements as specified in secti on 95486(f) and the following requirements:A-44 (1) For purposes of this provision, “new pathway” means the proposed full fuel-cycle (well-to-wheel) pathway is not already in the ARB Lookup Table specified in section 95486(b)(1), as determined by the Executive Officer;

(2) The regulated party must demonstr ate to the Executive Officer’s

satisfaction that the CA-GREET can be modified successfully to generate the proposed new pathway. If the Exec utive Officer determines that the

CA-GREET model cannot successfu lly generate the proposed new pathway, the proponent-regulated party must use either Method 1 or Method 2A to determine its fuel’s carbon intensity;

(3) The regulated party must identify a ll modified parameters for use in the CA-GREET for generating the new pathway;

(4) The CA-GREET inputs used to generat e the new pathway must accurately reflect the conditions specific to the regulated party’s production and marketing process; and

(5) The regulated party must request the Executive Officer to conduct an analysis or modeling to determine t he new pathway’s impact on total carbon intensity due to indirect effect s, including land-use changes, as the Executive Officer deems appropriate. The Executive Officer will use the GTAP model, which is incorporated by reference, or other model determined by the Executive Officer to be at least equivalent to the GTAP

model.

(e) Scientific Defensibility, Burden of Proof, Substantia lity, and Data Submittal Requirements and Procedure for Appr oval of Method 2A or 2B.

For a proposed Method 2A or 2B to be appr oved by the Executive Officer, the regulated party must demonstr ate that the met hod is both scientifically defensible and, for Method 2A, meets the substantia lity requirement, as specified below:

(1) Scientific Defensibility and Burden of Proof. This requirement applies to both Method 2A and 2B. A regulated par ty that proposes to use Method

2A or 2B bears the sole burden of dem onstrating to the Executive Officer’s satisfaction, that the proposed method is scientifically defensible.

(A) For purposes of this regulation, “scientifically defensible” means the

method has been demonstrated to the Executive Officer as being at least as valid and robust as Method 1 for calculating the fuel’s carbon intensity.

(B) Proof that a proposed method is scientifically defensible may rely on, but is not limited to, publicatio n of the proposed Method 2A orA-45 2B in a major, well-established an d peer-reviewed scientific journal (e.g., Science, Nature, Journal of the Air and Waste Management Association, Proceedings of the National Academies of Science).

(2) “5-10” Substantiality Requirement. This requirement applies only to a proposed use of Method 2A, as provided in section 95486(c). For each of its transportation fuels for which a regulated party is proposing to use Method 2A, the regulated party must demonstrate, to the Executive Officer’s satisfaction, that the pr oposed Method 2A m eets both of the following substantiality requirements:

(A) The s ource-to-tank carbon intensity fo r the fuel under the proposed Method 2A is at least 5.00 gram s CO2-eq/MJ less than the sourceto-tank carbon intensity for the fu el as calculated under Method 1. “Source-to-tank” means all the steps involved in the growing/extraction, production and transport of the fuel to California, but it does not include the carbon intensity due to the vehicle’s use of the fuel; “source-t o-tank” may also be referred to as

“well-to-tank” or “field-to-tank.”

(B) The regulated party can and is expected to provide in California more than 10 million gasoline gall on equivalents per year (1,156 MJ) of the regulated fuel. Th is requirement applies to a transportation fuel only if the tota l amount of the fuel sold in California from all providers of t hat fuel exceeds 10 million gasoline gallon equivalents per year.

(3) D a ta Submittal. This requirement applies to both Method 2A and 2B. A regulated party proposing Method 2A or 2B for a fuel’s carbon intensity

value must meet all the following requirements:

(A) Submit to the Executive Officer all supporting data, calculations, and other documentation, includ ing but not limited to, flow diagrams, flow rates, CA-G REET calculations, equipment description, maps, and other inform ation that the Executive Officer determines is necessary to veri fy the proposed fuel pathway and how the carbon intensity value proposed for that pathway was derived;

(B) All relevant data, calculati ons, and other documentation in (A) above must be submitted electronically, such as via email or an online web-based interface, whenever possible;

(C) The regulated party must spec ifically identify all information submitted pursuant to this provisi on that is a trade secret; “tradeA-46 secret” has the same meaning as defined in Government Code section 6254.7; and

(D) The regulated party must not co nvert spreadsheets in CA-GREET containing formulas into other file formats.

(f) Approval Process. To obtain Executive Officer approval of a proposed Method 2A or 2B, the regulated party must submit an application as follows:

(1) General Information Requirements.

(A) For a proposed use of Method 2A , the regulated party’s application must contain all the information spec ified in section 95486(c), (e), and (f)(2);

(B) For a proposed use of Method 2B , the regulated party’s application must contain all the information specified in section 95486(d), (e)(1), (e)(3), and (f)(2).

(2) Use of Method 2A or 2B Prohibited Without Executive Officer Approval.

The regulated party must obtain the Exec utive Officer’s written approval of its application submitted pursuant to section 95486(f)(1) above before using a proposed Method 2A or 2B for any purpose under the LCFS regulation. Any use of a proposed Method 2A or 2B before Executive Officer approval is granted shall constitute a violation of this regulation for each day that the violation occurs. A regulated party that submits any information or documentation in suppor t of a proposed Method 2A or 2B

must include a written stat ement clearly showing t hat the regulated party understands and agrees to the following:

(A) All information not identified in 95486(e)(3)(C) as trade secrets are subject to public disclosure pursuant to 17 CCR §§ 91000-91022 and the California Public Records Act (Government Code section 6250 et seq.); and

(B) If the application is approved by the Executive Officer, the carbon intensity values, associated param eters, and other fuel pathwayrelated information obtained or deriv ed from the appl ication will be incorporated into the Method 1 Lookup Table for use on a free, unlimited license, and otherwise unres tricted basis by any person;

(3) Completeness/Incompleteness Determination. After receiving an application submitted under this sect ion, the Executive Officer shall determine whether the application is co mplete within 15 calendar days. If

the Executive Officer determines t he application is incomplete, theA-47 Executive Officer shall notify the regul ated party accordingly and identify the deficiencies in the application. T he deadline set forth in this provision shall also apply to supplemental in formation submitted in response to an incompleteness determination by the Executive Officer.

(4) Public Review . After determining an application is complete, the Executive Officer shall publish the application and its details on ARB’s

internet site and make it available for a minimum 30-calendar day, publicreview process. The Executive Officer shall treat all trade secrets specifically identified by the regulated party under section 95486(e)(3)(C)

above in accordance with 17 CCR §§ 91000-91022 and the California Public Records Act (Government Code section 6250 et seq.).

(5) Final Action. Within 45 calendar days afte r the public review process set forth in subsection (f)(3) above ends, the Executive Officer shall take final action to approve or disapprove an applic ation submitted pursuant to this subsection (f). The Executive Of ficer shall notify the regulated party accordingly and publish the final action on ARB’s internet site. If the final action is approval of a new carbon intensity value and associated fuel pathway, the Executive Officer shall update the Lookup Table to reflect the new value accordingly. If t he Executive Officer disapproves an application, the disapproval shall identify the basis for the disapproval.

NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 39515, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).



### Section 95487. Requirements fo r Multimedia Evaluation

(a) Pre-Sale Approval Requirement.

Except as provided for in section 95487( c), a regulated party must not sell, supply, distribute, import, offe r for sale, or offer for us e in California a regulated

fuel unless one of the followin g conditions has first been met:

(1) a multimedia evaluation for t he regulated fuel has been conducted pursuant to the requirements specif ied in this regulation, and that evaluation has been approved by the Executive Officer; orA-48 (2) a multimedia evaluat ion for the regulated fuel has been conducted, and that evaluation was approved by the Ex ecutive Officer prior to the date the Office of Administrative Law (OAL ) approves the LCFS regulation.

(b) Requirements.

(1) The Executive Officer, or his or her designee, shall not approve a multimedia evaluation subject to this section 95487(b) unless the evaluation has undergone the process for review and approval specified in H&S section 43830.8, including but not limited to, receiving peer review and approval by the California Envir onmental Policy Council pursuant to H&S section 43830.8(d)-(g). For pur poses of H&S section 43830.8(a), each Executive Officer approval of a r egulated fuel for compliance with the LCFS regulation under section 95487(a)(1) shall constitute compliance with the requirement in H&S sect ion 43830.8(a) for conducting a multimedia evaluation prior to adoption of a “regulation that establishes a specification for moto r vehicle fuel.”

(2) All multimedia evaluations subjec t to this section 95487shall be evaluated
in accordance with the California Environmental Protection Agency (Cal/EPA) guidance do cument entitled, Guidance Document and Recommendations on the Types of Sci entific Information Submitted by Applicants for California Fuels Envi ronmental Multimedia Evaluations (June 2008) , which can be downloaded at http://www.arb.ca.gov/f uels/multimedia/080608guidance.pdf, and which is incorporated herein by reference.

(c) Exemptions.

(1) Negative Declaration For ARB- Adopted New Or Amended Fuel Specifications

.

The requirements of this section 95487 do not apply to a regulated fuel if:

(A) the regulated fuel is subj ect to a proposed ARB regulation establishing a new or amending an ex isting fuel specification, which ARB adopts after the date OAL approv es the LCFS regulation; and

(B) the California Environmental Po licy Council, following an initial evaluation of the propos ed regulation, conclusively determines that the regulation will not have any si gnificant adverse impact on public

health or the environment.

(2) CaRFG, Diesel Fuel, E100, E85, CNG, LNG, and Hydrogen.

The requirements of this section 95487 do not apply to a regulated fuel if:A-49 (A) the fuel is subject to an ARB-adopted fuel specification; and

(B) the Executive Officer does not am end that fuel specification after OAL approves the LCFS regulation.

Fuels currently subject to this provis ion include CaRFG, diesel fuel, E100, E85, CNG, LNG, and hydrogen. This provision applies only to the extent

that the Executive Officer does not amend the fuel specification for any of the above fuels. When OAL approves an ARB amendment to a fuel specification identified abov e, this provision shall no longer apply for that

fuel.

(3) Biomass-Based Diesel and Electricity.

The requirements of th is section 95487 do not apply to a regulated fuel

that:

(A) is subject to the Division of Measurement Standar ds’ Engine Fuels Standards (4 CCR §4140 et seq.); but

(B) is not subject to an ARB-adopted fuel specification.

Fuels currently subject to this provision include biomass-based diesel, and electricity. This provis ion applies only to the extent that the Executive Officer does not adopt a fuel specification for any of the above fuels. When OAL approves an ARB-adopted fuel specification for a f uel identified above, th is provision shall no longer apply for that fuel.

NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 395 15, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).A-50 

### Section 95488. Cap and Trade

(a) [This section is reserved for future use]

NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 39515, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).



### Section 95489. Regulation Review

The Executive Officer shall conduct a revi ew of the implement ation of the LCFS program by January 1, 2012. The Exec utive Officer shall determine the scope and

content of the review.

NOTE: Authority cited: Sections 38510, 38560, 38560.5, 38571, 38580, 39600, 39601, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975). Reference cited: Secti ons 38501, 38510, 38560, 38560.5, 38571, 38580, 39000, 39001, 39002, 39003, 39515, 39516, 41510, 41511, 43013, and 43018, Health and Safety Code; and Western Oil and Gas Ass’n v. Orange County Air Pollution

Control District , 14 Cal.3rd 411, 121 Cal.Rptr. 249 (1975).A-51