LCFS Basics with Notes

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In 2009 the Board approved the LCFS regulation to reduce the carbon intensity (CI) of

transportation fuel used in California by at least 10 percent by 2020 from a 2010 baseline.

In 2011, the Board approved amendments to clarify, streamline, and enhance certain

provisions of the regulation. In 2015, the Board re‐adopted the LCFS to address procedural

issues, which began implementation on January 1, 2016. In 2018, the Board approved

amendments to the re gulation, which includes strengthening and smoothing the CI

benchmarks through 2030 in‐line with California’s 2030 GHG target enacte d through SB32.

The LCFS is one of the key AB 32 measures to reduce greenhouse gas emissions in

California but also has other significant benefits. It transforms and diversifies the fuel pool

in California to reduce petroleum dependency and achieves air quality benefits, which are

State priorities that preceded AB 32.

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The LCFS is designed to reduce GHG emissions in the transportation sector, which is

responsible for about 50 percent of GHG emissions (including industrial sector emissions

from refining and crude production), 80 percent of ozone‐forming gas emissions, and over

95 percent of diesel particulate matter.

It is a key part of a comprehensive set of programs in California to reduce emissions from

the transportation sector, including the Cap and Trade Program, Advanced Clean Cars

Program, and SB 375.

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The LCFS sets annual carbon intensity (CI) standards, or benchmarks, which reduce over

time, for gasoline, diesel, and the fuels that replace them.

Carbon intensity is expressed in grams of carbon dioxide equivalent per megajoule of

energy provided by that fuel. CI takes into account the GHG emissions associated with all

of the steps of producing, transporting, and consuming a fuel—also known as a complete

life cycle of that fuel.

The LCFS lets the market determine which mix of fuels will be used to reach the program

targets.

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Fuels and fuel blendstocks introduced into the California fuel system that have a CI higher

than the benchmark generate deficits. Similarly, fuels and fuel blendstocks with CIs below

the benchmark generate credits. Annual compliance is achieved when a regulated party

uses credits to match its deficits.

Since the regulation was first adopted, the compliance curves have been “back‐loaded” to

allow time for the development of low‐CI fuels and advanced vehicles (the benchmark CI

reduction was frozen by court order for three years between 2013 and 2015). Due to this

program design choice, there has always been the expectation that excess credits

generated in the early years of the program would be available for use in more stringent

future years, if needed.

Under the current LCFS regulation, the 2030 standard of a 20 percent CI decline will also be

imposed for all years post‐2030.

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Since the regulation went into effect, low carbon fuel use has increased. Fuel producers

are also taking action to decrease the carbon intensity of their fuels.

The program has an established market for credit transactions. The total value of credit

transactions exceeded $2 billion in 2018.

The LCFS Data Dashboard web page was created to display the current and historical LCFS

program data. Some of the information found in the Data Dashboard are the following:

• Volume of fuels and credits generated under the LCFS

• Compliance curve and the percent reduction in carbon intensity to date

• Credit volumes transacted and the average credit prices per month under the LCFS.

To see the Data Dashboard, please see

http://www.arb.ca.gov/fuels/lcfs/dashboard/dashboard.htm.

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Other jurisdictions are joining California, which is evident in the Pacific Coast Collaborative,

a regional agreement between California, Oregon, Washington, and British Columbia to

strategically align policies to reduce greenhouse gases and promote clean energy.

One of the provisions of this Collaborative explicitly addresses Low Carbon Fuel Standard

programs. California, Oregon, and British Columbia have existing LCFS programs in place

and the Washington legislature is considering a program.

Staff has been routinely working with these jurisdictions, providing assistance where we

can. Over time, these LCFS programs will build an integrated West Coast market for low‐

carbon fuels that will create greater market pull, increased confidence for investors of low

carbon alternative fuels, and synergistic implementation and enforcement programs.

Other regions including Canada and Brazil are also noticing California’s success and

developing LCFS‐like performance standards for transportation fuels.

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There are three ways to generate credits in the LCFS: fuel pathways, projects, and capacity‐

based crediting.

Under fuel pathway‐based crediting, all transportation fuels need a carbon intensity score

to participate in the LCFS, and the fuel type dictates which process is used to determine

that CI. Providers of low carbon fuels used in California transportation generate credits by

obtaining a certified CI and reporting transaction quantities on a quarterly basis. Credits

are calculated relative to the annual CI benchmark and will undergo verification post credit

generation.

Under project‐based crediting, projects include actions to reduce GHG emissions in the

petroleum supply chain, and also CCS using Direct Air Capture. Crediting for projects is

based on life cycle emission reductions, and credits are issued after the reported

reductions are verified.

Finally, the 2018 amendments added a new crediting mechanism to the LCFS which is

designed to support the deployment of zero emission vehicle infrastructure. Crediting for

ZEV infrastructure is based on the capacity of the hydrogen station or EV fast charging site

minus the actual fuel dispensed.

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The Alternative Fuels Portal (AFP) and the LCFS Credit Banking and Transfer System (LRT‐CBTS) are two of the modules that

make up the LCFS database management system. Not depicted here is the Verification module, which will provide access to

participant data for LCFS‐accredited Verification Bodies.

The AFP facilitates the application process to obtain a certified CI score. Applicants for Tier 1 and Tier 2 pathways, which rely

on site‐specific data, use this portal to submit their CI calculator and supplemental information.

All Lookup Table CI values were historically obtained through the LRT‐CBTS. Beginning in 2019, all applicants for Hydrogen

Lookup Table pathways will apply through the AFP, along with applicants for the Zero‐CI Electricity Lookup Table pathway.

Entities seeking any other Lookup Table pathway, including CARBOB, ULSD, California Average Grid Electricity, CNG, LPG, and

Smart Charging or Smart Electrolysis, do not need to register in the AFP and will continue to use the LRT‐CBTS.

The LRT‐CBTS is designed specifically to facilitate reporting and credit banking and transfers. Beginning in 2019 it will also be

able to process project‐based crediting and ZEV infrastructure crediting applications.

Entity requirements and responsibilities are defined by the role each entity plays. An entity may have multiple roles in the

LCFS, such as an alternative liquid fuel producer may be a Fuel Pathway applicant, but because this entity also reports and

generates credits, they are a fuel reporting entity as well. A hydrogen station owner who generates infrastructure credits must

also be a fuel reporting entity (to report the quantity of fuel dispensed); this entity may also be a pathway holder, or another

entity could have taken the responsibilities of applying for and maintaining the pathway. All fuel pathway applicants become

fuel pathway holders once their CI is certified; they must annually demonstrate that the pathway remains valid.

Note that applications for carbon capture and sequestration may be approved through the:

• AFP (fuel pathway‐based crediting) if the capture occurs within the process of an alternative fuel pathway, e.g., CO

from

ethanol fermentation

• LRT (project‐based crediting) if the capture is associated with crude oil production (Innovative Crude provisions) or a

petroleum refinery (Refinery Investment Credit provisions), or by direct air capture (not associated with any fuel; may be

credited as a stand‐alone project).

To access the LRT‐CBTS and AFP, please see https://ssl.arb.ca.gov/lcfsrt/index.html?aspxerrorpath=/lcfsrt/Login.aspx.

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The LCFS regulation does not apply to an alternative fuel that is not a biomass‐based fuel or

is supplied in California with an aggregated quantity of less than 420 million MJ/year.

Conventional jet fuel, aviation gasoline, deficit‐generating fuel used in military tactical

vehicles, and credit‐generating fossil CNG or fossil propane dispensed at a fueling station

with total throughput of 150,000 gasoline‐gallons equivalent or less per year (until 2021 or

2024, respectively) are also exempt from the LCFS. The LCFS regulation also does not apply

to fuels used in interstate locomotives, ocean‐going vessels, and deficit‐generating fossil

propane and CNG used in school buses purchased prior to January 1, 2020.

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Credits and deficits are calculated using the carbon intensity benchmarks for gasoline and

diesel fuel in each calendar year. These benchmarks equate to a 6.25 percent reduction in

carbon intensity relative to 2010 in the 2019 compliance year, increasing linearly to a 20

percent reduction in 2030.

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Since conventional jet fuel is not subject to the LCFS regulation and does not generate

deficits, these carbon intensity benchmarks are used specifically to calculate credits from

alternative jet fuel. The jet fuel benchmarks remain fixed at the 2010 baseline CI for

conventional jet fuel, with a zero percent reduction in each year, until the benchmark for

diesel substitute s declines below the CI baseline for jet fuel, in 2023. The jet fuel

benchmarks then mirror the benchmarks for diesel through 2030.

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The CI includes the “direct” effects of producing and using the fuel, as well as “indirect”

effects that are primarily associated with crop‐based biofuels. Two models are used to

calculate the direct effects, which are the California Greenhouse Gases, Regulated

Emissions, and Energy Use in Transportation (CA‐GREET) and Oil Production Greenhouse

gas Emissions Estimator (OPGEE) models. To calculate the indirect effects, the Global Trade

Analysis Project (GTAP) model was updated and the Agro‐Ecological Zone Emissions Factor

(AEZ‐EF) model was created to supplement GTAP’s estimates of greenhouse gas emissions

from various types of land conversions.

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This is an illustration of the life cycle assessment of California Reformulated Gasoline

Blendstock for Oxygenate Blending (CARBOB). CARBOB makes up the petroleum fraction of

California reformulated gasoline (CaRFG) before any fuel oxygenate is added; CARFG is

essentially 90 percent CARBOB blended with 10 percent ethanol by volume.

CARBOB CI is based on the 2010 average crude oil supplied to California refineries and

average California refinery efficiencies. Crude oil is evaluated using the OPGEE model; the

crude supplied to California refineries in 2010 was found to have an average CI of 11.78

gCO

e/MJ, with some crudes ranging from as low as 4 to as high as 30 gCO

e/MJ.

Production of CARBOB at all California refineries adds 14.8 g/MJ to the fuel cycle CI. About

75 percent of the GHG emissions from the life cycle of CARBOB occur during combustion in

vehicles (tailpipe emissions).

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This is an illustration of the life cycle assessment of corn ethanol. Emissions associated with agriculture

contribute 29 gCO

e/MJ; of that, 11 g result from the production of fertilizer and soil amendments, and the

soil emissions resulting from synthetic and organic additions contribute an additional 14 g/MJ, and on‐farm

emissions from energy use in tractors during activities such as planting, cultivation and harvest, make up the

remainder.

Emissions from production at the ethanol facilities vary widely depending on their process fuels, their

efficiencies, and any processing of co‐products, such as drying distiller’s grains and solubles (DGS). Please

note that this slide contains numerical values for illustrative purposes only.

DGS is the remnants of the corn after fermentation and is sold and used as livestock feed. A credit of‐12

g/MJ is assessed for the production of DGS at a typical rate of 5.31 dry pounds per gallon of ethanol; this

credit reflects market displacement of corn and other feed ingredients from LCFS application

Contributing substantially to the impacts associated with corn (and other crops) used to produce biofuels is

the phenomenon called land use change, or LUC. LUC occurs when higher ethanol demand increases the

demand for corn, raising its market price. Someone, somewhere, reacting to this price signal, will convert

land to corn production, either directly or through a series of daisy‐chain events, which will result in carbon

emissions from that land. The estimated amount of land conversion and associated GHG emissions are

determined using the GTAP and AEZ‐EF models and are added to the CI of corn ethanol. All crop‐based

feedstocks have LUC values.

Finally, the CO

emitted from vehicles during biofuel combustion is considered carbon neutral, in accordance

with IPCC and U.S. EPA GHG inventory guidelines, as the carbon released was uptaken from the atmosphere

by the corn within a short timeframe. Additionally, ethanol is required to be denatured in order to render it

unfit for human consumption. A small amount of gasoline blendstock is added, typically 2.5%v/v, for this

purpose, adding 1 g/MJ to the CI of denatured ethanol.

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This is an illustration of the life cycle assessment of biodiesel made from used cooking oil

(UCO). UCO, also known as waste grease, is collected from sites like industrial food

processors and restaurants. The UCO is transported to a rendering facility where it is

filtered and purified to remove any water, solids, contaminants, to reduce the level of free

fatty acids (FFA) and ensure the oil has the correct properties required for fuel production.

The rendered oil is then transported to a biorefinery where it is converted to biodiesel by

reacting with methanol in a chemical process called esterification. The process also yields

a co‐product, glycerin; an accounting method known as energy‐based allocation is used to

divide the total emissions from the facility between its two products. 95 percent of the

production emissions are attributed to biodiesel and the remaining 5 percent to glycerin.

Please note that this slide contains numerical values for illustrative purposes only.

The CO

emitted from vehicles during biofuel combustion is considered carbon neutral, in

accordance with IPCC and U.S. EPA GHG inventory guidelines, as the carbon released was

uptaken from the atmosphere within a short timeframe by the plant that produced the oil.

A small amount of emissions, less than 1 g/MJ, result from the GHGs (methane and nitrous

oxide) that form during biodiesel combustion.

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This is an illustration of the life cycle assessment of California’s average grid electricity when it is

used to charge Electric Vehicles (EV).

The carbon intensity of California electricity is calculated in CA‐GREET 3.0 using the 2017 average

California generation resource mix from the CEC database

, slightly modified to match CA‐GREET

resource categories

in order to calculate the emissions associated with each resource.

The GHG emissions for this pathway consist of the upstream emissions associated with producing

and transporting each fuel to the power plant, the emissions associated with generating electricity

(combustion of fossil based resources like natural gas), and transmission line losses (translated to

emissions from the excess electricity that must be supplied to meet demand).

Finally, EVs in the Light‐duty Vehicles (LDV) and Medium‐duty Vehicles (MDV) are over three times

more efficient than the internal combustion engines (ICE) they replace. The life cycle emissions

from electricity generation sum up to 81.49 gCO

/MJ of electricity, but the effective CI shown here

is on the basis of the amount of gasoline that is displaced by the use of EVs. The efficiency ratio is,

therefore, translated to an emission savings representing the smaller amount of energy an EV

needs to travel the same distance as an ICE.

2017 California Total System Electric Generation, California Energy Commission:

https://www.energy.ca.gov/almanac/electricity_data/total_system_power.html

California Air Resources Board, CA‐GREET 3.0 Supplemental Document and Tables of Changes, 13‐

AUG‐2018: https://www.arb.ca.gov/fuels/lcfs/ca‐greet/cagreet_supp_doc_clean.pdf

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This illustration shows the stages that are analyzed while performing life cycle assessment of compressed natural

gas (CNG) from landfill gas (LFG). LFG is also known as biogas as it originates from organic materials which

decompose without oxygen in landfills, resulting in generation of methane. Biogas is typically 50‐60% methane and

the remainder is made up of CO

and trace gases.

Recovery of biogas is accomplished using electrical fans to draw gas up through wells inserted throughout a landfill.

Most landfills are required to capture LFG and oxidize methane to CO

by the use of a flare or thermal oxidizer. By

capturing and using this gas as a transportation fuel rather than flaring, CO

emissions are avoided.

Capture mechanisms are imperfect, resulting in an estimated 25 percent of LFG that escapes the flare; this emission

is considered outside of the LCA system boundary, as it occurs whether a landfill is capturing gas for use as a fuel, or

for flaring. This is a principle of life cycle assessment, which seeks to determine what emissions would occur in a

reference or baseline scenario, and compares the project case in order to determine the net change caused by a

process or product.

Biogas upgrading is where the majority of the emissions associated with LFG to CNG occur. The objective is to

remove CO

, water, and to scrub unwanted components such as hydrogen sulfide in order to bring the biogas to

pipeline‐quality and motor vehicle standards. At this stage the gas is referred to as biomethane.

Transmission via the system of natural gas pipelines that span the U.S. can also result in a significant quantity of

emissions, for a conservative distance from a landfill to CA, 3,600 miles pipeline is chosen. Compressors require

energy to move gas through pipelines, and methane has opportunities to escape during gas transmission; the

magnitude of emissions is dependent on the distance gas travels from its source to its end use.

When pipeline gas is withdrawn at a refueling station, it is compressed to CNG before it is injected into a vehicle.

The tailpipe emissions that occur during combustion of CNG in a natural gas engine for methane and nitrous oxide

only; CO2 is cancelled with the avoidance of the combustion of a flare. Please note that this slide contains

numerical values for illustrative purposes only.

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All transportation fuels need a carbon intensity score to participate in the LCFS, and the fuel type

dictates which process is used to determine that CI.

Lookup Table pathways have CI scores that are predetermined by CARB using industry‐wide

average inputs, or conservative assumptions. Most of the fuels in the Lookup Table don’t require

an application, and those that do require an application have a few requirements and a very

streamlined approval process.

The Tier 1 pathway application process is for the most common low carbon fuels, and applicants

use a Simplified CI Calculator to determine their site‐specific fuel production and transport

emissions. Under Tier 1, most emissions from feedstock production are based on standard inputs,

but the calculators have some flexibility to accommodate user‐defined process energy inputs.

The Tier 2 application process is designed for innovative, next‐generation pathways, which may use

unique feedstocks or include advanced technologies like Carbon Capture and Sequestration. Tier 2

fuels include Alternative jet fuel, and any other pathway that is not eligible to use the Lookup Table

or Tier 1 process. Applicants for these pathways can fully customize the California GREET model to

accurately determine their site‐specific CI.

The diagram shows the basic process for credit generation. Credits for fuel pathways are calculated

based on the CI score that is determined in the initial pathway application, the energy economy

ratio or EER for the type of vehicle the fuel is used in, and the quantity of fuel reported. Credits are

issued quarterly, and pathways with site‐specific CI data will typically be verified annually.

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A regulated entity ’s annual compliance obligation is met when the regulated entity

demonstrates via its annual report that it possessed and has retired a number of credits

from its credit account that is equal to its compliance obligation. The annual compliance

period is January 1

through December 31

of each calendar year.

Fuel transactions from each calendar quarter are reported during the next calendar

quarter. After each deadline, no credits can be generated for an activity that took place in

the prior quarter. Transactions involving business partners must be reconciled by the

“Deadline” dates shown in the LCFS Reporting Schedule table. The quarterly reporting

schedule is as follows:

• June 30

: For the first calendar quarter covering January through March

• September 30

: For the second calendar quarter covering April through June

• December 31

: For the third calendar quarter covering July through September

• March 31

: For the fourth calendar quarter covering October through December

The annual compliance reports must be submitted by April 30

of each year.

For more information on the LRT‐CBTS and AFP, or to submit quarterly or annual reports,

please visit the Data Management System web page:

http://www.arb.ca.gov/fuels/lcfs/reportingtool/datamanagementsystem.htm.

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A system for third‐party verification is needed to ensure accuracy of reported greenhouse

gas data. The framework and principles of the LCFS verification program are consistent

with the verification systems that support CARB’s Cap‐and‐Trade program. The LCFS

verification program provides confidence and reliability in reported data for stak eholders,

market participants, and the public—the data have financial implications and quality

assurance must meet a specified level of rigor.

Third‐party verification is international best practice for credible greenhouse gas

monitoring and reporting and considered a re quirement for carbon pricing systems. The

verification program is based on ISO 14064‐3 and 14065. It also provides a systematic,

independent, and documented process for evaluation of reported data against the LCFS

regulatory requirements and methods for calculation.

Beginning in 2019, verifiers will apply for CARB accreditation and take required tr aining and

exam(s). CARB will publish on the LCFS website the list of verification bodies and verifiers

accredited to perform LCFS verification services.

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The entities required to contract for verification services are summarized here.

Regulated entities specified in section 95500 are required to retain the ser vices of

independent verifiers accredited by CARB, beginning with 2020 fuel pathway applications

and in 2021 for LCFS data reports, and thereafter. Deferred verification statements are due

in 2023 for those who are eligible.

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The LCFS Regulation includes requirements for data accuracy and meter calibration.

Reported LCFS data have financial implications and must meet the specified level of rigor.

All entities that submit LCFS data used to calculate GHG emissions and reductions must

attest to its accuracy. Most LCFS data are based on financial transaction meters that meet

CARB’s accuracy requirements: suppliers and purchasers who do not have common owners

rely on the measurements for sales, meters are sealed with a valid seal from the county

sealer of weights and measures or from a county certified designee, or third parties

operate the meters. Meters that do not meet the criteria above, referred to as “internal

meters,” must be installed, operated, and maintained according to manufacturer‐

recommended calibration frequency and precision requirements to meet accuracy

requirements for LCFS data. In addition, entities responsible for obtaining third‐party

verification must document measurement device information in a written Monitoring Plan

according to section 95491.1(c) and demonstrate acceptable measurement accuracy. If

data are missing, the regulated entity must be able to demonstrate to the verifier that

reported data are accurate within +/‐ 5 percent or must obtain CARB approval of an

alternate monitoring method pursuant to section 95488.8(k).

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If a regulated party does not retire sufficient credits to meet its compliance obligation, then

a Credit Clearance Market will be initiated. Entities with credits to sell can opt to pledge

credits into the market and entities needing credits must purchase their pro‐rata share of

these pledged credits. A price cap in the clearance market prevents extreme market

volatility, thereby providing consumer protection.

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The LCFS contains two credit opportunities for refineries, an expanded credit opportunity

for crude production, and Carbon Capture and Sequestration by Direct Air Capture.

The renewable hydrogen refinery credit provision allows refineries to generate credits

through the use of renewable hydrogen at the refinery to produce gasoline and diesel.

Renewable hydrogen can be produced using steam methane reforming of renewable

natural gas or through electrolysis using renewable electricity.

The refinery investment credit provision allows refineries to generate credits for GHG

reduction projects undertaken at a refinery. These projects include use of renewable

energy sources, conversion of combustion power sources to electricity, use of carbon

capture and sequestration, and process improvement projects.

The innovative crude credit provision supports innovative technologies for solar steam or

heat generation, solar‐ or wind‐based electricity, renewable natural gas or biogas energy,

and carbon capture and sequestration.

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Projects claiming CCS credits must comply with the CCS Protocol. Credits must be prorated

based on the volumes delivered to California, ex cept for direct air capture projects.

The amount of net CO

sequestered by alternative fuel producers can be used to adjust the

carbon intensities of the associated fuel pathways.

All CCS projects must undergo verification.

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Examples of how the CCS Protocol c an be used in the LCFS include low carbon fuel

pathway, refinery investment, innovative crude, or direct air capture.

To generate credits for CCS projects, credits go to the capture facility. The storage facility

must also be a co‐applicant, but capture and storage facilities do not need to be co‐located.

All CCS projects must receive a Permanence Certification before LCFS credit generation is

possible.

Recognized reservoirs under the LCFS include saline formations, CO

enhanced oil recovery,

and depleted oil and gas reservoirs.

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Electric vehicles, trucks, electric transit systems (fixed guideway, buses), electric forklifts,

electric cargo‐handling equipment, electric transportation refrigeration units, and shore

power to ocean‐going vessels at‐berth are eligible to generate credits.

Due to the fact that consumer preferences of electric vehicle owners has not resulted in

widespread installation of separate metering in residences, CARB calculates the credits for

non‐metered residential charging of EVs, to maintain the quality and accuracy of the credit

generations. Electrical Distribution Utilities (EDU) e arn “base” credits for all residential

charging using the grid average CI, and the load serving entity, auto manufacturer, or

another entity may also generate “incre mental” credits for supplying metered, low‐CI

electricity or smart charging to those residences. In the event that multiple entities claim

incremental credits for a given residence, the LCFS provides the following order of priority:

the Load‐Serving Entity (LSE), including a Community Choice Aggregator (CCA); the

automobile manufacturer who provides metered charging data through on‐vehicle

telematics; and any other entity who can provide the metered data has the third priority,

which could include a charging service provider or an aggregator. All electricity credit

generators must use credit proceeds to promote transportation electrification, and provide

benefits to their EV customers and educate them about the benefits of EV transportation.

The LCFS streamlines and facilitates the credit generation and reporting for public,

workplace and fleet charging. Utilities will receive those credits unless electrical vehicle

service providers, site hosts or fleet owners opt in.

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The combination of zero‐carbon electricity and zero‐emission vehicles offer s significant

opportunity for reductions that are not well recognized by the program to date. To address

this issue, the 2018 amendments allow renewable power generated off‐site to be used in

EV charging and hydrogen production by electrolysis. The amendments also recognize the

benefits of shifting EV charging and electrolyzer loads to periods of time when excess

renewable electricity might otherwise be wasted. These amendments are intended to be a

first step in promoting further expansion of zero‐emission vehicle infrastructure through

the LCFS, as directed by the Governor’s Executive Order. They would help make these

vehicles fully “zero emission” on a life cycle basis.

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The LCFS also contains hydrogen provisions. The person who owns the hydrogen fueling

supply equipment or the hydrogen forklift fleet is eligible to generate credits for hydrogen

fueling. Lookup Table pathways for hydrogen produced in California are available to

streamline participation. Hydrogen is an opt‐in fuel until statewide use in transportation

meets a threshold of 3,500 tons per year.

To learn more about the LCFS electricity and hydrogen provisions, please see

http://www.arb.ca.gov/fuels/lcfs/electricity/electricityh2.htm.

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In April 2018, the Board also directed staff to explore the establishment of a statewide

Clean Fuel Reward program funded by the sale of LCFS credits and given at the point of

electric vehicle sale or lease. Since the April Board hearing, a coalition of Electrical Utilities

and Automakers have come together to lay the groundwork for such a program. The

approach required targeted changes in the LCFS to accommodate the rebate program: we

have set a minimum percentage contribution from all utilities that opt in, which scales with

utility size and increases over time; and we have also established batter y‐capacity tiers—in‐

line with the federal rebate structure—to ensure EVs with higher battery capacity get the

maximum rebate.

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To provide additional incentives for growth of ZEVs, in the recent round of rulemaking, the

program included a provision termed “infrastructure crediting” to include both hydrogen

refueling stations and DC fast chargers. The concept is simple: The LCFS will credit eligible

stations based on the capacity of the station to deliver fuel once the station is fully utilized.

Infrastructure credits will decrease as a station/charger reaches full utilization, until it is

only generating credits for its dispensed fuel. In this way, the provision is designed to be

“self‐sunsetting.” This provision is designed to address the “chicken & egg” problem, in

which demand for zero emission vehicles is low because consumers can’t refuel them, and

refueling station developers won’t build stations until more vehicles are sold.

For more information on the LCFS ZEV Infrastructure Crediting Provision, please see

https://www.arb.ca.gov/fuels/lcfs/electricity/zev_infrastructure/zev_infrastructure.htm