2019 POLICY REPORT

THE LCFS AND
CCS PROTOCOL:AN OVERVIEW FOR
POLICYMAKERS
AND PROJECTDEVELOPERS

ALEX TOWNSEND
Senior Consultant - Economics
IAN HAVERCROFT
Senior Consultant - Legal & Regulatory

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Contents
Key messages......................................................4
1.0 Introduction................................................... 6
2.0 The main elements of the CCS
Protocol of the LCFS..........................................7
3.0 A comparison to other
US regulations....................................................16
4.0 Combining LCFS credits with
45Q tax credits.................................................20
5.0 Conclusions................................................22
6.0 References..................................................23

POLICY REPORT3

POLICY REPORT4

KEY MESSAGES
1. The Low Carbon Fuel Standard (“LCFS”) is one ofseveral policies in California that originate from the
Global Warming Act of 2006. It places lifecycle carbon
intensity targets on all transportation fuels sold in
California, with the aim of diversifying the State’s fuelmix, reducing petroleum dependency, and reducing
GHG emissions and other air pollutants. Fuels thathave a lower carbon intensity than the carbon intensity
target generate credits and fuels with a higher carbon
intensity than the target generate deficits.
2. In 2018, the LCFS was amended to enable CCS
projects that reduce emissions associated with the
production of transport fuels sold in California, andprojects that directly capture CO2 from the air, togenerate LCFS credits. These changes came into
effect in January 2019. To qualify, projects need tomeet the requirements of the CCS Protocol which
is subordinate to the LCFS Regulation Order. Thechanges have attracted attention from policymakers inother jurisdictions and CCS project developers keen tounderstand the program, particularly given the credits
have been trading on average between $122/tCO2
and $190/tCO2 in the past 12 months to February 2019.
3. This report provides a summary of the main elementsof the CCS Protocol, to help improve awareness andunderstanding of how CCS projects could accessrevenues by generating and selling credits under
the LCFS. It also provides a comparison to otherregulations and incentives in the US associated with
the injection and geologic sequestration of CO2 thatproject operators must comply with or can benefit from.

1

Greater than 90% probability.

POLICY REPORT

4. CCS projects must apply for and receive Permanence
Certification before they can claim credits under the
LCFS. To receive certification, operators are required
to meet several minimum site selection criteria, toprepare, maintain and comply with a range of sitespecific plans throughout the lifecycle of the project,
and to submit regular reports to the California Air
Resources Board (“CARB”). Operators must monitor
the site for at least 100 years post-injection and only
sites in which the fraction of CO2 retained in thestorage complex is very likely1 to exceed 99% over 100
years post-injection will be approved.
5. The number of credits a project can claim is specified
in the accounting requirements of the CCS Protocol.
CCS projects must contribute between 8% and 16.4%of the credits they generate to a Buffer Account which
provides a reserve that can be drawn on to maintainthe environmental integrity of the LCFS in the eventof CO2 leaking from a storage complex. In addition,
operators are required to hold a financial instrument,such as insurance, that covers the cost of performing
corrective action, plugging wells, post injection sitecare and closure, and emergency and remedial
response, based on the cost of hiring a third party
to conduct those activities. The financial instrument
would, for example, cover the costs of maintaining
and closing the site in the event the operator goesout of business before site closure has been granted.

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6. The relationship between the credits obtained
under the LCFS and those generated under the US
Federal Government’s 45Q scheme has been raised,with several commentators highlighting the potential
opportunity from combining or “stacking” LCFS credits
and 45Q tax credits. The 45Q scheme provides tax
credits in 2019 worth $31/tCO2 for CCS projects that
inject CO2 into dedicated geological storage and $19/
tCO2 for CO2 utilization and direct air capture projects.
The value of credits rises linearly, to $50/tCO2 and$35/tCO2 respectively by 2026 and with inflation
thereafter.
7. To be eligible to claim 45Q tax credits a project
operator must demonstrate the secure geologicalstorage of CO2 and the IRS is currently consulting on
the requirements an operator would need to satisfy todemonstrate this. Under the current proposal, where
CO2 is injected underground, the operator would
need to be in possession of either a Class II or ClassVI permit as required under the Underground Injection
Control (“UIC”) Program. They would also need to havean EPA-approved site-specific monitoring, reportingand verification plan, as required under Subpart RRof the GHG Reporting Program. The IRS is seeking
views on whether to designate alternative pathways
to demonstrate secure geological storage including
the use of standards developed by the International
Organization for Standardization.

8. The CCS Protocol’s permanence requirements gobeyond the federal requirements for both Class II andClass VI wells. For example, the minimum post injection
site care period for Class VI wells is 50 years rather than
the Protocol’s 100-year requirement, and the focus of
the Class VI well requirements is on the protection ofdrinking water resources rather than public health andthe environment more generally. The differences are
greater with respect to the federal requirements forClass II wells which have no post-injection site carerequirements. CCS projects in the US with a Class II
or Class VI permit and complying with the Subpart RR
monitoring and reporting regulations may therefore
need to change their operations, reporting, financial
cover or administrative processes to qualify for the
LCFS.

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1.0 INTRODUCTION
This report provides a summary of the CCS Protocol of
the California Low Carbon Fuel Standard (“LCFS”) and
how it compares to other significant regulations andpolicies in the US associated with the injection andgeologic sequestration of CO2. The other regulations
and policies covered include the Underground
Injection Control (“UIC”) Program, GHG Reporting
Program and 45Q tax credits. An illustration of how
these regulations and policies fit together and thesections of the report in which they are discussed isprovided in Figure 1.
The report was written to inform policymakers and CCS
project developers interested in understanding themain elements of the regulations and the requirements
a CCS project would need to fulfill to generate LCFS
credits. The report necessarily simplifies the regulatory
text and interested readers are encouraged to read the
LCFS Regulation Order and CCS Protocol in full to geta better understanding of the detailed requirements of
the regulations.

The report is structured as follows. Section 2.0
describes the main elements of the CCS Protocol,
including eligibility, permanence, and reporting andverification requirements, as well as the approachproject operators need to take to estimate thenumber of credits that can be claimed for their project.
Section 3.0 compares the permanence requirementsof the CCS Protocol with the requirements of theUnderground Injection Control Program, with which
all US projects injecting CO2 underground mustcomply. Section 4.0 draws on this analysis to assess
the similarities and differences between the eligibility
and operating requirements project operators would
need to meet to qualify to generate LCFS credits and
45Q tax credits, and the potential value from ‘stacking’these credits. Section 5.0 concludes the report.

Figure 1: An illustration of how the regulations and policies in this report relate to one another2

Operators in the US injecting
CO2 underground must report
information to the EPA under
Subpart RR or UU of the GHG
Reporting Program(Section 3.0)

Operators in the US mustobtain a permit to inject CO2
underground under the federal
or state-level Underground
Injection Control (“UIC”)
Program (Section 3.0)
2

FUEL

CO2

CCS project operators that sellfuel into California or directly
capture CO2 from the air canclaim LCFS credits, provided
they meet the requirements of
the CCS protocol (Section 2.0)

Operators in the US that
demonstrate secure geologic
storage of CO2 can claim 45Q
tax credits (Section 4.0)

Direct Air Capture projects are an exception as they are not required to sell transportation fuel into the California market to generate credits (see Section 2.1).

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2.0 THE MAINELEMENTS OF THE
CCS PROTOCOL OF
THE LCFS
2.1. An introduction to the
LCFS and CCS Protocol
The Low Carbon Fuel Standard (“LCFS”) was introduced
by Executive Order in 2007. It is one of several policies
in California designed to reduce greenhouse gas(“GHG”) emissions as required by Assembly Bill 32,
the 2006 Global Warming Solutions Act. The programis administered by the California Air Resources Board(“CARB”) which under the Clean Air Act has primacy toregulate GHG emissions in California.
The LCFS is a market-based policy that sets annual
carbon intensity benchmarks on transport fuels
sold, supplied or offered for sale in California. The
benchmarks reflect the full lifecycle emissions oftransportation fuels and include all GHG emissions
associated with producing, distributing, and using
the fuel, expressed as grams of CO2e per megajoule(“MJ”). The benchmarks fall over time up to 2030 withthe aim of reducing the carbon intensity of the State’s
transport fuel mix by 20% by 2030, relative to 2010
levels.
Separate benchmarks are placed on gasoline, diesel
and jet fuel, and the respective fuels that replace them.
Fuels with a carbon intensity that is lower than therelevant annual benchmark generate credits and fuelswith a carbon intensity that is higher than the relevantbenchmark generate deficits.

Providers of clean, alternative fuels that already meetthe relevant 2030 carbon intensity benchmark are
exempt from the LCFS but may opt-in to the program
to receive credits for the fuels they sell in California.3
Electricity, biogas and renewable propane all fall
into this category of fuels, as do fuels produced with
innovative production methods.4
Fuel providers that produce, import, distribute or selltransportation fuels in California must on an annual
basis have enough credits to compensate for any
deficits created by the sale of carbon intensive fuels.
These fuel providers are referred to as Regulated
Parties under the LCFS. To ensure they have sufficientcredits in a given year, a Regulated Party can:• use credits banked from previous years, if available;• buy credits from another Regulated Party in
California, or a provider of clean, alternative fuelsthat has opted into the LCFS;• increase the volumes of fuels they sell that have acarbon intensity below the benchmark, or reducethe volumes of fuels they sell that have a carbon
intensity above the benchmark;• change production processes for the fuels they
produce, to make them less carbon intensive; or• transfer the obligation through written contract toanother party.

Other exemptions include fuels used for military vehicles and equipment, locomotives, ocean going vessels, as well as propane, non-biomass-based fuel, conventional jet
fuel and fuels for which sales are below 420 million MJ/year.
4
Innovative production methods include the use of low carbon intensity process energy sources. It also includes CCS, which is the main subject of this report.
3

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Credits banked from previous years are held on the
LCFS Reporting Tool and Credit Bank & Transfer
System (“LRT-CBTS”) and are available indefinitely
until used to meet annual targets. The LRT-CBTS is
also used to record information on credit transactions
between Regulated Parties, including the price andvolume of every credit transaction. This information
is aggregated and published by CARB, providing atransparent price signal to potential credit generators.
Credit prices have been highly volatile over the past
year, with monthly average prices ranging from $122/
tCO2 to $190/tCO2.5

Regulated Parties must report quarterly on fueltransactions and submit annual compliance reports
to CARB via the LRT-CBTS. If a fuel provider has ashortage of credits after taking account of all credits
retired in the calendar year and any purchased up to
the end of April the following year,6 they must purchasetheir pro-rata share of their outstanding obligationon the Credit Clearance Market (“CCM”). The Credit
Clearance Market is a cost-containment mechanismthat provides an additional route to compliance, withthe cost of credits capped at $200/tCO2 in 2016 prices,
rising with inflation. If the fuel provider is not able topurchase enough credits from other Regulated Parties
on the Credit Clearance Market, they must retire theremaining balance of their obligation, with interest,
within five years.

Figure 2: Summary of how the LCFS works and how CCS projects can be used to meet targets

CARB sets
annual carbon
intensity (“CI”)
target in eachyear for gasoline
and diesel

Fuels that have ahigher CI than thetarget generate
deficts and fuels witha lower CI generatecredits

Fuel providers in
California must ineach year haveenough credits tocompensate for
deficits

Options to ensure fuel providers

Use credits banked
from previous years(if available)

Buy credits
from anotherfuel provider in
California, or an
opted-in credit
generator

Fuel providers
submit an annualcompliancereportIf still in deficit, must
purchase credits on
the CCM and retire
outstanding balance
within 5 years

have sufficient credits in a given year

Increase production or
imports of low CI fuels,or reduce imports or
production ofhigh CI fuels

Change production
methods to makefuels less carbon
intensive

Transfer ownershipof the fuel andcompliancerequirements

CCS PROJECTS CAN BE USED AS PART OF THESE COMPLIANCE OPTIONS

5
6

Taken from Monthly LCFS Credit Transfer Activity Reports from March 2018 to February 2019 available at: https://www.arb.ca.gov/fuels/lcfs/credit/lrtmonthlycreditreports.htm.
Known as “carryback” credits.

POLICY REPORT9

In 2018, the LCFS was amended to allow CCS projects
to generate LCFS credits by reducing the emissions
associated with the production of transport fuels or bydirectly capturing CO2 from the air, provided they meetthe requirements specified in the CCS Protocol. Thesechanges came into effect in January 2019. A summaryof how CCS projects could generate credits andsupport compliance within the broader context of the
LCFS is provided in Figure 2. The extension of the LCFS
has attracted interest from both policymakers and CCS
project developers and may provide a strong financial
incentive to support the increase in deployment of
CCS needed to meet climate targets at the lowest
possible cost. A broad range of CCS projects canqualify to generate credits under the LCFS, provided
they sequester the captured CO2 onshore, in either
saline or depleted oil and gas reservoirs, or oil and gas
reservoirs used for CO2-enhanced oil recovery (“CO2EOR”).
Credits can be generated under one of two crediting
methods. Operators can opt-in to receive projectbased credits, receiving the number of credits equal
to the emissions reductions they achieve from the
project (see Section 2.3). Alternatively, operators cangenerate credits under the fuel pathway approach,which requires them to apply for a new fuel pathway
carbon intensity score that they can claim credits
against. Some projects are restricted to particular
types of crediting schemes, as illustrated in Figure 3.

Direct Air Capture (“DAC”) projects anywhere in theworld can generate credits by opting in to the LCFS.
These projects are an exception to the LCFS as they
are not required to sell transportation fuel into the
California market to generate credits. In actual fact,
CO2 derived from direct air capture that is converted
to fuels is not eligible for project-based crediting under
the LCFS and would need to apply for a separate fuelpathway to be eligible to generate credits.
CCS projects at refineries and at oil and gas production
facilities must apply for credits under the Refinery
Investment Credit Program and Innovative Crude
Provision respectively. These project-based crediting
schemes place additional restrictions on applicants,
such as minimum size thresholds or limiting the point
in time from which projects are eligible.
All other projects, such as ethanol production with
CCS, have similar eligibility requirements to DAC
projects, but can either claim credits under a projectbased or fuel pathway approach. Similar to projects at
refineries and oil and gas production facilities, theseprojects can be located outside of California, but can
only claim credits for the proportion of transport fuelsold into the Californian market.

Figure 3: Different types of CCS projects that can qualify to generate credits under the LCFSDIRECT AIR
CAPTUREPROJECTS
Location of
CCS project

CCS AT OIL & GAS
PRODUCTION
FACILITIESCCS AT REFINERIESPROJECTS

Anywhere, provided they Anywhere, provided they
Anywhere in the world sell the transportationsell the transportation fuelfuel in California
in California

ALL OTHER CCS
PROJECTS (E.G. CCS
WITH ETHANOL)
Anywhere, provided
they sell thetransportation fuel in
California

Storage site

Onshore saline or depleted oil and gas reservoirs, or oil and gas reservoirs used for CO2-EOR

Credit method

Project-based

Project-based, underthe Innovative Crude
Provision

Project-based, under the
Refinery Investment Credit
Program

Project-based or fuelpathway

Earliest date
which existing
projects eligible

Any

2010

2016

Any

Requirements
Additional
restrictions

Project must meet requirements specified in the CCS Protocol
None

Must achieve minimum
CI or emission reduction

None

None

POLICY REPORT102.2. Permanence
requirements of the CCS
ProtocolTo be eligible to claim credits, a CCS operator mustfirst demonstrate that the sequestration site is suitableto permanently store CO2 and that they have theplans and financial resources in place to manage
any residual risk of CO2 leakage throughout the
lifetime of the project. This is achieved by applying
for and receiving Sequestration Site Certification and
CCS Project Certification, collectively referred to as
Permanence Certification.
The sequestration site must meet several minimum
selection criteria to be eligible to receive Permanence
Certification. For example, the site must be of sufficientvolume, porosity, permeability and injectivity to receive
the total anticipated volume of CO2, have a minimum
injection depth of 800m or depth corresponding to theconditions where CO2 exists in a supercritical state, andhave a confining system free from transmissive faults
or fractures. In addition, only sites in which the fractionof CO2 retained in the storage complex is very likely(greater than 90% probability of occurrence) to exceed
99% over 100 years post-injection will be eligible togenerate credits under the LCFS.

7
8Alongside the minimum site selection criteria,
the project must also satisfy an expansive set of
requirements throughout the project lifetime to receive
and maintain Permanence Certification. This includes
maintaining, updating and submitting changes toplans throughout the project, constructing wells inaccordance with the specified standards, undertaking
testing and monitoring to ensure mechanical integrityat the site is maintained and that there are no leaks,
plugging wells in a way that protects against leaks,
and monitoring the site for at least 100 years postinjection. These requirements remain until site closure
has been granted and the operator is released of theirpost-injection site care duties. A summary of the mainelements of the permanence requirements over the
lifecycle of the project is shown in Figure 4.
Applications for Permanence Certification must be
submitted jointly by the capture and storage operator
and must be verified by a CARB approved third
party prior to submission. A professional geologist
must certify that the data submitted as part of theSequestration Site Certification are true, accurate
and complete, and that the risks identified in the SiteBased Risk Assessment are sufficiently monitoredor remediated in the Emergency and Remedial
Response Plan.7 A professional engineer must certifythat the information submitted under the CCS Project
Certification is sufficiently robust and that, in theirprofessional judgement, the CCS project is able
to meet the permanence requirements of the CCS
Protocol.8

Professional geologists must be licensed under Chapter 12.5 of Division 3 of the California Business and Professions Code §§ 7800 – 7887.
Professional engineers must be licensed under Chapter 7 of Division 3 of the California Business and Professions Code §§ 6700 – 6799.

POLICY REPORT11

Figure 4: A summary of the main aspects of the permanence requirements of the CCS Protocol
PHASE OF PROJECTSUMMARY OF REQUIREMENTS

Site
characterization
and riskassessment• Project operators must submit detailed information on the geological and hydrologic characteristicsof the storage site and a Formation Testing and Well Logging Plan to explain how they will confirm
these characteristics.
• Project operators must complete a risk assessment and risk management plan that quantifies therisk of CO2 leakage up to 100 years post-injection. A project cannot qualify for the LCFS if its risk
management plan includes a risk with a High classification.
• Computational modelling of the CO2 plume must be done in accordance with the Protocol.

Well construction
and corrective
action• Wells must be constructed such that they prevent the movement of fluids into or between any
unauthorized zones, allow the use of appropriate testing devices and workover tools, and permit
continuous monitoring of pressure at specific locations at the site.
• Deviations in construction from the Well Construction Plan must be approved by the Executive
Officer before Permanence Certification is granted.
• All materials used in the construction of wells must be compatible with the fluids they may comeinto contact with, meet or exceed API, ASTM International, or comparable standards, and be of
sufficient structural strength to last the design life of the project.
• Several tests on injection wells must be performed prior to commencing CO2 injection to confirm
the characteristics of the site, ensure conformance with well construction requirements, andestablish accurate baseline data (e.g. step-rate and pressure fall off tests).
• Prior to injection, the operator must complete corrective action on all wells that either penetrate thestorage complex or are within its surface projection and are determined to need corrective action.
A report must be submitted demonstrating how corrective action was applied to deficient wells
prior to Permanence Certification being granted.

Operation• The injection pressure must not exceed 80 percent of the fracture pressure of the sequestration
zone, except when approved by the Executive Officer.
• Injection must not initiate fractures in the confining system, cause movement of the injection orformation fluids out of the storage complex, or unacceptably increase the risk of significant induced
seismicity.
• The mechanical integrity of wells must be maintained at all times, except during maintenance.
In the event of a loss of mechanical integrity or suspected leak, the operator must implement its
emergency plan. It must immediately cease injection in the affected well(s), take all reasonable
steps to determine whether there has been any leakage of CO2, notify the Executive Officer within
24 hours and restore and demonstrate mechanical integrity prior to resuming injection.
• Routine well maintenance must be conducted at least every 6 months.

Testing andmonitoring• The CCS Project Operator must prepare, maintain, and comply with a plan for testing andmonitoring to ensure that the CCS project is operating as certified and that the CO2 injected ispermanently sequestered. Monitoring must continue for at least 100 years post-injection.
• Injection rate and volume, and wellhead and downhole pressure must be monitored continuously
during the operation of the well.
• The CO2 plume must be reevaluated and revalidated at least every 5 years to confirm the plume iswithin the storage complex.
• Internal mechanical integrity of a well must be demonstrated prior to injection, and at least every 5
years thereafter. External mechanical integrity must be demonstrated within 3 months after injectioncommences and every year thereafter.
• Well materials must be tested for corrosion at least once every 5 years.
• Wellheads, valves, pipelines and surface equipment must be inspected at least annually.

Well plugging andabandonment• The CCS project operator must prepare, maintain and comply with a plan to plug all injection,
production and monitoring wells associated with the CCS project.
• The operator must notify the Executive Officer at least 30 days before plugging, converting or
abandoning a well. Written approval must be received before plugging can be completed.
• Within 60 days of plugging a well, the operator must submit a well plugging report confirming theplugging method used and that the well was found to be free from leaks.

Post-injection
site care and site
closure• Once all injection activity has been completed, the project operator must comply with theirpreviously submitted post-injection site care and site closure plan.
• All injection and production wells must be plugged within 24 months of injection completion.
Monitoring wells may remain open during the post-injection site care period.
• No sooner than 15 years post-injection, the operator may submit evidence to CARB to demonstratethat the CO2 plume has stabilized. If approved, all remaining open wells may be plugged andabandoned (securely and permanently sealed). The operator must implement a leak detection
strategy thereafter.
• Site closure may only occur at least 100 years after injection has been completed. Once approved,
the operator is released of their post-injection site care duties.

POLICY REPORT122.3. Calculating theemissions reductions of the
project
The accounting requirements of the CCS Protocol set
out the approach to estimating the GHG emissions
reductions from CCS projects. The emissions reductions
can be used directly to calculate the total number of
LCFS credits a project generates, where the projectis in a project-based crediting scheme such as under
the Refinery Investment Credit Program, Innovative
Crude Provision or is a DAC project. Alternatively, theemissions reductions can contribute to a reduction in
the carbon intensity of a fuel and be included in theapplication for a new fuel pathway, against which
credits can be generated. The calculations for thenumber of credits for both approaches is summarized
below, where the energy economy ratio takes accountof differences in the ability of a fuel to be converted todrive.9
Project based crediting
Number of credits (tCO2) = GHG emissions
reductions from project
Fuel pathway crediting
Number of credits (tCO2) = (CI of benchmark - CI offuel) * Energy economy ratio * Conversion factor

The annual GHG emissions reductions from a CCS
project are calculated by subtracting the GHG
emissions associated with the process of capturing,transporting and injecting CO2 from the amount of CO2
equivalents (“CO2e”) that is injected in that year. In thecontext of the CCS Protocol, GHG emissions include
emissions of carbon dioxide (“CO2”), methane (“CH4”),
nitrous oxide (“N2O”), volatile organic compounds(“VOC”) and carbon monoxide (“CO”). Both direct andindirect emissions are included within the calculationof the emissions from the project, as illustrated in
Figure 5.

9

The emissions associated with the capture, transport
and injection of CO2 are estimated using the CAGREET model available on the CARB website. The
CA-GREET model includes data on the global warming
potential of different GHG emissions to convert theminto CO2 e, as well as emissions factors to calculate theembodied emissions from electricity and fuel use in
the capture, transport and injection processes.
The emissions associated with direct land use change
resulting from the installation of new pipelines andconstruction of new CO2 injection sites are calculatedusing the Global Trade Assessment Project model or
CARB approved land use emission factors. While the
CCS Protocol only includes direct land use change,
when the feedstock used for the production of atransportation fuel results in land use change, such as
ethanol, this change will be factored into the carbon
intensity of the fuel elsewhere in the calculations.
There will be some instances where the projectapplicant will need to adjust the inputs and outputs of
the CA-GREET model to deal with a specific accounting
issue or take account of data that is not in the model.
This includes instances where the injected CO2
comes from multiple capture sources with different
GHG emissions which would need to be calculated
separately and combined to estimate the relevant
emissions for the project. Similarly, it includes instanceswhere pipelines serving the storage complex transport
CO2 to multiple sites, where values need to be prorated to only include the emissions attributable to theproject. For these exceptions the CCS Protocol sets
out the approach that project developers are required
to take.

CARB (2018), Public Workshop to Discuss Implementation: Low Carbon Fuel Standard, Available at: https://www.arb.ca.gov/fuels/lcfs/lcfs_meetings/112818presentation.pdf.

POLICY REPORT13

Figure 5: Approach to estimating the GHG emissions reductions from CCS under the CCS Protocol

GHG EMISSIONS REDUCTIONS = CO2 INJECTED - GHG EMISSIONS OF PROJECTGHG OFCAPTUREGHG emissions from the capture, dehydration and compression of CO2 including:• Fuel combustion in stationary equipment, including emissions from parasitic load
• Embodied emissions from electricity, steam and fuel used in carbon capture• Embodied emissions from chemicals used in carbon capture+
GHG OF
TRANSPORT+GHG OFINJECTION+
GHG OF DIRECTLAND USE
CHANGEGHG emissions from CO2 transport, including:• Fuel combustion in stationary equipment used in CO2 transport• Embodied emissions from electricity and fuel used in CO2 transport

GHG emissions associated with injecting CO2 including:• Fuel combustion in stationary equipment used for CO2 injection and recycling• Embodied emissions from purchased electricity, steam and fuel• CO2 vented, that leaks from storage or fugitive CO2 emissions from surface
equipment• Entrained CO2 in water, natural gas and oil produced (EOR only)• CO2 transferred outside of the site to another project (EOR only)

GHG emissions from changes in the land use resulting from the installation of new
pipelines and construction of the new CO2 injection sites

2.4. Contributions to the
Buffer Account, and financial
and insurance mechanisms
required
CCS projects seeking credit issuance under the LCFS
must contribute a percentage of the LCFS credits theygenerate to the Buffer Account. The Buffer Accountprovides a reserve that can be drawn on in the eventthat credits issued are no longer valid due to theleakage of CO2, in order to maintain the environmental
integrity of the LCFS. In addition to credits from CCS
projects, the Buffer Account includes credits remaining
from deactivated accounts, a provision for year-to-year
differences between reported and verified operational
carbon intensities, and any credits deleted or modified
by the Executive Officer.

CCS projects are required to contribute between 8%
and 16.4% of the credits they generate to the Buffer
Account. The amount they contribute depends on
the project risk rating, based on the potential for CO2
leakage associated with different types of risks andproject-specific circumstances. These risks include
the financial risk of the company, the social risk of the
project in terms of its location globally, the quality ofthe site in terms of its geological characteristics, themanagement of the facility and the integrity of the CCS
project wells. It is for project operators to conduct therisk assessment and report this to CARB, along with
the implied contribution they will make to the Buffer
Account.

POLICY REPORT14

The credits generated by CCS projects can beinvalidated if the CO2 associated with them migrates
outside of the storage complex or is released to theatmosphere. For the period up to 50 years postinjection, the invalid credits are first taken fromthe contribution to the Buffer Account made by
the CCS project when the credits were issued. In
instances where the volume of the leakage is larger
than the number of credits contributed to the Buffer
Account, a project operator must retire sufficientcredits to cover the outstanding balance by eitherpurchasing additional credits or using credits they
have generated. After 50 years post-injection, thecontributions made by all parties to the Buffer Accountwould be used to cover any credits found to be invalid
due to leakage and the project operator would not be
required to retire any additional credits. CO2 is thenconsidered permanently stored once it has remainedin the storage site for at least 100 years. The 100year assumption is consistent with IPCC guidance
and other sequestration projects, such as the forestry
offset protocol.10,11

A range of financial instruments can be used to satisfy
this requirement as stated in the Protocol, including
for example a trust bond, surety bond, letter ofcredit, insurance, self-insurance or escrow account.
When using a third-party instrument to demonstrate
financial responsibility, the CCS Project Operator
must provide proof that the third-party provider meets
certain financial conditions. A separate set of financial
conditions needs to be met should the operator want
to use self-insurance as the financial mechanism.
The operator is required to maintain a detailed written
estimate of the cost of the activities described above
and update it within 60 days of any changes to theplans on which it is based. If the estimate falls, theoperator may release funds tied up in the financial
instrument, subject to approval from CARB. If theestimate increases, the operator must within 60 days
update their cover to the higher amount, either using
the existing or a new instrument.

In addition to the contributions to the Buffer Account,throughout the lifetime of the project the CCS project
operator must maintain sufficient financial instrumentsthat provide cover to address the potential
endangerment to public health and the environment
from CO2 leakage. Specifically, the instruments mustbe sufficient to cover the cost of performing corrective
action, plugging wells, post injection site care andclosure, and emergency and remedial response,
based on the cost of hiring a third party to conduct
those activities. This would, for example, cover the
future costs of the project should the operator cease
to exist prior to site closure being granted.

10
11

CARB (2018), Final Statement of Reasons, pp. 594-607. Accessed 19 March 2019. Available at: https://www.arb.ca.gov/regact/2018/lcfs18/fsorlcfs.pdf.
IPCC, Land Use, Land-Use Change and Forestry. Accessed: February 17, 2018. Available: http://www.ipcc.ch/ipccreports/sres/land_use/index.php?idp=74.

POLICY REPORT15

2.5. Reporting andverification of emissions
reductions
For crediting purposes, CCS operators are required
to submit quarterly or annual reports throughout
the lifetime of the project, depending on how often
the project elects to undergo verification. Reports
must include information on the injection rate andvolume, analysis of the CO2 stream and all meteredmeasurements for the calculation of GHG emissions
reductions. Data must be uploaded in the LRT-CBTS
data management portal within the first 45 days after
the end of the reporting period and project reports
submitted within 3 months of the end of the reporting
period.

This includes information on any storage reevaluationor corrective action undertaken, any events that have
led to the implementation of the emergency plan, andresults from inspections and tests over the previous
year. A summary of the reporting requirements isshown in Figure 6.
All reports must be verified by an approved
verification body. The verification body is required toreview all plans, assessments and reports to ensure
they meet the requirements of the CCS Protocol and
LCFS Regulation Order, and summarize their findings
in a verification report. Verification reports must be
submitted within 8 months of the end of the reporting
period.

All projects must submit an annual compliance report
within 4 months of the end of a calendar year. This isseparate from the annual compliance report that fuelproviders must submit under the LCFS. The annual
report includes the information described above andprovides additional information on a range of topics.
Figure 6: Summary of the quarterly and annual reporting requirements of the CCS Protocol

INFORMATIONREPORTED FOR
CREDITING AND
VERIFICATIONINFORMATIONREPORTEDTO SATISFYREQUIREMENTS FORPERMANENCE

Reported quarterlyor annually

Reported annually• All metered measurements for calculation of GHG emission reductions• Injection rate and volume data
• Analysis of CO2 stream• All measurements required in quarterly reports and summary of their
credit position• A summary of any incidents that may have triggered a storage
complex reevaluation• A summary of any incidents that required implementation of theemergency plan
• External mechanical integrity well results every year, and internalmechanical integrity checks at least every 5 years• Results of pressure fall-off tests at least every 5 years• A report on any corrective action undertaken• A summary of inspections undertaken on wellheads, valves andpipelines

POLICY REPORT

16

3.0 A COMPARISONTO OTHER USREGULATIONS
All projects in the US that inject CO2 underground must
apply for and receive a permit in accordance with theUnderground Injection Control (“UIC”) Program. Thismeans that any US project applying for LCFS credits
must also meet the requirements of the UIC Program.
The UIC Program was created under the authority of the
Safe Drinking Water Act (“SDWA”). Under the SDWA,
the EPA developed minimum federal requirements toprotect public health by preventing injection wells fromcontaminating underground sources of drinking water.
There are six different well classifications under the
UIC Program, with Class II and Class VI being most
relevant in the context of CO2 injection.12 Class II wells
are those that are used to inject fluids associatedwith oil and gas operations, including wells used
for enhanced recovery of oil and natural gas. ClassVI wells are those used for the injection of CO2 into
geological formations, for the primary purpose of longterm storage. The Federal regulations for Class II wells
have been in force since the 1980s and Class VI well
regulations were later added in 2010.13
States can apply for primary enforcement authority,often called primacy, to regulate injection activities.
Forty-one states have EPA approved primacy
programs for Class II wells and one state, North
Dakota, has an approved primacy program for Class VI
wells.14 For all other states, the EPA directly implements
the Class II and Class VI program. The promulgationof state-level programs means an operator with CO2
injection operations in multiple states may need tomeet different requirements for each well, particularly
with respect to Class II permits.
Operators injecting CO2 underground in the US
must also report to EPA under the Greenhouse Gas

Reporting Program. Subpart RR of the program, whichapplies to CO2 injected for the purposes of geologic
sequestration such as Class VI wells, requires
operators to report annually on the amount of CO2
injected, produced and emitted to calculate the total
amount of CO2 sequestered. Operators must also
develop an EPA-approved monitoring, reporting andverification (“MRV”) plan which includes extensivemodelling and monitoring of the CO2 plume, to detect
any surface leakage and ensure the environmental
integrity of the project. Class II wells are only required
to report information on the CO2 received for injection
as required under Subpart UU of the Greenhouse Gas
Reporting Program but can opt-in to Subpart RR.
There are several significant differences between
the federal requirements for Class II wells that reportunder Subpart RR and the permanence requirementsof the LCFS, as shown in Figure 7. For example, therequirements for Class II wells are less prescriptive,
such that they are open to broader interpretation. The
scope of financial responsibility for Class II wells under
the SDWA is narrower, as financial mechanisms need
only cover the endangerment to underground sourcesof drinking water rather than to the environment andpublic health. Operators of Class II wells are also
not required to fulfill any specific post-injection sitecare duties under the federal regulations. For thesereasons a CCS project that meets the minimum
federal requirements of a Class II permit and reports
under the Subpart RR regulations may not be eligible
to qualify for the LCFS without significant changes totheir operations.
The requirements for Class VI wells are more closelyaligned to the CCS Protocol and in places the text in
the Protocol has been copied directly from the UIC
regulations.

Class IV wells, which are shallow wells used to dispose hazardous or radioactive wastes, were banned in 1984 such that, technically, there are only five types of well.
https://www.epa.gov/uic/class-vi-wells-used-geologic-sequestration-CO2.
14https://www.epa.gov/sites/production/files/2019-04/documents/primacy_status_revised_april17_2019_508c.pdf.
12
13

POLICY REPORT

17

However, there are some notable differences suchthat an operator with a Class VI permit will not
automatically meet the permanence requirements of
the CCS Protocol. For example:• The post-injection site care period for Class VI wells
is 50 years, or potentially shorter where agreementwith the EPA is reached. An operator with a Class VI
permit wishing to qualify for the LCFS will need toextend their post-injection site care plan to at least
100 years post-injection and monitor the site for theduration of that period. They will also need to provide
financial assurance cover for the extended period,
either by extending their existing financial assurance
mechanism(s) or providing a separate mechanism tocover potential costs for the remainder of the period.

• Similar to Class II wells, the Class VI regulations only
require the operator to maintain a financial instrument
to address the endangerment of undergroundsources of drinking water. The operator may need toamend the financial instrument in place, or provide
an additional instrument, to cover the broader
financial responsibility under the CCS Protocol.
• The operating requirements of the Class VI
regulations allow for a maximum injection pressureof 90% of the fracture pressure, rather than thedefault 80% in the CCS Protocol. Injection pressures
above 80% are permitted under the CCS Protocol
but require prior approval from the Executive Officer.

Figure 7: Similarities and differences between federal requirements for Class II and Class VI wells, and the CCS Protocol

PHASE OFPROJECT

CLASS II WELLS
CO2 INJECTED FOR EOR

CLASS VI WELLSDEDICATED GEOLOGICAL STORAGE

Permitting

Operators must provide similar information
to receive a permit, but requirements areless prescriptive providing some potential fordifferences in the information provided

Similar extent of information required to CCS
ProtocolWellconstruction
and corrective
actionSimilar requirements to CCS Protocol

Similar requirements to CCS Protocol

Operation

Injection pressure during operation not toexceed the maximum injection pressure rather
than 80%. No reference to the action required in
the event of an emergency

Injection pressure during operation not toexceed 90% of the maximum injection pressure
rather than 80%, but actions to take during an
emergency are the same

Testing andmonitoring

Observations of injection pressure and flow raterequired on a less frequent basis than in the
CCS Protocol, and no testing and monitoringplan required

Similar requirements to CCS Protocol

Plugging andabandonment

All wells must be plugged prior toabandonment, but process and information to
be reported is less detailed

Similar requirements to CCS Protocol

Post-injection
site care andclosureThere are no specific post-injection site careobligations for Class II wells

Post-injection site care responsibilities are
similar, except that the post-injection sitecare period is 50 years (subject to the EPA
discretion) rather than the 100 years specified
in the CCS Protocol

Insurance
and financial
mechanisms

Text on financial mechanisms is similar, but theterminology used for the costs to be covered by
the mechanism is different and may be open tointerpretation. In addition, the mechanism needs
only cover the cost of endangerment to drinking
water resources and not the environment andpublic health as specified in the CCS Protocol

Text on financial mechanisms is identical,
except that the financial mechanism needs only
cover the cost of endangerment to drinking
water resources and not the broader definitionof environment and public health as specified
in the CCS Protocol

Reporting

Similar requirements to CCS Protocol(when reporting under Subpart RR)

Similar requirements to CCS Protocol

POLICY REPORT18

CASE STUDY

THE LCFS, UIC PROGRAM AND
GHG REPORTING PROGRAM
An ethanol producer located in the US sells ethanol
into the California market to be blended with gasoline.
The producer is considering investing in carbon
capture equipment at their biorefinery. They want tobe able to generate LCFS credits and at the same time
meet the requirements of the UIC Program and GHG
Reporting Program.
As the project is located in a state that has not sought
primacy to implement the UIC Program for Class VI
wells, the producer applies for a Class VI permit fromthe EPA. They also submit an MRV plan to the EPA
as required under Subpart RR of the GHG Reporting
Program. The MRV plan includes extensive modellingand monitoring of the CO2 plume to detect any surface
leakage to ensure the environmental integrity of the
project. The EPA issue a Class VI permit for the project
and approve the MRV plan.
The producer also applies for and receives
Permanence Certification under the CCS Protocol
from CARB. The post-injection site care plan andfinancial instrument they submit covers a minimumof 100 years post-injection, as required by the CCS
Protocol, which goes further than the requirements of
the Class VI permit. The producer owns and operates
the storage site where the CO2 is being injected,
so does not need to submit the application with aseparate storage operator.

Before the producer can claim any credits, it must
apply for a new fuel pathway to be established under
the LCFS against which they can claim credits. A fuelpathway for ethanol without CCS already exists so they
only need to provide one fuel pathway application.
They calculate the lifecycle emissions associated withethanol production with CCS and use the CA-GREET
and GTAP model to calculate the carbon intensity
value of the fuel. Applying CCS to the fermentationand distillation process in the biorefinery reduces
the carbon intensity of the fuel from 79gCO2e/MJ to
63gCO2e/MJ.15
The application for the fuel pathway is approved andthe producer starts injecting CO2 from mid-2020. They
opt to verify emissions for the LCFS on a quarterly
basis. They submit data for Q3 of 2020 into the LRTCBTS by mid-November 2020 and submit their firstquarterly report to CARB by the end of December
2020. Shortly after submitting their report, they
provide a verification statement from a third party that
confirms the project has met the requirements in the
CCS Protocol.

Lifecycle emissions of corn ethanol production are taken from https://www.arb.ca.gov/fuels/lcfs/background/basics-notes.pdf. Assumes a 50% reduction in biorefinery
emissions, drawing on analysis by S McCoy (2016).

15

POLICY REPORT19

They calculate the number of credits to be awardedin two steps. First, they subtract the carbon intensityof the fuel with CCS (63 gCO2e/MJ) from the carbon
intensity benchmark for gasoline in that year
(92gCO2e/MJ). They then multiply this by the volume
of fuel produced and a conversion factor to transfer
the value into tCO2 credits generated. On the basisof this calculation they estimate they are eligible to10,000 LCFS credits.

In March 2021 and every year thereafter, the operator
is required to submit an annual report to the EPA under
Subpart RR of the Greenhouse Reporting Program. At
the end of April 2021 in each year the operator must
submit an annual compliance report to CARB. The
Credit Clearance Market goes ahead in June and Julyof 2021 and the value of credits in the market reaches
the $200/tCO2 price cap (adjusted for inflation).

CARB approve the claim and the operator is awarded
10,000 LCFS credits for Q3 2020. As they are a low
risk site, they surrender 8%, or 800, of the credits to
the Buffer Account. They sell half of the remaining
LCFS credits generated to a Regulated Party in
California for $150/tCO2 and pledge the other half tobe sold on the Credit Clearance Market.

POLICY REPORT

20

4.0 COMBININGLCFS CREDITS WITH
45Q TAX CREDITS
Several commentators have noted the potential
opportunity for projects in the US to combine or ‘stack’
LCFS credits and 45Q tax credits. In combination,
LCFS credits and 45Q tax credits could provide CCS
project developers in the US with a strong financial
incentive to capture CO2 emissions and invest in CCS.

In contrast to the price of LCFS credits that vary fromday-to-day based on the supply and demand in themarket, the value of 45Q tax credits is fixed ahead oftime. Under the changes made through the Bipartisan
Budget Act, the value of tax credits rises linearly from$31/tCO2 and $19/tCO2 respectively in 2019 for CO2
stored in dedicated geological storage and injected
for utilization purposes, to $50/tCO2 and $35/tCO2
respectively in 2026. Thereafter, the value of the tax
credit rises with inflation, as shown in Figure 8.

The 45Q tax credit was introduced under the Energy
Improvement and Extension Act of 2008 and recently
amended under the Bipartisan Budget Act in 2018.
It provides capture operators with credits for eachtonne of CO2 stored or utilized, including for CO2-EOR,
which can be used to reduce the capture operator’s
tax liability. If a capture operator’s tax liability is lessthan the value of the tax credits received, the capture
operator can transfer the tax credits claimed to thestorage operator or sell them on the tax equity market.

The 45Q tax credit scheme is open to power plants,
industrial plants and DAC facilities, provided theymeet the minimum eligibility requirements specified
in the Internal Revenue Code. This includes the needfor new projects to be under construction by 1 January2024 and meet minimum annual capture thresholds.

Figure 8: 45Q tax credit values in each year (US$/tCO2)15

2019

2020

2021

2022

2023

2024

2025

2026 2026 onwards

Dedicated geologicalstorage

31

34

36

39

42

45

47

50

CO2-EOR

19

22

24

26

28

31

33

35

Other CO2 utilization
processes

19

22

24

26

28

31

33

35

15

Adapted from Energy Futures Initiative (2018), Advancing Large Scale Carbon Management: Expansion of the 45Q Tax Credit.

POLICY REPORT

Indexed toinflation

21

To qualify to claim 45Q tax credits, project operatorsneed to demonstrate the secure geologic storageof emissions. The Internal Revenue Service (“IRS”)
is currently consulting on the requirements anoperator would need to satisfy to demonstrate this,along with other changes required to implement thechanges resulting from the passage of the Bipartisan
Budget Act. Under the consultation proposal, secure
geological storage is defined as requiring an EPAapproved MRV plan.16

This would be achieved by having either a Class II
permit and EPA-approved MRV plan or a Class VI
permit and an EPA-approved MRV plan, as requiredfor operators in the US injecting CO2 undergroundand reporting under Subpart RR of the GHG Reporting
Program.
There are several differences between the eligibility
requirements for 45Q and the LCFS, as summarized
in Figure 9. This may mean there are some CCS
operators in the US that would not be able to claim
both 45Q tax credits and LCFS credits.

Figure 9: Comparison of the eligibility requirements and scope of the LCFS and 45Q

LCFS

45Q

GEOGRAPHIC
SCOPE

Any location globally, provided sequestrationsite is onshore and transport fuel sold in
California (except for DAC projects)

TYPES OF CCS
PROJECTAny fuel production facility or Direct Air
Any industrial or Direct Air Capture facility that
Capture facility that captures CO2 and either
either stores CO2 in a dedicated geologicalstores it in a dedicated geological site or uses it site or uses it for CO2-EOR or other utilization
for CO2-EOR
purposes

MINIMUM
PROJECT SIZE

Any project size, except for projects applying
under the Innovative Crude Provision whichmust meet minimum size thresholds

EMISSIONSCOVERED

Carbon dioxide, methane, nitrous oxide, volatile
Carbon dioxide and carbon monoxideorganic compounds and carbon monoxide

QUALIFICATIONPERIOD
RESTRICTIONS

None

Only facilities for which construction begins
before January 1 2024 are eligible

CREDIT
GENERATIONDURATION

Duration of the injection period

12 years

Operators must contribute between 8% and
CREDIT BUFFER & 16.4% of credits generated to a Buffer Account
INVALIDATION
and retire credits to cover any leaks that occur
up to 50 years post-injection
PERMANENCEREQUIREMENTS

16

Demonstrated through receiving andmaintaining Permanence Certification under
the LCFS

Any location in the United States

Projects are required to meet the following
annual minimum capture thresholds in tonnesof CO2: Power generators (500,000); Industrial
and Direct Air Capture plants (100,000);
Industrial Pilot Plants (25,000)

IRS is currently consulting on the approachto the recapture of tax credits in the event ofleakage

IRS is currently consulting on the permanence
requirements

IRS (2019), Request for Comments on Credit for Carbon Oxide Sequestration, Notice 2019-32.

POLICY REPORT

22

5.0 CONCLUSIONSThe Low Carbon Fuel Standard (“LCFS”) is one ofseveral policies in California that originate from the
Global Warming Act 2006. It places lifecycle carbon
intensity targets on all transportation fuels sold in
California, with the aim of diversifying the State’s fuelmix, reducing petroleum dependency, and reducing
GHG emissions and other air pollutants. Fuels thathave a lower carbon intensity than the carbon intensity
target generate credits and fuels with a higher carbon
intensity than the target generate deficits.
The recent amendment to the program to allow
CCS projects to generate LCFS credits represents asignificant policy development for CCS. With credits
trading at up to $190/tCO2 over the past year, thechanges could provide a significant source of revenue
and support the increase in deployment of large-scale
CCS projects. Whether this happens will dependon the costs of complying with the requirementsin the CCS Protocol, which will only be known once
operators have started the process of applying forthe program. For this reason, the LCFS is likely to be a
hot topic for years to come for both policymakers and
CCS project operators.

POLICY REPORT

Several commentators have highlighted the additional
opportunity from combining or ‘stacking’ LCFS credits
and 45Q tax credits. At prevailing credit values,
this could provide an incentive for CCS projects
equivalent to over $200/tCO2. While the IRS has yet
to issue guidance and regulations covering all aspectsof 45Q, under their current proposal project operatorsin the US may need to go beyond the minimum
requirements for claiming 45Q tax credits if they are
to qualify for the LCFS. This partly reflects CARB’sintent for the CCS Protocol to be an internationallyapplicable standard and not just limited to California
or the US or tied to existing regulations.

23

6.0 REFERENCES
California Air Resources Board, Low Carbon Fuel Standard basics, Available at: https://www.arb.ca.gov/fuels/lcfs/
background/basics-notes.pdf
California Air Resources Board (2018), Staff presentation to Public Workshop held on 28 November 2018,
Available at: https://www.arb.ca.gov/fuels/lcfs/lcfs_meetings/112818presentation.pdf
California Air Resources Board (2019), Carbon Capture and Sequestration Protocol, Available at: https://www.arb.
ca.gov/fuels/lcfs/ccs_protocol_010919.pdf
California Air Resources Board, Low Carbon Fuel Standard Regulatory Order, Available at: https://www.arb.
ca.gov/fuels/lcfs/fro_oal_approved_clean_unofficial_010919.pdf
California Air Resources Board (2018), Public Workshop to Discuss Implementation: Low Carbon Fuel Standard,
Available at: https://www.arb.ca.gov/fuels/lcfs/lcfs_meetings/112818presentation.pdf
California Air Resources Board (2018), Statement of Reasons, Available at: https://www.arb.ca.gov/regact/2018/lcfs18/fsorlcfs.pdf
Catapult Energy Systems and the Energy Technology Institute (2018), California Low Carbon Fuel Standard:
Rethinking Decarbonisation Incentives – Policy Case Studies Available at: https://es.catapult.org.uk/wp-content/
uploads/2018/10/California-LCFS-Case-Study-FINAL.pdf
Energy Futures Initiative (2018), Advancing Large Scale Carbon Management: Expansion of the 45Q Tax Credit,
Available at: https://static1.squarespace.com/static/58ec123cb3db2bd94e057628/t/5b0604f30e2e7287abb8f3c
1/1527121150675/45Q_EFI_5.23.18.pdf
Environmental Protection Agency, States, Tribes and Territories Responsibility for the UIC Program, Available at:https://www.epa.gov/sites/production/files/2019-04/documents/primacy_status_revised_april17_2019_508c.pdf
Environmental Protection Agency, Final Greenhouse Gas Reporting Rule for Geologic Sequestration and Injectionof Carbon Dioxide: Subparts RR and UU, Available at: https://www.epa.gov/sites/production/files/2015-07/
documents/subpart-rr-uu-ppt.pdf
Environmental Protection Agency (2010), 40 CFR Parts 72, 78 and 98, Mandatory Reporting of Greenhouse
Gases: Injection and Geologic Sequestration of Carbon Dioxide; Final Rule
IPCC, Land Use, Land-Use Change and Forestry. Accessed: February 17, 2018. Available: http://www.ipcc.ch/
ipccreports/sres/land_use/index.php?idp=74
S McCoy (2016), Reducing lifecycle biofuel emissions with CCS, Available at: https://www.cslforum.org/cslf/sites/
default/files/documents/tokyo2016/McCoy-BiofuelsCCS-TG-Tokyo1016.pdf
The Department of the Treasury Internal Revenue Service (2018), Form 8933, Available at: https://www.irs.gov/
pub/irs-pdf/f8933.pdf
The Department of the Treasury Internal Revenue Service (2019), Request for Comments on Credit for Carbon
Oxide Sequestration, Notice 2019-32, Available at: http://src.bna.com/HRP

POLICY REPORT24

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POLICY REPORT