Since the regulation went into effect [15 April 2010], regulated parties have operated under the LCFS program with no significant compliance issues. In short, the LCFS is working as designed and intended...With that said, most complex regulations like the LCFS can generally benefit from further refinements. Based on feedback from regulated parties as well as other stakeholders, and by reviewing lessons learned since implementation began, staff identified specific areas of the regulation for clarification and other improvements. These proposed improvements are expected to better ensure the successful implementation of the LCFS program.

— ARB Staff Report: Initial Statement of Reasons (ISOR)

To develop the proposed amendments, ARB staff conducted three public workshops, held meetings and discussions with interested parties, and worked with transportation fuel providers and importers; environmental groups; academia; and other interested parties. Concurrently, ARB staff conducted the first review of two mandated reviews of the LCFS program with the external Advisory Panel.

The proposed amendments to be considered at the meeting do not reflect the staff’s ongoing work to update the indirect land-use change analysis (iLUC); staff expects to complete this ongoing work during the latter half of 2012, at which time it will propose regulatory amendments, if appropriate, for the Board’s consideration to reflect the completed update.

Among the amendements currently under consideration are:

• Opt-In and Opt-Out Provisions. Various low-carbon and exempted fuel providers with fuels already meeting the 2020 carbon intensity standards have expressed their intent and desire to opt into the LCFS program as a regulated party, but they are unsure of the process and if they can opt out in the future. To address this concern, staff is proposing to add specific opt-in and opt-out provisions in the regulation. These provisions would specify the process and information submittals needed for a fuel provider to opt in or opt out as a regulated party.

• Regulated party definitions. Staff has identified a couple ways to enhance the regulated party definitions so that more fuel producers and suppliers can become regulated parties.

• Approval of new or modified fuel pathways. The approval of new or modified fuel pathways (i.e., “Method 2A/2B approval”) under the regulation currently requires a formal rulemaking—a lengthy and resource-intensive undertaking, requiring an “initial statement of reasons”; a 45-day comment period; a “final statement of reasons,” in which comments received on the proposed rulemaking are responded to; and a public hearing. This formal process typically takes about six months to a year.

  Staff proposes to convert the current application process into a certification program to facilitate more expeditious reviews of Method 2A/2B submittals. The staff’s proposal maintains transparency and accountability by including provisions retaining the public’s ability to review and comment on proposed certifications.

• Credit Trading. The current regulatory text permits regulated parties to trade and transact LCFS credits, but it does not specify ARB’s role in the transactions, information about the credit market to be published by ARB, and other relevant provisions and requirements. Staff is proposing a new section to be added to the LCFS regulation to provide more detail on how credits and deficits will be tracked. The proposal also specifies the process for regulated parties to use for acquiring, banking, transferring, and retiring credits. Other provisions relevant to credit trading are also proposed.

• Electricity Regulated Party Revisions. The markets for electric vehicles (EV) and EV fueling infrastructure have evolved and continue to evolve. To reflect this market evolution, staff is proposing amendments that would better define the potential regulated parties for electricity and the order of priority in which that status would be conferred. The proposal would apply to potential regulated parties such as electric utilities, non-utilities installing electric vehicle service equipment (EVSE) with a customer contract, fleet operators, and business owners.

• Energy Economy Ratios. Staff has reevaluated the Energy Economy Ratios (EERs) for heavy-duty vehicles burning CNG or liquefied natural gas (LNG) vehicles and proposes to revise them to reflect updated information. In addition, staff has reevaluated and proposes revisions to the EERs for light-duty battery electric vehicles (BEV), plug-in-hybrid electric vehicles (PHEV), and light-duty fuel cell vehicles. These proposed changes to the EERs, along with proposed changes to how they are used in the calculations specified in the regulation, reflect engine efficiency and fuel economy data that were not available during the original 2009 rulemaking.

• Reporting Requirements. Staff proposes several amendments to various reporting requirements to simplify the provisions, including elimination of reporting energy volumes in “gasoline gallon equivalent” units and the reporting of renewable identification numbers (RINs). Similarly, staff also proposes to simplify reporting of significant figures by requiring such figures to be expressed in nearest whole units. Finally, staff proposes to require the use of the LCFS Reporting Tool (LRT) for reporting purposes. Although the current regulatory text does not explicitly require use of the LRT, it has become the de facto standard for reporting purposes, and staff’s proposal would simply formalize this.

• High Carbon-Intensity Crude Oil (HCICO). ARB staff is proposing what it valls “significant revisions” to the current regulation relative to the treatment of HCICO.

  There are many production techniques for crude oil recovery, some of which require more energy or emit more GHGs to produce and pre-process the oil. Thermally enhanced oil recovery, bitumen mining, upgrading, and excessive flaring of associated gas are examples of production methods and practices that lead to increased GHG emissions. Since the LCFS regulation takes into account full lifecycle GHG emissions for fuel pathways, including all stages of feedstock production and distribution, the upstream emissions from energy-intensive crude recovery methods need to be accounted for in the regulation.

  The purpose of the HCICO provisions is to ensure that increases in the overall CI of CARBOB (California Reformulated Gasoline Blendstock for Oxygenate Blending) and ULSD (Ultra Low Sulfur Diesel) that might occur over time due to the use of more carbon intensive crudes are mitigated and do not diminish the emission reductions anticipated from the LCFS regulation.

High Carbon-Intensity Crude Oil (HCICO). The current regulation contains a provision requiring regulated parties of petroleum-based fuels to account for their use of high carbon-intensity crude oil (HCICO) in their crude slates. The existing regulation employs a simple “bright line” approach to assigning carbon intensities to petroleum transportation fuels in California (i.e., a crude is determine to either be a HCICO or a non-HCICO).

A HCICO, as defined in the LCFS regulation, is any crude oil which 1) was not produced in one of the countries excluded from the HCICO provision; and 2) has a total production and transport carbon intensity (CI) value greater than 15 gCO₂e/MJ.

Currently, the crude oil mix refined in CA in the year 2006 is used as the baseline to calculate average Lookup Table CI values for CARBOB and ULSD pathways. Gasoline compliance targets are calculated relative to CI for CaRFG (California Reformulated Gasoline; 90% CARBOB and 10% average ethanol); diesel compliance targets are calculated relative to CI for ULSD. A regulated party is required to use the average CI value shown in the Lookup Table if the fuel/blendstock is derived from crude oil that is either not a HCICO, or was included in the 2006 California baseline crude mix (i.e., originated from a location which contributed two percent or more of the total crude oil refined in California in 2006 [“crude basket”]). A crude oil that does not satisfy both of these conditions is referred to as non-basket HCICO. For fuel/blendstock made from non-basket HCICOs, the regulated party is required to use the Lookup Table CI values associated with the specific HCICO pathways and to calculate and report the associated deficits from these sources.

ARB staff says that although the current approach has the benefit of being relatively simple, petroleum refiners in California assert that the current HCICO provisions are overly burdensome; discriminatory toward sources of crude oil; will result in global crude-shuffling that increases GHG emissions; and would put California refiners at an economic disadvantage to out-of-state refiners. They have requested that the 2006 baseline value be used for all production of CARBOB, and diesel fuel regardless of the type of crude supplies used by a refiner (i.e., no differentiation between the carbon intensities of crude oils).

Other stakeholders are adamant that the LCFS should continue to prevent increases in lifecycle carbon emissions that could occur if higher intensity crudes are used to replace existing supplies. These parties generally support approaches that discourage or fully mitigate the refining of HCICOs in California and incentivize carbon emission mitigation techniques for oil production, ARB staff said.

ARB staff is proposing a new accounting approach that would require regulated parties to account for: (1) the difference in carbon intensity between the LCFS compliance schedules and a specified baseline (i.e., the “baseline deficit”); and (2) the incremental difference in carbon intensity between the specified baseline and the actual carbon intensity of petroleum fuels used in California within a specified timeframe (i.e., the “incremental deficit”).

In essence, this approach would require the California petroleum-refining sector to not only account for the carbon-intensity reduction that the compliance schedules would otherwise require relative to a specified baseline, but it would also require this sector to account for changes in the actual carbon intensity of petroleum fuels due to the use of HCICO feedstocks.

Under the new proposals, most of the existing approach would be replaced with the new regulatory requirements. More specifically, the proposed approach would:

• Revise the portion of the CIs for CARBOB and ULSD due to the production and transport of crude oil to California refineries to reflect crude supplies used in the most recent year currently available, 2009. This would increase the CI value attributable to the production and transport of crude oil from the current 8.07 gCO₂e/MJ to a higher value of 9.72 gCO₂e/MJ; change the base CI values for CARBOB and ULSD from 95.86 gCO₂e/MJ and 94.71 gCO₂e/MJ to 97.51 gCO₂e/MJ and 96.36 gCO₂e/MJ, respectively; and require a corresponding change in the annual LCFS standards to reflect a higher CI baseline for CaRFG and ULSD. These changes would apply to fuels supplied between 2013 and 2020.

• Rescind the current approach for mitigating emissions greater than a baseline by removing any distinctions in how crudes included in the 2006 baseline mix are treated relative to crudes from sources outside of that mix; eliminating requirements that CI increases for crudes that are classified as HCICOs be individually calculated and mitigated; and eliminating a provision that non-baseline crudes can qualify as non-HCICOs if it is demonstrated that the crude has a production and transport CI value equal to or less than 15 gCO₂e/MJ.

• Establish a modified approach for mitigating higher emissions attributable to increases in crude production and transport CI by establishing a California average crude production and transport CI based on the crude slate refined in California during 2009; performing an annual calculation, beginning in 2013, using data from calendar year 2012, of the “current” California average crude production and transport CI using the crude slate refined in California during the year; determining if an increase has occurred between the base year average crude CI and the annual average crude CI; and requiring that increases due to higher annual average CI be mitigated.

• Implement the mitigation requirements by: including a baseline crude average and an annual crude average in the LCFS Lookup Table; requiring that if the annual crude average CI in a given year is greater than the baseline crude average CI, the incremental CI be used in the following year to calculate the additional deficits to be incurred by regulated parties that supply CARBOB and ULSD; calculating the amount of the incremental deficits for each regulated party by multiplying the incremental CI for a given year by the total amount of megajoules of CARBOB and ULSD reported by regulated parties for that year; adding the incremental deficits to the compliance obligation of regulated parties for the affected compliance period; and requiring that each affected regulated party retire sufficient credits by the end of the compliance period to offset the added incremental deficits.

• Establish a method whereby a regulated party could earn LCFS credits if it obtains crude from sources that have implemented innovative methods such as carbon capture and sequestration to reduce emissions for crude recovery.

The proposal calls for the new approach to go into effect on 1 January 2013. Because there could be a lag between implementation of the new approach and the existing “HCICO/non-HCICO” provisions, the proposal also specifies a list of crude oils that the Executive Office has determined, in consultation with stakeholders and sister agencies, to be clearly non-HCICO feedstocks. This list would sunset when the new approach described above goes into effect.

Resources

• Notice Of Public Hearing To Consider Amendments To The Low Carbon Fuel Standard Regulation

• ARB Staff Report: Initial Statement of Reasons (ISOR)

• Advisory Panel Low Carbon Fuel Standard 2011 Program Review Report Working Draft Version 1