Latham's Clean Energy Law Report

California Launches Major Rulemaking to Amend Low Carbon Fuel Standard

Posted in Uncategorized

By Joshua T. Bledsoe, Michael Dreibelbis, and Max Friedman

I. LCFS Readoption

On February 19, 2015, the California Air Resources Board (ARB) will take feedback on proposed regulations implementing the readoption and updating of California’s Low Carbon Fuel Standard (LCFS), with formal readoption targeted for the Summer of 2015.  Triggered by legal defects during the original adoption of the LCFS Program, ARB initiated the rulemaking after the U.S. Supreme Court denied certiorari regarding the constitutionality of the program.  ARB is building on a series of workshops held last year to institute a variety of major changes to the LCFS, going far beyond the largely procedural defects that catalyzed the rulemaking.

The LCFS, which was adopted pursuant to the Global Warming Solutions Act of 2006 (commonly known as “AB 32”), requires fuel suppliers to reduce the carbon intensity of transportation fuels to 10% below 2010 levels by 2020.  Those who over-comply generate credits that can be sold to those who miss their targets (and thus have deficits).  While the 10% target has not changed, a number of regulations pertaining to how that target is achieved, including the schedule of annual reduction requirements between 2016 and 2020 would be modified under ARB’s proposal.

II. Carbon Reduction Schedule

The current LCFS regulations contain a schedule of carbon intensity reductions to achieve the mandated 10% total reduction by 2020.  This “compliance curve” is frozen at its 2013 level by court order until ARB completes the readoption process.  As such, the original compliance curve has been disrupted and requires a more rapid acceleration through the final five years in order to achieve the desired reductions by 2020.  A summary of ARB’s proposed acceleration is below:

Table 1:  Comparison of Previous and Proposed Percent Reduction Requirements for Carbon Intensity over 2016-2020 Period
Year Current Reduction Percent Proposed Reduction Percent
2016 3.5% 2.0%
2017 5.0% 3.5%
2018 6.5% 5.0%
2019 8.0% 7.5%
2020 and beyond 10.0% 10.0%


This accelerated schedule flattens interim reduction targets, but places a considerably higher burden on the final three years of compliance, potentially creating a tight credit market during those years.  ARB has employed aggressive assumptions about technological innovations and the mix of available fuels during this period.  For example, ARB assumes that electric vehicles will generate 10x as many credits in 2020 as in 2013 and renewable CNG 32x as many credits.

III.       Cost-Containment Provisions

In an attempt to alleviate concerns about the ability of the market to produce enough credits in coming years, ARB is proposing to establish a “credit clearance market” whereby regulated parties can purchase credits from other market participants to make up credit shortfalls.  In the event of a credit shortfall, an inflation-adjusted credit price ceiling of $200 would apply.  The “credit clearance market” would function somewhat similarly to the consignment auction process in ARB’s Cap-and-Trade Program, with several key differences, including that ARB would publish the names of entities participating in the credit clearance market, including the number of credits that each participating entity must buy or sell.

Entities that are unable to obtain credits needed for compliance during the credit clearance event would be able to “carry over” deficits per a “5×5” rule:  5% interest on carried-over deficits with total debt due within 5 years.  Market participants previously expressed concern about the credit clearance proposal during ARB workshops, noting its potential to distort the market in ways not envisioned by ARB.

IV. Enforcement Mechanisms

The proposed rules would include a robust invalidation regime for LCFS credits, deficits, and carbon intensity determinations (an “Approved CI”), similar to the current ARB rules for emission offset credits in the Cap-and-Trade Program.  The new rules would allow ARB to delete an Approved CI or invalidate LCFS credits for a variety of reasons, including noncompliance with laws during credit generation.  This expansion of the invalidation regime could open the door to the kind of uncertainty that market participants have experienced in the Cap-and-Trade Program offset market.  ARB also proposes changing the definition of a violation to encompass each separate net deficit, which will allow for differentiation among small- and large-scale offenders.  However, the penalty for a single violation would shrink from a presumption of $35,000 to a maximum of $1,000.

V. Indirect Land-Use Change

ARB calculates carbon intensity using the CA-GREET model, which measures direct life-cycle emissions from “well to wheel,” including a fuel’s production, transport, storage, and use.  The Board also supplements this calculation with a calculation of indirect impacts on emissions due to land-use change (iLUC).  For example, carbon sequestered in soil and organic matter can be released when non-agricultural land is converted to agricultural use for growing biofuel crops.  Going forward, ARB proposes to modify its iLUC values for certain biofuels, including ethanol refined from corn, sugarcane, and sorghum and biodiesel from soy and palm.  These changes are based on new research regarding land-use changes and are lower than previous iLUC values, providing a benefit to ethanol producers.

Additionally, ARB will update the CA-GREET model, as well as the OPGEE model, which estimates carbon intensity for crude oil production and transport to petroleum refineries.

VI. Miscellaneous Further Changes

In addition to these major modifications to LCFS regulations, ARB has proposed a number of other important changes.

First, ARB would simplify the process for certifying certain established, compliant fuels and the procedures for generating them.  Under a new two-tiered system, stakeholders proposing to register pathways for established fuels (e.g., starch- and sugar-based ethanols) generated in a conventional manner would receive expedited approval.  Those seeking pathway approval for more novel fuels (e.g., cellulosic alcohols) or technologies to generate them would receive elevated scrutiny from ARB.

Second, certain innovative technologies for producing crude oil would offer the potential to generate additional credits.  Since 2011, producers that employ carbon capture and sequestration or solar steam generation have been eligible for credits, but no one has yet attempted to apply.  To facilitate such projects, ARB now proposes to:  (a) reduce the minimum threshold for carbon intensity reduction from such technologies from 1.0 gCO2e/MJ to 0.1 gCO2e/MJ or even lower in some cases; (b) simplify calculations of credits generated; (c) allow crude producers, in addition to refineries, to earn credits; and (d) add solar and wind electricity generation and solar thermal generation to the list of technologies that can yield credits.  Similarly, refineries would become eligible for credits if they invest in modifications that produce fuel derived in part from renewable feedstocks.

Third, petroleum refineries also would become eligible for credits if they employ low-energy-use refining processes, although these credits would not be available for sale.  Some smaller refineries could further benefit from a proposal to allow them to opt out of ARB’s statewide calculation of baseline average carbon intensity for all crude fuels produced in the state.  Instead of being judged against the 2010 baseline for the entire state, small, low-energy-use refineries could set their own baselines.  They would receive this opportunity only once and it would be irreversible, making the calculation a potentially risky one.  For those refineries subject to the statewide baseline, calculations of volume contributions would now come from government data, rather than reporting by the refineries themselves.

Fourth, additional transportation credits also would become available for electricity used not only by roadway vehicles (as is now the case), but also by trains and electric forklifts.

Finally, recordkeeping and reporting requirements for stakeholders also would change in important ways.  Minimum record retention would increase from three to five years. Quarterly reporting requirements would shift from a 60-day period in which parties can compile their data and reconcile it with that of their business partners to a “45/45 Schedule,” allowing 45 days to report data and an additional 45 days to reconcile it.

VII.     2030 Extension

While ARB proposes to institute many changes to the LCFS via the readoption process, one thing that has not changed is the fundamental target of a 10% reduction in carbon intensity by 2020; both the target reduction and the final date remain the same.  Nevertheless, ARB asserts that it intends, in a subsequent rulemaking, to extend the LCFS program through 2030 and apply aggressive new CI reduction targets for the 2020-2030 period.

White House Updates Draft Guidance on Climate Change Considerations in NEPA Review

Posted in Environmental and approvals

By Joshua T. Bledsoe and Stacey L. VanBelleghem

On December 18, 2014, the White House Council on Environmental Quality (CEQ) released revised draft guidance on the consideration of greenhouse gas (GHG) emissions and climate change in National Environmental Policy Act (NEPA) review.[1]  The CEQ previously issued this guidance in draft form in February 2010.[2]  Rather than finalize that draft, the CEQ opted to issue significantly revised draft guidance and open a 60-day public comment period, which closes on February 23, 2015.[3]

One of the most notable changes in this revised draft is that the CEQ addresses the question of whether agencies should monetize costs and benefits of a project.  The CEQ notes that the use of cost-benefit analysis depends on whether it is relevant to the choice among alternatives.  However, when agencies choose to include this analysis, the CEQ endorses the Federal social cost of carbon estimates as a “harmonized, interagency metric that can provide decision makers and the public with some context for meaningful NEPA review.”[4]  Following a June 27, 2014 U.S. District Court for the District of Colorado decision invalidating a final Environmental Impact Statement for failure to disclose the costs associated with GHG emissions and ignoring the social cost of carbon estimates,[5] there has been much uncertainty about the use of these estimates in NEPA documents.  The court decision and the 2014 Draft Guidance represent a shift in the use of those estimates, which were developed for significant federal rulemakings.  However, the extent to which agencies will use these estimates in NEPA review remains to be seen.  The revised draft acknowledges the limitations of the social cost of carbon estimates, including the fact that they were developed for rulemaking analysis, the estimates vary over time, and they are associated with different discount rates.[6]

Among other notable changes in the 2014 Draft Guidance, the CEQ definitively stated that agencies’ assessment of direct and indirect climate change effects should account for upstream and downstream emissions.[7]  This position goes further than the 2010 proposal, which stated that evaluation of upstream and downstream effects “must be bounded by limits of feasibility.”[8]  This new language could expand the scope of analysis for some agencies that had previously declined to consider upstream and downstream emissions.  Moreover, unlike the 2010 guidance, which did not apply to Federal land and resource management actions, the 2014 Draft Guidance specifically applies to those actions and includes guidance on biogenic sources of GHG emissions from land management actions.[9]

Other aspects of the revised guidance build upon and clarify concepts included in the 2010 Draft Guidance.  For instance, the 2010 Draft Guidance encouraged agencies to include a quantitative assessment of GHG emissions for projects expected to have direct GHG emissions of 25,000 metric tons or more on an annual basis.[10]  The 2014 guidance continues to recommend 25,000 annual metric tons of GHG emissions as a “reference point” for emissions warranting a quantitative assessment.[11]  Like the 2010 Draft Guidance, the 2014 Draft Guidance encourages agencies to include considerations of GHG emissions and climate change in alternatives analysis, mitigation considerations, and the evaluation of the environmental consequences of a proposed action.

The revised guidance is likely to result in expanded evaluation of GHG emissions and climate change impacts in agency NEPA review and is anticipated to have implications in the near term.  Indeed, while CEQ did not intend the 2010 Draft Guidance to become effective until its issuance in final form,[12] agencies commonly cited it in NEPA documents.  Similarly, while the preamble to the 2014 Draft Guidance states that it will be effective “once finalized,”[13] agencies are expected to refer to it in NEPA documents on an ongoing basis—particularly since the 2014 Draft Guidance expressly encourages agencies to apply it, “to the extent practicable,” in ongoing reviews.[14]  As the guidance is initially applied at the project-level, such environmental reviews may be prolonged.

[1]           Council on Environmental Quality, Revised Draft Guidance for Greenhouse Gas Emissions and Climate Change Impacts (Dec. 18, 2014) (hereinafter “2014 Draft Guidance”).

[2]           Memorandum from Nancy H. Sutley to Heads of Federal Departments and Agencies Regarding Draft NEPA Guidance on Consideration of the Effects of Climate Change and Greenhouse Gas Emissions (Feb. 18, 2010) (hereinafter “2010 Draft Guidance”).

[3]           Notice Of Availability, Request For Public Comments On Revised Draft Guidance For Federal Departments And Agencies On Consideration Of Greenhouse Gas Emissions And The Effects Of Climate Change In NEPA Reviews, 79 Fed. Reg. 77801 (Dec. 24, 2014).

[4]           2014 Draft Guidance at 16.

[5]           High Country Conservation Advocates v. U.S. Forest Service, No. 13-cv-01723-RBJ (D. Colo. June 27, 2014).

[6]           2014 Draft Guidance at 16.

[7]           Id. at 11.

[8]           2010 Draft Guidance at 3.

[9]           Compare 2010 Draft Guidance at 2 with 2014 Draft Guidance at 8, 16-18.

[10]          2010 Draft Guidance at 1.

[11]          2014 Draft Guidance at 18.

[12]          2010 Draft Guidance at 12.

[13]          79 Fed. Reg. at 77818.

[14]          2014 Draft Guidance at 14.

PJM Proposes Capacity Performance Rules That Will Present New Opportunities and Risks for Clean Energy Resources

Posted in Energy regulatory

By Michael Gergen and Eli Hopson

In response to poor performance by many generation resources in the PJM region during the 2104 “Polar Vortex” and concerns over the increasing reliance on natural gas-fired generation resources in the PJM region, PJM filed under Section 205 of the Federal Power Act (“FPA”) proposed “Capacity Performance” rules to revise its capacity market, known as the “Reliability Pricing Model” or “RPM”, with the Federal Energy Regulatory Commission (“FERC” or “Commission”) on December 12, 2014.  In connection with its filing of proposed tariff revisions, PJM also filed under both Sections 205 and 206 of the FPA proposed revisions to its Operating Agreement which would narrow force majeure for non-performance.  PJM’s proposed revisions to its capacity market construct, if implemented, would present clean energy resources with new opportunities and risks regarding their participation in PJM’s capacity market, by, among other things, allowing participation by energy storage resources.

PJM’s filing of its proposed Capacity Performance rules follows months of stakeholder deliberation over various straw proposals, and the proposed rules as filed with FERC contain a number of significant differences from the proposal last considered in the stakeholder process. PJM’s goal is for its new Capacity Performance rules to go into effect April 1, 2015.  PJM’s proposed Capacity Performance rules are based in part on the ISO New England’s “Pay for Performance” rules, which FERC approved in mid-2014.  PJM’s proposed Capacity Performance rules would establish a new capacity product—Capacity Performance Resources—with higher performance standards that would likely earn significantly greater capacity market revenues. The revisions would also significantly increase financial penalties for Capacity Resources that have cleared in the RPM auctions and that fail to perform when called upon by PJM during certain emergency conditions on the PJM grid.  Moreover, the revisions would also add a new definition for “Capacity Storage Resources,” which would include hydroelectric, flywheel, and storage resources as well as a new definition of “Intermittent Resources” which would include “Generation Capacity Resources with output that can vary as a function of its energy source, such as wind, solar, run of river hydroelectric power and other renewable resources.”

PJM also proposes to limit instances of force majeure for Capacity Generation Resources to only include instances of “Catastrophic Force Majeure,” defined in the proposed revisions to the Operating Agreement as widespread failure of the transmission system or fuel delivery system in all of the PJM area. As a result, unexpected individualized or localized risks will no longer excuse non-performance, and the determination of whether an event satisfies the “Catastrophic Force Majeure” definition will be made independently by the Office of Interconnection, rather than by a market participant.

Capacity Performance Resources Expected to Perform During Emergency Action Periods

PJM’s proposed Capacity Performance rules would fundamentally change and significantly increase the expectation for performance by capacity resources as they would be expected to provide energy and reserves when called upon by PJM, though their performance (and associated financial charges and credits) under PJM’s proposed “no-excuse” standard for failure would be determined based on their operation during “Emergency Action” periods. Rather than imposing front-end eligibility requirements for resources wishing to enter the market as Capacity Performance Resources (as was previously contemplated by PJM on August 20th and October 7th, including multi-hour performance capability), the Capacity Performance rules proposed before FERC seek to put the onus on capacity market sellers to provide “reasonable assurances” that their resources will perform when called upon during Emergency Action periods, (which PJM assumes, but does not guarantee, will occur as much as 30 hours per year in the summer and winter seasons). Under the proposed Capacity Performance rules Capacity Performance Resources will be required to have combined start-up and notification times as well as minimum down times that do not exceed one hour. To increase market competiveness, PJM proposes to impose a must-offer requirement on all resources that qualify as Capacity Performance Resources beginning in the 2018/2019 Delivery Year, with limited exceptions. All resources that qualify as Capacity Performance Resources will not have the option of not submitting offers or submitting offers as Base Capacity Resources without facing penalties. At the same time, PJM proposes that Intermittent Resources, Capacity Storage Resources and Energy Efficiency Resources, may, but will not be required to, submit offers as Capacity Performance Resources.

Substantial Penalties for Failure to Perform During Emergency Actions

Capacity Performance Resources that fail to perform during Emergency Actions will have to pay substantial penalties. PJM has patterned its penalty structure after that of ISO New England’s “Pay for Performance” standard. Rather than factoring in a resource’s forced outage history in determining acceptable levels of performance for future years, PJM proposes to adopt a more stringent, “no excuses” policy that simply compares a resource’s actual performance during Emergency Action hours and subjects any and all performance shortfalls to a “Non-Performance Charge” as high as an annual stop-loss of 1.5 times Net CONE times all of the resource’s committed capacity (where Net CONE is the first year total net revenue that a new resource would need to recover its capital and operating expenses, net of any returns in PJM’s energy and ancillary services markets).  Although Net CONE varies based on the geographic region and the year, RTO-wide values for the 2017/2018 RPM auction were $351.39/MW-day.   Due to the proposed revisions to the Operating Agreement discussed above, the only acceptable excuse for non-performance will be if a resource is on a planned or maintenance outage pre-approved by PJM.  As PJM states in its filing letter, “the proposed Non-Performance will impose serious adverse financial consequences on resources that do not perform during emergencies” and could turn a seller’s “RPM revenue stream into an RPM expense stream if its resource performs poorly in multiple emergencies during the Delivery Year.”

Alternatively, resources that exceed expected performance will be eligible to receive “Performance Payments,” collected from revenues generated by Non-Performance Charges. Under the proposed Capacity Performance rules, all market participants are eligible to receive Performance Payments, including non-Capacity Resources that “stand in” for non-performing Capacity Resources outside of the resource’s obligation period, effectively rendering any performance during such periods bonus-eligible.

Phased Transition to New Market

PJM proposes to complete a market transition to a 100% Capacity Performance Resource product by the 2020/2021 Delivery Year. Until that time, a resource failing to meet the Capacity Performance Resource standard will continue to be eligible to participate as Base Capacity Resources.  With the exceptions discussed above for Intermittent Resources, Capacity Storage Resources and Energy Efficiency Resources, which will be able to participate as Base Capacity Resources also, all other resources that do qualify as Capacity Performance Resources will only be eligible to participate as Capacity Performance Resources. By the end of the transition period, all capacity resources will be expected to make the transition to the Capacity Performance Resource standard.  PJM also proposes that resources such as storage, wind, and solar to aggregate to submit Sell Offers with other Energy Efficiency Resources located within the same Locational Deliverability Area (“LDA”) as either Base Capacity Resources or Capacity Performance Resources.  While not entirely clear, it appears that the proposed revisions also seek to exempt from the must offer requirement for Base Capacity Resources those resources that are exempt from the must offer requirement for Capacity Performance Resources.

PJM has requested that the Commission accept its proposed Capacity Performance rules by April 1, 2015.  PJM also requested that the Commission establish an extended comment period, with a deadline of January 12, 2015 for stakeholders to submit comments (or 31 days from the date of PJM’s filing), however, the Organization of PJM States filed a Motion to extend the comment period to January 20, 2015 given the length of the PJM filings.

Air & Climate Forecast: December 2014

Posted in Environmental and approvals

Latham & Watkins is pleased to present a complimentary 45-minute webcast on Thursday, December 11 at 9:00 am pacific/12:00 pm eastern. The webcast is presented by the Air Quality and Climate Change Practice and will address the following current air quality and climate change regulatory and policy updates:

  • Implications of EPA’s Newly Proposed Ozone Standard
  • EPA’s Aggressive Enforcement of GHG Requirements: the Settlement With Kia and Hyundai
  • EPA’s Clean Power Plan: Comments on the Proposal and Implications of the Recent US-China Climate Agreement

Click here to register. A confirmation will be sent via email upon completing your registration.

CARB Invalidates Offsets for Facility’s Alleged RCRA Noncompliance

Posted in Environmental and approvals

By Claudia O’Brien and Bart Kempf

On November 14, 2014, the California Air Resources Board (CARB) released a final determination invalidating almost 89,000 previously-issued offset credits due to CARB’s conclusion that the facility at issue failed to comply with a permit issued under the Resource Conservation and Recovery Act (RCRA).[1]  CARB reached this conclusion even though it determined that “the [GHG] emission reductions represented by the offsets at issue here are real, quantified, and verified reductions.”[2]  CARB’s decision comes following a months-long investigation, and leaves open a number of questions about how California will exercise its discretion to investigate and invalidate offsets in the future.

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Climate Action Plan for San Diego County Struck Down Under CEQA by Court of Appeal for Failure to Comply with Requirements for Plan Level Documents and Failure to Adequately Mitigate Associated GHG Impacts

Posted in Environmental and approvals

By Chris Garrett, Daniel Brunton, Taiga Takahashi, Andrew Yancey, and Natalie Rogers

On October 29, 2014, the Fourth District Court of Appeal of California upheld the Sierra Club’s challenges to the County of San Diego’s (“County”) approval of a climate action plan (“CAP”) and related significance thresholds under the California Environmental Quality Act (“CEQA”).  In Sierra Club v. County of San Diego, No. D064243, 2014 WL 5465857 (Cal. Ct. App. Oct. 29, 2014), the Court held that the County’s CAP did not ensure the necessary greenhouse gas (“GHG”) emissions reductions and that the County failed to meaningfully analyze the environmental impacts of the CAP.  This opinion was certified for publication on November 24, 2014.

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California Low Carbon Fuel Standard Overhaul Continues

Posted in Environmental and approvals

By Joshua Bledsoe, Michael Dreibelbis, Michele Leonelli, and Aron Potash

I. LCFS Readoption

The California Air Resources Board (“ARB”) is on the cusp of readopting the Low Carbon Fuel Standard (“LCFS”) regulation to remedy legal defects in the initial adoption process found by the California Court of Appeal on July 15, 2013.  In conjunction with the LCFS readoption, ARB is expected to propose significant changes to the program.  ARB staff has been vetting potential revisions via a series of workshops this year, and ARB plans to float a draft revised LCFS regulation next month.  The readoption process gained momentum this summer when the Supreme Court denied certiorari regarding the constitutionality of the program.  A new cost containment mechanism, an updated carbon intensity model, and a reanalysis of fuel availability are among the significant changes that could materially impact program participants, both obligated entities and opt-in fuel producers. 

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Air & Climate Forecast: November 2014

Posted in Environmental and approvals

Latham & Watkins is pleased to present a complimentary 45-minute webcast on Thursday, November 13 at 9:00 am pacific/12:00 pm eastern.The webcast is presented by the Air Quality and Climate Change Practice and will address the following current air quality and climate change regulatory and policy updates:

  • Vapor Intrusion – or EPA’s Foray into the Regulation of Indoor Air
  • CARB’s Post Hoc Invalidation of Offsets for Alleged Noncompliance with Other Environmental Laws
  • Market Design Issues With AB32 – and What Can Be Done

Click here to register. A confirmation will be sent via email upon completing your registration.

FERC Accepts Almost All of the CAISO’s Proposed Flexible Resource Adequacy Capacity and Must-Offer Obligation Requirements

Posted in Energy regulatory

By Michael J. Gergen and Marc T. Campopiano

On October 16, 2014, the Federal Energy Regulatory Commission (“FERC”) issued an Order on Tariff Revisions, FERC Docket No. ER14-2574, conditionally accepting, with two substantive modifications, tariff changes proposed by the California Independent System Operator (“CAISO”) to establish new flexible resource adequacy capacity (“FRAC”) and must-offer obligation (“MOO”) requirements intended to ensure that adequate flexible capacity is available to address the added variability and net load volatility associated with ongoing and expected future changes on the CAISO-controlled grid.  The FRAC-MOO requirements will be effective, subject to a compliance filing by the CAISO (due within 30 days of the date of the order), effective November 1, 2014, to allow load serving entities (“LSEs”) subject to the requirements time to make their first FRAC showings to the CAISO by November 15, 2014.

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CARB Proposes Invalidating Offset Credits for Facility’s Alleged RCRA Noncompliance

Posted in Environmental and approvals

By Claudia O’Brien and Bart Kempf

For the first time since California established its cap-and-trade market for greenhouse gas (GHG) emissions, the California Air Resources Board (CARB) has proposed canceling over 230,000 tons of offset credits due to a facility’s alleged potential failure to comply with unrelated environmental laws.[1]  CARB is proposing the invalidation even though it has concluded that “the [GHG] emission reductions represented by the offsets at issue here are real, quantified, and verified reductions.”[2]  CARB issued its preliminary determination on October 8, 2014, opening a 10-day comment period.  Following the comment period, CARB has 30 days to make a final determination.

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