Stephen d’Esterhazy James Duffy Alan Glabe Reza Lorestany Carolyn Lozo Alexander “Lex” Mitchell Manisha Singh Also, thanks to: Christopher Newton Ron Oineza Chan Pham Marcie Pullman Jose Saldana Katrina Sideco Susan Solarz TABLE OF CONTENTS
analysis—one that is commensurate with the charge of the Advisory Panel: technically sound, but not comprehensive or exhaustive. To that end, staff plans to recommend that the Economic Subgroup convene as soon as can be arranged to have such a discussion. Furthermore, staff has been working with the California Energy Commission (CEC) as they conduct an economic analysis on their illustrative scenarios. Therefore, further input from CEC’s will be valuable. Finally, staff is considering using a contractor to conduct a more comprehensive economic analysis of the LCFS. Such an analysis would not be completed until sometime in 2012 or early 2013. Meanwhile, staff has posed questions in this draft chapter to solicit input from the Panel on proceeding with the economic analysis of the LCFS. Staff’s goal is to complete an economic analysis for inclusion in the report to the Board in December, giving panelists time for review and comment. As specified in section 95489 of the LCFS regulation, the economic impacts analysis should consider the following areas: “The scope of each review shall include, at a minimum, consideration of the following areas: (8) The LCFS program’s impact on state revenues, consumers, and economic growth; (12) Significant economic issues… B. Background 1. 2009 Approach As part of the original Initial Statement of Reasons (ISOR) covering the LCFS, staff estimated the cost difference between producing the baseline transportation diesel, and CNG—and producing the lower-carbon-intensity (CI) transportation fuels that could be used to meet the requirements of the LCFS. The analysis that estimated the economic impacts of the LCFS was based on engineering production cost studies and, necessarily, assumptions about economic and market conditions. Staff calculated the economic impacts for the gasoline baseline and diesel baseline scenarios separately and individually. a. Assumptions Staff assumed that the price of crude oil for 2010 – 2020 would be $66 - $88/bbl. This assumption came from the 2007 California Energy Commission (CEC) Integrated Energy Policy Report (IEPR) and was also the assumption used for the AB 32 Scoping Plan. Staff assumed that the refineries in the State would continue to operate at normal throughput levels and would become net exporters of CARBOB if in-state consumption declined. The importers and in-state producers of fuel blendstocks and finished fuels
The base deficit for individual companies is calculated the same as in the current approach. However, individual companies only incur an Incremental Deficit if their own crude slate becomes more carbon intensive over time relative to their crude slate refined in the baseline year. This allows for individual companies to shift the crude slate they refine in California and not be penalized as long as the average CI of their own crude slate does not increase. Base Deficit: All producers of gasoline (diesel) will calculate a “Base” deficit using the difference between the average Lookup Table value for CARBOB (ULSD) and the compliance target in that year. This calculation is the same as currently in the regulation on page 52 and will be the same for each company regardless of their own crude slate. Company-Specific Incremental Deficit (Approach A): For each oil company: A “baseline” volume of HCICO would be determined using the crude slate refined by that company in CA during the baseline year. Each year of the regulation, a “current” volume of HCICO would be calculated using the crude slate refined by that company in CA during a prior year. If the company’s “current” volume of HCICO is greater than its “baseline” volume of HCICO, then the company will incur an incremental deficit calculated using the difference between the current volume and the baseline volume. An individual company can earn credits if it purchases crude from sources that have implemented innovative methods such as CCS to reduce emissions for crude recovery. The number of credits will be tied to the emissions reduction achieved by the innovative method. Company-Specific Incremental Deficit (Approach B): For each oil company: A “baseline” CI value would be calculated using the crude slate refined by that company in CA during the baseline year. Each year of the regulation, a “current” CI would be calculated using the crude slate refined by that company in CA during a prior year. If the “current” company-specific CI is greater than the “baseline” company-specific CI, then the company will incur an incremental deficit calculated using the difference between its current CI and its baseline CI.
Fermentation process: yeast, liquefaction, beerwell, and process condensate tanks Emission limit corresponding to use of a VOC control system capable of 99.5% or better control efficiency Distillation and wet cake processes Emission limit corresponding to use of a VOC control system (wet scrubber or equivalent) capable of 95% or better control efficiency Pumps and compressor seals No leak of methane greater than 100 ppm above background and inspection and maintenance program Valves, flanges, and other types of connectors No leak of methane greater than 100 ppm above background and inspection and maintenance program Storage tank (fixed roof) Emission limit corresponding to use of a VOC control system capable of
9 ppmvd @ 15% O2 (or 0.15 g/bhp-hr) Biogas-fired turbine, <3 MW 9 ppmvd @ 15% O2 60 ppmvd @ 15% O2 3.5 ppmvd @ 15% O2 Landfill gas: Emission limit corresponding to use of landfill gas with sulfur content of no more than 150 ppmv as H2S Digester gas: Emission limit corresponding to use of digester gas with sulfur content of no more than 40 ppmv as H2S Emission limit corresponding to use of a fuel gas pretreatment system for particulate removal Biogas-fired turbine, ≥3 MW 5 ppmvd @ 15% O2 Biomass reciprocating internal combustion engine 5 ppmvd @ 15% O2 N/A 25 ppmvd @ 15% O2 N/A N/A Diesel-fueled emergency engine generator Engine meeting emission standards of ARB’s Airborne Toxic Control Measure for Stationary Compression Ignition Engines for applicable horsepower range Engine meeting emission standards of ARB’s Airborne Toxic Control Measure for Stationary Compression Ignition Engines for applicable horsepower range Engine meeting emission standards of ARB’s Airborne Toxic Control Measure for Stationary Compression Ignition Engines for applicable horsepower range Emission limit corresponding to use of CARB, or very low sulfur, diesel fuel (15 ppm sulfur by weight) Engine meeting emission standards of ARB’s Airborne Toxic Control Measure for Stationary Compression Ignition Engines for applicable horsepower range Table 3. Most Stringent Emission Limits Identified for Process Equipment at Biorefineries – Miscellaneous Sources
Class/Category of Source NOx CO VOC SOx PM10 Grain receiving, conveying, and grinding operations Emission limit corresponding to use of a baghouse with 99% control, or equivalent Wet cooling tower Emission limit corresponding to use of a drift eliminator with 0.0005% drift loss Compressed gas dispensing operations No emissions – use of closed loop system with all vent and excess process gas directed to an on site treatment system, used in vehicles, or directed to another combustion or processing facility that can process the biogas and which has been issued a valid air permit Biogas-fueled fuel cell 0.5 lb/MWh Alternate Limit: 0.07 lb/MWh 6.0 lb/MWh Alternate Limit: 0.10 lb/MWh 1.0 lb/MWh Alternate Limit: 0.02 lb/MWh N/A N/A Composting Emission limit corresponding to use of a VOC control system (enclosure with biofilter or equivalent) capable of 80% or better control efficiency Ammonia: Emission limit corresponding to use of an NH3 control system capable of 80% or better control efficiency Emission limit corresponding to use of a PM10 control system capable of 99% or better control efficiency