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6 1) Introduction Chevron Richmond Refinery Revised Renewal Project Conditional Use Permit Application - Project Description The Chevron Richmond Refinery (Refinery) processes crude oil blends, externally sourced gas oils, and natural gas into a variety of fuel and oil products. In addition to producing motor gasoline, jet fuel, diesel fuel, and lubricating oils, the Refinery produces industrial fuel oil, liquefied petroleum gas, sulfur, and other products. The Refinery also produces steam, electricity, fuel gas, and hydrogen, primarily for its own use. In 2005, Chevron proposed the Hydrogen and Energy Renewal Project at the Refinery (Original Project). In 2008, the City of Richmond (City) certified an environmental impact report (Original EIR) and issued the necessary permits for the project. In 2010, the court ordered that the Original EIR be set aside. Chevron has reduced the overall project scope of the Original Project (now called the Revised Project). The Revised Project will complete construction and make operational only the Hydrogen Plant Replacement and Hydrogen Purity Improvement portions of the Original Project, as more fully described below. The Catalytic Reformer Replacement, Power Plant Replacement, and Other New and Replacement facilities (e.g. storage tanks) that were part of the Original Project are not part of the Revised Project. The City will prepare a Revised EIR to comply with the court decision regarding the Original EIR 1 and to address changes in the project proposed by Chevron which have reduced the overall project scope. The Revised EIR will be prepared by the City as the Lead Agency for the purpose of considering conditional use and design review permits for the Revised Project. In addition to the City permits, the project sponsor must obtain Authority to Construct from the Bay Area Air Quality Management District (BAAQMD) and comply with all applicable plans, rules and regulations of the BAAQMD in respect to air emissions from the Revised Project. 2) Project Location The Revised Project is located entirely within the boundaries of the existing 2,900 acre Refinery, at 841 Chevron Way in the City of Richmond, County of Contra Costa. As shown in Figure 1, the Project is located in the central and northern portions of the Refinery and within the existing Refinery footprint. The Hydrogen Plant Replacement will be installed in an area of the Central Yard referred to as the Y. The Y is currently occupied with the partially constructed Hydrogen Plant. Construction of the Hydrogen Purity Improvements will occur within or adjacent to the Sulfur Recovery Units (SRUs) and FCC 2 Feed Hydrotreater (FCCFHT). 1 The prior permit proceedings and court decisions are described in Appendix A. 2 FCC refers to the Fluid Catalytic Cracking Unit, a conversion unit which cracks gas oil molecules into smaller molecules suitable for further processing and blending into transportation fuels.

7 Southeast of the Refinery, across Castro Street and Garrard Boulevard, are the residential communities of Atchison Village, Santa Fe and Iron Triangle. Shields-Reid lies toward the northeast. Further east are central and downtown Richmond. Parchester Village is located northeast of the Refinery and Point Richmond is located to the southwest. Point San Pablo Peninsula and the San Francisco Bay form the western border of the Refinery and San Pablo Bay forms the northern boundary of the Refinery property. The main portion of the Refinery lies within the City s M-3 Heavy Industrial, Zoning District. The Refinery is bounded by the Chevron Richmond Marketing Fuels Terminal to the southeast, and Chevron Energy Technology Company to the south. The main Revised Project components will be located a minimum of 5,000 feet from any residential uses. 3) Project Objectives Chevron s primary objectives for the Revised Project are to: Allow the Refinery to process crude oil blends and externally-sourced gas oils containing higher levels of sulfur than those currently processed in order to continue producing competitive transportation fuels and lubricating oils. Replace existing hydrogen production facilities with modern facilities that are more energy efficient, produce purer hydrogen, and have sufficient capacity to meet Chevron s needs and enable the owner and operator of the new Hydrogen Plant to export hydrogen to third-party customers. 4) Revised Project Characteristics This discussion of the Revised Project characteristics is divided into three sections. The first section describes the specific equipment and equipment changes involved in the Revised Project. The second section provides a summary of the Refinery operational changes that could result from constructing and operating the Revised Project. The third section describes potential environmental effects that may be caused by the Revised Project or by the associated Refinery operational changes. a) Equipment Changes This section describes the equipment changes included in the Hydrogen Plant Replacement, Hydrogen Purity Improvements, and other infrastructure changes related to these components. Figure 2 is a Refinery flow diagram showing where these components fit in the Refinery s overall manufacturing process. Specific equipment changes are listed in Appendix B. Page 2 of 15

8 i) Hydrogen Plant Replacement The Refinery s existing Hydrogen Plant contains two hydrogen trains and hydrogen recovery vessels. It is 45 years old, and uses more energy to produce hydrogen that is less pure than that produced by modern plants. The existing maximum production capacity of each hydrogen train is 90 million standard cubic feet per day (SCFD) for a total of 180 million SCFD for both trains. Adding 50 million SCFD from hydrogen recovery vessels brings the total hydrogen production capacity to a total of 230 million SCFD. Currently, the product hydrogen is approximately 95 percent hydrogen, with 5 percent impurities consisting primarily of methane. The Revised Project proposes completion of construction of the new Hydrogen Plant and hydrogen recovery vessels. Following startup of the new plant the existing Hydrogen Plant and hydrogen recovery vessels will be removed from service. The new Hydrogen Plant consists of two trains, each capable of producing a maximum of 122 million SCFD hydrogen on an annual basis, plus 50 million SCFD of hydrogen from the hydrogen recovery unit, for a total of 294 million SCFD, a net increase of 64 million SCFD hydrogen capacity. The new equipment will be more energy efficient and will produce higher purity hydrogen. The new trains will use Pressure Swing Adsorption (PSA) technology allowing the Refinery to generate hydrogen from natural gas, ammonia, 3 and Refinery process gas. The resulting hydrogen product is expected to be greater than 99 percent hydrogen, a net increase of approximately four percent in hydrogen gas purity over current operations. Improving the purity of hydrogen reduces the density of the hydrogen streams which necessitates replacements or modifications of existing Refinery compressors to preserve their current operation and capacities. The replacements and modifications will reduce compressor energy consumption. The Revised Project will also include the installation of low-no X burners on five process heaters to maintain compliance with the Refinery-wide NO X emission limit in BAAQMD Regulation 9, Rule 10. ii) Hydrogen Purity Improvements (Sulfur Removal) Hydrogen Purity Improvements will enable the Refinery to process crude oil blends and gas oils with higher levels of sulfur. Although the Refinery cannot predict with certainty the sulfur content of future crude blends, it is reasonably foreseeable that post-project crude oil blends will contain up to as much as 3 percent sulfur. This compares to the current Refinery capacity of approximately 2 percent sulfur and a recent three-year 3 Ammonia fed to the new Hydrogen Plant is converted to hydrogen and nitrogen gas. Converting ammonia to hydrogen in the new Hydrogen Plant reduces natural gas consumption and CO2 production and reduces the quantities of ammonia stored on site and transported outside the refinery. Page 3 of 15

9 average of 1.5 percent sulfur. In addition, the Refinery will have the flexibility to process more externally-sourced medium-high sulfur gas oils, displacing low-sulfur gas oils 4. The Revised Project will increase the capacity of the Fluid Catalytic Cracker Feed Hydrotreater (FCCFHT) in keeping with a potentially higher sulfur feedstock slate, enable sulfur removal from the recycle hydrogen stream of the FCCFHT, add the #6 H 2 S Amine Regenerator, and increase the capacity of the Sulfur Recovery Units (SRUs). The following paragraphs describe the proposed equipment changes in greater detail. These descriptions focus on major equipment changes. There will also be modifications and additions of ancillary process equipment such as pumps, piping, heat exchangers vessels, tanks, instrumentation, off-plot interconnections and utilities. FCCFHT Capacity Increase. Presently, the Refinery feeds medium-high sulfur gas oils (both from the crude unit and externally-sourced gas oils) to the FCCFHT for sulfur removal (i.e. conversion into low sulfur gas oils). The FCCFHT low sulfur gas oil, along with externally-sourced low sulfur gas oils, are fed to the FCC. FCC capacity will remain unchanged. Increasing the capacity of the FCCFHT from 65 thousand barrels per day to 80 thousand barrels per day allows the Refinery the flexibility to use higher sulfur gas oil blends than are presently used. The existing major FCCFHT process equipment can accommodate the desired throughput. To eliminate hydraulic limitations related pumps, heat exchangers, vessels, and the recycle hydrogen compressor steam turbine driver will be modified or replaced. Several new heat exchangers and air coolers will be added to improve energy efficiency and allow the increased throughput, without raising furnace firing rates above existing permit limits. FCCFHT Recycle Hydrogen Sulfur Removal. The FCCFHT recycle hydrogen stream contains the Refinery s greatest concentration of recoverable sulfur and is the most efficient place to remove sulfur. 5 An amine contactor, ancillary pumps, piping vessels, and heat exchangers will be added to the FCCFHT recycle hydrogen stream. Diethanol amine (DEA) in the amine contactor absorbs hydrogen sulfide (H 2 S) from the recycle hydrogen stream and is then routed to the #6 H 2 S Amine Regenerator 6 described below. #6 H 2 S Amine Regenerator. The absorbed H 2 S will be stripped from the DEA in a new #6 H 2 S Amine Regenerator which will be built adjacent to the SRUs. It consists of a regenerator column, amine storage and handling facilities, and typical ancillary equipment. The H 2 S will then be routed to the Sulfur Recovery Units (SRUs) for conversion to elemental sulfur. 4 Medium-high sulfur gas oils contain 0.5 wt % sulfur or more. 5 The project component name, Hydrogen Purity Improvements, refers to the removal of sulfur from this hydrogen stream. 6 Amine regeneration could also take place in one or more of the Refinery s three existing amine regenerators. Page 4 of 15

10 SRU Capacity Increase. The Sulfur Recovery Units (SRUs) convert H 2 S to elemental sulfur, a product that is sold to various agriculture and industrial users. The Refinery s existing SRUs consist of three trains with a combined sulfur recovery capacity of 600 long tons 7 per day. Adding oxygen enrichment facilities enables the SRUs to increase the combined sulfur recovery capacity to 900 long tons per day without increasing the volume of gas that flows through the units. Since the gas flow does not increase, the main SRU equipment does not need to be enlarged. Oxygen storage and handling facilities will be added at the front end of the SRUs; the main reaction furnace burners will be converted to accommodate oxygen enrichment; and the boiler feed water system will be upgraded to enable additional heat recovery and steam generation. These modifications also allow the SRUs to process the Refinery s surplus ammonia. The tail gas units at the back ends of the SRUs will be modified to reduce sulfur dioxide (SO2), nitrogen oxide (NO X ), carbon monoxide (CO), particulate, and sulfuric acid mist emissions. Additional new ancillary equipment will include a new acid gas scrubber, which prevents the release of H 2 S during an unplanned loss of SRU operation; storage and loading facilities for process chemicals such as caustic, and sodium bisulfite; and a new sulfur loading rack equipped with enhanced vapor controls. iii) Other Infrastructure To tie the Hydrogen Plant Replacement and Hydrogen Purity Improvements into the existing Refinery process plants, new pipe racks, piping, and utility infrastructure (including electricity, steam, fuel gas, process gas, water, instrumentation, process and storm sewer connections) will be installed. Appendix B lists specific equipment to be installed or modified as part of the Revised Project. b) Operational Changes The Revised Project does not change the basic function and operation of the Refinery. However, there will be secondary operational changes as described in this section. i) Sulfur After the Revised Project equipment is installed, the additional sulfur from crude and gas oil feedstocks will be captured by hydrotreating and amine treating, and converted to sulfur in the higher-capacity SRUs. 7 One long ton (the standard unit for measuring sulfur exports) equals 2,240 pounds or 1.12 standard tons. Page 5 of 15

11 ii) Crude Unit and SDA The Crude Unit and Solvent Deasphalting Unit (SDA) are the first steps in converting crude oil blends to marketable transportation fuels and other products (see Figure 2). These units separate crude oil blends, a mixture of many hydrocarbon fractions, into various streams without altering the molecules that make up the fractions. The Crude Unit makes the separation by vaporizing and condensing the mixture in such a way that draws lighter fractions from the top of a distillation column, medium-weight fractions from the middle, and the heavier fractions from the bottom. The SDA further separates the heaviest fraction, vacuum residuum (vacuum resid) into gas oil and SDA residuum (SDA resid) by extracting the gas oil component with a solvent which is recycled. These units are not being modified as part of the Revised Project. While the Revised Project proposes equipment modifications that will enable the Refinery to process crude oil blends and externally-sourced gas oils with higher sulfur content, the Project does not involve any equipment changes to the Refinery s existing capacity with regard to crude oil heaviness. The Refinery has the capacity to process crude oil blends with heaviness at the lighter end of the intermediate range 8 (lightintermediate gravity), and will remain configured in the same manner to process such crude oil blends after the Revised Project is completed and becomes operational. The Refinery s capacity for processing the heaviest fraction of crude oil, vacuum resid, is limited by Crude Unit and SDA capacity. Processing crude oil blends heavier than the light-intermediate range would require an increase in SDA capacity, among other changes, or the addition of a new process unit such as a coker to convert vacuum resid to lighter materials. Crude Unit and SDA capacities will not change as part of the Project. The operation of the SDA is constrained by its throughput capacity limit which corresponds to an annual average gravity of approximately 28 API for crude oil blends fed to the crude unit. In the past three years, the Refinery has not used all of its existing capacity for vacuum resid, and has run the SDA in the range of thousand barrels per day. During this period the annual average gravity for crude oil blends fed to the crude unit was 34 API. Post-Project it is reasonably foreseeable that, in running crude oil blends with increased sulfur content, the Refinery will run some crude oil blends that have more vacuum resid than the recent operating conditions, but within the existing capacity of units that limit the heaviness of crude oil blends that can be processed and within existing BAAQMD air permit limits. Among other things, the Revised EIR will analyze the potential 8 Heaviness of crude oil is generally measured in degrees of API gravity. Light crude is above 36 API, intermediate crude is from 18 to 36 API, and heavy crude is below 18 API. [California Energy Commission (CEC), 2006, Fossil Fuels Office, Fuels and Transportation Division, Sheridan, Margaret: California Crude Oil Production and Imports, at page 1, CEC , April 2006] Page 6 of 15

12 environmental effects of processing the full range of light-intermediate crude blends, consistent with existing Refinery capacity, as compared to the current operating baseline. iii) Conversion and Treating Units Conversion and treating are processes that change the molecules in various hydrocarbon fractions. Conversion units (shown in Figure 2 as FCC, TKN Hydrocracker, and Lube Crackers and Finishers) break gas oil molecules into smaller ones, more suitable for further treating and blending into lighter transportation fuels. Treating Units (shown in Figure 2 as FCCFHT, NHT, JHT, DHT, Penhex Isom, and Reformers), use catalyst to remove impurities from molecules, or alter the structures of molecules, without changing their size. Removing impurities prevents catalyst contamination in downstream units and helps produce cleaner burning transportation fuels. The only physical change the Revised Project will make to conversion and treating units is the increase in throughput capacity of the FCCFHT. In addition, the Revised EIR will examine the range of reasonably foreseeable operating scenarios for all the conversion and treating units. iv) Fuel Gas System Nearly all Refinery process units generate process gases that are collected, treated to remove H2S, and blended with natural gas and other refinery gases in the fuel gas system to become fuel for Refinery furnaces. Small amounts of sulfur remaining in the process gases are emitted from furnace stacks. When the new Hydrogen Plant begins operation, up to two-thirds of the Refinery s process gas will feed the new Hydrogen Plant 9 where all sulfur will be removed. Refinery process gas previously routed to the fuel gas system will be replaced by commercial natural gas which has much less sulfur. Currently, to maintain hydrogen system purity, some Refinery hydrogen is routed to the fuel gas system and burned, rather than being recycled through the hydrogen recovery units. With the Revised Project, hydrogen systems will maintain the necessary purity without having to route hydrogen to the fuel gas system. The hydrogen otherwise lost to the fuel gas system will be recovered, thereby reducing the quantity of hydrogen that needs to be produced 10. v) Energy Efficiency and Greenhouse Gas Emissions The replacement Hydrogen Plant will be approximately 15% more energy efficient than the existing Hydrogen Plant on an emission basis per unit volume of hydrogen product. However, because the replacement Hydrogen Plant has additional capacity, at maximum 9 The existing Hydrogen Plant uses purchased natural gas as its feedstock. 10 Removing hydrogen from the fuel gas system increases the amount of natural gas needed to maintain the Refinery s fuel requirements. But this increased natural gas demand is offset by the reduction in the demand for natural gas for Hydrogen Plant feed. Page 7 of 15

13 production it will generate more Greenhouse Gas (GHG) emissions than the existing Hydrogen Plant. The Hydrogen Purity Improvements will require additional energy in the form of increased electricity, steam, and fuel gas consumption to support the additional sulfur removal capability. The Revised EIR baseline and post-project GHG emissions will be calculated according to California Air Resources Board AB-32 protocols. vi) Flaring Potential changes in Refinery emergencies and flaring as a result of the Revised Project will be considered. c) Potential Environmental Effects The previous sections describe potential increases and reductions in Refinery combustion, process emissions and discharges. These include changes in criteria air pollutants, toxic air contaminants, greenhouse gases, and potentially other Refinery discharges resulting from equipment and operational changes. All potential impacts that may be associated with the Revised Project components and changes in Refinery operations resulting from the new components will be evaluated in the Revised EIR. Details of the pre- and post-project emissions and discharges will be confirmed by the BAAQMD and other state agencies, and will be described in detail in the Revised EIR. 5) Court Decision and Writ of Mandate The Revised EIR is intended to comply with the court decisions in the context of the Revised Project, as described below. Project Description. The court decision held that the project description in the Original EIR was unclear and inconsistent as to whether or not the project will enable Chevron to process a heavier crude slate than it is currently processing. The Revised EIR will clarify that the Revised Project does not include changes that would enable processing crude oil blends with heaviness outside the range of the Refinery s current capacity, and that the Refinery will continue to operate in the light-intermediate crude gravity range. Baseline and crude slate changes. The court decision held that the Original EIR did not state a baseline for measuring the potential for increased impacts from changes in the crude oil slate at the Refinery following the project. The Revised EIR will describe the crude slate used by Chevron for the last three years and other historical data to define the operational baseline. This operational baseline will be used to analyze whether there Page 8 of 15

14 would be any potential environmental impacts from the Revised Project or from changes to Refinery operations, taking into account both potential project-level and cumulative impacts, for all relevant resources identified in Appendix G to the California Environmental Quality Act (CEQA) Guidelines, including air toxics health risks, water discharges, and GHG emissions. Greenhouse Gas Emissions. The Court decision held that the City improperly deferred the formulation of GHG mitigation measures to a future, post-eir process. The Revised EIR baseline and post-project GHG emissions will be calculated according to California Air Resources Board AB-32 protocols, and will identify specific measures to achieve a netzero emissions standard for GHG emissions over the pre-project baseline. Cumulative Impacts. The Court decision indicated that the EIR s cumulative impacts analysis may be affected by the additional CEQA analysis described above. The Revised EIR will consider whether there will be potentially significant cumulative impacts from operation of the Revised Project or the Refinery as modified by the Project. 6) Discretionary Actions/Permits The Revised Project will require the following permits and approvals before construction of the new Hydrogen Plant and Hydrogen Purity Improvements can recommence: Conditional Use and Design Review Permits from the City of Richmond Building permits from the City of Richmond Authority to Construct from the BAAQMD Page 9 of 15

15 APPENDIX A - LEGAL BACKGROUND On April 6, 2005, Chevron applied to the City of Richmond (City) for permits necessary to construct and operate the Energy and Hydrogen Renewal Project (Original Project) within existing manufacturing facilities at the Richmond Refinery. The Original Project involved the replacement of existing equipment at four main process plants with newer technology and included the following components: Hydrogen Plant Replacement Hydrogen Purity Improvements Power Plant Replacement Catalytic Reformer Replacement Associated infrastructure modifications Other New and Replacement Facilities (e.g., storage tanks) On July 17, 2008, the City certified an environmental impact report (Original EIR or EIR) and approved the permits for the Original Project. Following the City s issuance of the Notice of Determination (NOD) on August 5, 2008, and the issuance of an authority to construct by the Bay Area Air Quality Management District (BAAQMD) on September 19, 2008, Chevron proceeded with construction of the Hydrogen Plant Replacement and Hydrogen Purity Improvements. Construction of these components was more than 50% complete when, in July 2009, the project was halted under a writ of mandate and injunction issued by the Superior Court of Contra Costa County ( Superior Court ) pursuant to the petition filed by Communities for a Better Environment, West County Toxics Coalition and Asian Pacific Environmental Network. Chevron appealed the Superior Court s ruling and in April 2010, the Court of Appeal issued a decision instructing the Superior Court to enter a new and different judgment granting the petition for writ of mandate with regard to the EIR s failure to provide an adequate project description and its failure to define mitigation measures for greenhouse gas emissions, while denying mandate relief with regard to the claim of improper segmentation of a larger project. (Communities for a Better Environment v.city of Richmond (2010) 184 Cal.App.4th 70.) In its decision, the Court of Appeal held that (i) the project description in the Original EIR was unclear and inconsistent as to whether or not the project would enable Chevron to process a heavier crude slate than it currently processes; (ii) the EIR did not establish a baseline for purposes of determining whether there would be any increased impacts from any changes in the crude slate processed at the Refinery; and (iii) the EIR improperly deferred the formulation of greenhouse gas mitigation measures to a future, post-eir process. The Court of Appeal did not address the EIR s cumulative impacts analysis challenged by Petitioners on the basis that the analysis would likely be affected by a revised project description and greenhouse gas analysis. As directed by the Court of Appeal, the Superior Court entered a final judgment and issued a writ of mandate (Writ of Mandate) on March 16, 2011directing the City to set aside (1) Resolution No , under which the City Council upheld the Planning Page 10 of 15

16 Commission's certification of the Original EIR and adopted findings and a mitigation monitoring and reporting program for the Original Project; (2) Resolution No , under which the City Council upheld the Planning Commission s approval of the conditional use and design review permits for the Original Project, and (3) any additional permits, authorizations, and any and all other approvals for the Original Project. The Writ of Mandate also ordered that the City take no action in reliance on the EIR and permits until the City reconsiders its approval of the EIR, brings the EIR into compliance with the requirements of CEQA, and makes the EIR consistent with the Court of Appeal s decision. Additionally, the Writ of Mandate enjoins Chevron from engaging in any project activity until the City complies with the Writ and issues new permits for the project. Page 11 of 15

17 Appendix B - Specific Equipment To Be Installed or Modified As Part of the Revised Project: Component Hydrogen Plant Replacement (construction 50% complete) Proposed Scope 1. Construct new hydrogen plant, including hydrogen separation PSA units (2 trains) Shut down existing hydrogen plant (2 trains) 3. Install hydrogen recovery PSA unit (1) 4. Shut down PSA section of the existing hydrogen recovery unit (1) 5. Construct new cooling water tower (1) 6. Construct new flare (1) 7. Construct a new Hydrogen Plant Control Room (1) 8. Upgrade Richmond Lube Oil Plant (RLOP) Area Compressors (4) 9. Upgrade Distillation and Reforming Area Compressors (3) 10. Install Steam Turbine Generator (1) 11. Install low-nitrogen oxides (NO x ) burners on existing TKN Hydrocracker 12 furnaces (3) 12. Install low-nox burners on existing Poly (Polymer) Plant furnaces (2) 13. Upgrade Isomax Area Compressors (8) 14. Relocate electrical infrastructure and Refinery power cables (5) 15. Install communication cables (6) 11 The Revised Project includes one new stand-alone hydrogen recovery unit, a Pressure Swing Adsorption ("PSA") unit that recovers hydrogen from the feed to the new hydrogen plant before that feed is sent to the hydrogen plant. This is BAAQMD source S Each of the new hydrogen plants (S-4449 and S-4450) also includes a PSA unit after the reformer furnace to separate produced hydrogen from byproducts. These PSA units are considered part of each respective hydrogen plant, and are not considered separate units (i.e., they do not have a separate BAAQMD source number). 12 TKN is the trade name of a Hydrocracker at the Refinery. Page 12 of 15

18 Component Hydrogen Purity Improvements (construction 57% complete) Associated Infrastructure Improvements (construction 60% complete) Proposed Scope 1. Construct new Recycle Hydrogen Amine Contactor (1) for Fluid Catalytic Cracker Feed Hydrotreater 2. Refurbish and rename Fresh Amine Storage Tank T-2421 from T (1) (switched to Amine service from caustic) 3. Construct new Rich Amine Storage Tank T-2420 (1) 4. Construct new Amine Regenerator (1) 5. Upgrade Isomax Area Compressor (1) 6. Construct new Oxygen Storage Tanks (2) 7. Upgrade sour water processing 8. Construct new Acid Gas Scrubber (1) 9. Construct new Fresh Caustic Tank T-2440 (1) 10. Construct new Spent Caustic Tank T-2445 (1) 11. Modify existing Fluid Catalytic Cracker Feed Hydrotreater (1) 12. Modify existing Sulfur Recovery Units (3) 13. Install new sulfur loading rack (1) including option to replace or upgrade existing vent scrubber (1) 14. Install truck and railcar loading and unloading stations for amines, sodium bisulfite, fresh and spent caustic (5) 15. Install automated caustic dilution and delivery system (1) 1. Construct P, Q, U, V, and W Pipe Racks from various plants to hydrogen plant for refinery process gas, hydrogen gas and utilities (steam, instrument air, firewater, freshwater). 2. Install approximately 7 miles of new process and utility piping 3. Install or modify Refinery Electrical Infrastructure 4. Install or Modify Instrument and Communication Cables with Pipe- Way Structural Supports Page 13 of 15

19 Figure 1. Richmond Refinery Site Plan (Colors match Figure 2) FCC Feed Hydrotreater Sulfur Recovery Units Hydrogen Plant Detail Page 14 of 15

20 Crude Figure 2. Richmond Refinery Block Flow Diagram Crude Unit NHT * Process Gas with H 2 S H 2 S Plants* LPG H H 2 2 Naphtha Jet Diesel H 2 Lt Gas Oil Hvy Gas Oil JHT H 2 * * Reformers H 2 Hydrocracker (TKN) H 2 S H 2 Penhex Isom Fuel Gas (for furnaces) Reformate Splitter DHT Sulfur Recovery Unit * Export Sulfur Isomerate Gasoline Reformate Gasoline Jet Diesel Iso Overhead H Gasoline * 2 Lube Crackers and Finishers * Lubricants Resid Low Sulfur Gas Oil High Sulfur Gas Oil H 2 FCCFHT * FCC Poly LPG Butamer Alky Tetramer Av Gas Alkylate Gasoline FCC Light Gasoline FCC Hvy Gasoline HSFO Replaced Equipment SDA Altered Equipment Process gas with H 2 S * Nat l Gas LPG Hydrogen H 2 Hydrogen Plant H 2 Fuel Fuel Power Plant Cogens Steam Electricity Steam * A new FCCFHT amine contactor and a new #6 H 2 S amine regenerator will be added to the Refinery s existing H2S Plants Page 15 of 15