3.4 Petroleum Refining

Category ID	Description	EIC
10	Basic Refining Processes	Various
11	Wastewater Collection & Separation Systems	Various
12	Wastewater Treatment Facilities	Various
16	Other Refining Processes	Various
2559	12-15 Miscellaneous Refining Emissions	Various

Introduction

This chapter describes the methodology used to estimate non-fuel combustion greenhouse gas (GHG) emissions from the Petroleum Refining subsector in the San Francisco Bay Area (SFBA). These emissions arise not from the combustion of fuels for energy, but rather as by-products of various chemical and thermal processes used to convert crude oil into refined petroleum products. The analysis presented here focuses on four main source categories based on the California Air Resources Board’s (CARB) emissions reporting framework:

• Category 10 – Basic Refining Processes (excluding hydrogen production)
• Category 11 – Wastewater Collection and Separation Systems
• Category 12 – Wastewater Treatment Facilities
• Category 16 – Hydrogen Production and Associated Units

Among these, Categories 10 and 16 account for the vast majority of GHG emissions from petroleum refining operations, while Categories 11 and 12 contribute relatively small amounts.

Category 10 – Basic Refining Processes

Category 10 includes emissions from major refining units that break down complex hydrocarbons into simpler compounds used to produce gasoline, diesel, and other fuels. These processes involve high temperatures and/or catalysts and release carbon dioxide (CO₂) as a by-product of chemical reactions and catalyst regeneration. The main units in this category include:

• Fluid Catalytic Cracking (FCC): This process uses a powdered catalyst and high temperatures (approximately 500°C) to break heavy hydrocarbons into lighter molecules, such as gasoline. The system includes two main components: a reactor, where cracking occurs upon contact with the catalyst, and a regenerator, where the catalyst is reactivated by burning off carbon-rich deposits known as coke. The coke combustion generates large amounts of CO₂. The flue gas from the regenerator may pass through a carbon monoxide (CO) boiler, which oxidizes residual CO into additional CO₂.
• Hydrocracking: Like FCC, hydrocracking breaks down heavy hydrocarbons into lighter products, but it uses hydrogen and operates under high pressure in the presence of a catalyst. Unlike FCC, the catalyst does not require continuous regeneration. This results in significantly lower direct CO₂ emissions. Hydrocracking is especially important for producing diesel and jet fuel.
• Coking (e.g., delayed coking): Cokers use thermal cracking—high temperatures without a catalyst—to break down the heaviest fractions of crude oil. This process typically precedes FCC or hydrocracking and produces solid coke and lighter hydrocarbons. While CO₂ emissions from coking are relatively minor compared to FCC and hydrogen production, the process is essential for maximizing yield from heavy crude oils.

Category 16 – Hydrogen Production

Hydrogen is an essential input for hydrocracking and for removing sulfur from refined fuels to meet regulatory limits on sulfur content. In refineries, hydrogen is primarily produced through steam methane reforming (SMR). In this process, natural gas (primarily methane, CH₄) reacts with high-temperature steam to produce hydrogen (H₂) and carbon dioxide (CO₂). The reaction typically follows this overall chemical equation:

CH₄ + 2H₂O → CO₂ + 4H₂

In addition to CO₂ formed directly from the reforming reaction, fugitive methane emissions can occur through leaks or incomplete combustion in the system. These fugitive emissions are especially important to track because CH₄ is a potent GHG with a global warming potential 25–80 times that of CO₂, depending on the time horizon considered.

Categories 11 and 12 – Wastewater Systems and Treatment

Petroleum refining also generates liquid waste streams that must be managed through wastewater collection (Category 11) and treatment systems (Category 12). Although these sources contribute only a small fraction of total refinery GHG emissions, they are included for completeness. GHG emissions from wastewater primarily consist of methane (CH₄) produced during the breakdown of organic matter under anaerobic (oxygen-limited) conditions. These emissions can occur during:

• Oil-water separation processes,
• Aerated lagoons used for sludge processing,
• Primary and secondary treatment stages.

GHG emissions from the combustion of fuel to generate heat at refineries are covered under the Refinery Fuel Combustion methodology documentation, while fuel combustion emissions to power engines and turbines are covered in the documentation on Fuel Combustion - Turbines and Engines.

Methodology

Point sources are operations that emit air pollution into the atmosphere at a fixed location within a facility, and for which the Bay Area Air Quality Management District (BAAQMD or the Air District) has issued a permit to operate (PTO), e.g. refinery cooling towers. These point sources could also be a collection of similar equipment and/or sources located across multiple facilities, e.g. reciprocating engines.

During the PTO issuance process, the Air District collects site-specific information from the operating facility and/or determines from published literature, e.g. United States Environmental Protection Agency’s (USEPA) AP-42 (USEPA, 2024), characteristics of a source including maximum throughput, emission factors for emitted pollutants, and control factors associated with downstream abatement devices. This data is then compared against the Air District’s Regulations to ensure compliance. Facilities that hold a PTO are required to renew their permit periodically (this period varies based on facility and source type). Upon renewal, the facilities are requested to provide any updates to source characteristics as well as the source throughput for the past twelve months. This throughput, in combination with the emission factors and controls factors stored in the Air District’s internal database, are used to programmatically estimate annual emissions at the source level. The methodology used to calculate emissions for the reported base year(s) of a permitted point source is as follows:

Base Year(s) Emissions _{source,pollutant} =

Activity Data _source × Emission Factor_pollutant × Control Factor_pollutant × GWP _pollutant

Base Year(s) Emissions _county = ∑ ^N_i=1 Emissions_i

Where:

• Base Year: is a year for which activity / throughput data is available from permit records.
• Activity Data_source is the throughput or activity data for applicable base year(s) at the source/equipment level. This data is usually available from the internal permit records that are provided annually to the Air District at permit renewal by the facility operator.
• Emission Factor_pollutant is a factor that allocates an amount of emissions, in mass, of a particular pollutant by unit of activity data. For example, tons CO₂ per gallons of gasoline burned or pounds of N₂O per million standard cubic feet of natural gas combusted. GHG emissions are calculated by using specific emission factors for every source/operation for which information has been supplied by the facility (and verified/validated through source tests). If no specific emission factors are available, generalized factors developed by Air District staff are used to determine emissions. These default factors typically come from published literature such as USEPA’s AP-42 (USEPA, 2024) or California Air Resource Board’s (CARB) Mandatory Reporting Requirement (CARB, 2019) for Greenhouse Gases.
• Control Factor_pollutant is a fractional ratio (between 0 and 1) that captures the estimated reduction in emissions as a result of District rules and regulations.
• GWP _pollutant is the Global Warming Potential. The current version of the GHG emissions inventory incorporates the global warming potential (GWP) reported in the Fifth Assessment report of the Intergovernmental Panel for Climate Change (IPCC, 2014). The GWPs for the three principal GHGs are 1 for carbon dioxide (CO₂), 34 for methane (CH₄), and 298 for nitrous oxide (N₂O), when calculated on a 100-year basis with climate-carbon feedback included.
• N is the number of permitted and similar sources in a county.

If available, a facility can provide emission factors specific to the source that are verified and validated through source tests to estimate GHG emissions. If no specific emission factors are available, general factors developed by Air District staff are used to estimate emissions. These source level emissions are then sorted and aggregated by year, county, and category.

Further speciation and quality assurance of emissions, including those of GHGs, are performed as a part of the inventory refinement process. A systematic crosswalk has been developed between CARB’s California Emissions Projection Analysis Model (CEPAM) source category classification using the primary sector emission inventory codes (EICs) and the Air District’s source category classification (category identification number - cat_ids), which ensures consistency when reporting annual emissions under the California Emissions Inventory Data Analysis and Reporting Systems (CEIDARS) to CARB (CARB, 2022a). This emissions data represents the reported base years emissions for a point source category.

Once base year emissions are determined, historical backcasting and forecasting of emissions relative to the base year emissions are estimated using growth profiles as follows:

Current Year Emissions_county = Base Year(s) Emission_county x Growth Factor

Where:

• Growth Factor: is a scaling factor that is used to derive historical emissions estimates for years for which activity data and/or emissions are not available, and to forecast emissions for future years, using surrogates that are assumed to be representative of activity and/or emissions trends.

For those years where no data is available, emissions data are backcast to the year 1990, as well as forecasted to year 2050 using either interpolation or another mathematical approach (see Trends section), or by applying a growth profile based on socioeconomic indicators. GHG emissions data from the years 1990 to 2050, including the projections outlined below, are analyzed for each source category and pollutant, with the trends evaluated for any observed anomalies and modified, if needed:

• Historical Backcast (1990 – 2006): Association of Bay Area Governments (ABAG) Employment growth profiles (ABAG, 2024) and scaled District permitted data
• Base Years (2007 – 2022): District permitted data
• Future Projection (2023 – 2050): CARB 2022 Scoping Plan projection profiles (CARB, 2022b)

Emissions data is finally aggregated under sub-sectors and sectors for tracking trends and documentation purposes.

Local Controls

Several Air District regulations influence current and future process-related emissions at petroleum refineries. While many of these rules primarily target criteria air pollutants and toxic air contaminants, some also affect the accuracy and completeness of GHG emissions inventories. The most relevant regulations include:

Regulation 12, Rule 15 – Petroleum Refining Emissions Tracking

Regulation 12-15 (BAAQMD, 2021d) has significantly improved the quality and granularity of refinery GHG emissions data. Prior to 2019, refinery process emissions were estimated by Air District staff using best-available emission factors, engineering calculations, and source test data. With the implementation of Regulation 12-15, refineries are now required to submit detailed emissions inventories based on continuous monitoring and internal process data (e.g., from Supervisory Control and Data Acquisition [SCADA] systems). This shift has enhanced consistency between local GHG estimates and those reported to CARB and USEPA, and has improved process-level categorization of emissions.

Regulation 13, Rule 5 – Industrial Hydrogen Plants

Regulation 13-5 (BAAQMD, 2022) targets methane emissions from industrial hydrogen plants, particularly fugitive emissions from process vents associated with steam methane reforming (SMR). While methane used as a feedstock in SMR is assumed to be fully converted to CO₂ for the purposes of the GHG inventory, real-world conditions indicate that some methane escapes as unburned CH₄.

To better understand and quantify these emissions, the Air District has funded airborne methane measurement studies and collaborated with NASA Jet Propulsion Laboratory (NASA-JPL) on aerial remote sensing campaigns (Guha et al., 2020). These efforts revealed that actual methane emissions from hydrogen production units may be 4 to 23 times higher than estimates derived from bottom-up inventory methods, indicating a systemic underestimation of CH₄ emissions. Regulation 13-5 is intended to address this gap through more robust quantification and monitoring requirements. However, due to continued uncertainties in estimating methane reductions from this rule, its impact has not yet been incorporated into the current inventory.

Regulation 6, Rule 5 - Particulate Emissions from Petroleum Refinery Fluidized Catalytic Cracking Units (BAAQMD, 2021b) and Regulation 11-10 - Hexavalent Chromium and Total Hydrocarbon Emissions from Cooling Towers (BAAQMD, 2021c) are applicable to refinery processes, but are only designed to control particulate matter and toxic compound emissions from catalytic crackers and cooling towers, respectively. These rules do not have a direct impact on GHG emissions and are not expected to influence future GHG inventory estimates.

Historical Emissions

Historical emissions for point sources are derived from source-specific data provided by the facility on throughputs, compiled or reported emission factors, and regulation-based control factors. This information is archived in the Air District’s internal database and is queried to retrieve the data for historical and current years. Interpolation techniques to account for missing data are used when necessary.

In the case of GHGs, up until the year 2006, the Air District was not engaged in systematic information collection during permit renewal process. This changed when AB32 bill was passed into a statewide law in 2006, and a statewide Cap and Trade system was introduced to reduce GHG emissions from specific facilities. Hence, GHG emissions data for years 1990-2006 are derived from the historical emissions data reported in the base year 2011 GHG inventory (released in year 2012). The historic emissions dataset is scaled to sync with the data in the permit database (which started systematic GHG data accounting from year 2006 onwards), to generate a complete GHG emissions time series for each point source category from 1990 to 2050.

Future Projections

Forecasting of point source emissions is done based on calculations as shown in the equation below using recently updated growth profiles and a base year of 2022. The growth profiles for the current base year inventory have been verified and updated to represent the most likely surrogate for forecasting emissions for a given category up to the year 2050. Forecasting for point source emissions includes impact of in-place regulations but does not include estimation of controls that will theoretically be implemented as part of future policy emission targets or proposed regulation and legislation.

PE = Gr × C_i × E_i

PE = projected emissions of pollutant i in a future year

Gr = growth rate by economic profile of industry or population

C_i = control factor of pollutant i based on adopted rules and regulations
E_i = base year emissions of pollutant i

Forecast for energy use associated with refinery and process gas are applied from CARB’s E3 Pathways model as used in their 2022 Scoping Plan (CARB, 2022b). Refinery and process gas are generated during the processes mentioned above (FCC, hydrocracking, etc.), therefore, trends for these gases are assumed to reflect trends in the resulting process emissions. E3 forecasting assumes a decrease in petroleum refining in-line with in-state petroleum demand. This demand is forecasted to decrease as zero-emissions technologies are promoted and adopted. The forecast also accounts for historical emissions, which show an overall downward trend at the state level for the industrial sector.

Emissions

The detailed breakdown of 2022 Petroleum Refining GHG emissions in units of metric tons of CO₂ equivalents (MTCO₂eq) is provided in the table below.

ID	Description	CH2Cl2	CH4	CO2	N2O	Total
16	Other Refining Processes	0.0	72014.8	2210160.7	101.9	2282277.4
10	Basic Refining Processes	2.1	2044.2	1893366.6	3238.1	1898651.0
12	Wastewater Treatment Facilities	3.7	5.4	0.0	0.0	9.1
11	Wastewater Collection & Separation Systems	0.5	0.0	0.0	0.0	0.5

Summary of Base Year 2022 Emissions

The relative contribution of Petroleum Refining, process GHG emissions to region-wide and sector-level GHG emissions totals are highlighted in the table below. Refinery processes are one of the top three sources of emissions in the Industrial sector, accounting for almost the same amount of GHG emissions as combustion from non-refinery industries. As mentioned previously, most of the GHG emissions in this subsector are attributed to emissions from Categories 10 and 16.

Contribution of Petroleum Refining Emissions by Sector

Subsector	Sector	Subsector GHG Emissions (MMTCO2eq)	Sector GHG Emissions (MMTCO2eq)	% of Sector
Petroleum Refining	Industrial	4.18	17.90	23.35%

Contribution of Petroleum Refining Emissions to Regional Total

Subsector	Subsector GHG Emissions (MMTCO2eq)	Regional Total GHG Emissions (MMTCO2eq)	% of Regional Total
Petroleum Refining	4.18	65.68	6.37%

Trends

The time series chart below shows the emission trends for all categories.

Summary of Trends

From the years 1990 to 2007, emissions in this sector have steadily increased, following the historical rise in production and use of petroleum products. Starting in year 2007, there are increases and decreases in emissions at individual-refinery scales due to refinery turnaround events and replacement of hydrogen plants with newer units. From year 2022 and onward, a decrease in refinery emissions is seen in line with the predicted adoption of greener energy and conversion of multiple refineries in the SFBA to biofuel refining facilities.

Uncertainties

As noted above, point source emissions are calculated at an individual source level. The accuracy of these calculations is limited by the accuracy of the specific emission factors applied and estimated throughput. As these emissions are aggregated to create category level summaries, it is difficult to define a quantitative error associated with the total.

For petroleum refineries, there is an additional state level requirement to report greenhouse gases under the CARB Mandatory Reporting Requirement (MRR) (CARB, 2019). These reported emissions are independently validated by a third-party verifier and are generally considered to be the best estimate of greenhouse gas emissions. The Air District’s calculated refinery emissions are compared against these reported and verified emissions to identify any significant outliers. If an outlier is identified, a detailed analysis is done to confirm whether the Air District estimates should be left “as-is” or corrected to align with reported emissions. This additional verification provides more certainty in the emissions presented for the base year.

Contact

Author: Ariana Husain

Reviewer: Abhinav Guha

Last Update: 08/15/2025

References

ABAG. 2024. Association of Bay Area Governments. Historical Growth Profiles from Archived Internal Database. Accessed October 3, 2022.

CARB. 2019. Regulation for the Mandatory Reporting of Greenhouse Gas Emissions. https://ww2.arb.ca.gov/sites/default/files/classic/cc/reporting/ghg-rep/regulation/mrr-2018-unofficial-2019-4-3.pdf

CARB. 2022a. Emission Inventory Documentation. https://ww2.arb.ca.gov/emission-inventory-documentation. Accessed October 3, 2022. Accessed October 3, 2022.

CARB. 2022b. CARB 2022 Scoping Plan. https://ww2.arb.ca.gov/our-work/programs/ab-32-climate-change-scoping-plan/2022-scoping-plan-documents. Accessed October 3, 2022.

Guha et al. 2020. Assessment of Regional Methane Emission Inventories through Airborne Quantification in the San Francisco Bay Area. Environmental Science and Technology. 2020, 54, 15, 9254–9264. https://pubs.acs.org/doi/10.1021/acs.est.0c01212

USEPA. 2024. AP-42: Compilation of Air Emissions Factors from Stationary Sources. https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emissions-factors-stationary-sources. Accessed November, 2024.

BAAQMD. 2021a. Regulation 9, Rule 10: Nitrogen Oxides and Carbon Monoxide from Boilers, Steam Generators, and Process Heaters in Petroleum Refineries. https://www.baaqmd.gov/rules-and-compliance/rules/reg-9-rule-10-nitrogen-oxides-and-carbon-monoxide-from-boilers-steam-generators-and-process-heaters

BAAQMD. 2021b. Regulation 6, Rule 5: Particulate Emissions from Petroleum Refinery Fluidized Catalytic Cracking Units. https://www.baaqmd.gov/en/rules-and-compliance/rules/reg-6-rule-5-particulate-emissions-from-refinery-fluidized-catalytic-cracking-units?rule_version=2021%20Nov%20Amendment

BAAQMD. 2021c. Regulation 11, Rule 10 – Hexavalent Chromium Emissions from All Cooling Towers and Total Hydrocarbon Emissions from Petroleum Refinery Cooling Towers. https://www.baaqmd.gov/en/rules-and-compliance/rules/reg-11-rule-10-hexavalent-chromium-emissions-from-all-cooling-towers-and-total-hydrocarbon-emissions?rule_version=2021%20Amendment

BAAQMD. 2021d. Regulation 12, Rule 15 – Petroleum Refining Emissions Tracking. https://www.baaqmd.gov/en/rules-and-compliance/rules/regulation-12-rule-15--petroleum-refining-emissions-tracking?rule_version=2021%20Amendment

BAAQMD. 2022. Regulation 13, Rule 5 – Industrial Hydrogen Plants. https://www.baaqmd.gov/en/rules-and-compliance/rules/reg-13-rule-5-industrial-hydrogen-plants

BAAQMD. 2025. Regulation 8: Organic Compounds. https://www.baaqmd.gov/en/rules-and-compliance/rules/reg-8-organic-compounds. Accessed February 24, 2025.