4.1 Cogeneration
| Category ID | Description | EIC |
|---|---|---|
| 290 | Cogeneration - Boilers | 2000501100000, 2000501300000, 4007001300000 |
| 291 | Cogeneration - Turbines | Various |
| 292 | Cogeneration - Reciprocating Engines | Various |
Introduction
This chapter outlines the methodology for estimating greenhouse gas (GHG) emissions from cogeneration units that generate electricity using natural gas combustion at industrial facilities and power plants. These emissions result from the operation of boilers, turbines, and engines, with some permitted exceptions, and can be categorized as follows:
- Category 290 – Combustion in Boilers
- Category 291 – Combustion in Turbines
- Category 292 – Combustion in Reciprocating Engines
Cogeneration, also referred to as combined heat and power (CHP), is used to improve energy efficiency in the electricity generation process by capturing and utilizing heat that would otherwise be wasted. There are three stages of energy production in cogeneration:
Stage 1: Electrical energy is produced by fuel combustion in a gas turbine or reciprocating engine. Reciprocating engines are often used for smaller to medium cogeneration units and turbines are used for large units.
Stage 2: Electrical energy is produced by a steam turbine, that is powered by the waste heat recovered from boilers.
Stage 3: Heat energy recovered from the steam turbine is used to heat water for other on-site processes
The presence of Stage 3 above is what differentiates between a cogeneration system and a combine cycle system, the latter of which is often used in power plants. In addition to utilizing waste heat, an industrial facility may run a cogeneration system to reduce their reliance on external power grids. Emissions from combined cycle generation at power plants is included in the Electricity Generation sector and covered under the Power Plants methodology chapter.
These combustion processes are a major source of the key GHG pollutant carbon dioxide (CO₂), with minor quantities of methane (CH₄), and nitrous oxide (N₂O) also emitted.
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 Factorpollutant × Control Factorpollutant × GWP pollutant
Base Year(s) Emissions county = ∑ Ni=1 Emissionsi
Where:
- Base Year: is a year for which activity / throughput data is available from permit records.
- Activity Datasource 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 Factorpollutant 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, 1998) or California Air Resource Board’s (CARB) Mandatory Reporting Requirement (CARB, 2019) for Greenhouse Gases.
- Control Factorpollutant 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 Emissionscounty = Base Year(s) Emissioncounty 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 from base years
- Base Years (2007 – 2022): District permitted data
- Future Projection (2023 – 2050): CARB 2022 Scoping Plan projection profiles (CARB, 2022b)
The emissions estimation methodology for this sub-sector has not changed since the base year 2015 GHG emissions inventory, but updates to the 2022 base year inventory have improved the representativeness of the GHG emissions data.
Local Controls
Air District Regulation 9, Rule 11 – Nitrogen Oxides and Carbon Monoxide from Electric Power Generating Steam Boilers (BAAQMD, 2010) governs emissions under category 290. This regulation establishes NOx emissions limits based on boiler heat input and fuel type. The limits and compliance dates are summarized below:
Boiler Heat Rating (MMBtu/hr) | Fuel Type | NOx limit (ppmv @ 3% O2) | Compliance Date |
>= 1.75 billion | Gaseous | 10 | December 2001 |
Non-Gaseous | 25 | ||
Both (Gaseous & Non-Gaseous) | Weighted average of above | ||
1.5 billion – 1.75 billion | Gaseous | 25 | December 2004 |
Non-Gaseous | 110 | ||
Both (Gaseous & Non-Gaseous) | Weighted average of above | ||
< 1.5 billion | Gaseous | 30 | December 2004 |
Non-Gaseous | 110 | ||
Both (Gaseous & Non-Gaseous) | Weighted average of above |
Since compliance deadlines have passed several years prior to the base year of this inventory, and the required controls have been in place for two decades, the estimated emissions reductions have been achieved and are reported in the facility’s annual emissions. No additional controls are required to be accounted for the source categories under this rule.
Similarly, Regulation 9, Rule 9 – Nitrogen Oxides from Stationary Gas Turbines (BAAQMD, 2006) applies to emissions under category 291. This rule sets NOx emissions limits based on turbine heat input and fuel type, with specific restrictions for turbines using refinery fuel gas. All compliance deadlines were set for the year 2010, which is well prior to the base year of this inventory. As a result, any emission reductions required by this rule are already reflected in actual emissions data, and no further adjustments are necessary.
Regulation 9, Rule 8 – Nitrogen Oxides and Carbon Monoxide from Stationary Internal Combustion Engines (BAAQMD, 2007) governs emissions under category 292. This rule sets NOx emissions limits for spark-ignited and compression-ignited engines powered by diesel, natural gas, and waste derived fuels. Compliance deadlines fall on years 1997, 2012, and 2016. These years are well prior to this inventory’s base year and the rule is not expected to require any further controls that impact emissions going forward.
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 × Ci × Ei
PE = projected emissions of pollutant i in a future year
Gr = growth rate by economic profile of industry or population
Ci = control factor of pollutant i based on adopted rules and regulations
Ei = base year emissions of pollutant i
The CARB Scoping Plan (CARB, 2022b) includes two scenarios for future cogeneration subsector fuel combustion emissions trends: a reference scenario and a scoping scenario. The reference scenario estimates a minimal decrease in emissions from the use of waste heat at industrial facilities. In comparison, the scoping scenario makes a very generous prediction of emissions decreases, forecasting that 100% of energy previously produced via waste heat will be electrified. To represent business-as-usual conditions and the most probable emissions reductions, the CARB reference scenario for energy from waste heat is used to forecast emissions for these categories.
Emissions
The detailed breakdown of 2022 Cogeneration GHG emissions in units of metric tons of CO2 equivalents (MTCO2eq) is provided in the table below.
| ID | Description | CH2Cl2 | CH4 | CO2 | CO2_bio | N2O | Total |
|---|---|---|---|---|---|---|---|
| 291 | Cogeneration - Turbines | 0.0 | 4487.0 | 3822880.2 | 220345.8 | 3420.3 | 4051133.3 |
| 290 | Cogeneration - Boilers | 37.9 | 342.5 | 343905.0 | 0.0 | 466.3 | 344751.7 |
| 292 | Cogeneration - Reciprocating Engines | 0.0 | 23661.1 | 60156.9 | 84011.9 | 63.0 | 167892.9 |
Summary of Base Year 2022 Emissions
The relative contribution of Cogeneration subsector GHG emissions to region-wide and sector-level GHG emissions totals are highlighted in the table below. Leaving emissions from mobile sources in Transportation sector aside, GHG emissions from the Cogeneration subsector are lower than those of Industrial Combustion and Residential Combustion subsectors, but higher than those of the Power Plant subsector, respectively. This is most likely due to the high number of industrial and commercial facilities in the San Francisco Bay Area that use cogeneration to generate their own electricity.
Contribution of Cogeneration Emissions by Sector| Subsector | Sector | Subsector GHG Emissions (MMTCO2eq) | Sector GHG Emissions (MMTCO2eq) | % of Sector |
|---|---|---|---|---|
| Cogeneration | Electricity Generation | 4.26 | 8.47 | 50.32% |
Contribution of Cogeneration Emissions to Regional Total
| Subsector | Subsector GHG Emissions (MMTCO2eq) | Regional Total GHG Emissions (MMTCO2eq) | % of Regional Total |
|---|---|---|---|
| Cogeneration | 4.26 | 65.68 | 6.48% |
Trends
The time series chart below shows the emission trends for all categories.
Summary of Trends
As stated in the forecast section, emissions from these categories are not expected to vary much in the future as there are no proposed amendments or regulations targeting further reductions from these processes. The overall trend for the Cogeneration sector is dictated by category 291, combustion in turbines, followed by categories 290 and 292.
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.
Most facilities that have cogeneration units are large enough to be subject to the 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 cogeneration emissions are compared to 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: 08/19/2025
References
ABAG. 2024. Historical Growth Profiles from Archived Internal Database, Association of Bay Area Governments. Accessed October 3, 2022.
BAAQMD. 2000. Regulation 9, Rule 11: Nitrogen Oxides and Carbon Monoxide from Utility Electric Power Generating Boilers, Bay Area Air Quality Management District. https://www.baaqmd.gov/en/rules-and-compliance/rules/reg-9-rule-11-nitrogen-oxides-and-carbon-monoxide-from-utility-electric-power-generating-boilers
BAAQMD. 2006. Regulation 9, Rule 9: Nitrogen Oxides and Carbon Monoxide from Stationary Gas Turbines, Bay Area Air Quality Management District. https://www.baaqmd.gov/en/rules-and-compliance/rules/reg-9-rule-9-nitrogen-oxides-and-carbon-monoxide-from-stationary-gas-turbines
BAAQMD. 2007. Regulation 9, Rule 8: Nitrogen Oxides and Carbon Monoxide from Stationary Internal Combustion Engines, Bay Area Air Quality Management District. https://www.baaqmd.gov/en/rules-and-compliance/rules/reg-9-rule-8-nitrogen-oxides-and-carbon-monoxide-from-stationary-internal-combustion-engines
CARB. 2019. Regulation for the Mandatory Reporting of Greenhouse Gas Emissions, California Air Resources Board. 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, California Air Resources Board. https://ww2.arb.ca.gov/emission-inventory-documentation. Accessed October 3, 2022. Accessed October 3, 2022.
CARB. 2022b. CARB 2022 Scoping Plan, California Air Resources Board. https://ww2.arb.ca.gov/our-work/programs/ab-32-climate-change-scoping-plan/2022-scoping-plan-documents. Accessed October 3, 2022.
USEPA. 1998. AP-42, Fifth Edition, Volume I, Compilation of Air Emissions Factors from Stationary Source, Chapter 1 External Combustion Sources, Subchapter 4 Natural Gas Combustion, United States Environmental Protection Agency. https://www.epa.gov/sites/default/files/2020-09/documents/1.4_natural_gas_combustion.pdf
USEPA. 2024. AP-42: Compilation of Air Emissions Factors from Stationary Sources, United States Environment Protection Agency. https://www.epa.gov/air-emissions-factors-and-quantification/ap-42-compilation-air-emissions-factors-stationary-sources. Accessed November, 2024.