Greenhouse gas (GHG) reporting has evolved from a voluntary corporate sustainability exercise to a mandatory regulatory requirement for thousands of facilities. EPA's Greenhouse Gas Reporting Program (GHGRP) under 40 CFR Part 98 requires facilities emitting 25,000 metric tons or more of CO2 equivalent per year to report annual GHG emissions. State programs in California, Washington, and others have their own reporting thresholds. The SEC climate disclosure rule adds reporting requirements for publicly traded companies. And an increasing number of customers, lenders, and insurers are requesting GHG data from companies of all sizes.
Despite the proliferation of reporting requirements, the underlying calculations are straightforward engineering. GHG reporting is fundamentally about multiplying activity data (fuel burned, electricity consumed, refrigerant purchased) by emission factors and global warming potentials to produce a CO2-equivalent total. If you can read a utility bill and multiply, you can calculate your GHG footprint. The complexity comes from the reporting rules, verification requirements, and the sheer number of sources and gases that must be tracked. This guide walks through the framework, the calculations, and the practical steps to build a defensible GHG inventory.
Scope 1, 2, and 3: Where to Draw the Lines
The GHG Protocol, developed by the World Resources Institute (WRI) and the World Business Council for Sustainable Development (WBCSD), established the standard framework for categorizing greenhouse gas emissions into three scopes. This framework is used by EPA's GHGRP, the SEC disclosure rule, CDP (formerly Carbon Disclosure Project), and virtually every voluntary and regulatory GHG reporting program worldwide. Understanding the three scopes is the starting point for any GHG inventory.
Scope 1 covers direct emissions from sources owned or controlled by your facility. This includes combustion of fuels in boilers, furnaces, generators, and vehicles; process emissions from chemical reactions or manufacturing; fugitive emissions from equipment leaks; and releases of fluorinated gases from refrigeration and air conditioning. Scope 1 is what your facility physically puts into the atmosphere. For most industrial facilities, Scope 1 is dominated by natural gas combustion, with smaller contributions from diesel generators, fleet vehicles, and refrigerant leaks.
Scope 2 covers indirect emissions from purchased electricity, steam, heating, and cooling. When you buy electricity from the grid, the power plant that generated it released GHGs. Those emissions are your Scope 2. The calculation is straightforward: multiply your electricity consumption (kWh) by the grid emission factor for your region. EPA publishes regional emission factors through the eGRID database. National average is about 0.86 lbs CO2 per kWh, but regional factors range from 0.3 (Pacific Northwest, heavy hydro) to 1.5 (parts of the Midwest, heavy coal). Scope 2 often equals or exceeds Scope 1 for facilities that are not heavy fuel burners.
Scope 3 covers all other indirect emissions in your value chain: business travel, employee commuting, purchased goods and services, transportation and distribution, waste disposal, and downstream use of your products. Scope 3 is the broadest and most difficult to quantify. It is not required under EPA's GHGRP or most regulatory programs, but it is increasingly expected by voluntary frameworks (CDP, SBTi) and may be required under SEC climate disclosure rules for large companies. For most facilities starting their GHG journey, focus on Scopes 1 and 2 first and tackle Scope 3 after you have a solid foundation.
Scope 1 (Direct): Natural gas, diesel, propane, gasoline you burn; refrigerant leaks; process emissions; company vehicles
Scope 2 (Indirect - Energy): Purchased electricity; purchased steam or hot water; purchased chilled water
Scope 3 (Indirect - Value Chain): Business travel; employee commuting; purchased materials; freight; waste disposal
Start with Scope 1 + Scope 2. These represent the emissions you can directly influence through operational decisions.
CO2 Capture / Carbon Intensity Calculator
Calculate gross and net CO2 emissions with carbon capture, CH4 and N2O equivalents, and carbon intensity per unit output. Uses 40 CFR Part 98 factors.
EPA Mandatory Reporting Rule: 40 CFR Part 98
EPA's Greenhouse Gas Reporting Program (GHGRP), codified at 40 CFR Part 98, requires annual reporting of GHG emissions from facilities that emit 25,000 metric tons or more of CO2 equivalent per year. The program covers approximately 8,000 facilities that collectively account for about 85% of US greenhouse gas emissions. Reports are due by March 31 for the prior calendar year and are submitted electronically through EPA's e-GGRT system. The data is publicly available through EPA's FLIGHT tool.
Part 98 is organized into subparts, each covering a specific source category with its own calculation methods. Subpart C covers stationary fuel combustion (the most widely applicable). Subpart W covers petroleum and natural gas systems. Subpart L covers fluorinated gas production. Subpart DD covers electrical transmission and distribution (SF6). For most industrial facilities, Subpart C is the primary concern: it requires calculating CO2, CH4, and N2O from every stationary combustion unit using fuel-specific emission factors from Table C-1. The calculation is simple: fuel consumed (MMBtu) × emission factor (kg CO2/MMBtu) = CO2 emissions.
The 25,000 metric ton threshold applies to direct (Scope 1) emissions only — purchased electricity (Scope 2) is not included in the Part 98 threshold calculation. As a rough screen, 25,000 MT CO2e is approximately equivalent to burning 130 million cubic feet of natural gas per year, or about 475,000 gallons of diesel. A facility with a couple of large boilers, a fleet of generators, and multiple process sources can reach this threshold. Once you trigger reporting, you must continue reporting even if emissions drop below 25,000 metric tons in subsequent years, until emissions stay below 15,000 metric tons for five consecutive years (or below 25,000 for three consecutive years if you use simplified methods).
Data quality requirements under Part 98 are specific. Fuel quantity must be based on company records (invoices, meter readings, tank gauging). For natural gas, you must use the higher heating value (HHV) from your gas supplier or a default of 1,020 BTU/scf. Calibration requirements apply to fuel flow meters, and missing data substitution procedures must be followed for any data gaps. EPA conducts desk audits and on-site inspections to verify reported data. Errors discovered during an audit can result in data resubmission, penalties for misreporting, and increased scrutiny in future years. Take the reporting requirements seriously from the start.
Reporting threshold: 25,000 metric tons CO2e/year
Annual report due: March 31 (for prior calendar year)
Report submitted via: EPA e-GGRT electronic system
Designated representative required: Must register in e-GGRT
Exit threshold: <15,000 MT for 5 consecutive years or <25,000 MT for 3 years
Penalties for failure to report or misreporting: up to $124,426 per day (2025 adjusted) per violation under current EPA penalty policy.
GHG Reporting Consolidator
Consolidate Scope 1 combustion, fugitive refrigerant, and Scope 2 electricity emissions into a single CO2e inventory with eGRID factors and breakdown by scope.
Global Warming Potentials: Converting Gases to CO2 Equivalent
Greenhouse gas emissions are reported in metric tons of CO2 equivalent (MT CO2e), which normalizes different gases based on their heat-trapping ability relative to CO2. To convert a non-CO2 gas to CO2e, multiply the mass of the gas by its Global Warming Potential (GWP). The GWP values used depend on which reporting program you are complying with. EPA Part 98 currently uses the IPCC Fourth Assessment Report (AR4) GWP values, while some voluntary programs use the more recent AR5 or AR6 values.
The six main GHGs and their AR4 100-year GWP values are: carbon dioxide (CO2, GWP=1), methane (CH4, GWP=25), nitrous oxide (N2O, GWP=298), hydrofluorocarbons (HFCs, varying by compound, from GWP 12 for HFC-161 to GWP 14,800 for HFC-23), perfluorocarbons (PFCs, GWP 7,390 to 12,200), and sulfur hexafluoride (SF6, GWP=22,800). For most industrial facilities, CO2 from combustion is the dominant GHG, with methane and nitrous oxide as minor components. Facilities with refrigeration systems, electrical switchgear, or semiconductor manufacturing may also have significant fluorinated gas emissions.
The practical impact of GWP values is that small quantities of high-GWP gases can dominate a facility's GHG footprint. A facility that leaks 50 lbs of SF6 from electrical switchgear has emitted the CO2 equivalent of burning 57,000 gallons of gasoline. A supermarket leaking 200 lbs per year of R-404A (GWP=3,922) contributes 356 metric tons CO2e just from refrigerant losses — equivalent to running 150 residential furnaces for a year. This is why refrigerant management, SF6 leak detection, and high-GWP gas substitution are high-priority GHG reduction strategies even though the mass of gas involved seems small.
When reporting, calculate CO2e for each gas separately and then sum to get total facility CO2e. For combustion, calculate CO2, CH4, and N2O separately using the fuel-specific factors in Part 98 Table C-1 (for CO2) and Table C-2 (for CH4 and N2O). The CH4 and N2O contributions from natural gas combustion are small (typically less than 1% of total CO2e), but they must be included for regulatory reporting. For oil and coal combustion, the CH4 and N2O contributions are somewhat larger. For fluorinated gases, track each compound separately because GWPs vary widely even within the HFC family.
CO2: 1 | CH4: 25 | N2O: 298
R-134a (HFC): 1,430 | R-410A (HFC blend): 2,088 | R-404A (HFC blend): 3,922
R-22 (HCFC): 1,810 | SF6: 22,800
CO2e = mass of gas (metric tons) × GWP
Example: 100 kg CH4 = 0.1 MT × 25 = 2.5 MT CO2e
Example: 10 kg R-410A = 0.01 MT × 2,088 = 20.88 MT CO2e
Calculation Methods: Getting the Numbers Right
GHG calculations for most facilities boil down to three types of sources: stationary combustion, purchased energy, and fugitive emissions. Each has a well-defined calculation method. The key is matching the right data to the right factors and keeping units straight. Most GHG calculation errors come from unit conversion mistakes (therms vs. CCF vs. MCF for natural gas, short tons vs. metric tons, gallons vs. barrels), not from using the wrong method.
For Scope 1 stationary combustion, the basic formula is: Fuel Consumed (in energy units) × Emission Factor = CO2 emissions. For natural gas, if your bill shows 50,000 therms per year: 50,000 therms × 100,000 BTU/therm = 5,000 MMBtu. CO2 = 5,000 MMBtu × 53.06 kg CO2/MMBtu = 265,300 kg = 265.3 metric tons CO2. Add CH4 (5,000 MMBtu × 1.0E-3 kg/MMBtu × 25 GWP = 0.125 MT CO2e) and N2O (5,000 MMBtu × 1.0E-4 kg/MMBtu × 298 GWP = 0.149 MT CO2e) for a total of about 265.6 MT CO2e. The CH4 and N2O are minor for gas but add up for coal and oil.
For Scope 2 purchased electricity: Annual electricity consumption (kWh) × eGRID emission factor (lbs CO2/kWh) ÷ 2,204.6 (lbs per metric ton) = MT CO2. EPA's eGRID provides emission factors by subregion. For example, a facility in the RFCW (RFC West) subregion consuming 10 million kWh: 10,000,000 × 1.098 lbs CO2/kWh = 10,980,000 lbs = 4,981 MT CO2. Some programs also allow a market-based method using supplier-specific factors or renewable energy certificates (RECs), which can significantly lower Scope 2 if you purchase renewable energy.
For fugitive fluorinated gas emissions (refrigerants, SF6), the screening method is based on purchases: total gas purchased during the year minus gas returned for reclamation or destruction, plus gas in equipment at the beginning of the year minus gas in equipment at end of year. This gives net gas emitted. Multiply by GWP to get CO2e. The mass balance method is more accurate: for each piece of equipment, track beginning charge, gas added, gas recovered, and ending charge. The difference is the emission. For EPA Part 98 reporting, the required method depends on the source category and the facility's situation. Most facilities use the simplified purchase-based approach unless they have detailed equipment-level records.
1 therm = 100,000 BTU
1 CCF natural gas ≈ 1.02 therms (at 1,020 BTU/cf)
1 MCF = 10 CCF = 1,000 cubic feet
1 gallon diesel = 137,381 BTU (HHV)
1 gallon gasoline = 120,238 BTU (HHV)
1 short ton = 2,000 lbs = 0.907 metric tons
1 metric ton = 2,204.6 lbs = 1.102 short tons
1 kg = 2.205 lbs
Double-check units at every step. The most common GHG calculation error is a unit mismatch.
CO2 Capture / Carbon Intensity Calculator
Calculate gross and net CO2 emissions with carbon capture, CH4 and N2O equivalents, and carbon intensity per unit output. Uses 40 CFR Part 98 factors.
Reporting Requirements and Thresholds
The GHG reporting landscape includes federal, state, and voluntary programs, each with different thresholds, reporting formats, and deadlines. EPA Part 98 is the baseline for large emitters (25,000+ MT CO2e). California's Mandatory Reporting Regulation (MRR) applies to facilities emitting 10,000+ MT CO2e in California and requires third-party verification. Washington's Climate Commitment Act requires reporting at 10,000+ MT CO2e. Oregon, Massachusetts, New York, and other states have or are developing their own programs with varying thresholds.
Beyond mandatory programs, voluntary reporting through CDP, SBTi (Science Based Targets initiative), and The Climate Registry is increasingly expected by customers, investors, and supply chain partners. These programs generally follow the GHG Protocol and require Scope 1 and 2 emissions at minimum, with Scope 3 expected for larger companies. The benefit of voluntary reporting is that it builds the data infrastructure and organizational capability before mandatory requirements arrive. Facilities that have been voluntarily reporting for several years find the transition to mandatory reporting much smoother than starting from scratch.
Third-party verification is required by California MRR, may be required under SEC climate disclosure, and is becoming standard for voluntary programs. Verification involves an independent auditor reviewing your GHG inventory methodology, data sources, calculations, and quality controls. The verifier checks that fuel records match utility bills, that emission factors are correctly applied, that equipment inventories are complete, and that the calculation methodology follows the applicable protocol. A reasonable assurance verification typically costs $10,000-$30,000 for a single facility, depending on complexity.
Building a defensible GHG inventory system means documenting everything from the start. Create a GHG reporting manual that describes your organizational boundary (which facilities are included), operational boundary (which sources and scopes are included), calculation methodologies for each source, data sources and responsible personnel, quality assurance procedures, and record retention policies. This manual is the first thing a verifier asks for and the last thing most facilities think to create. Write it while you are building the inventory, not after. Future you will be grateful when reporting deadlines arrive and every calculation is traceable to a documented methodology and data source.
EPA Part 98: 25,000 MT CO2e threshold, due March 31, no verification required
California MRR: 10,000 MT CO2e threshold, due April 10, third-party verification required
Washington CCA: 10,000 MT CO2e threshold, due March 31, verification for 25,000+ MT
CDP: Voluntary (but customers may require it), due July, scoring A-D
SEC Climate Disclosure: Phased implementation, Scopes 1+2 for large accelerated filers
Check applicable state programs — several new state GHG reporting rules are being adopted.
GHG Reporting Consolidator
Consolidate Scope 1 combustion, fugitive refrigerant, and Scope 2 electricity emissions into a single CO2e inventory with eGRID factors and breakdown by scope.