Portland is considering the most literal building decarbonization schedule in the country: not a target with a plan to have a plan, but a staircase written into city code — cut your building’s greenhouse gas intensity by 20 percent, then 20 percent again, every five years, until it reaches zero in 2050. The proposal is still moving through City Council, and the details matter for any owner of a larger commercial or multifamily building in the city. Here is what the ordinance actually says.
What is Portland proposing?
The proposal is Ordinance 2026-377, which would replace City Code Chapter 17.104 with a new chapter: Climate and Health Standards for Buildings. Its stated purpose is to reduce carbon emissions from commercial and multifamily residential buildings to zero by 2050, and to give tenants information about the affordability, health, and resilience of rental housing.
Status matters here: this is a proposal, not a law. The Sustainability and Climate Commission endorsed it in August 2026. The Housing and Permitting Committee took it up on October 20, 2026 and continued it to December 1, 2026 — so the next decision point is December 1, and the draft can still change. Everything below describes the ordinance as currently written.
Which buildings would be covered?
Covered buildings are commercial buildings and residential buildings with four or more dwelling units, with specified exclusions. The carbon performance standards apply to covered buildings of at least 20,000 square feet.
Reporting comes first. Annual energy performance reporting would apply to covered buildings of at least 20,000 square feet beginning June 1, 2028. That is an extension of familiar ground: Portland has run a Commercial Building Energy Reporting Program since 2015, and in 2025–2026 the city piloted multifamily reporting with five properties. The pilot found the first year of benchmarking took 3 to 9 hours of active staff time (median 6), and participants expected two hours or less in later years.
How does the step-down work?
The standard is a greenhouse gas intensity (GHGI) target — emissions per square foot — that tightens in 20-percent increments every five years, beginning with the 2030 performance standard and reaching zero carbon emissions by 2050.
Zero means zero. The code defines the final standard as a GHGI of zero without the use of offsets, renewable natural gas, or unregulated credit mechanisms. There is no buying your way to the last step.
One provision works in owners’ favor: the code’s emissions factors are designed to account for Oregon’s clean-energy targets, so as the electric grid gets cleaner, an electrified building’s measured intensity falls with it. Efficiency and electrification do the rest.
What happens if a building misses its standard?
It pays a carbon pollution impact fee. For the first interim standard, the ordinance sets the cost of carbon at $380 per metric ton of CO2e per year, charged on emissions above the building’s target.
Three features of the fee are worth knowing:
It ratchets. Future rates are set by the City Administrator, reviewed at least every five years, and approved by Council — and a future fee may not be lower than the fee for the previous interim standard.
The money is locked to compliance. Fee revenue goes into a dedicated fund used solely to support compliance with the chapter — grants, technical assistance, and financing for retrofits — with priority for regulated affordable housing, naturally occurring affordable housing, small property owners, and buildings serving low-income or climate-vulnerable tenants. Administrative costs paid from the fund are capped at seven percent.
It is also an off-ramp in hard cases (see below).
What are the off-ramps?
The ordinance builds in flexibility, because a hard staircase meets buildings that genuinely cannot climb it on schedule:
Extensions and exemptions for specified circumstances.
Alternate Compliance Plans for qualifying campus portfolios with shared utility services — a provision shaped by higher-education and institutional owners whose energy systems serve whole campuses.
A full exemption from both the carbon performance standards and the impact fee for regulated affordable housing.
A displacement escape valve: if required whole-building upgrades would force tenant relocation for more than ten calendar days or termination of a tenancy, the City Administrator may authorize compliance through payment of the impact fee instead of the upgrades.
At least once every five years after 2030, the City Administrator must also publish an impact report — covering displacement, implementation costs, electric-system capacity and reliability, and utility-cost impacts — with recommendations for adjusting the program or its timeline.
What changes for tenants?
The standards’ costs may not be passed through to residential tenants. Beyond that, the chapter adds a tenant-information layer that starts before the first carbon standard bites:
Beginning January 1, 2028, prospective tenants get climate and health information, including utility costs and energy assistance, cooking fuel and ventilation, and mechanical and passive cooling.
Beginning June 1, 2028, residential covered buildings complete a climate and health inventory every five years.
When upgrades require temporary relocation, owners must file a tenant impact plan — addressing temporary housing and, where applicable, moving, storage, and transportation assistance — and guarantee a right to return to the same unit.
What should an owner do while this is still a proposal?
Three things. First, watch December 1 — that is when the committee takes the ordinance up again. Second, if your building already benchmarks under the 2015 reporting program, treat that data as the foundation it is: a step-down schedule measures every future cut against your baseline, so a sloppy baseline becomes a permanent handicap. Third, read the proposal alongside the other performance-standard regimes now stacking up — Washington D.C.’s BEPS pathways and New York’s LL84/LL97 benchmarking-and-limits sequence are the closest cousins, and portfolios that span cities are already learning to run one compliance calendar for all of them.
Portland’s draft is unusually honest about its own mechanics: the steps, the price of missing one, and the exits are all on the page. Whether Council adopts it as written is the December question.
Corporate Carbon Footprint Calculator — enter one year of fuel and electricity use. Results update as you type, in metric tons of CO2 equivalent (tCO2e). This is a planning estimate built on published U.S. EPA factors — not an audit, not a GHG Protocol inventory, and not a certification. The method, the factors, and the limits are set out below the calculator and in the guide that follows it.
Scope 1 — fuels you burn on site or in your own vehicles
What this number is not: an audit, a verified inventory under the GHG Protocol Corporate Standard, or a certification of any kind. It covers the four fuel lines above and purchased electricity only — no Scope 3, no refrigerants, no process emissions. Scope 2 here is location-based only (the average emissions of the grid where the electricity is used); market-based Scope 2 accounting, which reflects specific contracts and renewable instruments, is not covered. Use it to size a footprint and find the big lines before commissioning a full inventory.
The factors, and where they come from. Fuel factors: U.S. EPA, Emission Factors for Greenhouse Gas Inventories (last modified January 15, 2025), Table 1 (stationary combustion), converted to CO2e with the document’s own 100-year global warming potentials from IPCC AR5 (CH4 = 28, N2O = 265). Electricity factors: U.S. EPA eGRID2023 (Revision 2, June 2025), Table 1, total output CO2e rates. Nothing on this page uses an unsourced or estimated factor.
Input
EPA factor (CO2 + CH4 + N2O)
= kg CO2e per unit
Natural gas, per therm
5.306 kg CO2 + 0.10 g CH4 + 0.010 g N2O
5.311
Diesel (distillate fuel oil No. 2), per gallon
10.21 kg CO2 + 0.41 g CH4 + 0.08 g N2O
10.243
Gasoline (motor gasoline), per gallon
8.78 kg CO2 + 0.38 g CH4 + 0.08 g N2O
8.812
Propane, per gallon
5.72 kg CO2 + 0.27 g CH4 + 0.05 g N2O
5.741
Purchased electricity, U.S. average, per kWh
770.9 lb CO2e per MWh (eGRID2023 total output rate)
0.350
All eGRID2023 subregion electricity rates used in the selector (lb CO2e per MWh, total output, eGRID2023 Rev. 2, Table 1)
Subregion
Name
lb CO2e/MWh
kg CO2e/kWh
AKGD
ASCC Alaska Grid
905.1
0.411
AKMS
ASCC Miscellaneous
522.4
0.237
AZNM
WECC Southwest
706.2
0.320
CAMX
WECC California
430.0
0.195
ERCT
ERCOT All
736.6
0.334
FRCC
FRCC All
784.8
0.356
HIMS
HICC Miscellaneous
1,133.3
0.514
HIOA
HICC Oahu
1,498.9
0.680
MROE
MRO East
1,405.0
0.637
MROW
MRO West
926.6
0.420
NEWE
NPCC New England
543.2
0.246
NWPP
WECC Northwest
635.3
0.288
NYCW
NPCC NYC/Westchester
865.7
0.393
NYLI
NPCC Long Island
1,189.3
0.539
NYUP
NPCC Upstate NY
242.8
0.110
PRMS
Puerto Rico Miscellaneous
1,548.5
0.702
RFCE
RFC East
599.2
0.272
RFCM
RFC Michigan
976.0
0.443
RFCW
RFC West
916.1
0.416
RMPA
WECC Rockies
1,042.5
0.473
SPNO
SPP North
867.7
0.394
SPSO
SPP South
875.6
0.397
SRMV
SERC Mississippi Valley
741.7
0.336
SRMW
SERC Midwest
1,248.6
0.566
SRSO
SERC South
846.0
0.384
SRTV
SERC Tennessee Valley
903.3
0.410
SRVC
SERC Virginia/Carolina
596.3
0.270
There is no meter you can clamp onto a whole company. A corporate carbon footprint is built — line by line, from fuel receipts, utility bills, and travel records — using the method set out in the GHG Protocol Corporate Accounting and Reporting Standard, the framework developed by the World Resources Institute (WRI) and the World Business Council for Sustainable Development (WBCSD) that nearly every reporting regime now builds on. This page is the calculation, explained the way an operator actually runs it: what the three scopes mean, what data to gather before you start, how the arithmetic works, how to read the number you get, and where that number stops being reliable. Where BC ESG has a working tool for a specific job — the Local Law 97 penalty calculator for New York buildings, the vendor carbon report template for trade and restoration work — it is linked below, because a building-penalty calculation and a corporate inventory are different instruments and should not be confused.
What is a corporate carbon footprint, exactly?
A corporate carbon footprint is the total greenhouse gas emissions attributable to one company over a defined period, usually a year, expressed in metric tons of carbon dioxide equivalent (tCO2e). The “equivalent” matters: the GHG Protocol covers seven greenhouse gases, not just carbon dioxide, and each gas is converted into CO2e using its global warming potential, so methane released from a landfill contract and diesel burned in a company truck land in the same unit and can be added together honestly.
A footprint is an inventory, not a measurement. Nobody observes a company’s emissions directly; the company assembles activity records and converts them with published emission factors. That is why two footprints are only comparable when they were built on the same boundary, the same period, and the same rules — and why the method on this page matters more than any single number it produces.
What are Scope 1, Scope 2, and Scope 3?
Scope 1 is direct emissions from sources the company owns or controls: fuel burned in its boilers, furnaces, generators, and vehicles, refrigerant leaking from its own equipment, and emissions from any industrial process it runs. If the company can turn the source off, its emissions are almost certainly Scope 1.
Scope 2 is indirect emissions from the generation of energy the company buys and consumes — purchased electricity, steam, heating, and cooling. The GHG Protocol’s Scope 2 Guidance gives companies two ways to count purchased electricity: location-based, using the average emissions intensity of the grid where the consumption happens, and market-based, reflecting the specific contracts and instruments the company has bought. Companies with market-based instruments generally report both figures, because each one answers a different question.
Scope 3 is everything else indirect, upstream and downstream, in the company’s value chain: purchased goods and services, capital goods, business travel, employee commuting, waste, transportation and distribution, the use of products the company sells, and their end-of-life treatment. The GHG Protocol’s Corporate Value Chain (Scope 3) Standard organizes these into 15 categories. One company’s Scope 3 is, in large part, other companies’ Scope 1 and 2 — which is why the vendor report a customer sends your firm is not paperwork for its own sake.
How does the calculation actually work?
Every line of a footprint is the same multiplication: activity data times an emission factor. Gallons of diesel burned, multiplied by the published factor for diesel combustion, gives that line’s emissions; kilowatt-hours purchased, multiplied by the grid factor for the region, gives another. Add the lines within each scope, convert gases to CO2e where a factor does not already do it, and the three scope totals are the footprint. The arithmetic is simple. The work is in the boundary, the data, and the factors.
The boundary comes first. The GHG Protocol lets a company consolidate by equity share or by control — financial control or operational control — and the choice decides which facilities, subsidiaries, and leased assets are inside the inventory at all. A base year is fixed next, so future inventories can be compared against something stable, and the Corporate Standard sets rules for recalculating that base year when the company buys, sells, or restructures a business. Skipping these two decisions is how a company ends up with a number it cannot reproduce the following year.
Emission factors come from published sources, and naming the source is part of the calculation, not a footnote. In the United States, the working references are the U.S. Environmental Protection Agency’s GHG Emission Factors Hub for fuel, waste, and travel factors, and the EPA’s eGRID database for the emissions intensity of purchased electricity by grid region. Factors are revised as grids and fuels change, so an inventory should record which vintage of each factor it used — a result you cannot trace back to its factors is an estimate wearing a costume.
What do you need to gather before you start?
For Scope 1: twelve months of fuel purchase or consumption records for every facility and fuel type, fleet fuel logs or mileage records, generator run and fuel records, and refrigerant service records showing what was added to which system — refrigerant top-ups are the record of what leaked. For Scope 2: twelve months of utility bills for electricity, gas, steam, and chilled water for every site inside the boundary, plus any renewable energy contracts or certificates if a market-based figure will be reported.
For Scope 3, start with a screen, not a census. Pull the year’s purchasing ledger by vendor and category, business travel reports, waste hauling invoices, and whatever commuting data the company can reasonably estimate, then identify which of the 15 categories are plausibly material before collecting anything in depth. A restoration contractor, for example, will usually find vehicles and fuel already sitting in Scope 1, purchased materials and subcontracted work waiting in Scope 3, and very little that needs a survey to discover.
The gathering rule that saves the second year: capture the record at the source, in the system that already exists. Fuel and utility data that live in accounting, refrigerant data that lives in service tickets, and travel data that lives in expense reports can all feed an inventory — but only if someone decided in January, not the following December, that those records would be kept in a usable shape.
How do you read the result, and what do you do with it?
Read the footprint by scope and category, not as a single total. The total tells you the size of the thing; the breakdown tells you where it lives — the two or three lines that dominate the inventory are where reduction money earns something, and the long tail of small categories is where effort goes to die. A footprint that is 80 percent purchased electricity is an energy-procurement conversation; a footprint dominated by fleet fuel is a routing, vehicle, and idle-time conversation.
Then make it comparable. Divide by something the business actually manages — revenue, square footage, headcount, jobs completed — to get an intensity figure, and track intensity against the base year rather than celebrating or mourning raw totals that move whenever the company grows. The inventory earns its keep when it feeds a decision: a capital plan, a fleet replacement cycle, a customer’s supplier questionnaire answered from records instead of adjectives, or a disclosure the company is required to file, such as the Scope 1 and 2 reporting California’s SB 253 regime is phasing in for large companies doing business in the state (see our walkthrough, Three Doors Into November 10: How the First SB 253 Filing Actually Works).
What are the limits of the estimate?
A footprint is a structured estimate, and its precision is uneven by design. Scope 1 and 2, built from metered energy and fuel records, can be tight. Scope 3 lines built from spending data — dollars multiplied by an industry-average factor — are order-of-magnitude figures, useful for finding hotspots and useless for claiming a total to the nearest ton. Emission factors are averages: the grid factor for a region is not the emissions of the specific power your building drew at 2 p.m., and factor tables always lag the grid they describe.
Two limits deserve plain words. First, a footprint is not an audit and not a certification: preparing an inventory under the GHG Protocol and having that inventory independently assured are separate steps, and no page on this site — this one included — certifies anything about your company. Second, a precise-looking number built on thin data is the specific shape greenwashing enforcement keeps finding. Reporting the total alongside its boundary, its factor sources, and its known gaps is not weakness; it is what makes the number defensible when a customer, a lender, or a regulator asks how it was built.
What is the sensible next step?
Start where your records are strongest: build Scope 1 and Scope 2 first, from a full year of fuel and utility data, with the boundary and base year written down. Screen Scope 3 from the purchasing ledger in the same pass, and go deep only on the categories the screen shows are material. Fix the collection points while you work — the vendor carbon report template linked below exists because the cheapest Scope 3 data is the record a vendor hands you in a standard shape at the time of the job, not the one you reconstruct from invoices at year-end.
If the footprint is being built because a specific rule is asking, use the specific instrument. New York City building owners facing Local Law 97 are not really doing a corporate inventory — they are doing a building emissions calculation against statutory limits and a $268-per-ton penalty, and the LL97 penalty calculator below runs that math from the rule itself. Companies preparing for California’s climate disclosure laws need the inventory discipline on this page plus the filing mechanics, which our SB 253 coverage walks through door by door.
For NYC and Long Island building teams
BCESG’s NYC desk covers how this topic lands on the ground for owners, facility managers, and tenants:
Updated: October 29, 2026 — Re-engineered for commercial facility operations: base building vs. tenant boundaries, EPA Section 608 fugitive refrigerant math, district steam factors, and 4-step utility data ingestion workflow.
For commercial building owners, facility managers, and chief engineers, carbon accounting is not an abstract corporate reporting exercise—it is a rigorous engineering discipline. Translating monthly Con Edison, National Grid, PG&E, or municipal utility bills, central chiller maintenance logs, and tenant submeters into defensible greenhouse gas (GHG) inventories is required to satisfy municipal building performance standards and mandatory corporate climate disclosure laws.
By Will Tygart, author of the Commercial Restoration Carbon Protocol (CRCP). All conversion factors, regulatory formulas, and global warming potential (GWP) metrics cite primary EPA, GHG Protocol, and NYC Department of Buildings standards.
The Commercial Real Estate Emissions Boundary Map: Base Building vs. Tenant Scopes
In commercial real estate, operational and legal boundaries dictate emissions ownership under the GHG Protocol Corporate Standard:
Scope 1 (Direct Facility Combustion & Leakage): On-site combustion in central heating boilers, domestic hot water heaters, and emergency backup diesel generators, plus fugitive refrigerant releases from HVAC chillers and split systems.
Scope 2 (Indirect Purchased Energy): Purchased grid electricity consumed by central plant equipment (elevators, common-area lighting, ventilation fans, base-building chillers) and purchased district steam or chilled water loops.
Scope 3 Category 13 (Downstream Leased Assets): Tenant plug loads, demised lighting, and dedicated supplemental AC in leased tenant spaces where tenants hold operational control under triple-net (NNN) leases.
1. Facility Scope Boundaries & The Control Approach
Under the GHG Protocol Corporate Standard, building owners must select an organizational boundary consolidation approach: Operational Control, Financial Control, or Equity Share. Over 90% of commercial real estate portfolios select Operational Control:
Operational Control Boundary: The entity accounts for 100% of emissions from operations over which it has the full authority to introduce and implement operating policies. For a commercial landlord, this encompasses all base-building mechanical systems, central heating and cooling plants, vertical transportation, exterior facade lighting, and common areas.
The Landlord-Tenant Split: When a tenant leases commercial office or retail space under a triple-net lease and controls its own operating schedule, thermostat setpoints, and interior equipment, that energy use falls outside the landlord’s operational control. Under the GHG Protocol, tenant energy is classified as Scope 3, Category 13 (Downstream Leased Assets) for the landlord, while representing Scope 1 and Scope 2 for the tenant.
Fugitive refrigerant leakage is one of the most frequently omitted or miscalculated components of commercial facility carbon accounting. In large commercial properties with central chillers or distributed VRF systems, refrigerant top-ups can account for 15% to 30% of direct Scope 1 greenhouse gas emissions.
The Refrigerant Emissions Formula
Because Global Warming Potentials (GWPs) represent the atmospheric warming impact relative to CO2 over a 100-year horizon, even modest physical losses generate massive carbon footprints:
Emissions (tCO2e) = [Refrigerant Added to Restore Full Charge (lbs) × GWP100] ÷ 2,204.62
Authoritative 100-Year Global Warming Potentials (GWP100)
R-410A: GWP = 2,088 (EPA GHGRP 40 CFR Part 98 / IPCC AR4). Commonly used in commercial rooftop units, packaged heat pumps, and VRF systems.
R-134a: GWP = 1,430 (EPA GHGRP / IPCC AR4). Common in centrifugal water-cooled chillers.
R-32: GWP = 675. Next-generation low-GWP refrigerant in modern heat pump systems.
Engineering Worked Example: Central Chiller Servicing
Consider a 500-ton commercial centrifugal chiller operating with an 800 lb factory charge of R-134a. During annual spring servicing, mechanical contractors discover a shaft seal leak and add 65 lbs of R-134a to restore optimal operating charge. Under EPA Section 608 maintenance logs:
That single 65 lb service top-up emits 42.16 metric tons of CO2e—equivalent to consuming roughly 4,750 gallons of gasoline or burning 8,000 therms of natural gas. Failure to extract contractor EPA Section 608 service invoices will severely distort your Scope 1 emissions audit.
Under both the GHG Protocol and international reporting frameworks like ISSB IFRS S2, tenant operational energy consumption represents the landlord’s Scope 3 Category 13 emissions. To capture this data without violating tenant privacy or operational autonomy:
Green Lease Language: Modern institutional leases mandate that tenants provide annual or quarterly energy consumption summaries, or execute letters of authorization (LOAs) permitting landlords to pull whole-building aggregated utility data.
Submetering Infrastructure: Installing digital electric submeters at each tenant electrical panel allows automatic capture of tenant plug loads and supplemental heating/cooling use.
Categories 1 & 2: Embodied Carbon in Fit-Outs and Restoration
When commercial office space turns over between leases, demolition and reconstruction of interior partitions, carpet, ceiling tiles, and branch ductwork generate significant embodied greenhouse gas emissions. For guidance on tracking carbon from interior demolition, reconstruction, and disaster drying, review our Restoration Carbon Protocol (CRCP) Commercial Real Estate Scope 3 Guide.
5. Step-by-Step Facility Data Ingestion Workflow
Establishing an auditable greenhouse gas inventory requires a systematic 4-step workflow that moves from field meters to verified disclosures:
Step 1 — Establish Meter Architecture in ENERGY STAR Portfolio Manager (ESPM): Set up every physical utility meter (electric, gas, fuel oil, steam, water) within ESPM. Map meters explicitly to base-building common areas versus demised tenant spaces to preserve scope boundaries.
Step 2 — Automate Electronic Data Interchange (EDI) Utility Feeds: Replace manual utility bill entry with automated EDI utility integrations or third-party automated energy data capture services. Automated feeds pull kilowatt-hours, peak demand (kW), therms, and billing dates directly from utility databases, eliminating data-entry transcription errors.
Step 3 — Extract Mechanical Contractor EPA Section 608 Logs: Establish a mandatory quarterly procurement protocol requiring all mechanical and HVAC contractors to submit signed EPA Section 608 refrigerant service reports detailing initial equipment charge, pounds of refrigerant recovered, and pounds added.
Step 4 — Weather-Normalize Energy Use Intensity (EUI): Normalize energy data against National Oceanic and Atmospheric Administration (NOAA) local weather station Heating Degree Days (HDD) and Cooling Degree Days (CDD). Weather normalization isolates physical building performance from anomalous winter freezes or summer heat waves.
6. Regulatory Alignment: Local Law 97, California SB 253, and ISSB S2
Commercial carbon accounting directly feeds mandatory compliance regimes across jurisdictions:
NYC Local Law 97: Measures building operational carbon (Scope 1 natural gas/fuel oil plus Scope 2 electricity and district steam) against statutory limits. Excess emissions trigger civil penalties of $268/tCO2e. Review our LL97 Penalty Calculator and statutory compliance guides.
California SB 253: Mandates complete Scope 1 and Scope 2 disclosures for entities doing business in California with annual revenues exceeding $1 billion, with first filings due to CARB by November 10, 2026. Scope 3 reporting begins in 2027. Review our California SB 253 Compliance Guide.
ISSB IFRS S2: Requires institutional property portfolios to publish audited Scope 1 and Scope 2 metrics, provide transition plans, and quantify physical climate resilience.
Frequently Asked Questions
What is the difference between Location-Based and Market-Based Scope 2 emissions?
Location-based Scope 2 calculates emissions based on the average carbon intensity of the physical electrical grid supplying the building (using EPA eGRID subregion factors). Market-based Scope 2 reflects the specific contractual terms of the electricity purchased by the facility—including utility green tariffs, Power Purchase Agreements (PPAs), and Energy Attribute Certificates (EACs/RECs). The GHG Protocol mandates dual reporting so that investors see both physical grid impact and contractual procurement.
Do contractor vehicles and material deliveries count as Scope 1 or Scope 3?
If the vehicles or equipment are owned or directly leased by the building owner, their fuel combustion is Scope 1 (Mobile Combustion). If the vehicles are owned and operated by independent third-party vendors, suppliers, or restoration contractors, their fuel consumption is Scope 3 (Category 4: Upstream Transportation and Distribution or Category 1: Purchased Goods and Services).
How does district steam compare to on-site natural gas in carbon intensity?
In New York City under 1 RCNY § 103-14, district steam carries an emissions coefficient of 0.00004493 tCO2e/kBtu (or 0.04493 tCO2e/Mlb), whereas natural gas is 0.00005311 tCO2e/kBtu (0.005311 tCO2e/Therm). While district steam has a lower carbon factor than on-site natural gas under current municipal coefficients, building operators must maintain steam traps and condensate return systems to prevent high thermal losses.
Mandatory Environmental Accounting Notice
Notice on Carbon Accounting: This methodology guide reflects standards outlined in the GHG Protocol Corporate Accounting and Reporting Standard and ISO 14064-1. Calculations are provided for facility benchmarking and internal ESG planning. Formal regulatory filings (such as California SB 253 or NYC Local Law 97) require third-party data verification and certification by accredited GHG verifiers or licensed professional engineers.
