Location-based vs market-based Scope 2: two maps of the same Kentucky grid

The short answer: location-based vs market-based Scope 2 is not a choice you make. If you have any operations in the US, where contractual instruments such as renewable energy certificates (RECs) exist, the GHG Protocol’s 2015 Scope 2 Guidance says you shall report both figures and label each one. The location-based number shows what the grid around your meters emits on average. The market-based number shows what your electricity contracts say you bought.

For a Kentucky facility with no RECs, no green tariff and no supplier-specific emission rate, the two numbers land within a fraction of a percent of each other. They separate only when you buy, or give away, something contractual. That is the part customers and lenders now ask about, and it is where first-year reports most often go wrong.

Location-based vs market-based Scope 2: what each measures

The Guidance defines the two methods this way:

• Location-based “reflects the average emissions intensity of grids on which energy consumption occurs,” mostly using grid-average factors. In the US, that usually means EPA’s eGRID subregion rates.
• Market-based “reflects emissions from electricity that companies have purposefully chosen (or their lack of choice).” Its factors come from contractual instruments: RECs, power purchase agreements that carry RECs, utility-specific emission rates and, where one exists, a residual mix.

Think of them as two maps of the same territory. One shows the power lines. The other lays your contracts over them. A good report tells the reader which map they are holding.

Two details first-time reporters often miss:

1. Both methods use the same kWh. Activity data comes from your utility bills or interval data either way. Only the emission factor changes.
2. Transmission and distribution losses are not Scope 2. The Guidance says grid emission factors exclude T&D losses and upstream fuel emissions; those belong in Scope 3, category 3. If a customer asks for that category, eGRID2023 lists a grid gross loss of 4.2% for the subregions that cover Kentucky.

Which eGRID factors apply in Kentucky

EPA’s Emissions & Generation Resource Integrated Database (eGRID) divides the country into subregions drawn around how the grid operates, not around state lines. The GHG Protocol’s location-based hierarchy names eGRID subregion output rates as its US example.

In EPA’s eGRID2023 plant data, the Kentucky plants of LG&E and KU, TVA, East Kentucky Power Cooperative and Big Rivers Electric are all assigned to the SERC Tennessee Valley (SRTV) subregion. Kentucky plants tied to Duke Energy Kentucky and Kentucky Power are assigned to RFC West (RFCW). Your facility’s subregion follows your serving utility, so confirm it in EPA’s Power Profiler, which EPA points to for that lookup.

eGRID2023 factor	Total output emission rate (lb CO2e/MWh)
SRTV (SERC Tennessee Valley)	903.306
RFCW (RFC West)	916.054
U.S. average	770.884
Kentucky state (generation located in Kentucky)	1,747.004

Source: EPA eGRID2023 summary tables, revision 2.

The non-obvious part: your subregion is not your utility

Look at the last row. Power plants located in Kentucky emitted about 1,747 lb CO2e per MWh in 2023, nearly double the SRTV rate. Inside the LG&E and KU balancing area alone, eGRID2023 shows about 1,908 lb/MWh from generation that was 81% coal. The SRTV subregion blends that with TVA’s fleet, which was about 42% nuclear, so the subregion lands near 903.

A Lexington manufacturer’s location-based figure therefore reflects the Tennessee Valley as a whole, not the plants down the road. That is correct under the GHG Protocol, which ranks grid-region factors above production-boundary averages such as state totals, because state lines ignore power flowing in and out. It has a consequence, though. If your utility publishes a delivered-electricity emission rate that meets the quality criteria, the market-based method uses it, and for a coal-heavy supplier that rate could exceed the subregion average. Market-based is not automatically the smaller number.

What counts in the market-based method

The market-based method accepts only contractual instruments that meet the Scope 2 Quality Criteria in Table 7.1 of the Guidance. In plain terms, every instrument must:

1. Convey the GHG emission rate of the electricity it represents.
2. Be the only instrument carrying that claim for that quantity of electricity.
3. Be tracked and retired, redeemed or canceled by you or on your behalf.
4. Be issued and retired as close as possible to the period of consumption it covers.
5. Come from the same market as the operations it is applied to.

Three more criteria cover utility emission rates, direct contracts and on-site generation, and the residual mix.

In the US, RECs are the standard instrument; the Guidance notes that most states and the Green-e Energy standard define a REC as conveying all environmental attributes of a megawatt-hour. What fails matters as much as what passes. If you host solar on your roof but sold its RECs, the Guidance says to treat the electricity you consume as if it came from the grid. You cannot claim zero emissions for power whose attributes belong to someone else.

For a side-by-side of how a green tariff, unbundled RECs and on-site solar show up in reporting, see green tariff vs RECs vs on-site solar.

The US residual mix problem

When some of your load has no instruments, the market-based method falls back down a hierarchy. The ideal fallback is a residual mix: the grid’s emission rate after removing every megawatt-hour someone else already claimed. Without it, the same clean megawatt-hour can be counted twice, once by the REC buyer and again by everyone using the grid average.

The US has no complete residual mix. The closest thing is the Green-e Residual Mix Emissions Rates from the Center for Resource Solutions (CRS). The 2025 table, released January 29, 2026 and based on 2023 data, removes only Green-e Energy certified sales from each eGRID subregion. CRS says regional rates that factor out all specified purchases are “not yet available” for all US regions.

For Kentucky, the adjustment is tiny:

• SRTV: 903.72 lb/MWh residual mix vs 903.306 in eGRID, a 0.05% difference
• RFCW: 917.78 lb/MWh vs 916.054, a 0.19% difference

So using eGRID factors for uncovered load in a US market-based total is a permitted fallback, and in Kentucky it changes the answer by less than a fifth of one percent. The Guidance allows unadjusted grid-average factors when no residual mix is available. It also requires you to note that an adjusted factor is not available and that this “may result in double counting between electricity consumers.” Put that sentence in your report. A careful reviewer will look for it.

A worked example: one Kentucky plant, two numbers

This is illustrative. A made-up parts plant in Lexington buys 4,200 MWh a year from Kentucky Utilities, which places it in SRTV. This year it buys and retires 1,500 MWh of RECs that meet the quality criteria. It has no supplier-specific emission rate.

Line	MWh	Factor (lb/MWh)	Factor source	Metric tons CO2e
Location-based total	4,200	903.306	eGRID2023, SRTV	1,720.9
Market-based: REC-covered	1,500	0	Retired RECs	0
Market-based: uncovered	2,700	903.72	Green-e 2025 residual mix, SRTV	1,106.8
Market-based total	4,200			1,106.8
Error to avoid: state rate	4,200	1,747.004	eGRID2023, Kentucky state	3,328.2

We convert at 2,204.62 lb per metric ton. These are non-certified estimates based on published methodologies, not verified or assured figures.

What the table shows:

• The RECs cut the market-based figure by about 615 metric tons, or 36%. The location-based figure did not move at all. Among your own actions, only drawing less from the grid, through efficiency or on-site generation whose RECs you keep, moves that number.
• The fallback choice barely matters here. Using eGRID instead of the residual mix for the uncovered 2,700 MWh changes the answer by half a ton. Document the choice and move on.
• Picking the wrong factor matters far more than choosing between defensible ones. Applying the state rate nearly doubles the location-based figure.

If you run a plant and want to see how figures like these land in a customer’s form, see our illustrative Scott County supplier scenario.

What is changing: the GHG Protocol Scope 2 revision

The 2015 Guidance is under revision. Here is where things stand, based on the GHG Protocol’s own update dated October 16, 2026:

• Consultation. A public consultation ran from October 20, 2025 to January 31, 2026. It proposed that certificates count in the market-based method only if they are matched to consumption by the hour (“hourly matching”) and come from a grid region that can deliver power to where you use it (“deliverability”).
• Feedback. Responses split into two camps. One favored hourly, same-grid and newly built (“incremental”) clean power. The other favored annual matching and broad boundaries to keep the certificate market easy to join.
• Two methods. In 2026, the Independent Standards Board backed developing two market-based methods: Method 1, with hourly matching, deliverability and incrementality, and Method 2, which keeps the 2015 rules. In September it proposed a direction in which companies may use Method 2 until a date still to be set, should use Method 1, must disclose which one they apply, and after that date must use Method 1 where qualifying data exists. Whether reporting a market-based figure will be required (“shall”), recommended (“should”) or optional (“may”) is also still open.
• Timeline. A consolidated public consultation covering Scopes 1, 2 and 3 is slated for Q2 2027. The joint GHG Protocol–ISO Corporate Standard is slated for publication in Q4 2028.

As of November 1, 2026: the 2015 Scope 2 Guidance is still the operative rulebook, and none of the revision is final. EPA’s eGRID pages still list eGRID2023 (2023 data; revision 2 posted June 12, 2025) as the current edition. Unofficial 2024 estimates from third parties are not EPA releases. Check the edition and date of any factor before you use it.

For a Kentucky business buying RECs today, annual US RECs that meet the quality criteria remain valid under the 2015 rules. If you are signing a multi-year REC or green tariff contract, ask how it would hold up under hourly matching and deliverability tests, because that is the direction Method 1 points.

What we’d do

If you are preparing your first Scope 2 figures:

1. Pull 12 months of bills for every meter and total the kWh by facility. Fill missing months before choosing any factor.
2. Confirm each site’s eGRID subregion in Power Profiler, and record the edition and revision you used.
3. Calculate location-based first. It is the baseline every reviewer can reproduce.
4. List every contractual instrument, including RECs, green tariff purchases, PPAs and REC ownership for any on-site solar, and check each against the quality criteria.
5. Choose and disclose your market-based fallback for uncovered load, with the double-counting note.
6. State which figure you use for targets. The Guidance requires you to specify the method used for goal-setting and tracking.
7. Keep a one-page assumptions sheet so next year’s numbers stay consistent and your answers match across customer questionnaires.

Our Carbon & Scope 2 Reporting service follows these steps, uses published methodologies and shows every factor we rely on. Our figures are non-certified estimates. We don’t provide third-party verification or assurance; if a customer requires it, we organize your file for the verifier you hire.