Evaluating DER impact across projects, types, and geographies.
Why we need standardized impact metrics beyond kWh and kW
Measuring emissions impact using average and marginal grid intensity
Six $/kW-year value streams measuring DER contributions to the grid
Capacity measurement, units, and the six-element framework
Bridging hourly savings to comparable impact metrics.
Now that we can measure hourly savings, how do we evaluate and compare the impact of different DER projects?
Which project delivers more grid value? More carbon value? The answer depends on when the savings happen and what the grid needed at that moment.
Both start from the same input: hourly energy savings from a standardized methodology.
Emissions impact using grid intensity data.
We compute both. They often tell different stories — a project in a coal-heavy region may have a high average score but a moderate marginal score if the marginal generator is gas.
| Hour | Savings | Avg impact | Marg. impact |
|---|---|---|---|
| 2pm | +20 kWh | +5.0 kg | +6.0 kg |
| 6pm | +80 kWh | +40.0 kg | +52.0 kg |
| 2am | −30 kWh | −12.0 kg | −15.0 kg |
| Average | 11.0 kg/hr | 14.3 kg/hr |
The 6pm hour is worth more in both lenses — the grid is dirtier and the savings are larger. The 2am penalty hurts less because the grid is cleaner at night.
Six $/kW-year value streams measuring DER contributions to the grid.
A Grid Score of 0.30 means 30% of the project's total displaced electricity occurred during grid stress hours. Higher is better. All six scores are pure, unweighted kWh ratios.
Data availability varies significantly by geography. Wholesale-market scores require ISO data. Capacity/RA is broadly available via EIA-930. Tariff savings is computable everywhere. T&D deferral is the most constrained — limited to CA and NY for distribution-level data.
A Grid Score of $60/kW-yr for Capacity/RA means each kW of DER capacity delivers $60/year of capacity value to the grid. The coincidence factor adjusts for how well the technology actually captures that value. Higher is better.
Low / mid / high (e.g. 0.85 / 1.00 / 1.25) are error bars around the medium estimate, not distinct scenarios. They capture uncertainty in load growth and market evolution.
| Grid Score | What It Measures | $/kW-yr Data Source | Geographic Level |
|---|---|---|---|
| Tariff Savings | Retail rate structure alignment | Utility tariff schedules (TOU, demand charges) | Utility service territory |
| Energy Arbitrage | Value of shifting energy across time | Energy component of LMP | Pricing node or zone |
| Congestion Relief | Wholesale market congestion relief | Congestion component of LMP | Pricing node or zone |
| Capacity / RA | Peak demand contribution | RA clearing price or BRA auction results | Balancing Authority |
| Ancillary Services | Grid balancing contribution | Composite AS clearing price | Zone or system-wide |
| T&D Deferral | Local infrastructure relief | NWA filings, LNBA, E3 ACC fallbacks | Transmission node / feeder |
Each score is denominated in $/kW-year — the annualized value a 1 kW DER delivers through that stream. The coincidence factor for each technology adjusts for realistic operating constraints. A rooftop solar project might score well on energy arbitrage but poorly on capacity/RA — the multi-dimensional view is the point.
Each DER is classified by technology (battery, HVAC, smart-thermostat, solar+storage) and control mode (wholesale-bid, self-consumption, demand-response). The combination determines which value streams the project is eligible for and how much of each stream it captures.
The fraction of a stream's theoretical value that the archetype captures under realistic operating constraints. Not the fraction of theoretical capacity — the fraction of theoretical value. A factor of 0.00 means the project is ineligible for that stream.
Coincidence factors vary by stream — a battery might be 0.90 for energy arbitrage but 0.60 for ancillary services (must reserve state-of-charge headroom). A wholesale-bid battery gets 0.00 for tariff savings (no retail exposure).
| Technology | Control Mode | Factor | Citation |
|---|---|---|---|
| battery | wholesale-bid | 0.85 | CAISO 2024 RA QC; PJM ELCC 4-hr derate |
| battery | self-consumption | 0.00 | Not counted towards capacity |
| hvac | demand-response | 0.70 | Internal est.; FERC-201 participation |
| smart-thermostat | demand-response | 0.40 | Internal est.; seasonal availability |
| solar+storage | wholesale-bid | 0.80 | NREL ATB 2024; coupled capacity credit |
Two modes for computing grid value. Forecasting uses coincidence factors to estimate what a DER will deliver.
| Stream | Settlement | Forecast |
|---|---|---|
| Tariff Savings | Metered actuals | Deemed loadshape × coincidence |
| Energy Arbitrage | Hourly actuals | Deemed loadshape × coincidence |
| Congestion Relief | Hourly actuals | Deemed loadshape × coincidence |
| Capacity / RA | Entirely deemed (settlement = forecast) | |
| Ancillary Services | Entirely deemed (settlement = forecast) | |
| T&D Deferral | Entirely deemed (settlement = forecast) | |
Deemed streams always use coincidence factors. Hourly-settled streams only use them in forecast mode — settlement has real data instead.
How much a DER reduces a customer's retail electricity bill.
Tariffs vary enormously by utility, rate class, and vintage — the score must reference each project's specific applicable tariff.
Both derived from LMP decomposition: LMP = Energy + Congestion + Losses. Each component is scored separately.
The value of committing dispatchable capacity to meet peak demand.
The DER commits a fixed capacity (kW) to the grid operator. The clearing price sets $/kW-yr for that commitment. The coincidence factor derate reflects how much of nameplate the technology can reliably deliver (e.g. a 4-hr battery can't sustain output through an 8-hr peak).
Unlike energy or congestion scores, there are no hourly price signals. Value is fixed at the auction clearing price × the promised capacity. This is a contract-based value stream, not a market-price-based one.
The value of providing frequency regulation and reserves to keep the grid balanced.
Only batteries on wholesale-bid participate (all others = 0.00 coincidence)
The value of avoiding or deferring utility transmission and distribution infrastructure investment.
Transmission — visible through LMP spreads; requires mapping DER location to relevant constraint
Distribution — feeder/substation congestion via hosting capacity analysis
The most locally valuable score, and the hardest to compute. NWA programs in CA and NY already use similar logic.
Project: 500 kW Battery Storage (wholesale-bid), PJM (Northern Virginia) · Period: January 2026 · Scenario: mid
| Score | Benchmark | Coinc. | $/kW-yr |
|---|---|---|---|
| Carbon (Average) | — | 0.38 tCO₂/MWh | |
| Carbon (Marginal) | — | 0.52 tCO₂/MWh | |
| Ancillary Services | $33.73 | 0.60 | $20.24 |
| Energy Arbitrage | ~$15 | 0.90 | ~$13.50 |
| T&D Deferral | $18.50 | 0.50 | ~$9.25 |
| Capacity / RA | $10.56 | 0.85 | ~$8.98 |
| Congestion Relief | ~$10 | 0.70 | ~$7.00 |
| Tariff Savings | — | 0.00 | $0 |
This battery's grid value is dominated by ancillary services and energy arbitrage. Tariff savings is zero because wholesale-bid batteries have no retail tariff exposure. The stacked view shows where the value comes from — buyers weight streams by what they care about.
What does “capacity” mean for different DER types? How should we handle resources that can’t sustain output for extended periods?
Or should grid scores use a unit closer to energy (e.g. $/MWh, $/kWh)? What are the trade-offs for different market participants?
Are there value streams missing? Are any of these redundant or better combined? Does this decomposition match how you think about DER value?
Hourly savings are the foundation. Carbon Scores measure emissions impact. Grid Scores measure the $/kW-year value a DER delivers across six value streams — making grid contributions meaningful, comparable, and actionable for different buyers.
Formula reference, data sources, and the NREL ELCC research.