Research brief · Applied Energy
Every U.S. wastewater plant with a digester makes methane. Feed it hydrogen and it makes pipeline gas. We modelled all 2,952 of them to find where that pays.
Jiang J., Du L., Li X., Chen C., Ren Z.J. Spatially resolved national assessment of renewable natural gas potential from water resource recovery facilities through biomethanation. Applied Energy 417 (2026) 128025. Read the paper →
A national database of every wastewater facility running anaerobic digestion — assembled from CWNS, WEF, DOE CHP and Argonne National Laboratory records — put through a facility-by-facility optimisation.
Biomethanation converts digester CO2 into methane using hydrogen. That hydrogen has an alternative buyer, the upgraded gas has to reach a pipeline, and both facts vary by location — so the decision is different at every plant.
A mixed-integer program was written for each facility, carrying its own energy prices, its own distance to gas infrastructure, its treatment capacity and the incentives available in its state. Each was solved to the pathway with the best annualised cash flow against business-as-usual, with capital cost piecewise-linearised and an industry-guided 70% producer share assumed on RIN revenue.
CWNS, WEF, DOE CHP and Argonne records reconciled into 2,952 facilities.
Pipeline distances, state energy prices and LCFS eligibility attached to each site.
Mixed-integer program per facility, solved globally in Gurobi.
1,000 Monte Carlo iterations across seven uncertain parameters.
Each facility is assigned the pathway that maximises its annualised cash flow relative to doing nothing. Under base capital cost, the CHP upgrade never wins anywhere.
| Pathway | What happens | Plants |
|---|---|---|
| Stay as-is | Business as usual. No biomethanation; biogas burns in the existing combined heat and power unit, and any electrolysis runs independently. |
1,583 |
| Upgrade the CHP | Biomethanation built, upgraded gas fed back into the CHP for more heat and power. Only viable under low capital cost — 119 plants, 91% of them in California — and never chosen at base or high cost. |
0 |
| Build a pipeline | Renewable gas injected into the grid through newly built pipe to the nearest gas infrastructure. |
432 |
| Truck it instead | Gas compressed and hauled by CNG trailer to an injection point — the answer for remote and mid-size plants. |
937 |
All 2,952 facilities under base capital cost. Filter to see where each pathway wins.
Showing 2,952 facilities. Circle size follows treatment capacity.
Drag to pan, scroll or use +/− to zoom. Boundaries: U.S. Census / Natural Earth (public domain).
01
1,369 of 2,952 facilities are viable at base capital cost, carrying 5,781 MW of renewable gas capacity. The cutoff sits at 2–3 MGD; above 10 MGD, almost every plant clears it.
02
Renewable identification numbers bring $4.69B a year across viable facilities — the largest single cash flow in the model, and the strongest positive driver of viability at PRCC +0.91.
03
Diverting hydrogen away from direct sale costs $1.31B a year. At PRCC −0.96, the hydrogen price is the most influential parameter in the whole analysis.
04
937 facilities — 68% of the viable set — choose CNG trucking over building pipe. New pipeline only pays when the plant is large enough or the run short enough.
05
Low carbon fuel standards in California, Oregon and Washington add $145M a year. Real money, but not enough on its own — federal incentives stay essential.
06
Across 1,000 stochastic runs, viability lands between 21.5% and 59.6%, median 44.2%, with a 90% interval of 34.5–52.2%. The conclusion is structural, not a knife-edge.
Partial rank correlation coefficients from 1,000 Monte Carlo runs. Bars right raise the share of viable plants; bars left lower it.
Each facility's annual economics balance renewable gas sales, RIN credits and LCFS credits against capital cost, pipeline construction, forgone CHP output, and the hydrogen it no longer sells.
The two parameters that matter sit at opposite ends of the chart, and both are prices set outside the plant gate. That is the finding underneath the finding: this is not an engineering problem waiting on a better reactor, it is a market problem waiting on a stable signal.
Facilities by pathway for the top 30 states under base capital cost.
A thousand runs, each drawing new values for hydrogen price, RIN price, natural gas price, electricity price, discount rate, trucking cost and pipeline capital cost.
Share of facilities viable in each run. Median 44.2%, 90% interval 34.5–52.2%.
One dot per run. Colour carries the RIN price coefficient — blue high, rust low.
Federal and state incentives reshape this landscape more than any technical parameter. The analysis assumes producers keep 70% of RIN revenue.
PRCC +0.91
$145M per year
PRCC −0.96
Biomethanation at wastewater plants is a scalable, infrastructure-compatible route to renewable natural gas, and the economics are not subtle: RIN credits decide whether projects happen, and hydrogen opportunity cost decides where they stop. Across 1,000 simulations viability holds at a median of 44.2%, with a 90% interval of 34.5–52.2%. What municipal investors need is not a better process — it is a RIN market that stays put long enough to finance against, or capital grants that do the same job.