Carbon capture and storage can become California LCFS's last credit source
The benchmark passes below ethanol in 2033, renewable diesel in 2037 and biodiesel in 2038. Lowering a fuel's own carbon intensity is the one response that still works.
Summary
- California pays a fuel for the distance between the annual benchmark and that fuel's certified carbon intensity. The benchmark falls each year while a certified pathway holds its number, so the payment per gallon shrinks on a published schedule.
- On CARB's post-2025 schedule the diesel benchmark falls from 81.70 gCO2e/MJ in 2025 to 26.44 by 2040. Ethanol stops earning in 2033, renewable diesel and alternative jet fuel in 2037, biodiesel in 2038.
- An energy-economy ratio of 3.4 gives electricity the widest headroom in the programme. A grid at 40.0 gCO2e/MJ still needs a gasoline benchmark above 11.8, and the 2045 benchmark is 9.91.
- All 18 approved projects under innovative crude oil are solar electricity or solar steam at Kern County heavy-oil fields, worth 0.023 M MT against a 34.19 M MT market. Section 95489(c)(5) ends crediting for every non-CCS project on 31 December 2040.
- Section 95490 of the California LCFS credits project CCS and direct air capture, uncapped for DAC and exempt from the California-volume proration. It has had no applications. Capture that does reach the LCFS today arrives as a lower Tier 2 pathway carbon intensity.
How the LCFS pays a fuel
A fuel earns credits equal to the benchmark multiplied by its energy-economy ratio, less the fuel's own certified carbon intensity, multiplied by the energy delivered. The energy-economy ratio rewards drivetrains that convert energy into distance more efficiently, which is how electricity at a ratio of 3.4 clears a benchmark that a litre of diesel cannot.
The July 2025 amendments cut the 2025 benchmark by 22.75 per cent against the 13.75 per cent then in force, and the schedule keeps tightening after that. The diesel benchmark runs 81.70 gCO2e/MJ in 2025, 50.23 in 2035 and 10.57 by 2045. A renewable diesel pathway certified at 43.7 gCO2e/MJ therefore earns 38.0 gCO2e/MJ of yield in 2025 and 6.5 in 2035, an 83 per cent compression across a decade in which the fuel itself is unchanged.
Selling more of a fuel cannot repair this. Once a pathway's carbon intensity sits above the benchmark, every additional gallon generates deficits. Past the crossover, growth in that fuel makes the market shorter.
When each fuel crosses
Holding every pathway at the carbon intensity and energy-economy ratio it carries today, and running CARB's benchmark schedule forward, gives the year each one stops paying and begins owing.
| Fuel | Carbon intensity (gCO2e/MJ) | EER | Deficit from |
|---|---|---|---|
| Ethanol | 58.4 | 1.00 | 2033 |
| Renewable diesel | 43.7 | 1.00 | 2037 |
| Alternative jet fuel | 44.1 | 1.00 | 2037 |
| Biodiesel | 38.5 | 1.00 | 2038 |
| Electricity, light-duty | 40.0 | 3.40 | 2045 |
| Hydrogen | 21.2 | 2.45 | beyond 2045 |
| Biomethane | −186.6 | 0.90 | beyond 2045 |
Grid electricity deserves attention. It holds the widest headroom in the programme and still runs out. The fuel that carries California's credit supply through the 2030s reaches the same wall roughly a decade after the liquids do, and it reaches it while EV adoption is still rising.
What section 95489 credits
Section 95489 credits innovative methods of lowering the carbon intensity of crude production, and it is widely read as a carbon-capture provision. All 18 approved projects are solar electricity or solar steam installations at Kern County heavy-oil fields. CARB's own reconciliation puts the stream at 0.023 M MT against a 34.19 M MT market, or 0.07 per cent of credits.
Section 95489(c)(5) ends the crediting period for every non-CCS project on 31 December 2040.
The two doors capture can use
Section 95490, standalone and unused
Section 95490 credits project-based carbon capture and direct air capture as activities in their own right. Direct air capture is uncapped, and by the express words of section 95490(b)(3) it is exempt from the proration that binds every other project type. An ethanol or hydrogen plant capturing CO2 in Iowa earns credit only on the share of its fuel that reaches California; a direct air capture facility does not face that test.
Of 365 carbon capture and carbon removal projects across the United States, 17 have a pipeline into the LCFS. Project capture and direct air capture have had no applications at all.
The Tier 2 pathway, which is the door in use
Capture that reaches the programme today arrives inside a fuel pathway. Capturing the CO2 from a hydrogen reformer or an ethanol fermenter lowers that facility's certified carbon intensity, and every gallon it ships afterwards earns a wider gap for the life of the pathway. The instrument is unchanged. The same credit simply arrives at a higher rate per unit of fuel.
Section 95482(h) already compels this for hydrogen. From 2030 a hydrogen pathway must be at least 80 per cent renewable or capture-backed, and from 2035 fossil-gas hydrogen is ineligible unless fully biomethane-matched or fully captured. The 21.2 gCO2e/MJ that keeps hydrogen earning past 2045 in the table above is already, in large part, a capture number.
Weighing a capture project against an LCFS pathway? We model both routes.
Book a briefing →Why capture is the remaining lever
Three responses are available once a fuel crosses the benchmark. Two of them fail.
Selling more of the fuel deepens the deficit. Switching to a cleaner fuel buys time until that fuel crosses as well. What survives is lowering the carbon intensity of the fuel being sold. At a mature facility, the feedstock and the process are largely fixed, so capturing and storing the process CO2 is the one change that moves the certified number without rebuilding the plant.
The same logic reaches the grid. Keeping electricity on the credit side past 2045 requires a California grid below 11.8 gCO2e/MJ measured against the gasoline benchmark. For the gas-fired share of that grid, capture is the only route that leaves the plant running.
A programme in which every fuel generates deficits has no credit supply and no clearing price below its own cap. CARB holds three instruments that prevent it. It can amend the benchmark schedule, certify lower-carbon-intensity pathways, or open a credit source whose value does not depend on the benchmark at all. Section 95490 is written for the third, and direct air capture is the only category in the regulation carrying neither a volume cap nor a California proration.
What to watch
- Applications under section 95490. The count stands at zero. A first application, and the carbon-intensity methodology CARB approves alongside it, sets the precedent for every project behind it.
- Certified carbon intensities at ethanol and hydrogen plants. A step down in a certified Tier 2 number moves the crossover year for that entire pathway, and it moves it for every gallon already flowing.
- The 2040 sunset in section 95489(c)(5). Whether CARB extends the innovative crude window, and whether capture projects become eligible under it, is the clearest available signal of how the agency intends to keep credit supply on the board.
Model the crossover before it reaches your pathway
Climate Decode runs the California benchmark schedule against certified pathway carbon intensities, so producers and credit buyers can date the year a fuel stops paying and test what capture does to it.
Method and sources
Regulation: California Code of Regulations title 17, sections 95482, 95485, 95489 and 95490. Market data: CARB quarterly LCFS data summary. Crossover years are modelled in the Climate Decode California LCFS model, hold each pathway at its currently certified carbon intensity and energy-economy ratio, and move if CARB certifies a lower carbon intensity or amends the benchmark schedule. Provided for information and not as investment, legal or compliance advice. © 2026 Climate Decode.