Green Hydrocarbons vs Green Hydrogen: Portfolio Roles in OBBBA World

Posed as a contest, green hydrocarbons versus green hydrogen is the wrong question. They are not substitutes competing for the same dollar; they are different points in the same value chain, with very different policy support, demand certainty and time-to-cash. After OBBBA, and after a year in which crude has whipsawed from $55 to $120, the allocation question has a clearer answer than the slogans suggest, and it turns almost entirely on one thing: the incentive stack.

They Are Not Competitors

Green hydrocarbons, drop-in renewable diesel, sustainable aviation fuel, and synthetic e-fuels, are molecules that slot into existing engines, pipelines and refineries and sell into markets that already exist. Green hydrogen is, for most of its near-term uses, an input: it goes into refining, ammonia, and, crucially, into the synthesis of those same e-fuels. The instinct to pit them against each other obscures the real relationship. Hydrogen sits upstream of the hydrocarbon. The investment question is not which one wins; it is where in that chain the policy and the demand actually pay, and the answer has moved decisively toward the molecule that can be sold.

The Incentive Stack: Three Credits Versus One

This is the heart of it, and it is the part most strategy decks skip. A green-hydrocarbon producer does not earn one subsidy; it earns a stack of independent, overlapping credits.

Pathway	45Z	RIN (RFS)	LCFS	Total stack	Earliest expiry
Renewable diesel ($/gal)	$1.00	~$1.50	~$0.55	~$3.05	45Z 2029; RIN/LCFS ongoing
SAF ($/gal)	$1.00	~$1.60	~$0.55	~$3.15	45Z 2029; RIN/LCFS ongoing
Merchant green H2 ($/kg)	–	–	–	$3.00 (45V only)	45V cliff Jan 2028

A gallon of renewable diesel or SAF stacks the federal 45Z clean-fuel credit, federal RFS RINs (a gallon of SAF generates about 1.6 of them, currently worth roughly a dollar each), and a state LCFS credit on top. The combined stack lands near $3 a gallon, which is often at or above the wholesale value of the fuel itself. Read that twice: for green hydrocarbons, the credits can be worth more than the product. These are, in plain terms, policy-arbitrage machines with a fuel by-product, and they have three independent legs to stand on.

Merchant green hydrogen has one. The 45V Clean Hydrogen Production Credit, up to $3 a kilogram, is its entire support, and there is no RIN, no LCFS, and no blending mandate pulling merchant hydrogen into a market at a premium. One credit, no demand-pull, against a stack of three credits plus mandated and oil-linked demand. That asymmetry is the whole portfolio argument.

The Policy Runway Under OBBBA

OBBBA did not just change the levels; it changed the runways, and it did so unevenly.

The 45V hydrogen credit now requires projects to begin construction before 1 January 2028, an accelerated cliff that gives merchant hydrogen the shortest runway of any clean-fuel incentive. The 45Z clean-fuel credit runs through 2029, and the RFS and California’s LCFS are ongoing programmes, the former soft on price lately, the latter tightening. The 45Q credit for carbon capture, which underpins blue hydrogen, was treated most generously of all. So the policy gradient runs against merchant green hydrogen and toward the liquids and toward carbon capture. An allocator who ignores the runway is mispricing duration risk.

The Quiet Demotion of SAF

One nuance inside the stack matters for anyone overweight aviation. In 2026 the 45Z credit for SAF was cut to $1.00 a gallon from $1.75, and its feedstocks were restricted to North America. The headline that circulated in the trade press, that 45Z “takes off, but not to expand SAF,” is accurate: federal credit support now tilts toward road renewable diesel over aviation fuel, even as Europe’s ReFuelEU mandate pulls the other way. The practical read is that SAF’s US economics lean more heavily on the RIN and LCFS legs and on the European premium than on 45Z, and that the relative attractiveness of renewable diesel has quietly improved. The stack is deep, but its composition is shifting, and it pays to know which leg is carrying the weight.

The Green Hydrogen Graveyard: What the Cancellations Teach

The theory above is not theory any more. 2025 was the year the merchant-hydrogen thesis was tested in the market, and it largely failed. Companies cancelled roughly 60 major clean-hydrogen projects in the year, about 4.9 million tonnes a year of would-be capacity, and more than 100 have been cancelled, paused or scaled back since mid-2024. Only somewhere around 6 to 9 percent of announced capacity has reached a final investment decision. The gap between what was announced and what got financed is the whole story.

The names matter, because each one teaches a specific lesson an operator should price in:

What happened (2025-26)	The lesson for underwriting
Fortescue abandoned its Arizona and Gladstone PEM50 projects in July 2025, after breaking ground, citing the US policy shift.	A final investment decision is not irreversible. Policy risk persists past sanction; do not treat FID as the end of duration risk.
Air Products took a write-down of up to $3.1bn and exited three US projects, including Massena, New York, whose hydropower lost 45V eligibility.	One credit is not a stack. A project whose economics hang on a single eligibility ruling is one ruling away from a write-down.
BP cancelled the 1.5GW Duqm project in Oman in December 2025 and earlier walked from the $36bn Australian Renewable Energy Hub.	Scale does not substitute for offtake. Mega-projects without a buyer are the first to be cut when capital tightens.
Nikola filed for Chapter 11 in February 2025; its workforce fell from 874 to one before the assets were auctioned.	A hydrogen demand story with no profitable end market is a cash-burn story. Underwrite the offtake, not the vision.

Strip these to their causes and the same five failure modes recur: no bankable offtake, because buyers will not sign the ten to twenty year, billion-dollar commitments producers need; a viability gap, where production cost runs far above what end-users will pay and, unlike renewable diesel or SAF, no mandate exists to close it; electrolyzer costs that never fell as promised, because each plant is bespoke and the learning curve has not arrived; chicken-and-egg infrastructure, with hydrogen and CO2 pipelines shelved for want of committed volume; and fatal single-credit dependence, where one policy change ends the project. Every one of these maps to a column in the scorecard above, and every one is a risk the green-hydrocarbon producer has already retired by selling a drop-in fuel into a mandated, oil-linked market with a three-credit stack.

The inverse is the useful part. The green-hydrogen projects still moving share a profile: they are offtake-backed, embedded in an e-fuel that inherits the liquids stack, or captive to a single creditworthy industrial buyer. It is the merchant pure-play, the molecule with no contracted home, that fills the graveyard. That is not an argument against hydrogen. It is an argument about where in the chain you take the risk.

Where Hydrogen Actually Pays: Embedded, Not Merchant

None of this makes green hydrogen uninvestable. It relocates where the value is captured. Because merchant hydrogen has no demand-pull and a 2028 cliff, its strongest near-term investment case is as a captive input to a green hydrocarbon. Feed green hydrogen and captured CO2 into an e-fuel, an e-SAF or e-diesel, and the hydrogen’s value is monetised through the finished fuel’s incentive stack, the very RIN, LCFS and 45Z legs that merchant hydrogen cannot touch, plus the oil-linked price of the liquid. The hydrogen stops being a molecule searching for a buyer and becomes a margin input to a molecule that already has one. That is the synthesis the “versus” framing misses: in an OBBBA world, you do not choose hydrogen or hydrocarbons; you capture hydrogen value inside hydrocarbons.

The Portfolio Scorecard

Scored across the dimensions that actually decide an allocation, the near-term gap is stark.

Dimension	Green hydrocarbons	Merchant green H2
Existing infrastructure / drop-in	5	2
Demand certainty (mandates)	5	2
Incentive-stack depth	5	2
Policy durability under OBBBA	4	2
Oil-price tailwind (2026)	5	2
Time to cash	5	2
Long-duration scale optionality	3	5
Total (of 35)	32	17

Hydrocarbons win every near-term dimension. Hydrogen wins only one, long-duration scale optionality, because in the 2040s, when the easy liquid feedstocks are exhausted and deep decarbonisation needs molecules made from CO2 and water, hydrogen is the backbone. But that is a 2040s thesis being asked to clear a 2026 hurdle rate, and even then the value is best captured embedded in an e-fuel rather than sold merchant.

How We’d Allocate

Weight the near-term book to green hydrocarbons: drop-in renewable diesel and, selectively, SAF, where the three-credit stack and the oil-linked price are doing the work and the cash is real today. Treat the credit stack itself as the asset and the fuel as the by-product, and underwrite the durability of each leg, especially the 2029 45Z runway and the soft RIN. Hold green hydrogen as a long-duration option, and capture it where it actually pays, embedded in e-fuels with a route to the hydrocarbon stack, or as the input to a hard-to-abate industrial offtake with a real contract. Avoid the merchant-hydrogen pure-play whose entire case is a single credit that cliffs in 2028. In a policy-defined market, the portfolio role of each asset is written in its incentive stack and its runway, not in its press releases.

What Clears an Investment Committee

1. Map the full incentive stack and its expiry. Which credits (45Z, RIN, LCFS, 45V, 45Q), what value, what runway. The stack, not the technology, sets the margin.

2. Stress each credit leg independently. Soft RINs, a 45Z lapse after 2029, an LCFS amendment. If the project only clears with all legs intact, it is fragile.

3. For hydrogen, find the demand-pull. A merchant molecule with no mandate and a 2028 cliff is an orphan. Is it embedded in an e-fuel or contracted to a creditworthy industrial offtake?

4. Price the oil linkage. Hydrocarbons gain when crude is high and lose when it normalises; size accordingly after a spike.

5. Run the project against the five failure modes. No bankable offtake, an unfunded viability gap, an assumed electrolyzer cost curve, unfinanced shared infrastructure, single-credit dependence. If it trips two, it belongs in the graveyard, not the book.

6. Separate the 2026 cash from the 2040s option. Do not pay a growth multiple for a near-term cash asset, or underwrite a long-duration option at today’s hurdle.

Hydrocarbons vs Hydrogen: Investor FAQ

Are green hydrocarbons or green hydrogen the better investment under OBBBA?

For near-term cash, green hydrocarbons, by a wide margin. They stack three independent credits (45Z, RIN, LCFS) worth around $3 a gallon, use existing infrastructure, have mandated demand, and benefit from high oil prices. Merchant green hydrogen has a single credit (45V) that cliffs in 2028 and no demand-pull. Hydrogen is a long-duration option best captured embedded in e-fuels.

What is the incentive stack for renewable diesel and SAF?

The federal 45Z clean-fuel credit (about $1/gal in 2026), RFS RINs (a gallon of SAF earns ~1.6 RINs at roughly $1 each), and a state LCFS credit (~$0.50/gal). Combined, roughly $3 a gallon, often at or above the fuel’s wholesale value.

How did OBBBA change the 45V hydrogen credit?

It accelerated the begin-construction deadline to 1 January 2028, giving green hydrogen the shortest runway of any clean-fuel incentive, while the 45Z clean-fuel credit runs to 2029 and the RFS and LCFS continue. The policy gradient now favours liquids and carbon capture over merchant green hydrogen.

Did 45Z reduce support for SAF?

Yes. In 2026 the 45Z SAF rate was cut to $1.00 a gallon from $1.75 and feedstocks were restricted to North America, so US federal credit support tilts toward road renewable diesel over aviation fuel. SAF’s US case now leans more on RINs, LCFS and the European ReFuelEU premium.

Where does green hydrogen actually make money today?

Embedded, not merchant. Fed into an e-fuel (e-SAF or e-diesel) with captured CO2, hydrogen is monetised through the finished fuel’s RIN, LCFS and 45Z stack and its oil-linked price, the demand-pull and credits a merchant molecule cannot access. Its other near-term home is a contracted hard-to-abate industrial offtake.

Why are green hydrogen projects being cancelled in 2025 and 2026?

Roughly 60 major clean-hydrogen projects were cancelled in 2025 (about 4.9 Mtpa), and only ~6-9% of announced capacity has reached a final investment decision. The recurring causes are no bankable offtake, a viability gap with no mandate to close it, electrolyzer costs that have not fallen, missing shared infrastructure, and dependence on a single credit. Named cases include Fortescue (Arizona and Gladstone, post-FID), Air Products (a write-down of up to $3.1bn), BP (Duqm, Oman) and Nikola (Chapter 11). The survivors are offtake-backed, embedded in e-fuels, or captive to a creditworthy industrial buyer.

Methodology: incentive values are 2026 reference points (D4 RIN ~$1.00-1.08; LCFS ~$65-75/t; 45Z ~$1.00/gal; 45V up to $3/kg) and move with markets and guidance. Portfolio scores are Trident’s framework. Sources: EIA (RINs); CARB / Stillwater (LCFS); Fastmarkets / CoBank / Crux (45Z); OBBBA analyses. Analysis, not investment advice.