RNG vs Green Hydrogen: Carbon Intensity, Cost Curves & Best Uses

By Green Gas Turbines Team · Published November 29, 2025 · 18 min read

RNG vs Green Hydrogen: Same “Clean Molecules” Story, Very Different Numbers

Renewable Natural Gas (RNG) and green hydrogen are increasingly positioned as drop-in solutions for decarbonizing gas turbines, pipelines, and heavy transport. Both are marketed as “low-carbon fuels” that can reuse existing gas infrastructure. But when you look at lifecycle carbon intensity (CI) and cost curves, the two pathways behave very differently.

This comparison guide breaks down where RNG and green hydrogen really sit today on carbon intensity, cost per unit of energy, scalability, and their practical role in gas turbine decarbonization and grid planning.

Definitions and System Boundaries

What we mean by Renewable Natural Gas (RNG)

RNG (also called biomethane) is methane upgraded from biogas produced by anaerobic digestion or thermal conversion of organic material. Common feedstocks include:

Landfill gas
Dairy and livestock manure
Wastewater treatment plant (WWTP) sludge
Food and organic waste
Agricultural residues and woody biomass (gasification + methanation)

After CO₂ and impurities are removed, RNG can meet pipeline-quality specs and behave almost identically to fossil natural gas in a gas turbine or boiler.

What we mean by Green Hydrogen

Green hydrogen is hydrogen produced via water electrolysis powered by renewable electricity (wind, solar, hydro, etc.), with no fossil feedstock and strict limits on associated emissions. Depending on jurisdiction, “green” or “renewable” hydrogen must meet a maximum lifecycle emissions intensity (e.g., below a specified gCO₂e/MJ threshold).

Hydrogen is then used as a fuel in:

Hydrogen-ready gas turbines and reciprocating engines
Fuel cells (PEM, SOFC, etc.)
Industrial processes (steel, refining, ammonia)
Transport (trucks, ships, trains) via direct H₂ or derivatives (ammonia, e-fuels)

How we compare carbon intensity

To compare apples-to-apples, we look at lifecycle carbon intensity in grams of CO₂-equivalent per megajoule of energy delivered (gCO₂e/MJ), using typical ranges from recent LCA and policy studies. Values vary by feedstock, process configuration, and system boundaries, so treat the ranges below as indicative, not exact.

Carbon Intensity: RNG vs Green Hydrogen

Baseline: fossil natural gas

Fossil natural gas used in power and heat typically has a lifecycle CI around 60–70 gCO₂e/MJ when upstream methane leakage is included, based on recent LCA reviews of gas and oil products. This is our reference point for comparing “low-carbon” alternatives.

RNG carbon intensity by feedstock

RNG’s carbon intensity depends heavily on the feedstock and the accounting of avoided methane emissions:

Landfill gas RNG: Often in the range of ~40–80 gCO₂e/MJ in LCFS-type frameworks, reflecting both emissions from gas collection systems and credits for avoided landfill methane.
Wastewater treatment plant (WWTP) RNG: Several studies and LCFS pathway data put WWTP RNG around 30–40 gCO₂e/MJ, roughly half the intensity of fossil natural gas but clearly not carbon-neutral.
Food waste and municipal solid waste RNG: Typically in the 10–40 gCO₂e/MJ range depending on system boundaries and energy use for upgrading.
Dairy manure RNG: Early California LCFS pathways reported very negative CI scores (-100 to -400 gCO₂e/MJ) when full methane avoidance credit was given. More recent work that assumes methane would eventually be controlled anyway suggests that effective CI may be closer to ~30–40 gCO₂e/MJ, similar to other RNG sources.
Woody biomass / gasified residues RNG: Well-designed systems can reach single-digit gCO₂e/MJ values or low tens, particularly when using waste biomass and low-carbon electricity for upgrading.

The key takeaway: most RNG pathways are substantially lower in CI than fossil natural gas, and some feedstocks (especially manure under generous crediting) can appear carbon-negative. But those “carbon-negative” scores are highly sensitive to policy assumptions about methane that would be controlled anyway.

Green hydrogen carbon intensity

For green hydrogen, lifecycle CI is dominated by the emissions of the electricity that feeds the electrolyser:

Green hydrogen definitions under some policy schemes require a 60–70% reduction vs SMR, leading to thresholds around 28–36 gCO₂e/MJ of H₂.
Detailed LCAs show wind-based green hydrogen as low as ~0.6 kg CO₂e/kg H₂ (roughly 5 gCO₂e/MJ), with solar-based electrolytic hydrogen often in the 1.5–2.5 kg CO₂e/kg range (roughly 12–21 gCO₂e/MJ), depending on the supply chain and electrolyser manufacturing assumptions.
Electrolysis using average or carbon-intensive grid electricity can easily exceed 100 gCO₂e/MJ, making such hydrogen no better or even worse than fossil-based H₂ unless the grid is already largely decarbonized.

In other words, strictly defined green hydrogen produced from dedicated renewables can have CI comparable to, or lower than, the best RNG pathways. But “electrolysis” is not automatically low-carbon; grid mix and policy rules (hourly matching, additionality) matter.

Side-by-side CI comparison (illustrative ranges)

Fuel / Pathway	Typical Lifecycle CI (gCO₂e/MJ)	Comments
Fossil natural gas	~60–70	Baseline including upstream methane leakage.
RNG – WWTP / landfill	~30–60	Lower than fossil gas but not zero; depends on capture efficiency and energy use for upgrading.
RNG – food & organic waste	~10–40	Good performance when displacing uncontrolled methane sources.
RNG – dairy manure (legacy LCFS)	-100 to -400 (policy-dependent)	Highly negative scores rely on giving full credit for avoided methane that may be regulated anyway.
RNG – dairy manure (revised view)	~30–40	More conservative estimates once additional methane control policies are considered.
Green H₂ – wind electrolysis	~5–10	Very low CI when powered by near-zero-carbon wind resources.
Green H₂ – solar electrolysis	~12–25	Still well below fossil gas; depends strongly on PV manufacturing footprint and capacity factor.
Electrolysis – average grid mix	~30–100+	Can underperform fossil pathways if grid electricity is carbon-intensive.

Cost Curves: $/MMBtu and $/tCO₂ Abated

RNG costs today

RNG is inherently feedstock- and site-dependent, but several large-scale studies give a consistent picture:

Upgrading biogas to RNG typically costs around USD 7–23/MMBtu for many projects, with some woody-biomass gasification pathways in the USD 13–15/MMBtu range.
Case studies for California projects show a very wide range, from as low as USD ~5.5/MMBtu (large landfill projects) up to USD ~90/MMBtu for small, capital-intensive dairy projects.
Recent US gas foundation work suggests that roughly three-quarters of RNG production potential could be available at < USD 20/MMBtu, with implied abatement costs of USD 70–400/tCO₂e depending on the pathway.
For comparison, US Henry Hub fossil gas has often traded in the low single digits (e.g. around USD 2–3/MMBtu in recent years). RNG is therefore typically an order of magnitude more expensive than commodity gas on an energy basis, and its viability depends heavily on LCFS-style credits, RINs, or tax incentives.

Green hydrogen costs today

Global benchmarks for green hydrogen levelized cost of hydrogen (LCOH) are still high but falling:

Recent IRENA and IEA assessments place current green hydrogen costs in many markets around USD 4.5–6/kg, with particularly high-RES locations and subsidies pushing toward USD ~2–3/kg.
High-profile projects in markets like Australia and Germany report real-world early-stage costs closer to USD 8–11/kg or EUR ~6/kg, emphasizing that on-the-ground costs can significantly exceed techno-economic projections.
The 2022 US Inflation Reduction Act (IRA) offers up to USD 3/kg production tax credit for low-carbon hydrogen, which can bring effective costs for well-sited projects down below USD 2/kg.

On an energy-equivalent basis, 1 MMBtu is roughly 8.8 kg of hydrogen (LHV). That means:

At USD 4.5–6/kg, green hydrogen equates to roughly USD 40–53/MMBtu.
At USD 2/kg (aggressive but achievable with strong incentives and cheap renewables), it is about USD 18/MMBtu.

So in many current markets, green hydrogen is more expensive per unit of energy than most RNG pathways. The difference is that hydrogen costs are expected to fall substantially with scale and learning, while RNG costs are constrained by physical feedstock and project economics.

2030–2050 cost outlooks (directionally)

RNG: Studies suggest a fairly flat cost curve with modest reductions from technology learning, but the cheapest feedstock opportunities are exploited first. Large-scale RNG is likely to remain a relatively high-cost, limited-volume fuel, with average project costs often in the USD 13–20/MMBtu range in mature markets.
Green H₂: Multiple global analyses indicate a potential path toward USD ~1–2/kg green hydrogen in high-quality renewable resource regions by 2035–2050, assuming aggressive deployment of renewables and electrolysers. That corresponds to roughly USD 9–18/MMBtu, competitive with or even below many RNG pathways on an energy basis.

Scalability and Volume Potential

RNG: limited by waste streams

RNG production is fundamentally limited by the availability of biogenic methane sources—landfills, manure, wastewater, organic waste, and residues. Even optimistic assessments of technical RNG potential in regions like North America or Europe generally conclude that RNG can cover only a fraction (single-digit to low double-digit percent) of current natural gas demand.

This has two implications:

RNG is best reserved for high-value, hard-to-electrify segments or where methane avoidance delivers outsized climate benefits.
RNG should not be viewed as a one-for-one replacement for fossil gas at system scale; rather, it is a premium decarbonization tool to be deployed selectively.

Green hydrogen: limited by renewables and electrolysers

Green hydrogen’s theoretical resource base is much larger, because it is constrained by renewable electricity and electrolyser capacity rather than organic waste streams. Large-scale modelling suggests that:

Electrolyser manufacturing and renewable build-out, not physical feedstock, are the main bottlenecks.
In 1.5–2°C pathways, green hydrogen scales to tens of millions of tonnes per year globally by 2050, serving industry, transport, and power sectors.
The same hydrogen infrastructure (pipelines, storage, terminals) can be used to service multiple sectors, spreading costs over a larger demand base.

In short, RNG is constrained by biology; green hydrogen is constrained by engineering and capital. Over multi-decade planning horizons, that makes hydrogen the more scalable option for very large volumes of low-carbon molecules.

Implications for Gas Turbines and Power Markets

RNG in gas turbines

From a combustion standpoint, RNG is almost a drop-in replacement for fossil natural gas:

Flame speed, Wobbe index, and volumetric heating value are similar, though minor adjustments to fuel control and tuning may be needed for specific RNG blends.
No major redesign of burners or combustors is required; emissions behavior is broadly similar to conventional gas.
For peaker plants in agricultural or landfill-rich areas, RNG offtake agreements can deliver near-term CO₂e reductions with minimal hardware change.

The limitations are commercial rather than technical: price and volume. Long-term, it is unrealistic to run entire gas turbine fleets on RNG alone at scale.

Green hydrogen in gas turbines

Hydrogen-ready gas turbines require more engineering but offer deeper decarbonization and greater scalability:

Hydrogen has a much higher flame speed and broader flammability limits than methane, requiring advanced dry low-NO_x hydrogen combustors to avoid flashback and manage NO_x.
Modern OEM roadmaps show turbines capable of burning high H₂ blends moving toward 100% H₂, unlocking near-zero CO₂ operation when paired with green hydrogen.
Hydrogen can be stored at massive scale in underground caverns and repurposed gas infrastructure, turning gas turbines into part of a long-duration storage system (power-to-gas-to-power).

In net-zero planning, hydrogen-ready turbines are increasingly seen as firm capacity and long-duration storage enablers, whereas RNG is a niche decarbonization fuel for specific projects.

Strategic Comparison: Where RNG and Green Hydrogen Each Make Sense

Where RNG tends to win

Near-term pipeline decarbonization: Injecting RNG into existing gas networks to reduce average CI without immediate hydrogen conversion costs.
Waste-methane hotspots: Projects at landfills, dairies, or WWTPs where capturing methane provides major local climate and air-quality benefits.
Drop-in peaker decarbonization: Existing gas peakers in proximity to RNG supply can cut emissions quickly with minimal turbine modifications.
Heavy transport where CNG/LNG infrastructure exists: RNG as a drop-in for CNG/LNG trucking or fleet applications under strong LCFS/RIN regimes.

Where green hydrogen tends to win

Long-term, large-scale system decarbonization: Hydrogen can scale to industrial volumes across steel, chemicals, refining, and power.
Hard-to-electrify industrial processes: Direct reduction of iron, high-temperature heat, refineries, and ammonia production.
Peakers and mid-merit plants in 60–90% renewables grids: Hydrogen gas turbines plus storage provide firm capacity and multi-day energy backup.
Global trade in energy carriers: Hydrogen and derivatives (ammonia, e-methanol) enable cross-border trade, unlike locally constrained RNG.

Side-by-Side Summary Table

Attribute	RNG (Biomethane)	Green Hydrogen
Typical lifecycle CI	~10–60 gCO₂e/MJ (feedstock-dependent; some policy-driven negative CI cases).	~5–25 gCO₂e/MJ with dedicated renewables; much higher if using fossil-heavy grid electricity.
Cost today (energy basis)	Roughly USD 7–23/MMBtu for many projects; can be lower/higher in specific cases.	Roughly USD 40–53/MMBtu at USD 4.5–6/kg; potentially ~USD 18/MMBtu at USD 2/kg with strong policy support.
2050 cost potential	Moderate cost reduction; still a premium fuel limited by feedstock.	Aggressive scenarios: USD ~1–2/kg (USD 9–18/MMBtu) in best locations.
Scalability	Constrained by biological waste streams; single-digit–low double-digit percent of gas demand.	Constrained by renewables and electrolysers; can, in principle, scale to global multi-sector demand.
Compatibility with existing turbines	Near drop-in; minor tuning and gas-quality management.	Requires hydrogen-ready combustors, safety upgrades, and sometimes new turbines.
Best use cases	High-value, near-term decarbonization of waste methane; selective turbine and transport fuel use.	System-level decarbonization across industry, transport, and power; long-duration storage with H₂ GTs.

Frequently Asked Questions

Is RNG really carbon-negative?

Some RNG pathways, especially dairy manure projects in certain LCFS frameworks, have been assigned strongly negative CI scores when they receive full credit for avoided methane emissions. However, those scores depend on assumptions that, in the absence of the project, methane would continue to vent uncontrolled. As methane regulations tighten, the “additional” climate benefit shrinks, and effective CI values for dairy RNG converge toward positive but low gCO₂e/MJ values. It’s safer to treat RNG as low-carbon, not a permanent carbon sink.

Which is cheaper to run a gas turbine on: RNG or green hydrogen?

Today, for most markets, RNG is cheaper than green hydrogen per MMBtu of fuel, but both are much more expensive than fossil gas. Typical RNG project costs cluster in the low tens of dollars per MMBtu, whereas many real green hydrogen projects still sit at effective costs equivalent to ~USD 40–50+/MMBtu or higher without subsidies. Over time, green hydrogen has more room to fall in cost; RNG does not scale or cheapen as dramatically because of feedstock constraints.

From a climate standpoint, should I prioritize RNG or green hydrogen?

It depends on your system and timeframe. RNG can deliver fast, low-regret reductions where waste methane is currently uncontrolled and turbines or pipelines can accept drop-in fuels. For deep decarbonization of an entire portfolio, especially over multi-decade horizons, green hydrogen (plus electrification) has more scalable potential. Many utilities and industrials are pursuing a hybrid approach: near-term RNG where it is cheap and impactful, while preparing for hydrogen-ready infrastructure for long-term net-zero.

Can I blend RNG and green hydrogen together?

Yes, but with important caveats. RNG and natural gas are both methane, so they mix seamlessly in pipelines. Hydrogen can also be blended into methane pipelines up to certain percentages (often ~10–20% by volume today) before gas quality, materials, and appliance issues appear. For gas turbines, hydrogen blending limits are defined by combustor design, Wobbe index restrictions, and materials/safety constraints. Any project contemplating triple blends (fossil gas + RNG + H₂) needs careful engineering and OEM engagement.

How should a peaker plant owner think about RNG vs hydrogen?

If you have near-term access to RNG at a reasonable price—especially from landfill or manure projects in your region—it can be an attractive way to cut emissions quickly without a turbine retrofit. But if you’re planning for 2040–2050 net-zero requirements, the bigger question is how your plant fits into a system with high renewables, large hydrogen infrastructure, and possible power-to-gas-to-power architectures. In that world, being hydrogen-ready and connected to H₂ storage may matter more than a long-term RNG contract.

Can RNG and green hydrogen both qualify as “low-carbon fuels” under the same policies?

Yes. Many policy frameworks (LCFS, EU low-carbon fuel rules, national hydrogen standards) are moving toward performance-based CI thresholds. RNG from certain feedstocks and green hydrogen from renewables can both qualify, but they will sit at different points on the cost curve and have different volume ceilings. Portfolio designers should think in terms of cost per tonne of CO₂e abated and strategic scarcity: RNG for niche, high-leverage uses; green hydrogen for large-scale structural change.