What Does Green Ammonia Really Cost?

Published figures for green ammonia span several hundred to several thousand dollars per tonne, and they are rarely comparable. This article applies a transparent, bottom-up EnviroSusIQ cost model and a common cradle-to-gate carbon benchmark to grey, blue, green and grid-electrolytic ammonia – and tests what it would take for green ammonia to compete.

Why green ammonia cost claims need a bottom-up economic test

Published figures for green ammonia span several hundred to several thousand dollars per tonne, and they are rarely comparable. Some are project targets, some are production-cost estimates for the best sites, and some mix plant-gate costs with delivered prices. The International Energy Agency (IEA) expects fossil-based hydrogen production to remain cheaper than renewable hydrogen in most regions in the near term [1], and it reports installed electrolyser costs of USD 2,000–2,600/kW outside China in 2024, against USD 600–1,200/kW in China [2]. A decision-grade answer needs an explicit boundary, a defined plant and a common functional unit.

This article applies that test using a transparent EnviroSusIQ model. The functional unit is one tonne of anhydrous NH₃ at the plant gate in real 2026 US dollars, for an illustrative 1,500 t/day plant with a 25-year life. Delivered cost to a north-west European importer is reported separately. Emissions are cradle-to-gate in tCO₂e/t NH₃ using 100-year global warming potentials (GWP100). Two terms are kept distinct: green describes a production pathway, while low-carbon describes an emissions outcome, and qualification under either label depends on the applicable rules [3][4][5]. Results in this article are scenario outputs, not market quotations or certified values.

The components that determine green ammonia cost

Figure 1 shows the model structure. Hydrogen demand starts from stoichiometry: 3H₂ + N₂ → 2NH₃ gives 0.1776 t H₂/t NH₃ with standard molar masses. The model assumes 0.180 t/t, an EnviroSusIQ allowance of about 1.4% for purge and recycle losses. The Haber–Bosch (HB) plant runs at an 85% annual load factor, giving 1,500 × 365 × 0.85 = 465,375 t/yr of NH₃. The electrolyser consumes 52 kWh/kg at beginning of life, raised by 3% to a life-average 53.56 kWh/kg; this degradation adjustment is applied to both electricity use and electrolyser sizing.

The core equations use unrounded workbook inputs (CF is the electrolyser capacity factor, r the real weighted average cost of capital or WACC, n the 25-year life and c the 3-year construction period):

LCOA is the levelised cost of ammonia, CRF the capital recovery factor and IDC an interest-during-construction factor that approximates an even three-year drawdown (within about 0.2% of a mid-year schedule). The delivered electricity price combines a USD 40/MWh hybrid solar–wind levelised cost, consistent with IRENA's 2024 global weighted averages of USD 34/MWh for onshore wind and USD 43/MWh for solar PV [6], 7% curtailment and a USD 6/MWh balancing adder. Because this is a power-purchase-agreement (PPA) equivalent price, renewable generation CAPEX is not added again. The electrolyser installed cost of USD 2,000/kW sits at the bottom of the IEA range for outside China and includes engineering, procurement and construction (EPC) [2]. A 15% owner's-cost and contingency allowance is applied to the other equipment: hydrogen compression and buffer storage, the air separation unit (ASU) for nitrogen, the HB loop with its balance of plant (BoP), and NH₃ storage.

Total overnight CAPEX is USD 2.85 billion: USD 1.86 billion for the electrolyser and USD 0.99 billion for everything else. The annual capital charge (CAPEX × CRF × IDC) is USD 644/t. The cost bridge splits this into straight-line depreciation of each asset (USD 245/t in total, of which the electrolyser is USD 160/t) and a single financing line of USD 399/t covering return on capital and IDC. No separate interest is added, so financing is neither omitted nor double counted. Electrolyser fixed O&M and stack replacement (accrued per operating hour) add USD 116/t. This simplified levelised method is not a project-finance model; debt sculpting, tax and policy revenue would change the results. Table 1 lists the main inputs.

The Base result is USD 1,373/t NH₃ at the plant gate (Figure 2). Electricity is 38% of cost, financing 29% and electrolyser depreciation, O&M and stacks a further 20%; nitrogen separation, synthesis and storage depreciation together add about USD 55/t. This is consistent with IRENA's 2022 estimate of USD 720–1,400/t for new renewable ammonia plants [7]. Export terminal, shipping, import terminal and losses (EnviroSusIQ assumptions within IRENA's USD 45–100/t shipping range [7]) bring the delivered cost to USD 1,460/t.

Costs, emissions and key assumptions

All pathways use the same cradle-to-gate boundary: direct plant emissions after capture, electricity, upstream gas including methane, and other upstream materials. No credits are taken for urea CO₂ use or steam export. Grey ammonia from a steam methane reformer (SMR) using 30 GJ/t of gas (IEA best available technology is 28 GJ/t [11]) costs USD 270/t at USD 4/MMBtu, close to a published US estimate of about USD 230/t [12]. Its direct emissions are 30 GJ × 0.0561 tCO₂/GJ = 1.68 t/t, in line with about 1.8 t/t for best-available SMR [13]. Adding 0.06 t/t from grid electricity (0.15 MWh/t at 0.4 t/MWh) and 0.30 t/t of upstream gas emissions gives 2.04 tCO₂e/t, near IRENA's figure of roughly 2.2 including upstream [7].

Blue ammonia is not one product. About two-thirds of SMR CO₂ is in the concentrated process stream [7][14]. Capturing 95% of that stream (Blue-A) removes about 62% of direct CO₂ in this model, but cuts cradle-to-gate emissions only by about half, to 1.05 t/t. An autothermal reformer (ATR) with full capture (Blue-B) is modelled at 95% of direct CO₂, inside the 93–98% design range [10]. The IEA notes that high-capture CCUS-based hydrogen production has yet to be demonstrated [15], so this is a design assumption. Blue-B reaches 0.59 t/t, of which only 0.09 t is residual direct CO₂; upstream methane (0.32 t) and power (0.18 t) dominate the rest.

Electrolytic does not automatically mean low-carbon. The grid case holds the HB plant and output constant and resizes the electrolyser to a 95% CF. On a grid emitting 0.4 tCO₂/MWh, 10.645 MWh/t gives 4.26 t/t, plus 0.03 t/t of other upstream emissions, for 4.29 t/t, more than twice grey; a much cleaner grid or hourly-matched clean supply would change this. EU renewable fuels of non-biological origin (RFNBOs) must meet additionality, geographic-correlation and temporal-correlation rules, with monthly matching to the end of 2029 and hourly matching from 2030 [3]. They must also achieve a 70% saving against a 94 gCO₂e/MJ comparator [4], and a parallel 70% test applies to low-carbon fuels including blue [5]. Using ammonia's lower heating value (LHV) of 18.6 GJ/t, 94 × 0.30 × 18.6 ÷ 1,000 gives an indicative 0.5245 tCO₂e/t. At Base, Blue-A (1.05) and Blue-B (0.59) are above it; green (0.30) is below it, but only marginally above (0.53) in the High case because of the lifecycle emissions of renewable power, which the RFNBO method counts as zero for directly connected supply. This simplified screen is not a certification determination.

Energy-equivalent, hydrogen-equivalent and CO₂ abatement cost

USD/GJ divides LCOA by the 18.6 GJ/t LHV: green is USD 74/GJ against USD 15/GJ for grey. This compares chemical energy only, not end-use performance. USD/kg H₂-equivalent divides LCOA by the theoretical 0.1776 t H₂/t: green equals USD 7.73/kg and grey USD 1.52/kg (Figure 5). This is a theoretical feedstock equivalence, not a delivered-hydrogen cost; cracking ammonia back to hydrogen requires additional energy, equipment and purification, which are not modelled. Cost of CO₂ avoided compares each pathway with grey in the same scenario, using plant-gate costs and cradle-to-gate emissions. It is reported as undefined when emissions are not lower (Figure 6):

Rounding the inputs to 1,373, 270, 2.04 and 0.30 gives about USD 634; the unrounded workbook value is USD 632. Blue-A abates at USD 53/tCO₂e (27–112), Blue-B at USD 92 (54–183) and green at USD 632 (275–1,263); grid electrolysis abates nothing. Blue looks cheap per tonne avoided, but Blue-A avoids only about 1.0 t/t. A carbon-price break-even depends on which emissions an instrument actually prices. The EU Emissions Trading System (ETS) covers direct installation emissions. The Carbon Border Adjustment Mechanism (CBAM) prices imported fertilisers, including ammonia, on both direct and indirect electricity emissions [16][17], with obligations adjusted for EU free allocation during the 2026–2034 phase-in [16]. Neither prices upstream methane. On CBAM-style coverage, green breaks even with grey at about USD 633/tCO₂e and Blue-B at USD 91; on ETS-style coverage, the figures are USD 656 and USD 84 (Figure 8). A direct-only price would even favour grid electrolysis despite its higher lifecycle emissions, which shows why coverage matters. The Q3 2026 CBAM certificate price of EUR 82.32 [18], about USD 95 at 1.1537 USD/EUR [19], closes the Blue-B gap but leaves green about USD 940/t short. These break-evens are full-price shadow indicators, not liability estimates.

Electricity, utilisation, financing, carbon price and regional differences

The tornado in Figure 7 varies one input at a time between its Low and High values, holding everything else at Base. Electrolyser CAPEX (USD 430/t swing), renewable electricity cost (401), WACC (328) and electrolyser CF (317) dominate. Efficiency, BoP CAPEX, HB load factor, curtailment, stacks and water each move LCOA by about USD 100/t or less. With USD 20/MWh power and a 70% CF, Base green ammonia still costs about USD 1,030/t, 3.8 times Base grey.

The cheapest power does not automatically produce the cheapest ammonia. In the illustrative regional cases, a hybrid-renewables export hub with USD 28/MWh power and a 65% CF reaches USD 1,276/t, only 7% below Base, because an assumed 10% WACC absorbs much of the advantage. A US Gulf Coast case (USD 42/MWh, 45% CF, 7.5% WACC) reaches USD 1,481/t and a north-west European case (USD 65/MWh, 40% CF) USD 1,881/t. Gas prices move the other side of the comparison. At the 2025 Title Transfer Facility (TTF) average of USD 11.96/MMBtu [9], the European case puts grey at USD 518/t. At September 2026's monthly TTF average of USD 25.42/MMBtu [9], Base grey would cost about USD 930/t, still below green. IRENA's 2022 estimate that about USD 150/tCO₂ would make renewable ammonia competitive [7] assumed best-site costs and higher 2022 gas prices, which is why it is far below this model's Base break-even.

On this model, green ammonia in 2026 costs roughly four to six times grey at the plant gate, with a Base abatement cost of about USD 630/tCO₂e. High-capture blue routes abate far more cheaply, but whether they fall below low-carbon thresholds depends on measured upstream methane and power supply, and on capture performance that is still to be demonstrated at scale. Four variables will shift these numbers: whether electrolyser costs outside China converge towards Chinese levels [2]; renewable power cost and achievable utilisation; financing costs, which depend on bankable offtake and policy; and how strictly regulators apply temporal matching and methane accounting [3][5]. In the United States, the Section 45V hydrogen credit applies only to facilities beginning construction before 1 January 2028 [20]. It is paid per kilogram of hydrogen in four lifecycle-emissions tiers, from USD 3.00/kg below 0.45 kgCO₂e/kg H₂ (with labour requirements met) to USD 0.60/kg at 2.5–4 kg, assessed with the 45VH2-GREET model [21], so not every ammonia project qualifies for the full value.

Publicly accessible; all accessed 13 October 2026. Research cut-off: 13 October 2026. Real 2026 USD, plant gate unless stated, lower-heating-value basis. Figures are EnviroSusIQ model outputs unless attributed.

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Methodology note:all costs, emissions and break-evens are EnviroSusIQ scenario outputs unless attributed. They are not market quotations, project targets or certified values, and the model has passed internal reconciliation checks but has not been independently verified. Subscription price services (Argus, S&P Global, CRISIL, ICIS) were not used. Abbreviations: CCUS = carbon capture, utilisation and storage; MMBtu = million British thermal units; O&M = operation and maintenance; T&S = transport and storage.

Decision-grade ammonia and hydrogen economics

EnviroSusIQ supports these decisions with bottom-up green hydrogen and ammonia cost modelling, renewable-power and electrolyser sensitivities, grey/blue/green benchmarking, lifecycle-emissions analysis, abatement-cost and carbon-price break-even assessment, and regional and export economics. The transparent model behind this article can be adapted to a specific site, contract structure or data set.

To discuss a tailored benchmark for your project or procurement strategy, visit EnviroSusIQ – https://www.envirosusiq.com/.