Economics reference

Modelled

What a typical asset earns

Capex and gross annual revenue at industry-reference assumptions, per infrastructure group. Numbers are for scale comparison only — they exclude fuel, CO₂, subsidies, PPAs, capacity payments, and every project-specific term. Per-asset economics for power plants live on the asset detail page; portfolio roll-ups on the owner directory.

How to read these numbers

• Capex = greenfield replacement cost at reference technology cost. Not what the asset traded for, not book value.
• Revenue = gross revenue at industry-typical utilisation × industry-typical price. No fuel or CO₂ cost deducted. Not profit.
• Payback = capex ÷ annual revenue. Not IRR. Useful for order-of-magnitude — meaningless for underwriting.
• Reference numbers refresh as public data does; nothing on this page auto-updates today.

Power generation

Per-asset economics on any /asset/ page →

Per-asset numbers derived from these reference costs are live on every power-asset detail page. Group defaults refined by technology hint: OCGT peakers, offshore wind, lignite each get a distinct profile.

Technology	Capex $/kW	Capacity factor	Revenue €/MWh	Simple payback (yrs)
Nuclear	5,500	90%	70	9.2
Coal (hard)	2,500	55%	55	8.7
Coal (lignite)	2,200	65%	50	7.1
Gas — CCGT	1,100	40%	60	4.8
Gas — OCGT / peaker	750	10%	100	7.9
Oil	1,500	15%	90	11.7
Hydro	2,800	45%	55	11.9
Solar utility PV	850	14%	50	12.8
Wind — onshore	1,400	30%	55	8.9
Wind — offshore	3,000	45%	80	8.8
Geothermal	4,500	80%	90	6.6
Bioenergy	3,500	55%	100	6.7
Battery (2 h duration)	600	15%	90	4.7

Sources: IEA World Energy Outlook 2024 (overnight capex $/kW by tech, EU region; typical capacity factors), ENTSO-E Transparency Platform (EU day-ahead wholesale price context), CfD strike prices for offshore wind. USD-EUR 0.92.

Oil refinery

Modelled

Capacity unit

kbpd (thousand barrels per day of crude throughput)

Typical European size

150–350 kbpd typical for a European mid-complexity refinery.

Capex basis

Greenfield replacement cost at $15,000 per bbl/d installed (IEA Oil Market Report, Concawe European refining industry reports).

Capex range

€2.1–4.8 B installed for 150–350 kbpd (using USD-EUR 0.92).

Revenue basis

Gross refining margin (GRM) × throughput × 365 × utilisation (~85% typical). Reference GRM $6/bbl mid-cycle, spikes to $15+/bbl in tight markets.

Revenue range

€250 M – €650 M/yr gross margin (not revenue) at mid-cycle GRM $6/bbl and 85% utilisation.

Payback

Simple payback ~5–10 years at mid-cycle margins; can compress to 2–3 years in crack-spread-blowout windows (2022 post-invasion) or extend past 20 years in prolonged low-margin cycles.

Sources

· IEA Oil Market Report — reference refining margins
· Concawe — Europe's refining industry reports (europia.eu)
· Wood Mackenzie European Refining Data Service (paywalled — used only as validation)

Data gap

GEM's Oil & Gas Plant Tracker captures European refineries by name but doesn't consistently record kbpd throughput — the MW field on the tracker refers to on-site electricity, not refining capacity. Per-asset revenue modelling for refineries needs an ETL extension.

LNG import terminal (regasification)

Modelled

Capacity unit

bcma sendout (billion cubic metres of gas per year)

Typical European size

5–20 bcma sendout for a European regas terminal; FSRU-based deployments 3–7 bcma, onshore 8–20 bcma.

Capex basis

Onshore terminal €60–80 M/bcma of sendout capacity (Gate NL, Świnoujście PL, OLT IT project disclosures). FSRU charter ~€150–200 M/yr all-in (no upfront capex).

Capex range

€300 M – €1.6 B for onshore 5–20 bcma. FSRU: no capex, opex €150–200 M/yr.

Revenue basis

Regasification fee ~€0.5–1.5 /MMBtu × ~40 MMBtu/tonne × utilisation. Roughly €30–60 M/yr per bcma of sendout at typical fee levels.

Revenue range

€150 M – €1.2 B/yr revenue at 5–20 bcma at €30–60 M/bcma fee. Post-2022 European fees have been at the top of this range or above.

Payback

Onshore terminals target 15–25 year payback under long-term binding-capacity contracts. Post-2022 crisis capacity auctions in Northern Europe cleared at multiples of pre-crisis fees.

Sources

· GIE ALSI facility register (gie.eu) — capacity and operator per European terminal
· IEA Gas Market Report — global LNG trade balance and fee context
· Gate Terminal / Świnoujście Terminal / Wilhelmshaven public project cost disclosures

Data gap

The GEM LNG parser reads bcm/y capacity from GEM's tracker but currently writes null to the asset row. Per-asset LNG economics need that field preserved — see etl/parsers/lng.ts.

Underground gas storage (UGS)

Modelled

Capacity unit

bcm WGV (working gas volume — usable inventory)

Typical European size

0.5–5 bcm WGV per European site. Depleted-field UGS are typically 1–5 bcm; salt caverns 0.1–1 bcm; aquifer storage 0.5–3 bcm.

Capex basis

Depleted-field UGS €200–350 M/bcm WGV (RAG, Storengy disclosures). Salt caverns €500–800 M/bcm (higher deliverability). Aquifer storage similar to depleted-field.

Capex range

€100 M for a small (0.5 bcm) salt cavern up to €1.5 B for a 5 bcm depleted-field site.

Revenue basis

Capacity-auction spread bidding: typical mid-cycle revenue €10–30 M/bcm/yr. Post-2022 crisis auctions cleared 5–10× normal levels — Rehden 4 bcm site was reportedly booking €200+ M/yr during peak 2022 spread.

Revenue range

€30–150 M/yr per site at mid-cycle spreads. Spike to €200–400 M in crisis conditions.

Payback

Long capex recovery — typically 20–30 year payback expected under regulated / long-term capacity contracts. UGS economics are structurally cyclical because they earn on seasonal or price-volatility spreads.

Sources

· GIE AGSI+ facility register (agsi.gie.eu) — WGV, operator, injection/withdrawal per European UGS
· Trading Hub Europe / GasPool historical capacity-auction results
· Storengy / RAG / Astora (now SEFE) annual reports and public disclosures

Data gap

UGS is not currently a distinct group in the Asset Atlas data model — the GEM tracker suite doesn't cover UGS as a standalone class. Adding it requires a new parser sourcing from GIE AGSI+ (free API with registration) or a hand-curated CSV of the ~150 European UGS sites.

Gas trunk pipeline (transmission)

Modelled

Capacity unit

km × diameter (throughput a function of both)

Typical European size

500–1,500 km typical European transmission link. Diameter 30–56 inches. Throughput 10–55 bcma per single line at typical operating pressure.

Capex basis

Onshore 36–48" pipeline $3–5 M/km. Offshore 42–48" $5–10 M/km. Includes compressor stations amortised across the corridor. (TAP, EastMed project disclosures; Nord Stream 1 was ~$8 B for 1,224 km twin-line = ~€3 M/km per line at 2010 prices.)

Capex range

€1.5 B for a 500 km onshore small-diameter line up to €10 B+ for a 1,500 km offshore mixed-diameter corridor.

Revenue basis

Transmission tariffs set by national regulators / ACER methodology. Typical fully-utilised revenue €5–15 M/bcm/yr transported. At 30 bcma corridor: €150–450 M/yr revenue at full utilisation.

Revenue range

€100–500 M/yr per major corridor at full utilisation. Utilisation post-2022 has diverged widely (Nord Stream at 0%, Nordic corridor at capacity).

Payback

Regulated returns typically 5–8% real WACC for TSO-owned pipelines. Merchant pipelines (TAP, Nord Stream) took investment decisions on 15–20 year payback but real payback is a function of routing politics as much as economics.

Sources

· ENTSOG Transparency Platform — flows, capacities, tariff coefficients per interconnection point
· ACER — cross-border network tariff methodology reports
· National regulator tariff decisions (Bundesnetzagentur, CRE, Ofgem, ARERA)

Data gap

Asset Atlas already surfaces 806 European transmission pipelines with per-pipeline throughput (bcm/y) in the map drawer. Adding per-pipeline economics on top of that data is a smaller change than the LNG/UGS gap.