Generation Capacity

Natural gas technologies for expanding power generation capacity

Eight technologies, each answering a different constraint — bulk energy, speed to commercial operation, modular growth, fuel efficiency, or emissions. Choosing between them is really a question of which constraint is binding.

Start with the constraint, not the technology

Utility capacity planning has changed shape. For most of the last two decades the binding constraint was the cost of energy, and combined-cycle plants won on efficiency almost by default. Today the binding constraint is usually time — specifically, the 5–7 years a large new load now waits for transmission interconnection across much of North America.

That inverts the ranking. A technology that is eight points less efficient but arrives three years sooner is not a compromise; it is the only option that meets the requirement. The table below is ordered the way a planner actually weighs it: bulk energy first, then speed, then emissions.

The eight technologies

Combined-cycle gas turbine (CCGT)

Bulk firm capacity

A gas turbine generates power, then its 500–600 °C exhaust drives a heat-recovery steam generator and a steam turbine for a second round of generation from the same fuel. H-class machines exceed 64% net efficiency, making CCGT the most efficient thermal generation available and the default choice when a utility needs large blocks of firm, dispatchable capacity.

60–64% electrical50–500+ MWLead time: 3–4 yearsDetail

Simple-cycle & aeroderivative turbines

Peaking and reserve

A gas turbine without the steam bottoming cycle. Lower efficiency is the trade for speed in both senses: aeroderivative units reach full load in under ten minutes, and they can be permitted and built far faster than a combined-cycle plant. This is the technology utilities add when the constraint is peak hours or reserve margin rather than annual energy.

35–42% electrical20–100 MWLead time: 12–24 months

Reciprocating engine gensets

Modular, incremental capacity

Banks of large gas engines rather than one turbine. Efficiency holds at part load where turbines fall away, units reach full load in under five minutes, and capacity arrives in small increments — so a plant can be sized to actual load growth instead of a ten-year forecast. Losing one engine costs a fraction of the plant, not all of it.

45–50% electrical2–20 MW per unitLead time: 9–18 months

Combined heat and power (CHP)

Capacity without proportional fuel

Not a separate prime mover but a configuration: capture the thermal energy any of the above rejects and sell it as heat. Total fuel efficiency rises above 90% when the heat has a customer. For capacity expansion this matters because it adds useful energy output without adding fuel input — the cheapest megawatt is the one already being thrown away.

90%+ totalAny of the aboveLead time: AdditiveDetail

Linear generators

Fuel-flexible, fast-ramping

A linear reaction driving a magnet through a coil rather than a crankshaft or turbine — no combustion flame, so the machine runs on natural gas, biogas, ammonia or hydrogen and switches between them without hardware changes. Ramp rates measured in seconds and low NOx without after-treatment make it well suited to campuses that must follow load or respond to grid dispatch signals.

~50% electrical250 kW–10 MW modularLead time: 9–15 months

Solid oxide fuel cells (SOFC)

Highest electrical efficiency

Electrochemical conversion rather than combustion, which sidesteps the thermodynamic ceiling that limits engines and turbines — SOFC reaches 51–61% electrical efficiency at modest scale, where a turbine of the same output would manage barely 40%. Near-zero NOx and SOx simplifies air permitting in urban sites, and the high-temperature exhaust is well matched to district-heat export.

51–61% electrical250 kW–20 MW modularLead time: 12–18 months

Hydrogen-ready turbines

Future-proofing the addition

A turbine specified from day one to burn variable natural-gas/hydrogen blends and transition to 100% hydrogen without replacing the machine. Capacity added in 2026 will still be operating in 2060, so the fuel question is really a stranded-asset question. Hydrogen-ready specification costs little now and removes it.

64%+ retained50–500+ MWLead time: Same as CCGTDetail

Allam-Fetvedt cycle

Near-zero-emission dispatchable

Oxy-combustion in a supercritical CO₂ working fluid, which produces a pure, pipeline-ready CO₂ stream as an inherent output rather than a bolt-on capture step. It is the one gas cycle that delivers dispatchable power at near-zero emissions without an efficiency penalty large enough to make capture uneconomic — still first-of-a-kind commercially, but the most credible answer to firm capacity under a net-zero grid mandate.

~50–59% with capture~300 MW classLead time: First-of-a-kindDetail

The option that isn't on the list

Every technology above expands capacity on the supply side. There is a seventh answer that works on the load side, and for a utility facing a queue of gigawatt-scale data-centre requests it is frequently the fastest one available.

Behind-the-meter generation

A 300 MW campus that builds its own generation is a 300 MW load the utility never has to serve. From the utility's side that is indistinguishable from adding 300 MW of capacity — except it arrives in 18–24 months instead of 5–7 years, and the utility spends nothing.

Dispatchable load

AI compute is one of the few large loads that can genuinely shed and restore within seconds. Paired with storage, a campus becomes a resource the utility can call on at peak rather than a burden it has to plan around — releasing existing capacity instead of building new.

Heat export

Recovered 50 °C heat delivered into district energy displaces gas boilers in the buildings it serves. That is thermal demand permanently removed from the system, and it is the reason a data centre can be net additive to a constrained grid rather than net extractive.

How GRECO applies this

GRECO develops energy-first AI campuses in British Columbia and Alberta: on-site generation specified hydrogen-ready from day one, grid-scale storage in both lithium and vanadium-flow chemistries, liquid cooling, and 50 °C recovered heat metered into district energy. The campus arrives powered — so an offtaker leases finished capacity from one counterparty instead of holding a shell that waits years for a grid connection. Every configuration is modelled in a digital twin before anything is ordered.

Expanding generation capacity: common questions

Eight, each matched to a different constraint. Combined-cycle gas turbines (CCGT) deliver bulk firm capacity at 60–64% efficiency. Simple-cycle and aeroderivative turbines trade efficiency for speed. Reciprocating engine gensets add capacity in modular 2–20 MW increments. Linear generators and solid oxide fuel cells (SOFC) deliver high efficiency at modest scale with very low emissions, suiting urban sites. Combined heat and power lifts total fuel efficiency above 90%. Hydrogen-ready turbines protect against future fuel rules, and the Allam-Fetvedt cycle delivers near-zero-emission dispatchable power with inherent CO₂ capture.

Reciprocating engine gensets, linear generators and aeroderivative simple-cycle turbines, typically 9–24 months from order to commercial operation versus 3–4 years for a combined-cycle plant. All three add capacity in small increments so a plant can track actual load growth rather than a ten-year forecast. The trade is efficiency at the turbine end — 35–42% for simple cycle against the 60–64% a CCGT achieves.

It depends on scale. At utility scale the H-class combined-cycle gas turbine leads at over 64% net electrical efficiency, the highest of any thermal power cycle in commercial operation. Below roughly 20 MW, solid oxide fuel cells win: because they convert electrochemically rather than by combustion they reach 51–61% at sizes where a turbine would manage barely 40%. With combined heat and power, total fuel efficiency exceeds 90% in either case.

Solid oxide fuel cells and linear generators, for two reasons beyond efficiency. Both produce near-zero NOx and SOx without after-treatment, which is usually the binding constraint on air permitting inside a city. Both are modular in 250 kW to a few MW increments, so they fit constrained urban floor plates and can be phased as load grows — where a single large turbine would need space, noise mitigation and a permit the site cannot get.

Building the plant is rarely the bottleneck. A combined-cycle plant takes 3–4 years to construct and gas engines as little as 9–18 months, but new transmission interconnection for large loads now takes 5–7 years across much of North America. That gap is why behind-the-meter generation has become the faster route to powered capacity: it sidesteps the queue rather than joining it.

Two paths make it credible. Hydrogen-ready turbines burn gas or blends today and transition to 100% hydrogen without replacing the machine, so the asset is not stranded by future fuel rules. The Allam-Fetvedt cycle captures essentially all CO₂ at source as an inherent output of the cycle rather than a bolt-on. Both deliver the dispatchable firm capacity that variable renewables require a grid to hold in reserve.

When the load is real, financeable and time-sensitive, usually yes. Behind-the-meter generation energizes a campus in 18–24 months against a 5–7 year interconnection queue, and from the utility's perspective a self-powered load is equivalent to capacity it never had to build. GRECO develops the full stack — generation, storage, liquid cooling and heat export — so the campus arrives powered rather than waiting.

Sources & further reading

U.S. Department of Energy• 2024

Combined Heat and Power Basics

International Energy Agency• 2024

Natural Gas Information Overview

Gas Turbine World• 2024

Gas Turbine World Handbook

NET Power• 2024

NET Power — Allam-Fetvedt Cycle