Power Generation Systems Compared: Efficiency, Cost and Configuration

Choosing a power generation system is not a choice between technologies. It is a choice between duty cycles, and the technology follows.

A combined cycle plant at 64% efficiency loses to a 43% aeroderivative if you only run 1,500 hours a year. That is the argument this guide makes, with the heat rates, capacity factors, capital costs and emissions thresholds to support it. It also covers what changed on 9 January 2026, when the EPA finalized a new combustion turbine performance standard that turns capacity factor into a compliance threshold.

What a Power Generation System Is

A power generation system is the complete set of equipment that converts a fuel or energy resource into electricity at a defined voltage and frequency, comprising a prime mover, a generator, balance of plant, electrical interconnection and controls.

The prime mover is the machine that converts energy into rotating mechanical power, such as a gas turbine, steam turbine, reciprocating engine or hydraulic turbine. In photovoltaic systems there is no prime mover, because conversion is direct and an inverter replaces the generator.

Balance of plant means every system outside the prime mover and generator: fuel handling and conditioning, water treatment, cooling, compressed air, fire protection, medium and high voltage switchgear, step-up transformers, and the DCS or SCADA layer. Balance of plant typically represents a large share of total installed cost and nearly all of the integration risk.

Four decisions determine everything else. What fuel or resource you have. What duty cycle you will run. What emissions regime applies. What schedule you must meet. Technology selection is the output of those four, not the starting point.

The Technologies Compared

The table below compares every major generation technology on the metrics that determine selection, rather than on general advantages.

Three of these are resource-bound rather than choices. Hydroelectric requires a water resource and civil works that take a decade. Geothermal requires a proven subsurface resource and drilling risk. Nuclear requires regulated utility ownership and a licensing path measured in years. For an industrial operator selecting generation for a site, the realistic option set is gas turbines, reciprocating engines, solar, storage, and hybrids of those four.

Prismecs delivers gas turbines, reciprocating engines, balance of plant, solar integration and battery storage. It does not build dams, drill geothermal wells or deliver nuclear plant. The rows above exist so the comparison is complete, not to imply capability.

Efficiency: What the Numbers Actually Mean

Heat rate is the operating measure of power plant efficiency, expressed as the fuel energy in British thermal units required to produce one kilowatt-hour of electricity. Lower is better, and every plant on earth is measured this way.

Combined-cycle systems have an average operating heat rate of 7,146 Btu/kWh, against roughly 10,000 Btu/kWh for simple-cycle systems, based on EIA figures for natural gas fired generation. Combined-cycle plants placed online since 2010 averaged 6,960 Btu/kWh, equivalent to approximately 49% efficiency.

Convert heat rate to efficiency by dividing 3,412 by the heat rate. A plant at 7,146 Btu/kWh operates at 47.7% efficiency. A plant at 6,000 Btu/kWh operates at 56.9%. Top-tier J-class combined cycle units reach below 6,000 Btu/kWh.

LHV versus HHV changes the number by about 11%

Lower heating value excludes the latent heat of water vapour in the exhaust. Higher heating value includes it. For methane, the HHV of 55.50 MJ/kg compares with an LHV of 50.00 MJ/kg, an 11% difference.

OEM datasheets almost always quote efficiency on an LHV basis because it produces the higher number. US regulatory and utility reporting frequently uses HHV. A turbine advertised at 42% LHV is roughly 38% HHV. Always ask which basis a quoted figure uses, because comparing an LHV number against an HHV number will mislead you by several percentage points.

ISO conditions are the reference, not your site

Gas turbine ratings are published at ISO standard conditions of 15°C ambient temperature, 101.3 kPa atmospheric pressure and 60% relative humidity, at sea level. Your site is not ISO conditions.

Gas turbine output falls as ambient temperature rises, because warmer air is less dense and reduces mass flow through the compressor. Output also falls with altitude for the same reason. A machine rated at 34 MW at ISO conditions will produce materially less at 40°C and 1,000 metres, and the derate must be calculated before sizing.

Capacity Factor: Why Efficiency Only Matters at the Duty You Run

Capacity factor is the ratio of actual energy generated over a period to the energy that would have been generated at continuous full output, and it is the single variable that decides which technology wins.

This is the argument almost every technology comparison omits. Peak efficiency is a laboratory figure. What you pay for is efficiency across your actual operating profile, including starts, stops and part-load hours.

Combined cycle units commissioned between 2010 and 2022 averaged a 64% capacity factor, against 55% for units commissioned between 2000 and 2009, and 35% for those commissioned between 1990 and 1999. Grid operators dispatch from lowest to highest operating cost, so the most efficient units run the most, which compounds their advantage.

The rule that follows

At high capacity factor, fuel dominates lifetime cost and efficiency wins. Combined cycle is correct.

At low capacity factor, capital cost and start capability dominate and efficiency barely matters. A combined cycle plant running 1,500 hours a year never recovers its steam cycle capital, and its 30 to 60 minute start makes it useless for reserve duty.

At intermediate and cycling duty, part-load efficiency and start cost decide. This is where reciprocating engines and aeroderivative turbines compete, and where peak efficiency figures are actively misleading.

Cycling damages machines built for baseload

Thermal cycling drives hot section damage in gas turbines. Maintenance intervals are governed by factored fired hours or factored starts, whichever is reached first, so a peaking unit reaches its hot gas path inspection far sooner than a baseload unit at the same clock hours.

Availability factor is the proportion of a period the unit was available to run, whether dispatched or not, and it is a different measure from capacity factor. Modern reciprocating engines commonly exhibit availability factors of 95% or better when operated and maintained to manufacturer recommendations.

For how maintenance intervals and availability guarantees are defined and contracted, see our guide to choosing a power plant O&M provider and our field guide to rotating equipment maintenance.

Gas Turbines: Simple Cycle and Combined Cycle

A combined cycle gas turbine plant recovers exhaust heat from the gas turbine in a heat recovery steam generator, raising steam to drive a steam turbine, and lifts net efficiency from roughly 43% simple cycle to as much as 64% in baseload operation.

The gas turbine operates on the Brayton cycle, a continuous cycle of compression, combustion and expansion. The steam bottoming plant operates on the Rankine cycle, a closed water and steam cycle. A heat recovery steam generator, or HRSG, is the heat exchanger that connects them.

Turbine inlet temperature is the primary efficiency lever, and modern H-class machines operate above 1,400°C. Higher firing temperature raises efficiency and also raises thermal stress on hot section components, which is why advanced-class machines carry higher parts cost per fired hour.

Power block configuration

A 1x1 power block is one gas turbine with one HRSG and one steam turbine. A 2x1 block is two gas turbines feeding one steam turbine, which lowers capital cost per kW and allows one turbine to run in simple cycle while the other is down.

Average 2x1 power block capacity rose from 500 MW for blocks built before 2015 to over 700 MW for those built after 2015, as a new class of combustion turbines became available.

When simple cycle is the right answer

Choose simple cycle when capacity factor is low, when start time matters more than fuel cost, when you need the plant in service quickly, or when there is no steam host and no water for a cooling system. Adding a bottoming cycle roughly doubles construction time and adds water treatment, cooling and steam plant operations to your scope.

Aeroderivative versus heavy-duty frame

Aeroderivative turbines are derived from aircraft engines and are lighter, faster-starting and exchanged rather than repaired in place. Heavy-duty frame machines are purpose-built for stationary duty, physically larger, and repaired on site.

Prismecs has installed and commissioned aeroderivative fleets including TM2500 mobile units at Duqm, Oman and Birr, Switzerland, an LM2500XPRESS plant at Miaoli, Taiwan, and three LM6000PC units adding 150 MW of fast-start reserve.

Reciprocating Engines Versus Gas Turbines

Below roughly 50 MW of plant capacity, a modern reciprocating gas engine typically achieves 42% to 48% electrical efficiency in simple cycle, against approximately 30% to 40% for a simple cycle gas turbine of comparable output.

The gap widens at part load. Gas turbines reduce output by reducing mass flow, which lowers combustion temperature and therefore efficiency. Reciprocating engine plants are modular, so a 100 MW plant made of ten 10 MW engines can deliver 50 MW by running five engines at full load, holding near-peak efficiency at half output.

Those capital cost figures come from the EIA 2024 generator construction cost survey, which recorded combustion turbines at 1,418 MW installed at an average $841/kW and reciprocating engines at 480 MW at $1,490/kW.

The trade is direct. Engines cost more per kW installed and use less fuel per MWh at cycling duty. Turbines cost less per kW, use less land, and win at sustained high load. Which is cheaper over twenty years depends entirely on your capacity factor and your delivered fuel price, which is why neither vendor's brochure can answer the question for your site.

Solar, Storage and Hybrid Configurations

Solar and battery storage are not alternatives to thermal generation in most industrial applications. They are components of a configuration that also contains thermal capacity, because neither provides firm dispatchable power on its own.

Utility-scale photovoltaic modules convert 20% to 23% of incident solar energy to electricity, and a solar plant's capacity factor typically runs 15% to 30% depending on irradiance and tracking. That means a 100 MW solar plant delivers the annual energy of roughly a 25 MW firm generator, at times the resource decides rather than you.

Battery energy storage achieves 85% to 90% round-trip efficiency at the AC terminals and responds in milliseconds, which covers the ride-through window no rotating machine can. It does not add energy to the system, it time-shifts it.

The configurations that work on industrial sites combine these. Solar plus storage plus thermal backup displaces fuel while retaining firm capacity. Gas turbine plus storage lets the turbine run at its efficient point while storage absorbs load swings. Storage plus fast-start engines replaces a peaking turbine entirely where the peak is short and frequent.

For sizing, chemistry, permitting under NFPA 855 and interconnection under IEEE Std 1547-2018, see our guide to battery energy storage systems.

Emissions Compliance Changed in January 2026

The EPA finalized 40 CFR Part 60 Subpart KKKKa on 9 January 2026, published it in the Federal Register on 15 January 2026, and it now applies to stationary combustion turbines constructed, modified or reconstructed after 13 December 2024.

This matters to technology selection because the rule makes capacity factor a compliance threshold, not just an economic variable.

What the rule does

Subpart KKKKa establishes subcategories for new, modified or reconstructed stationary combustion turbines based on size, design efficiency and utilisation, and sets NOx standards of performance reflecting the best system of emissions reduction for each subcategory.

The EPA determined that for large new combustion turbines above 850 MMBtu/hr base load rating operating at a 12-calendar-month capacity factor greater than 45%, the best system of emissions reduction is combustion controls plus post-combustion selective catalytic reduction. Below that threshold, combustion controls alone remain the determination for most subcategories.

The agency set a 38% efficiency threshold on a higher heating value basis to distinguish higher and lower efficiency turbines within the subcategory structure. A 25 ppm NOx standard applies to certain subcategories. The final rule also created a new source category for temporary combustion turbines.

Selective catalytic reduction, or SCR, is a post-combustion NOx control that injects ammonia or urea into the exhaust stream across a catalyst. It adds capital cost, adds backpressure that slightly reduces output, and adds a reagent consumable and catalyst replacement cycle to operating cost.

The practical consequence for configuration

If your project is a large combustion turbine expected to run above a 45% capacity factor, budget for SCR from the outset. If your duty cycle sits below that threshold, the emissions capital is materially lower, which shifts the economics toward simple cycle and peaking configurations.

Capacity factor is therefore a design input with three simultaneous consequences: efficiency economics, maintenance interval consumption, and now emissions control capital. Establish your expected capacity factor before you select technology, because it drives all three.

The standards that apply, by correct designation

The NSPS applies to stationary combustion turbines with a base load rating greater than 10 MMBtu/hr heat input, with exemptions for emergency, military and firefighting turbines. Full detail is published on the EPA's stationary combustion turbines NSPS page.

Air permitting is frequently the critical path on a generation project. Establish which subpart applies and whether SCR is triggered before you order equipment, because the answer changes the equipment specification.

Emissions and ESG reporting

Technology selection determines your direct emissions profile and therefore your Scope 1 reporting. Efficiency reduces CO2 per MWh proportionally: a plant at 7,000 Btu/kWh emits roughly 30% less CO2 per MWh than one at 10,000 Btu/kWh burning the same fuel. Confirm the accounting basis your reporting framework requires before claiming a reduction.

Capital Cost, Lead Time and Availability

Indicative installed capital cost runs approximately $841 per kW for combustion turbines and approximately $1,490 per kW for reciprocating engines, per the EIA 2024 generator construction cost survey, before balance of plant, interconnection and site-specific civils.

Those figures are equipment and installation reference points, not project budgets. Interconnection, fuel gas infrastructure, water treatment, emissions control and permitting frequently add substantially to the total, and on constrained sites they can exceed the generation equipment itself.

Lead time is now a selection criterion

New gas turbines and large reciprocating engines carry manufacturing lead times of 18 to 24 months or more. Heavy-duty gas turbine capacity is more constrained than that: GE Vernova reported combined gas power equipment backlog and slot reservations of 116 GW at the end of Q2 2026 and had roughly 10 GW of production capacity remaining across 2029 and 2030 combined, with reservations now being taken for 2031.

Explosive compute demand in North America is absorbing 60 Hz gas turbines at record pace, tightening availability across both technologies and raising the value of fast-track delivery.

The consequence is that schedule now competes with efficiency as a selection driver. A machine you can deploy in six months at 40% efficiency may beat a 62% combined cycle plant that cannot be ordered until 2031. Modular, mobile and surplus assets have become strategically valuable for exactly this reason.

Fuel cost dominates lifetime cost at high utilisation

Fuel is typically the largest lifetime cost of a thermal plant, so the efficiency gap between technologies translates directly into operating cost. A turbine plant's profitability is more sensitive to fuel price movement than an engine plant's, because it burns more fuel per MWh at cycling duty.

Model the comparison with your delivered fuel price, your expected capacity factor and a realistic start count. A comparison run at nameplate efficiency and 90% capacity factor will recommend combined cycle every time, which is why it is rarely the right model.

Performance Testing: Proving What You Bought

Name the test code in the contract, because a heat rate guarantee without a specified test method is an argument about procedure rather than a measurable obligation.

Performance tests are corrected to reference conditions using the correction curves in the contract, because a test run at 35°C cannot be compared directly to an ISO-conditions guarantee. Agree the correction methodology, the instrumentation accuracy class and the acceptable measurement uncertainty before the test, not during it.

Plant efficiency degrades over time through compressor fouling, hot section deterioration, HRSG tube fouling and condenser performance loss. Establish a post-commissioning performance baseline under ASME PTC 46 so that later degradation can be measured against a known starting point rather than against a datasheet.

How to Choose: The Selection Framework

Work through these in order, because each answer constrains the next. Technology is the last decision, not the first.

Build or buy from the grid

Compare the delivered cost of self-generation against the utility tariff plus the cost of waiting. Where an interconnection upgrade carries a multi-year queue, on-site generation may be the only way to meet a schedule, and the comparison becomes schedule against capital rather than cents per kWh.

Retrofit before new build

An existing plant with an available interconnection, permit and site is usually cheaper and faster to uprate than a greenfield project. Options include turbine upgrades that raise firing temperature, adding a bottoming cycle to an existing simple cycle plant, adding storage to flatten the duty, and control system modernisation.

Combined heat and power

CHP recovers exhaust heat as process steam or hot water rather than converting it to more electricity. It makes sense only where a genuine, coincident thermal load exists. Gas turbines account for 64% of installed CHP capacity in the United States, per a 2021 DOE analysis.

Fuel flexibility and supply risk

Where gas supply is interruptible or a single pipeline serves the site, specify dual fuel capability with on-site liquid storage. Dual fuel adds capital and complicates emissions compliance, so specify it because the supply risk requires it rather than as a default.

Land, staffing and insurance

Reciprocating engine plants need substantially more land than turbine plants of equal output, which is decisive on constrained industrial sites. Engine plants generally need more maintenance labour hours per MW. Underwriters price on machinery type, protection systems, maintenance regime and fire protection design, so involve your broker before technology selection rather than after.

How Selection Changes by Sector

The framework is constant. The weighting changes with what failure costs and what constrains the site.

Data centers

Load is high and flat, so capacity factor is high and efficiency matters, but the binding constraint is usually schedule and interconnection rather than fuel cost. Fast-deployable modular generation and storage are winning where grid capacity cannot arrive in time. Weight lead time and start reliability above lifetime heat rate.

Oil, gas and petrochemicals

Captive power failure stops production, so downtime cost per hour usually exceeds any efficiency difference between technologies. Weight availability, dual fuel capability, hazardous area compliance and spares proximity. API 616 applies where turbines serve process duty.

Metals and mining

Remote sites, weak or absent grid connection, heavy motor starting loads and high ambient temperatures dominate. Reciprocating engines often win on altitude and temperature tolerance and on modular expansion. Weight in-country support and logistics above peak efficiency.

Island and remote grids

Small system size means a single unit trip is a system event, so redundancy and fast frequency response matter more than heat rate. Engine plants with unit staging, or aeroderivative turbines with storage, are the common configurations.

Utilities and IPPs

Dispatch economics, capacity market participation and emissions compliance dominate. Efficiency directly determines dispatch order, since grid operators dispatch from lowest to highest operating cost. Weight heat rate, ramp rate and emissions capital.

Plants below 20 MW

Combined cycle is rarely economic at this scale. The realistic choice is reciprocating engines or aeroderivative turbines, and engines usually win on efficiency and part-load performance while turbines win on footprint and maintenance simplicity.

What Prismecs Builds

Prismecs engineers, procures, installs, commissions and maintains power generation systems across gas turbines, reciprocating engines, balance of plant, solar integration and battery storage, working both as the delivery contractor and, on other projects, as the owner's engineer.

Delivered generation scope includes four TM2500 mobile gas turbine units at Duqm, Oman totalling 110 MW, eight TM2500 dual-fuel units at Birr, Switzerland totalling 260 MW with multi-year O&M crews and CMMS, an LM2500XPRESS plant at Miaoli, Taiwan delivered in ten months, and three LM6000PC units installed and commissioned to add 150 MW of fast-start reserve. Storage scope includes a 7 MW / 28 MWh BESS and a 9 MW BESS engineered, procured, built and commissioned for grid stability and ancillary revenue.

Prismecs does not build hydroelectric, geothermal or nuclear plant, and does not manufacture turbines. It is an OEM-agnostic engineering, procurement, construction management and O&M organisation, which means technology recommendations are not tied to a manufacturer's aftermarket.

Apply the framework in this article to any bidder, including us. Ask for guaranteed heat rate with the ASME test code named, the ISO-conditions correction curves, the expected capacity factor the design assumes, and which emissions subpart the equipment is specified against.

To request a generation configuration study, send twelve months of interval load data, your fuel supply position and your required in-service date to sales@prismecs.com or call +1 (888) 774-7632. We return a technology shortlist, an indicative heat rate and cost range, and a permitting path.

Frequently Asked Questions

What is heat rate and what is a good number?

Heat rate is the fuel energy in British thermal units required to produce one kilowatt-hour of electricity, and lower is better. Combined-cycle systems average 7,146 Btu/kWh against roughly 10,000 Btu/kWh for simple-cycle systems. Combined-cycle plants built since 2010 average 6,960 Btu/kWh, about 49% efficiency. Top-tier J-class units reach below 6,000 Btu/kWh. Convert heat rate to efficiency by dividing 3,412 by the heat rate.

How much more efficient is combined cycle than simple cycle?

Combined cycle raises net efficiency from roughly 43% in simple cycle to as much as 64% in baseload operation, by recovering gas turbine exhaust heat in a heat recovery steam generator to drive a steam turbine. In heat rate terms that is approximately 7,146 Btu/kWh against 10,000 Btu/kWh. The gain requires a steam plant, cooling system and water treatment, roughly doubling construction time.

What is the difference between LHV and HHV efficiency?

Lower heating value excludes the latent heat of water vapour in the exhaust; higher heating value includes it. For methane the HHV of 55.50 MJ/kg compares with an LHV of 50.00 MJ/kg, an 11% difference. OEM datasheets typically quote LHV because it gives the higher number, while US regulatory reporting often uses HHV. A turbine quoted at 42% LHV is roughly 38% HHV.

Should I choose a gas turbine or a reciprocating engine?

Below roughly 50 MW plant capacity, reciprocating gas engines typically achieve 42% to 48% simple cycle efficiency against 30% to 40% for simple cycle gas turbines, and hold near-peak efficiency at part load through unit staging. Gas turbines need substantially less land, cost less per kW installed at roughly $841 versus $1,490, and win at sustained high load. Capacity factor and delivered fuel price decide.

Why does capacity factor matter more than peak efficiency?

Capacity factor is the ratio of actual energy generated to energy at continuous full output, and it determines whether fuel cost or capital cost dominates lifetime economics. At high capacity factor fuel dominates and efficiency wins. At low capacity factor a combined cycle plant never recovers its steam cycle capital and its 30 to 60 minute start makes it unsuitable for reserve duty. Peak efficiency at the wrong duty is a misleading number.

What is 40 CFR Part 60 Subpart KKKKa?

Subpart KKKKa is the EPA New Source Performance Standard for stationary combustion turbines finalized on 9 January 2026 and published on 15 January 2026, applying to turbines constructed, modified or reconstructed after 13 December 2024. It establishes subcategories by size, design efficiency and utilisation, and sets NOx standards reflecting the best system of emissions reduction for each.

When does my project need SCR?

The EPA determined that for large new combustion turbines above 850 MMBtu/hr base load rating operating at a 12-calendar-month capacity factor greater than 45%, the best system of emissions reduction is combustion controls plus post-combustion selective catalytic reduction. Below that threshold combustion controls alone remain the determination for most subcategories. Establish your expected capacity factor before selecting equipment, because it drives emissions capital.

What are ISO conditions and why does my turbine produce less than rated?

Gas turbine ratings are published at ISO standard conditions of 15°C, 101.3 kPa and 60% relative humidity at sea level. Output falls as ambient temperature rises, because warmer air is less dense and reduces compressor mass flow, and falls again with altitude for the same reason. Reciprocating engines are more tolerant, with minimal output impact below 3,000 feet and 95°F.

Which test code proves a guaranteed heat rate?

ASME PTC 22, Performance Test Code on Gas Turbines, covers gas turbine output and heat rate. ASME PTC 46, Performance Test Code on Overall Plant Performance, covers whole plant net output and heat rate. ASME PTC 6 covers steam turbines. Internationally, ISO 2314 covers gas turbine acceptance testing and ISO 3046 and ISO 8528 cover reciprocating engine performance and generating sets.

What is the difference between aeroderivative and heavy-duty frame turbines?

Aeroderivative turbines derive from aircraft engines, reach 35% to 43% simple cycle efficiency, start in under ten minutes, and are exchanged and repaired off site, giving outages measured in days. Heavy-duty frame machines are purpose-built for stationary duty, reach 30% to 40% simple cycle, start in ten to thirty minutes, and are repaired in place over weeks. Aeroderivatives suit cycling; frames suit baseload.

Can I still buy a new gas turbine?

Not within a normal planning horizon for heavy-duty machines. GE Vernova reported 116 GW of combined gas power equipment backlog and slot reservations at the end of Q2 2026, with roughly 10 GW of capacity remaining across 2029 and 2030 combined and reservations being taken for 2031. New turbines and large reciprocating engines carry 18 to 24 month manufacturing lead times, so schedule now competes with efficiency as a selection driver.

Is hydroelectric, geothermal or nuclear a realistic option for an industrial site?

Generally no. All three are resource-bound or regulation-bound rather than freely selectable. Hydroelectric requires a water resource and civil works measured in years. Geothermal requires a proven subsurface resource and carries drilling risk. Nuclear requires regulated ownership and a multi-year licensing path. For industrial operators the realistic option set is gas turbines, reciprocating engines, solar, storage and hybrids of those.

Can battery storage replace a peaking plant?

Sometimes, where the peak is short and frequent. Battery storage achieves 85% to 90% round-trip efficiency and responds in milliseconds, covering a ride-through window no rotating machine can match, but it time-shifts energy rather than adding it. For extended outages or sustained peaks, storage paired with fast-start engines or aeroderivative turbines is the workable configuration rather than storage alone.

How do I decide between building generation and buying from the grid?

Compare delivered self-generation cost against the utility tariff plus the cost of waiting for interconnection. Where a grid upgrade carries a multi-year queue, on-site generation may be the only way to meet a required in-service date, which turns the comparison into schedule against capital rather than cents per kWh. Model both against twelve months of interval load data.

Tags: Power Generation Systems Combined Cycle Efficiency Gas Turbine vs Reciprocating Engine Heat Rate and Capacity Factor Combustion Turbine Emissions Compliance