Thermal & Economic Analysis of Supplementary Firing Large Combined Cycle Plants

Jon Backlund, Coen Company, Inc.
Jim Froemming, HRST, Inc.


The benefits of supplementary firing a large combined cycle plant depend on a number of factors. Plant design, cost of capital, cost of fuel, marginal cost of electricity production, and hours of operation are the most important. Since many variables are involved, most notably plant design and regional wholesale electricity prices, any particular application should be analyzed in detail to determine the full merit of adding supplementary firing.

Although a supplementary fired plant inherently has a lower efficiency than an unfired plant, the ability to produce more power output during periods of high electricity prices gives it an economic advantage depending on the demand for the electricity and the number of hours the high prices exist. Two types of supplementary-fired plants are compared with a nominal 500 MW unfired plant. The first adds approximately 80 MW of additional power from supplementary firing and the other only supplements the lost steam turbine power of an unfired plant during high ambient conditions. With this basis, the first type of plant achieves additional income as much as $7 million and the second type of plant achieves a payback in less than 3 years in most cities of the United States. Burner operation that is restricted to the summer on-peak hours is the most attractive.


It is the tradeoff between periods of high and low electricity prices that determines the economic benefits of supplementary firing. When electricity prices are below the cost of production, both unfired and fired plants have a net loss in income, but fired plants have a higher loss because they have a higher cost of production. When electricity prices are higher than the cost of production, both unfired and fired plants have a net gain in income, but fired plants have a higher gain because they have more generating capacity to sell.


For each type of supplementary-fired plant there is the ability to supply additional electricity as compared to the unfired base plant. However, there is a cost associated with this ability to supply additional electricity. The costs of electricity production – capital, fuel and operating & maintenance – increase.


Wholesale purchases of electricity can now be performed through regional power exchanges or futures markets. Through power exchanges, suppliers submit bids for providing power hour by hour and buyers submit bids to buy power hour by hour. Low electricity prices occur during off-peak hours and high electricity prices occur during the on-peak hours with the highest occurring during the summer months of July and August.


The intersection of the supply and demand curves for each hour produces the market-clearing price (MCP). Provided the incremental costs of this additional generating capacity are lower than the MCP, there will always be a demand for this less expensive power. Therefore, if a supplementary-fired plant’s increased revenue from selling its additional generating capacity can exceed its increased costs of electricity production there will be an economic benefit over an unfired plant.


The base plant selected is a nominal 500 MW combined-cycle power plant with no supplementary firing capability. It uses two (2) nominal 170 MW “F” class gas turbines with a common nominal 160 MW steam turbine and two (2) unfired HRSGs. The base plant has the same arrangement as the fired plant shown in Figure 1, but without the duct burner.


Two types of supplementary-fired plants are compared to the nominal 500 MW base plant without supplementary firing:

Case 1. The maximum net plant power output is increased by approximately 17% with the addition of supplementary firing with the steam turbine, HRSG, feedwater and transmission systems resized accordingly to handle the additional steam and power generation capacity.

Case 2. The maximum net plant power output is not increased, but the addition of supplementary firing allows design HP steam generation to be maintained for any ambient temperature. This prevents the loss of steam turbine output, which can be as much as 1% of total plant output at an ambient temperature of 100 deg F (based on no cooling of the gas turbine inlet air). No equipment is changed other than a slight modification to the HRSG inlet duct to accommodate the duct burner.

Figure 1, Process Diagram (Click image for a larger view)


The base unfired plant is compared to a supplementary-fired plant which is of the same basic design as the unfired plant, but modified to accommodate 400 MMBtu/hr (LHV) of supplementary firing per HRSG and the subsequent increased steam capacity. Only performance at 60F ambient is considered since it is representative of the relative difference between the two plants.

Table 1, Plant Performance at 60F Ambient

The general reason for the lower efficiency for the supplementary-fired plant in maximum-firing mode versus the base plant is that the net fuel added by supplementary firing has the effect of adding power in a Rankine cycle mode, which is less efficient than combined-cycle. The loss of efficiency is not as severe as would be for a conventional Rankine cycle since the combustion air is preheated and there is a side-benefit of additional heat recovery by the HRSG. The stack temperature reduces from 235 deg F to 200 deg F. The incremental heat rate of the fired plant is 7824 Btu/kWh from unfired to maximum firing.

The reason the supplementary-fired plant has a lower power output and efficiency during unfired operation as compared to the base plant is that the common equipment, particularly the steam turbine, being sized for the steam rate for maximum supplemental-firing and thus being less efficient at part load. Plant performance was modeled using HRST software, with typical industry values for component efficiencies obtained from equipment suppliers and users.


In 1999 the average natural gas price to electricity suppliers was $2.58/MMBtu HHV (source: Energy Information Administration/Electric Power Annual 1998 Volume I).

Table 2, Fuel Costs, Natural Gas Price of $2.58/MMBtu HH


Typical O&M costs for a nominal 500 MW plant are $2 per MWh or $8.4 million per year (based on 8400 hours of operation). This number is reconfirmed by EIA Report # DOE/EIA-0383(99). It is not unrealistic to assume that the supplementary-fired plants would be approximately the same.


Budgetary costs are obtained from equipment suppliers for the gas turbine, steam turbine, cooling tower and feed pumps. HRST modeling software estimated the HRSG costs. The most difficult costs to estimate are the additional costs of ancillary equipment, supply interfaces for transmission, gas, water and sewer, construction and project development. Therefore, two scenarios for these additional capital costs, except project development costs, are analyzed. On one extreme it is assumed these additional costs do not increase and on the other extreme it is assumed these additional costs are proportional to the maximum plant output. This is useful in determining the sensitivity of the analysis to increased capital equipment costs for the supplementary-fired plant.

A cost of capital or discount rate of 12% and a term of financing of 20 years is used. Note: The costs are in terms of $ per MWh of unfired operation.

Table 3, Cost of Capital


Using the costs determined in the preceding sections, a base cost of electricity production is determined for the base plant and the Case 1 fired plant for unfired operation.

Table 4, Base Cost of Electricity Production

The incremental cost of electricity production from supplementary firing the plant in Case 1 is $24.40 per MWh, the fuel costs in Table 2 plus O&M costs.


For the purposes of this analysis the price of off-peak power is set as the average fuel cost of the unfired base power plant, $18.54 per MWh (see Table 2). The exact amount may be somewhat lower, but this is not significant in comparing an unfired plant with a supplementary-fired plant since either plant does not typically recover capital costs during off-peak hours. It is the relative difference between the base costs of production for the two plants, which is key.


Charts 1 and 2 reflect the potential additional annual income that can be realized by a supplementary-fired plant for year-round operation and summer on-peak operation, respectively. If the additional capital costs for ancillary equipment, supply interfaces for transmission, gas, water and sewer, and construction do not increase significantly the supplementary-fired plant produces higher income than the unfired base plant. Potential annual income for a fired plant over an unfired plant ranges from a negative $3 million to a positive $6 million. Considering the lowest and highest cost scenarios for the incremental costs of the supply interfaces and the lowest and highest prices of electricity causes this wide range.

Chart 1, Additional Annual Income with Nominal 580 MW
Supplementary Fired Plant vs Nominal 500 MW Unfired plant – Year Round Operation

Summer on-peak operation is defined as operation during only the on-peak hours of business days from mid-May to mid-September. Potential higher income for the fired plant is as much as $7 million annually. See Chart 2 on the next page. For almost all combinations of electricity prices and capital costs, the fired plant has more economic benefit. However, if the price of electricity is at its lowest average futures price for the month, income ranges from a loss of $1 million to a gain of $2 million. Again, this depends on the additional capital costs for ancillary equipment, supply interfaces for transmission, gas, water and sewer, and construction.

Additional Annual Income Chart  -  Summer Operation

Chart 2, Additional Annual Income with Nominal 580 MW
Supplementary Fired Plant vs Nominal 500 MW Unfired Plant – Summer On Peak Operation


The previous analysis is based on 60ºF ambient temperature, but compressors of gas turbines are constant volume machines, therefore, as ambient air temperature increases, turbine air mass flow decreases due to the decreased density of air. Although turbine exhaust temperature increases about 1 degree F for every degree the ambient air temperature increases, the net effect is for the energy recovered by the HRSGs to reduce with increasing ambient air temperature (see Chart 3 below). Losing steam-generating capacity during the hottest weather, when wholesale electricity prices are at their peak, is not very desirable.

Chart 3, Turbine Exhaust Energy Absorbed by HRSGs, Nominal 500 MW Plant

Assuming there is no cooling of the inlet air at high ambient temperatures, there will be a loss of steam turbine output for the base plant, but no loss by the fired plant. Therefore, there is potential additional income for a fired plant.


A small duct burner can be added to supplement the turbine exhaust energy at high ambient temperatures to maintain design throttle flow to the steam turbine (see Chart 4). The additional expenses are the capital costs for the capability and the operating costs of the supplementary fuel. The additional revenue is from the sale of the electricity otherwise not available without supplementary firing. Note: for the Case 1 fired plant this burner is already in place, but other than no additional capital costs, the additional income is the same as for the Case 2 fired plant.


An economic analysis is done for 5 major cities in the U.S. – Phoenix, Houston, Atlanta, New York, and Chicago. The base unfired plant is compared to a supplementary-fired plant which is of the same basic design as the unfired plant, but with each HRSG modified to accommodate a small burner, duty of 25 MMBtu/hr (LHV).

Chart 4, Throttle Steam at High Ambient Temperatures, Nominal 500 MW Plant

Because supplementary firing reduces the LP steam to some extent, the full credit for plant output due to maintaining design HP throttle steam cannot be used.


Table 5, Supplementary Firing at High Ambient Temperatures

Chart 5, Average Ambient Temperature by Hour – Month of July


Based on supplementary-firing during on-peak hours of business days from mid-May to mid September (total of 1440 hours) to maintain HP throttle steam at the 60F design point, the additional annual income for 5 cities is shown in Chart 6.

Chart 6, Additional Annual Income with Supplementary Firing at High Ambient Temperatures


Each application will be different, but it is assumed that the increased cost of adding a small duct burner as a retrofit does not exceed $400,000. Based on this assumed capital cost the following paybacks are calculated:

Table 6, Number of Years for Payback

Therefore, even if only a small duct burner is added to a combined-cycle plant, the economic benefits of supplementary firing can be realized in a short payback period.


Adding the additional income shown in Chart 6 allows the Case 1 fired plant to always have more economic benefit than an unfired plant if operation is restricted to the summer on-peak hours. Also, even if operation is year-round, unless the prices realized are below the median price of electricity, the Case 1 fired plant always has more economic benefit than the base unfired plant.