Air Pollution Control Equipment Services, Emissions, Policy & Regulations

Range And Applicability Of Heat Rate Improvements

Issue 11 and Volume 118.

The Jeffrey Energy Center, a 1,857-MW coal-fired power plant in St. Marys, Kansas. For coal-fired power plants, fuel is the largest expense
The Jeffrey Energy Center, a 1,857-MW coal-fired power plant in St. Marys, Kansas. For coal-fired power plants, fuel is the largest expense. A 1-percent heat-rate reduction will save about $700,000 in annual fuel costs, according to the Electric Power Research Institute.

By S. Korellis, Electric Power Research Institute

A power plant’s heat rate measures the input of heat energy into the plant, relative to the output of electrical energy from that plant.

More specifically, heat rate compares the amount of heat in Btus required to generate 1 kilowatt-hour (kWh) of electricity. Accordingly, typical units for heat rate are Btu/kWh. Heat rate is also the inverse of plant efficiency. As such, a lower heat rate is better than a higher one.

A power plant’s heat rate depends on its design, its operating conditions, and its level of electric power output. For existing coal-fired power plants, heat rates are typically in the range of 9,000–11,000 Btu/kWh. A plant with the industry average heat rate of 10,300 Btu/kwh will operate with an overall plant efficiency of about 33 percent.

Benefits of Lowering Heat Rate

For a coal-fired plant, fuel is by far the largest expense item, amounting to about 55 to 75 percent of total plant costs. Coal costs $1.50 – 2.00 per million Btu, or about $30 a ton, and a typical coal plant consumes about 6,000 tons per day. The heat content of coal ranges from of 8,000 to 12,000 Btu/lb. Accordingly, reducing a power plant’s heat rate can significantly lower fuel consumption and expense. At a typical 500 megawatt (MW) plant operating at 80 percent capacity factor and firing $2.00/MBtu bituminous coal, a 1-percent heat rate reduction will save about $700,000 in annual fuel costs.

Improvements in heat rate are also the first step in reducing carbon dioxide (CO2) and other emissions. Heat rate reductions are commercially proven to be the most cost-effective and immediate process for controlling CO2. A 1 percent heat rate reduction corresponds to a 1 percent reduction in CO2 emissions-about 40,000 tons/year-which could amount to significant savings if new regulations permit trading of CO2 credits or impose fees on CO2 emissions.

Heat rate reductions will also result in decreases in other emissions, such as nitrogen oxides (NOx), sulfur dioxide (SO2), particulates, and mercury. These reductions can help plants meet other compliance requirements, and in some cases, the benefit of emissions reduction may exceed the value of fuel savings.

Historical Heat Rates

Since the mid-1960s, the average heat rates of fossil-fueled electric power plants in the United States have gradually increased. Several factors have contributed to this slow degradation in unit performance. First was the introduction of nuclear generating units to provide an increasing share of baseload generation, along with the anticipation of a large expanding nuclear construction program into the future. With these low-cost generating units forecast to provide a large fraction of the baseload capacity, utilities devoted less attention to the maintenance and upkeep of their older fossil stations in anticipation of their retirements in the 1970s and 1980s.

This trend was exacerbated as nuclear construction costs escalated, reducing the funds available for maintaining fossil station performance, as well as diverting the attention of utility upper management from the operation of these stations. For those utilities that brought nuclear units online, many of the fossil plants that formerly comprised their system’s baseload capacity were changed to cycling duty. The thermal inefficiencies associated with start-ups, shut-downs, and swings in load, as well as extended periods of operation at less than full power, resulted in increased heat rates for these units. Generating units are designed and built to achieve their best heat rates when operated in steady state at full load.

Additionally, environmental regulations were enacted that forced many utilities to retrofit energy-consuming, pollution-control equipment such as Flue Gas Desulfurization (FGD) systems. The addition of such controls had many deleterious effects, including increase in auxiliary power consumption and decrease in boiler efficiency. This adverse trend started with the required addition of electro-static precipitators (ESPs) to remove particulate matter from the flue gas prior to exhausting it out the stack. These new ESPs increased the consumption of auxiliary power and created a pressure drop, forcing fans to work harder.

Simultaneously, the use of fuels like Powder River Basin (PRB) with higher moisture contents contributed to a reduction in unit performance.

Most recently, the proliferation of renewable and gas generation has, along with economic factors, resulted in a need for more flexible operation of the existing coal-fired fleet, necessitating more frequent cycling and lower turndown, which has a substantial negative effect on plant heat rates.

The challenge of improving fossil plant heat rates in the 1980s was made more difficult by declining coal quality, the penalties associated with retrofitting air emission control equipment, and the normal degradation associated with aging units. This latter concern continues today, as units are operated with more rigorous emission controls, beyond their expected operating lifetimes, and on increasingly flexible schedules.

With all these elements working against heat rate improvements, current estimates suggest efficiencies at many existing coal-fired power plants have dropped by several percentage points. Some of this efficiency might be recoverable, provided that the correct processes, procedures, and resources are applied and maintained.

capital and maintenance projects

In 2008-2009, EPRI developed a methodology to assess the costs and benefits of potential maintenance improvements to coal-fired power plants, and refined this methodology to assess the net annual benefit of potential capital improvements to these plants.

The assessment methodologies were then applied to a hypothetical 500-MW plant to calculate the potential benefits of capital improvements and maintenance projects, including heat rate reduction benefits, reductions in auxiliary load, capacity increases, equivalent forced outage rate (EFOR) improvements, and emissions benefits. The calculations were captured in two spreadsheets-one for capital projects and the other for maintenance projects. Inputs could be modified according to plant-specific circumstances, thus making it possible for individual utilities to use the methodology for scoping studies. The magnitude of the actual heat rate improvements are site specific, as are the drivers and economic benefits.


The assessment methodologies followed a six-step approach that divided the effort into logical steps designed to ensure a reasonably comprehensive and technically accurate analysis.

1. Identify major systems in a typical plant.
2. Identify typical or potential projects for each system.
3. Obtain input data and values (e.g. costs and heat rate improvement).
4. Characterize typical or potential projects for each system.
5. Summarize uncertainty and potential findings.
6. Conduct a reasonability check of results and input data.

Capital Projects

The report contained spreadsheets listing 32 capital projects. For each project, the spreadsheets identify the estimated capital cost, added O&M cost per year, heat rate reduction (percent and Btu/kWh), estimated auxiliary load benefit, capacity increase, EFOR improvement benefit, heat rate benefit, emissions benefit, added power sales benefits, and net annual benefit. At the time the project was completed and the report written, the emissions benefit related only to NOx and SO2, but the equations could easily be adapted to include CO2 and mercury.

The report could benefit multiple projects including: turbine steam seal upgrades, turbine section replacements, intelligent soot-blowing systems, automated boiler drains, coal-drying systems, air heater baskets, and combustion optimization. The results represent a wide range. Not all projects generated net benefits with a positive payback. Heat rate reductions ranged from 0.10 to 2.50 percent. The spreadsheets can be used by plant engineers and planners to develop realistic cases for making specific capital investments.

Maintenance Projects

The report also contained spreadsheets listing 25 maintenance projects and practices. For each entry, the spreadsheets identify the estimated initial maintenance cost, additional O&M costs per year, heat rate reduction (percent and Btu/kWh), estimated auxiliary load benefit, capacity increase, EFOR improvement benefit, heat rate benefit, emissions benefit, added power sales benefits, maintenance annual benefit-cost ratio, useful life, and payback in years.

Example projects included: replacing feed pump turbine steam seals, repairing steam and water leaks, boiler chemical cleaning, repairing boiler air in-leakage, cleaning air preheater coils, repairing condensate pumps, and repairing flue gas desulfurization (FGD) systems. The results were wide-ranging. Heat rate reductions spanned from 0.03 to 1.50 percent.

heat rate improvements at five sites

The EPRI Production Cost Optimization (PCO) project assisted participating members in implementing or enhancing heat rate optimization programs to reduce production costs through sustainable performance improvements.

The PCO assessment process consisted of benchmarking plant thermal performance using historical plant data to identify potential areas for performance improvement. In some instances a significant heat rate improvement was achieved with a recommitment to best operating practices, and without the need for capital expenditures on new technology.

Unit heat rate improved at four of the five plants in the time between their initial and follow-up assessments. While most plants had estimates of the improvement expected with the actions taken, it was not always possible to reconcile observed improvements with estimated improvements.

The plant participants were not always able to implement all recommendations and often had their own initiatives for outage work that resulted in decreased heat rate. Performance improvements were significant and ranged from 3 to 5 percent. This level represents an equal percentage of each plant’s annual fuel bill and demonstrates that making heat rate an integral part of maintenance and operations activities can yield real and lasting financial savings, as well as a significant reduction in CO2 and other emissions.

The five coal-fired units had net capacities ranging from 95 to 650 MW. The service ages of the plants ranged from 30 to 55 years. The units represented the variation in design, configuration, fuel supply, and vendors observed in plants throughout the US.

Common Issues

In the five plants that completed analyses and reports, the common issues included:

  • Combustion problems and high air heater/stack exit gas temperatures
  • Limited heat rate information availability
  • Need for training to raise heat rate awareness, including understanding controllable losses
  • Need for unit and equipment performance testing
  • Feedwater heater train performance problems
  • Need for sootblowing optimization

Common Recommendations

The following recommendations were common to the five units covered by follow-up analyses:

  • Provide heat rate awareness training to operations staff that is focused on the basics of heat rate, the cost of heat rate deviations, and actionable heat rate information for operations.
  • Make heat rate information readily available to more plant personnel. Sharing heat rate-related information with a broader segment of plant personnel can result in earlier identification and resolution of heat rate problems. Incorporating thinking about heat rate into day-to-day operational decisions can reduce overall plant heat rate.
  • Improve utilization of controllable losses information by operations staff. Incentivize operations staff to monitor and minimize controllable losses. Keep targets achievable within constraints of equipment and operating conditions. This may require sites to enhance, upgrade, or initiate real-time controllable losses displays.
  • Optimize sootblower operation. This can help to improve steam temperature control, normalize heat absorption patterns, and improve precipitator performance. Additional benefits include reduced air heater/stack exit gas temperatures, decline in circumferential cracking of boiler tubes, and reduced NOx emissions.
  • Initiate a routine testing program. A periodic testing program should be established to aid in early detection of changes in equipment performance and/or unit operation to improve maintenance scheduling efforts and reduce unscheduled outages. By utilizing station instrumentation, a reliable and repeatable trend of unit performance can be developed.
  • Increase Feedwater Heater Performance Monitoring. Heater levels and performance parameters should be monitored on a daily basis to maintain best performance. The Drain Cooler Approach (DCA) should be checked to ensure that steam is not entering the drain cooler. If this happens for an extended period of time, the heater will be damaged, resulting in tube leaks, off-design operation, increased maintenance, and higher unit heat rate.

Quantified Benefits of Implementing Recommendations

Plant heat rates were trended for one-month periods during the original PCO assessment, and then again during the follow-up assessment. The time elapsed between the original and follow-up assessments ranged from 20 to 24 months.

Some plants reported expected heat rate improvements from actions they had taken, which ranged from 200 to 400 Btu/kWh, or approximately 2 to 4 percent. While it was difficult to correlate specific improvements with measured data, it was clear from the assessments that plant efficiencies improved significantly at four of the five plants that completed follow-up assessments. The magnitude of the heat rate improvements ranged from 279 to 557 Btu/kWh at or near fullload operation, as shown in Figure 1. This represents an improvement in heat rate of approximately 3 to 5 percent. The results of this project are site specific and are not universally applicable to all coal-fired power plants.

figure 1

Fuel Savings and CO2 Benefits

With heat rate improvements ranging from 3 to 5 percent, the results of the PCO follow-up studies clearly demonstrate that plant heat rate can be favorably affected by operational and maintenance activities undertaken by plant owners.

Figure 2 shows the range of equivalent fuel savings for a 5 percent reduction in heat rate at generating units of three different sizes, and factoring for different levels of fuel costs. The figure demonstrates that these savings are significant. A five percent improvement in the heat rate of a 500-MW (net) power plant can amount to $3.5 million in annual fuel savings. It can also reduce CO2 emissions over 180,000 tons annually.

figure 2

fleetwide assessment and Case study

In 2010, EPRI conducted a study with a member utility to identify power plant efficiency improvements that could reduce carbon dioxide (CO2) emissions in all 12 coal-fired plants in the fleet.

The project was undertaken to show how improvements in coal plant energy efficiency could be used to reduce carbon dioxide (CO2) emissions. The utility established an internal team to explore its options for improving coal plant efficiency. The results focused on the amount of CO2 reduced, as well as on the cost per ton of that CO2. The estimated cost per ton of reduced CO2 can be used to determine which projects are viable based on the price of CO2 credits.

During the study, the project team applied a standardized methodology previously developed for evaluating efficiency improving projects in a single power plant.

In this project, the team compiled a list of feasible efficiency improvement options and conducted analyses to determine project-specific net annual benefits in relation to reduction of CO2 emissions. Team members compiled information from various internal sources and then added more projects from the EPRI capital projects report. All projects were listed in a spreadsheet and normalized to match each unit within their current operating system.

The study covered only projects for existing coal-fired power plants. The assumption was made that net plant output remained constant. If the proposed project happened to increase capacity along with efficiency, the fuel burn was reduced to hold net output constant. The plant could then calculate and summarize the CO2 emissions that were reduced or avoided.

The following steps were used to evaluate potential energy efficiency improvement projects for the fleet:

  • Assemble a team of experts within the utility that have collective knowledge covering all the units being investigated, and all the projects being considered.
  • Identify potential projects.
  • Identify coal-fired units to be included in the analysis.
  • Screen projects for feasibility of application to each unit in the fleet.
  • Determine project attributes for each application.
  • Evaluate applicable projects for each unit.
  • Develop project rankings based on the cost-benefit analysis for each application.
  • Prepare Pareto curves to provide management with a decision-making tool to prepare for any future carbon-related charges.

Issue fleet-specific reports.

The technology feasibility screening process identified more than 40 candidate projects, organized by six major plant systems, as listed in Table 1.

Using this list, the project team conducted a fatal-flaw analysis to determine the feasibility of the efficiency projects on a unit-by-unit basis. Because of their configurations, some plants did not qualify for particular projects. Numerous efficiency projects had already been completed in advance of the study.

Top Projects

Over 490 potential projects were identified and screened for feasibility. Of these, 174 projects were identified as feasible.

Analysis determined that several projects were justified, independent of the project’s economic life. The following projects were justified without any CO2 credits:

  • Boiler drain automation (12 units)
  • Air heater seals (8 units)
  • Station air systems (2 units)
  • Circulating water strainers (8 units)
  • Air heater baskets (4 units)
  • Condenser ball cleaning systems (8 units)

Key Observations

Many projects can improve plant efficiencies and reduce CO2 emissions. Analysis provides a tool that can be used to evaluate and rank potential projects by their projected benefits. Based on a 30-year economic life, analysis estimated that, if all 174 projects were implemented, the upper limit for fleet-wide coal plant CO2 reductions would be about two million tons per year (an approximate 5.3 percent reduction of current operating fleet CO2 emissions), at an estimated capital cost of over $800 million. However, initial evaluations indicated that some projects should be investigated further, regardless of the value of CO2, thus yielding about one million tons a year in reduction of CO2 emissions (an approximate 2.7 percent reduction in the fleet’s CO2 emissions).

The Pareto-type curve in Figure 3 shows cumulative CO2 reduction, as well as the cost per ton of that CO2. The x-axis represents projects ranked in order of cost per ton of CO2 from Project Numbers 1-174. The y-axis represent the cumulative tons of CO2 reduced per year by all projects (green bars), as well as the cost per ton of CO2 reduced by each project (blue line). The red line separates projects that may be justified with a net annual benefit that is ≤ $0/ton of CO2. Projects with a negative cost per ton of CO2 may be justified without credit for CO2.

figure 3

Flexible Operation

Flexible operation refers to a plant’s ability to operate in part-load, load-following, and cycling modes. This is often done in response to economic conditions and increased utilization of non-coal-based generation. Operating plants in flexible modes can result in reductions in plant efficiency and increased degradation of components due to constant swings in operating temperature and pressure.

A 2010 EPRI study identified cost-effective capital modifications and adjustments to plant operating procedures that would improve heat rates during cycling operations. The study identified 10 upgrade options:

  • Automated pulverizer supervisory controls
  • Boiler draft system control schemes and operating philosophy
  • Cooling system optimization
  • Feedwater heater drain system modifications
  • Minimization of flow, pressure, and temperature oscillations
  • Optimum partial load operation of air quality control systems
  • Performance monitoring
  • Reduction of warm-up flow for idle boiler feed pumps
  • Sliding pressure operation
  • Variable-speed drives

Cycle Alignment

Cycle alignment, also known as cycle isolation, refers to alignments in valves that reduce the high-energy fluid leakage from the steam cycle at a power plant. Certain leaking valves will cause a direct loss in generation, or an increase in fuel costs.

When used as part of an overall plant performance improvement program, cycle alignment programs have provided large gains at low costs. With improved cycle alignment, heat rate improvements in the range of 50 Btu/kWh (about 0.5 percent) are common. Units with problematic valves or no history of cycle-alignment maintenance may experience a large one-time heat rate improvement upon the implementation of such a program.

Various methods have been used to ensure proper cycle alignment, but an application’s success and costs vary depending upon the specific valves and unit designs involved. In an effort to help power companies optimize the application of cycle alignments, a 2011 EPRI project assessed cycle alignment activities and identified their costs and benefits. The study identified field methods to estimate the leakage rates in valves and used several real-life examples to illustrate how cycle alignment programs have been implemented.

Remote Monitoring Centers

Remote monitoring centers (RMCs) have been used for many years to track and improve equipment reliability. In many cases, these same RMCs have thermal performance software installed for monitoring heat rate. The value of finding and fixing reliability issues can often be quantified, but placing a value on heat rate monitoring is not so easy.

The project team visited RMCs at three power generating companies. The main priority of these RMCs was to improve reliability, but they also monitored for heat rate improvements. In addition to improvement in equipment reliability, all of the visited companies were able to verify heat rate improvements based on the activities of the monitoring centers. In many cases, the heat rate improvements were significant and well surpassed the incremental costs for monitoring heat rate in addition to reliability. Heat rate improvements in the range of 2.5 to 4 percent have been reported as attributable to actions of these remote monitoring centers.

Steam Turbine Steam Path Modifications

Over the past 20 years, an increased number of nuclear and fossil power plants have undertaken modifications to increase the power rating and/or improve the heat rate of selected units. Many of these actions have resulted from physical upgrades to steam turbine generators, as well as enhancements to auxiliary components.

EPRI conducted a survey to compile the current results of performance. Commonly reported heat rate improvements attributed to turbine modifications were in the range of 2 to 4 percent.

Heat Rate Improvement Program Guidelines

Power plant facilities with heat rate improvement programs perform better than those without such programs. A heat rate improvement program typically provides sufficient information for decision making with respect to timely maintenance actions, operational adjustments, and physical modifications.

Monitoring the performance of any power plant component includes the trending of parameters that also describe the performance of other plant components, providing insight and information on improving their operation as a whole. A performance program creates a culture that is centered on improving plant performance. Sharing performance data with plant staff strengthens their understanding of how each individual may contribute, ultimately making heat rate improvement a team effort.

Steam Turbine Performance Engineer’s Guide

The steam turbine is the workhorse of most power plants. Its performance and reliability relate directly to the performance and reliability of the power plant it serves. The actions of the turbine performance engineer are crucial to the turbine’s high level of performance.

The primary role of a steam turbine performance engineer is to improve and maintain the efficiency and power output of the steam turbine cycle. One of the measurements of success is improved turbine heat rate.


Power plants are designed for an optimal heat rate. While that heat rate may not be the lowest achievable at a given point in time, trade-offs occur with respect to capital and O&M costs, siting, and fuel. The average coal-fired power plant is now 40 years old. Over the course of four decades, these plants have been subject to physical modifications and repairs, and have suffered age-related degradation. Many of these modifications have included the addition of emissions controls, which typically have an adverse effect on heat rate. Since initial startup, many units have changed their fuel supplies, reduced staffing sizes, and been called on for flexible operations that create adverse effects on heat rates. By improving the performance of multiple integrated systems within a power plant, heat rates can be improved and facilities rendered more efficient.


S. Korellis is a Project Manager at EPRI.

More Power Engineering Issue Articles
Power Engineerng Issue Archives
View Power Generation Articles on