Impact of Combined Heat and Power
 

on Energy Use and Carbon Emissions 

in the Dry Mill Ethanol Process 

U.S. Environmental Protection Agency 

Combined Heat and Power Partnership 

Updated 

November 2007 

For more information about the EPA CHP Partnership, 

visit: www.epa.gov/chp. 
 

EPA Combined Heat and Power Partnership 

The EPA CHP Partnership is a voluntary program that seeks to 

reduce the environmental impact of power generation by promoting 

the use of CHP. CHP is an efficient, clean, and reliable approach to 

generating power and thermal energy from a single fuel source. 

CHP can increase operational efficiency and decrease energy 

costs, while reducing emissions of greenhouse gases that 

contribute t o climate change. The Partnership works closely with 

energy users, the CHP industry, state and local governments, and 

other stakeholders to support the development of new projects and 

promote their energy, environmental, and economic benefits. 

The Partnership provides informational resources about CHP 

technologies, incentives, emissions profiles, and many other items 

on its Web site: wZw.epa.gov/chp. For more information contact 

Neeharika Naik-Dhungel at (202) 343-9553 or

 naik-dhungel.neeharika@epa.gov. 

Report prepared by: Energy and Environmental Analysis, Inc. (www.eea-inc.com) for the U. S. 

Environmental Protection Agency, Combined Heat and Power Partnership, November 2007. 
 

 

Executive Summary 

Fuel ethanol is one of the fastest growing segments of U.S. industry. Driven by provisions of the 

renewable fuels standard (RFS) in the Energy Policy Act of 2005 that increased the mandated 

use of renewable fuels, including ethanol and biodiesel, and a phase-out of methyl tertiary butyl 

ether (MTBE) as an oxygenate for reformulated gasoline, production of ethanol has increased 

by more than 300 percent since 2000. In 2006 the industry’s 110 operating plants produced 4.9 

billion gallons of ethanol, an increase of 25 percent over the previous year. At mid 2007, there 

were 82 new ethanol plants and twelve expansions under construction, which will add close to 7 

billion gallons of new production capacity by 2009,1

 far surpassing the RFS mandate of 7.5 

billion gallons in 2012. 

Historically, corn ethanol plants are classified into two types: wet milling and dry milling. In wet 

milling plants, corn kernels are soaked in water containing sulfur dioxide (SO2), which softens 

the kernels and loosens the hulls. Kernels are then degermed, and oil is extracted from the 

separated germs. The remaining kernels are ground, and the starch and gluten are separated. 

The starch is used for ethanol production. In dry milling plants, the whole dry kernels are milled. 

The milled kernels are sent to fermenters, and the starch portion is fermented into ethanol. The 

remaining, unfermentable portions are produced as distilled grains and solubles (DGS) and 

used for animal feed. Dry mill plants have become the primary production process for fuel 

ethanol. All corn ethanol plants that have come online in the past several years are dry milling 

plants, and the Renewable Fuels Association estimates that essentially all new plants expected 

to come online in the next few years will also be dry milling plants. 

Dry mill ethanol plants have traditionally used natural gas as the process fuel for production. 

Natural gas is used to raise steam for mash cooking, distillation, and evaporation. It is also used 

directly in DGS dryers and in thermal oxidizers that destroy the volatile organic compounds 

(VOCs) present in the dryer exhaust. 

The industry has made great progress in reducing energy consumption since its start in the 

1980s; to produce a gallon of ethanol, today’s dry mill plants only use about half of the energy 

used by the earliest plants.2

 Still, natural gas prices are on the rise, and energy costs are 

second only to raw material costs in the dry mill process. These factors are driving the industry 

to undertake further efforts to reduce energy use, or to switch from natural gas to other fuels 

such as coal, wood chips, or even the use of DGS and other process byproducts. 

Along with increased production efficiencies and expanded fuel capabilities, combined heat and 

power (CHP) is increasingly being considered as an efficient energy services option by many 

ethanol plant owner and financing groups. CHP is an efficient, clean, and reliable energy 

services alternative, based on generating electricity on site. CHP avoids line losses, increases 

reliability, and captures much of the heat energy normally wasted in power generation to supply 

steam and other thermal needs at the site. CHP systems typically achieve total system 

efficiencies of 60 to 80 percent compared to only about 50 percent for conventional separate 

electricity and thermal energy generation (see Figure 1). By efficiently providing electricity and 

thermal energy from the same fuel source at the point of use, CHP significantly reduces the total 

fuel used by a business or industrial plant, along with the corresponding emissions of carbon 

dioxide (CO2) and other pollutants. 

1 Ethanol Industry Outlook 2007. Renewable Fuels Association. February 2007 and EPA CHPP data. 2

 Huo, H., Wang, M., & Wu, M. Life Cycle and Greenhouse Gas Emissions Impacts of Different Corn Ethanol 

Plant Types. Argonne National Laboratory. 2007. 

1 
 

Figure 1. Total Efficiency Benefits of Combined Heat and Power 

To date, CHP and ethanol industry stakeholders have recognized that the efficiencies of CHP 

could further improve energy use patterns of dry mill ethanol plants, but the levels of impact 

have been unclear. This paper summarizes an analysis of state-of-the-art natural gas-, coal-, 

and biomass-fueled dry mill ethanol plants—comparing energy consumption and CO2 emissions 

of the ethanol production process with and without CHP systems. Only the energy consumed in 

the dry mill conversion process itself was examined; the analysis does not consider the energy 

consumed in growing, harvesting, and transporting the feedstock corn, or in transporting the 

ethanol product itself. The analysis examines the impact of CHP on total energy consumption, 

including the impact on reductions in central station power fuel use and CO2 emissions caused 

by displacing power purchases with CHP. The analysis shows that the use of CHP can result in 

reductions in total energy use of almost 55 percent over state-of-the-art dry mill ethanol plants 

that purchase central station power rather than use CHP. With certain CHP configurations, CO2 

emission reductions from using CHP to displace central station power even exceed the CO2 

emissions from the CHP system and ethanol plant, resulting in negative net CO2 emissions for 

the plant compared with base case conditions. 

Fuel selection at new dry mill ethanol plants is increasingly a decision based on perceptions of 

future natural gas prices and the cost and availability of alternatives such as coal or biomass. 

Whatever fuel is used, CHP increases the total energy efficiency of the dry mill process, 

providing reductions in both overall fuel use and total CO2 emissions. CHP, using any of a suite 

of technologies, can be applied with a variety of fuels to save operating costs for the user and 

reduce overall fuel use and CO2 emissions. These factors promise to be important 

considerations for the future of ethanol production as low carbon fuel standards are being 

evaluated at both the state and federal levels, and as carbon footprint becomes a critical 

industry measure. 

CHP is not new at ethanol plants. Five gas turbine CHP systems similar to the cases described 

in this paper are currently operating at dry mill ethanol plants in the United States.3

 The first 

coal-fueled dry mill ethanol plants are just coming online, and at least one includes a steam 

3

 Gas turbine CHP systems are installed at Adkins Energy LLC, Lena, Illinois; U.S. Energy Partners, Russell, 

Kansas.; Northeast Missouri Grain (POET Macon), Macon, Missouri.; Otter Creek Ethanol (POET Ashton), Ashton, 

Iowa; and Missouri Ethanol (POET Laddonia), Laddonia, Missouri. 

2 
 

 

 

turbine CHP system similar to the system described in this analysis.4 In addition, a biomassfueled CHP system is undergoing startup at an ethanol plant in Minnesota.5 

Baseline Energy Consumption Profiles for Dry Mill Ethanol Production Facilities 

Dry mill ethanol is the fastest growing market segment in the industry. It is comprised of 

dedicated ethanol facilities producing between 20 and more than 100 million gallons (MG) of 

ethanol per year. Energy is the second largest production cost for dry mill ethanol plants, 

surpassed only by the cost of the corn itself. Dry mill plants use significant amounts of steam for 

mash cooking, distillation, and evaporation. Steam or natural gas is also used for drying 

byproduct solids. (Dried distilled grains with solubles, or DDGS, are produced by drying the wet 

cake left over from the distillation process.) Electricity is used for process motors, grain 

preparation, and a variety of plant loads. A typical 50-MG-per-year (MGY) dry mill plant will have 

steam loads of 100,000 to 150,000 pounds per hour, and power demands of 4 to 6 megawatts 

(MW) depending on its vintage and mix of operations. 

Table 1 provides energy consumption estimates (natural gas-, coal-, and biomass-fueled) for a 

50-MGY state-of-the-art dry mill ethanol plant based on information from engineering and 

energy suppliers. The estimates reflect expected energy performance of new ethanol plants 

installed in 2006 and 2007. The assumptions in Table 1 are based on ethanol production only 

(e.g., no CO2 recovery) and 100 percent drying of the wet cake for cattle feed product (DDGS). 

The natural gas energy estimates are based on multiple packaged natural gas boilers 

generating steam for the production process. Natural gas is also used directly in the DDGS 

dryer, and in the regenerative thermal oxidizer that destroys the VOCs present in the dryer 

exhaust. The coal and biomass system estimates are based on fluidized bed boiler systems that 

integrate exhaust from a steam-heated DDGS dryer as combustion air to the boiler; in this case, 

VOC destruction occurs in the boiler itself and there is no need for a separate thermal oxidizer. 

The per-gallon electricity consumption is higher for the coal and biomass systems than for 

natural gas systems (0.90 kilowatt-hours [kWh]/gallon versus 0.75 kWh/gallon for natural gas) 

due to an estimated 20 percent additional power requirement for fuel handling, processing, and 

boiler ancillaries. The total steam consumption per gallon of ethanol is higher for the coal and 

biomass systems as well, reflecting the use of a steam DDGS dryer instead of a direct-fired 

system. The efficiency of the biomass fluidized bed boiler is lower than the coal boiler (72 

percent versus 75 percent), reflecting a higher moisture content in biomass fuels. There is no 

direct fuel consumption for either a DDGS dryer or a thermal oxidizer in the coal or biomassfueled systems.6 

4

 Central Illinois Energy in Canton, Illinois., is a 37 million gallons (MG) per year plant fueled by coal fines and coal. It 

incorporates a fluidized bed boiler/steam turbine CHP system. 

5 Central Minnesota Ethanol in Little Falls, Minnesota., is installing a biomass gasifier, fluidized bed boiler system with 

a steam turbine generator.

6 The configurations evaluated represent typical state-of-the-art dry mill plants for each of the fuels. There are, 

however, a number of variations in use. Several natural gas-fueled plants generate a majority of their process steam 

using heat recovery boilers on the exhaust of nonregenerative thermal oxidizers. There is at least one coal-fueled 

plant that uses natural gas in a DDGS dryer and thermal oxidizer. 

3 
 

 

 

 

 

 

 

Table 1. Energy Consumption Assumptions for State-of-the-Art Dry Mill Ethanol Plants7 

Natural GasFueled Plant Coal-Fueled 

Plant 

BiomassFueled Plant References 

Plant Capacity, MG/yr 

Ethanol Yield, Gal/bushel 

Operating Hours 

50 

2.8 

8,592 

50 

2.8 

8,592 

50 

2.8 

8,592 

1 

Electric Consumption, kWh/Gal 

Average Electric Demand, MW 

Annual Electric Consumption, MWh 

0.75 

4.4 

37,500 

0.90 

5.2 

45,000 

0.90 

5.2 

45,000 

Nat gas: 1,2; Coal: 2,4 

Calculated 

Calculated 

Boiler Type 

Boiler Efficiency, percent (HHV8

) 

Boiler Fuel Use for Process Steam, Btu/Gal 

Process Steam Use, MMBtu/hr 

Annual Process Steam Use, MMBtu 

Packaged 

80% 

21,500 

100.1 

860,000 

Fluidized Bed 

78% 

22,050 

100.1 

860,000 

Fluidized Bed 

72% 

22,050 

100.1 

860,000 

1, 2, 4, 5 

4, 5 

Nat gas: 1,2,3,4; Coal: 2,4,5 

Calculated 

Calculated 

DDGS Dryer Type 

Amount of Wet Cake Dried, percent 

DDGS Dryer Fuel Use, Btu/Gal 

DDGS Dryer Steam Use, Btu/Gal 

Annual DDGS Dryer Fuel Use, MMBtu 

Annual DDGS Dryer Steam Use, MMBtu 

Direct Fired 

100% 

10,500 

NA 

525,000 

NA 

Steam 

100% 

NA 

14,200 

NA 

710,000 

Steam 

100% 

NA 

14,200 

NA 

710,000 

2, 5 

Calculated 

1, 2, 3, 4 

4, 5 

Calculated 

Calculated 

Thermal Oxidizer 

Thermal Oxidizer Fuel Use, Btu/Gal 

Annual Thermal Oxidizer Fuel Use, MMBtu 

RTO 

330 

16,500 

Boiler 

NA 

NA 

Boiler 

NA 

NA 

2, 5 

4, 5, 6 

Calculated 

Total Annual Steam Use, MMBtu 

Total Annual Boiler Fuel Use, MMBtu 

Total Annual Fuel Use, MMBtu 

Total Fuel Use, Btu/Gal 

860,000 

1,075,000 

1,616,500 

32,330 

1,570,000 

2,015,000 

2,015,000 

40,260 

1,570,000 

2,183,000 

2,183,000 

43,660 

Calculated 

Calculated 

Calculated 

Calculated 

References for Table 1: 

1. “Dry Mill Ethanol Plants,” Bill Roddy, ICM, Governors’ Ethanol Coalition, Kansas City, Kansas, February 10, 2006. 

2. Personal Communications with Matt Haakenstad, U.S. Energy Services. 

3. “Thermal Requirements: Coal vs. Natural Gas,” Casey Whelan, U.S. Energy Services, Fuel Ethanol Workshop, 

Milwaukee, Wisconsin, June 20, 2006. 

4. Personal communications with Steffan Mueller, University of Illinois at Chicago; data from Henneman Engineering 

5. “Research Investigation for the Potential Use of Illinois Coal in Dry Mill Ethanol Plants,” Energy Resources Center, 

University of Illinois at Chicago, October 2006. 

6. Energy and Environmental Analysis, Inc. estimates. 

7 “State-of-the-art” reflects the energy performance of new dry mill ethanol plants in 2006 and 2007.
 8 All of the efficiencies and energy consumption values quoted in this paper are based on higher heating value (HHV) 

fuel consumption, which includes the heat of condensation of the water vapor in the combustion products. 

Engineering and scientific literature often use the lower heating value (LHV), which does not include the heat of 

condensation of the water vapor in the combustion products. The HHV is greater than the LHV by approximately 10
 

percent for natural gas, 6 to 8 percent for oil (liquid petroleum products), and 5 percent for coal. 

4 
 

 

 

The Impact of CHP on Plant Energy Consumption Profiles 

Based on the energy-use assumptions outlined in Table 1, an analysis was conducted of the 

relative energy consumption of conventional, non-CHP, dry mill ethanol boiler plant designs 

compared with those incorporating CHP. The analysis was based on state-of-the-art, 50 MGY 

natural gas-, coal-, and biomass-fueled ethanol plants as described above. Three base case 

plant designs were considered: 

•	 Natural Gas Base Case—Conventional (non-CHP) natural gas boiler, gas-fired DDGS dryer, 

and regenerative thermal oxidizer. 

•	 Coal Base Case—Non-CHP fluidized bed coal boiler with exhaust from a steam-heated 

DDGS dryer integrated into the boiler intake for VOC control. 

•	 Biomass Base Case—Non-CHP fluidized bed coal boiler with exhaust from a steam-heated 

DDGS dryer integrated into the boiler intake for VOC control. 

All three base cases were assumed to operate 24 hours per day, seven days per week, for 51 

weeks per year (8,592 hours). Table 2 presents the hourly steam and electric demands of the 

three base cases using the energy consumption assumptions outlined in Table 1. Steam 

consumption is based on delivering 150 pounds per square inch gauge (PSIG) saturated steam 

to the process (energy input from the boiler of 1,022 Btu [British thermal units] per pound of 

steam). 

Table 2. Base Case Steam and Electric Demands for 50 Million Gallons per Year Dry Mill 

Ethanol Plants 

Natural Gas 

Base Case 

Coal 

Base Case 

Biomass 

Base Case 

Plant Capacity, MGY 

Operating Hours 

Electric Consumption, kWh/Gal 

Average Electric Demand, MW 

Annual Electric Consumption, MWh 

Process Steam Use, MMBtu/hr 

Dryer Steam Use, MMBtu/hr 

Total Steam Use, MMBtu/hr 

Annual Steam Use, MMBtu 

50 

8,592 

0.75 

4.4 

37,500 

100.1 

NA 

100.1 

860,000 

50 

8,592 

0.90 

5.2 

45,000 

100.1 

82.6 

182.6 

1,570,000 

50 

8,592 

0.90 

5.2 

45,000 

100.1 

82.6 

182.6 

1,570,000 

Five CHP system configurations were evaluated and compared to the three base case non-CHP 

ethanol plants: 

•	 Natural Gas CHP 

Case 1: Gas turbine/supplemental-fired heat recovery steam generator (HRSG)—Electric 

output sized to meet plant demand; supplemental firing needed in the HRSG to 

augment steam recovered from the gas turbine exhaust. 

5 
 

 

Case 2: Gas turbine with power export—Thermal output sized to meet plant steam load 

without supplemental firing; excess power generated for export. 

Case 3: Gas turbine/steam turbine with power export (combined cycle)—Thermal output 

sized to meet plant steam load without supplemental firing; steam turbine added to 

generate additional power from high-pressure steam before going to process; 

maximum power generated for export. 

• Coal CHP 

Case 4: High-pressure fluidized bed coal boiler with steam turbine generator—Exhaust from 

steam-heated DDGS dryer integrated into the boiler intake for combustion air and 

VOC destruction. 

• Biomass CHP 

Case 5: High-pressure fluidized bed biomass boiler with steam turbine generator—Exhaust 

from steam-heated DDGS dryer integrated into the boiler intake for combustion air 

and VOC destruction. 

Table 3 provides the CHP system descriptions and performance characteristics assumed for the 

analysis. Note that in Case 1—the gas turbine sized to meet the plant’s electricity load—the 

exhaust from the gas turbine can only provide about 23 percent of the plant’s steam needs. A 

duct burner in the HRSG is used to provide supplemental heat to generate the additional steam 

at high efficiency (approaching 90 percent). In Cases 2 and 3, the system is sized to meet the 

thermal needs of the plant without supplemental firing. In Case 2, the simple-cycle gas turbine 

produces 22.1 MW of power and 100 MMBtu per hour of steam. The electrical output far 

exceeds the average 4.4 MW power requirements of the plant, meaning that excess power 

would need to be exported to the grid. This configuration might be installed by a third-party 

service provider, or as a joint venture between an ethanol plant and the servicing utility. The 

Case 3 combined-cycle configuration further increases the power output of the CHP system to 

30 MW. It does so by producing higher-pressure steam in the HRSG and driving a steam 

turbine to generate additional power before sending steam to the production process at 150 

PSIG. Again, this configuration might be installed by a third-party energy provider or a utilityethanol plant joint venture. 

The sizes of the coal- and biomass-fueled steam turbine systems are set by the steam demand 

and power requirements of the plant. The CHP systems analyzed consist of 180,000 pounds 

per hour fluidized bed boilers producing steam at pressures and temperatures higher than the 

process requirements (600 PSIG and 600°F). The entire steam output of the boilers enters 

back-pressure steam turbines where 5 MW of electricity is generated before the steam exits the 

turbine at the 150 PSIG pressure conditions required for the process.9

 The capacity of the 

steam turbine generator is approximately 95 percent of the average plant power demand, 

ensuring that all generated power can be used on site. 

9 Additional power could be generated in Cases 4 and 5 with higher-pressure boilers. Power output was limited in 

these cases to ensure all output could be used onsite, and to minimize incremental boiler costs over the base cases. 

6 
 

 

Table 3. CHP Case Descriptions 

CHP Case 1 CHP Case 2 CHP Case 3 CHP Case 4 CHP Case 5 

CHP System 

Net Electric Capacity, MW 

System Availability, percent 

Annual Operating Hours 

Annual Electric Generation, MWh 

CHP Steam Generation, MMBtu/hr 

Supplemental Firing Steam, MMBtu/hr 

Process Steam Generation, MMBtu/hr 

Annual Process Steam Generation, 

MMBtu 

Gas 

Turbine/FiredHRSG 

4.0 

97% 

8,334 

33,337 

22.5 

77.6 

100.1 

834,200 

Gas 

Turbine/HRSG 

22.1 

97% 

8,334 

184,187 

100.1 

NA 

100.1 

834,200 

Gas 

Combined 

Cycle 

30.0 

97% 

8,334 

250,027 

100.1 

NA 

100.1 

834,200 

Coal 

Boiler/Steam 

Turbine 

5.0 

95% 

8,334 

40,812 

204.3 

NA 

182.6 

1,521,800 

Biomass 

Boiler/Steam 

Turbine 

5.0 

95% 

8,334 

40,812 

204.3 

NA 

182.6 

1,521,800 

Table 4 compares the overall plant energy consumption profile of the three natural gas CHP 

cases to the natural gas base case. All three CHP cases increase the total fuel use at the plant, 

but plant electricity purchases are reduced by 89 percent. In Case 1, the fuel use increase is 

only marginal: about 6 percent more fuel use than the base case. In Cases 2 and 3, where 

much more power is generated than is needed at the plant, the increases are 62 and 90 

percent, respectively. 

Table 4. CHP Plant Energy Consumption Comparison—Natural Gas 

Characteristics 

Gas Base 

Case 

No CHP 

CHP Case 1 

Gas Turbine 

With Duct 

Firing 

CHP Case 2 

Gas Turbine 

With Export 

CHP Case 3 

Combined 

Cycle 

With Export 

Plant Capacity, MGY 50 50 50 50 

Average Electric Demand, MW 4.4 4.4 4.4 4.4 

CHP Capacity, MW 0 4.0 22.1 30.0 

CHP Availability, percent n/a 97% 97% 97% 

Electric Generated, MWh 0 33,337 184,187 250,027 

Electric Purchased, MWh 37,500 4,163 4,163 4,163 

Electric Exported, MWh 0 0 150,850 216,690 

Annual CHP Steam, MMBtu 0 834,200 834,200 834,200 

Annual Boiler Steam, MMBtu 860,000 25,800 25,800 25,800 

CHP Turbine Fuel Use, MMBtu 0 422,846 2,057,103 2,510,327 

Duct Firing Fuel Use, MMBtu 0 718,533 0 0 

Boiler Fuel Use, MMBtu 1,075,000 32,250 32,250 32,250 

Dryer/TO Fuel Use, MMBtu 541,500 541,500 541,500 541,500 

Total Plant Fuel Use, MMBtu 1,616,500 1,715,129 2,630,853 3,084,077 

Total Plant Fuel Use, Btu/Gal 32,330 34,303 52,617 61,682 

7 
 

Table 5 compares the overall plant energy consumption profile of the coal and biomass base 

cases to their respective CHP cases. Again, both CHP cases increase the total fuel use at the 

plant to provide the additional energy contained in high-pressure steam that will be turned into 

power in the steam turbine. Plant electricity purchases are reduced by 93 percent for both 

cases. 

Table 5. CHP Plant Energy Consumption Comparison—Coal and Biomass 

Characteristics 

Coal Base 

Case 

No CHP 

Case 4 

Coal CHP 

Boiler/Steam 

Turbine 

Biomass Base 

Case 

No CHP 

Case 5 

Biomass CHP 

Boiler/Steam 

Turbine 

Plant Capacity, MGY 50 50 50 50 

Average Electric Demand, MW 5.2 5.2 5.2 5.2 

CHP Capacity, MW 0 5.0 0 5.0 

CHP Availability, percent n/a 95% n/a 95% 

Electric Generated, MWh 0 40,812 0 40,812 

Electric Purchased, MWh 45,000 4,188 45,000 4,188 

Electric Exported, MWh 0 0 0 0 

Annual Boiler Steam, MMBtu 1,570,000 1,755,000 1,570,000 1,755,000 

Annual Process Steam, MMBtu 1,570,000 1,570,000 1,570,000 1,570,000 

Boiler Fuel Use, MMBtu 2,015,026 2,250,313 2,182,944 2,437,839 

Dryer/TO Fuel Use, MMBtu 0 0 0 0 

Total Plant Fuel Use, MMBtu 2,015,026 2,250,313 2,182,994 2,437,839 

Total Plant Fuel Use, Btu/Gal 40,300 45,005 43,660 48,760 

The economic value of CHP is a trade-off between capital costs, fuel costs at the plant, and 

decreased electricity purchases from the utility. While CHP increases the amount of fuel used at 

the plant in each of the CHP cases, it significantly reduces purchased electricity requirements. 

Whether this trade-off makes sense on an economic basis is site specific. It depends on the 

relative costs to the plant of purchased electricity and fuels; the capital and nonfuel operating 

costs of the CHP system; and the value of ancillary services, such as enhanced power reliability 

to the plant operator or the value of exported power, as in Cases 2 and 3. 

The Impact of CHP on Total Energy Use and CO2 Emissions 

From an overall energy and environmental policy perspective, it is essential to examine the 

impact of CHP on total energy consumption. This evaluation includes the effect on reductions in 

central station power fuel use and CO2 emissions caused by displacing power purchases with 

electricity generated on site by CHP. Table 6 compares the total energy consumption of the 

three natural gas CHP cases with the base case plant and central station fuel consumption. 

Central station fuel use and CO2 emissions were calculated based on the 2007 eGRID U.S. 

average fossil heat rate—equal to 10,215 Btu/kWh—and average fossil CO2 emissions of 1,867 

pounds per megawatt-hour (MWh). Transmission and distribution losses were assumed to be 7 

percent based on U.S. Department of Energy estimates of average annual transmission and 

8 
 

 

 

 

 

 

 

distribution system losses.10 CO2 emissions at the ethanol plant were calculated based on 117 

pounds of CO2 per MMBtu of natural gas consumed. 

As shown in the table, CHP reduces both the total energy used by the dry mill ethanol process 

and the total CO2 emissions. In Case 1, overall fuel use is reduced by 13 percent on a Btu-pergallon basis, and CO2 emissions are reduced by 21 percent on a pound-per-gallon basis. As 

more central station power is displaced in Cases 2 and 3, overall net fuel used to produce a 

gallon of ethanol, and associated net CO2 emissions, are further reduced. In Case 3, CHP 

reduces total net fuel consumption by 55 percent; CO2 emission reductions from displacing 

central station power exceed the CO2 emissions at the plant itself, resulting in negative net CO2 

emissions for the CHP system compared with base case conditions. 

Table 6. CHP Total Energy Consumption Comparison—Natural Gas 

Characteristics Base Case 

No CHP 

CHP Case 1 

Gas Turbine 

With Duct 

Firing 

CHP Case 2 

Gas Turbine 

With Export 

CHP Case 3 

Combined 

Cycle 

With Export 

Plant Fuel Use 

Total Plant Fuel Use, MMBtu 

Total Plant Fuel Use, Btu/Gal 

Central Station Fuel Use 

Purchased Power—MMBtu 

Export Power—MMBtu 

Total Net Fuel Use, MMBtu 

Net Fuel Use, Btu/Gal 

Plant CO2 Emissions, Tons/yr 

Central Station CO2 Emissions, Tons/yr 

Net CO2 Emissions, Tons/yr 

Net CO2 Emissions, lb/Gal 

1,616,500 

32,330 

411,548 

0 

2,028,048 

40,560 

94,565 

37,641 

132,206 

5.29 

1,715,129 

34,303 

45,688 

0 

1,760,817 

35,215 

100,335 

4,179 

104,514 

4.18 

2,630,853 

52,617 

45,688 

-1,539,633 

1,136,908 

22,738 

153,905 

-136,639 

17,265 

0.69 

3,084,077 

61,682 

45,688 

-2,211,628 

918,137 

18,363 

180,419 

-198,101 

-17,683 

-0.71 

Table 7 compares the total energy consumption of the coal and biomass CHP cases with their 

respective base cases. Central station fuel use and CO2 emissions were again based on the 

2007 eGRID U.S. average fossil heat rate—equal to 10,215 Btu/kWh—and average fossil CO2 

emissions of 1,867 pounds per MWh. Transmission and distribution losses were assumed to be 

7 percent based on DOE estimates of average annual losses. CO2 emissions at the ethanol 

plant were calculated based on industry-accepted values of 220 pounds of CO2 per MMBtu of 

coal. Biogenic biomass is considered carbon neutral—neither adding nor subtracting carbon 

emissions from the carbon cycle—and was assumed to have zero CO2 emissions. As shown, 

CHP again reduces both the total energy used by the dry mill ethanol process and the total CO2 

emissions. CHP reduces overall fuel use by 9 percent and CO2 emissions by approximately 5.6 

percent in the case of coal. CHP provides a total fuel reduction of 8 percent in the case of 

biomass-fueled ethanol production and results in CO2 reductions of 91 percent. 

10 No transmission and distribution losses were included in the calculation of central station fuel use and CO2 

emissions displaced by power exports from the CHP systems. 

9 
 

 

 

 

 

Table 7. CHP Total Energy Consumption Comparison—Coal and Biomass 

Characteristics 

Coal Base 

Case 

No CHP 

Case 4 

Coal CHP 

Boiler/Steam 

Turbine 

Biomass Base 

Case 

No CHP 

Case 5 

Biomass CHP 

Boiler/Steam 

Turbine 

Plant Fuel Use 

Total Plant Fuel Use, MMBtu 

Total Plant Fuel Use, Btu/Gal 

Central Station Fuel Use 

Purchased Power – MMBtu 

Export Power – MMBtu 

Total Net Fuel Use, MMBtu 

Net Fuel Use, Btu/Gal 

Plant CO2 Emissions, Tons/yr 

Central Station CO2 Emissions, Tons/yr 

Net CO2 Emissions, Tons/yr 

Net CO2 Emissions, lb/Gal 

2,015,026 

40,300 

493,858 

0 

2,508,884 

50,178 

221,653 

45,169 

266,822 

10.67 

2,250,313 

45,005 

45,962 

0 

2,296,275 

45,925 

247,534 

4,204 

251,738 

10.07 

2,182,994 

43,660 

493,858 

0 

2,676,852 

53,540 

0 

45,169 

45,169 

1.81 

2,437,839 

48,760 

45,962 

0 

289,801 

49,675 

0 

4,204 

4,204 

0.17 

Conclusions 

As shown above, use of CHP can lower the overall fuel use and CO2 emissions attributable to 

ethanol production at dry mill plants. Figure 2 compares the total fuel use impacts across the 

three base cases and five CHP cases. Note that the total fuel consumption—fuel consumed at 

the ethanol plant, as well as at the central station power facility to produce electricity purchased 

by the plant—is less for the base case natural gas ethanol plant than for either the coal or 

biomass base cases. 

In all cases, fuel consumption at the plant increases with the use of CHP. However, total net fuel 

consumption is reduced, as electricity generated by the CHP systems displaces less efficient 

central station power. In the two natural gas CHP cases with excess power available for export 

(Cases 2 and 3), the displaced central station fuel represents a significant credit against 

increased fuel use at the plant. The total fuel savings for Cases 2 and 3 are 44 percent and 55 

percent, respectively, over the natural gas base case. 

10 
Figure 2. Total Net Fuel Consumption for Dry Mill Ethanol Plants—Btu/Gallon 

0 

10,000 

20,000 

30,000 

40,000 

50,000 

60,000 

70,000 

Nat Gas 

Base 

CHP 

Case 1 

CHP 

Case 2 

CHP 

Case 3 

Coal 

Base 

CHP 

Case 4 

Biomass 

Base 

CHP 

Case 5 

Total Net Fuel Use, Btu/gallon 

Central Station Fuel Plant Fuel Displaced Central Station Fuel 

Figure 3 compares the impact of CHP on total CO2 emissions. Total CO2 emissions for the 

natural gas base case—CO2 emissions at the ethanol plant as well as at the central station 

power facility to produce electricity purchased by the plant—are significantly lower than for the 

coal base case. CO2 emissions for the biomass base case are the lowest, consisting of the 

central station emissions to provide purchased power to the plant. 

Total CO2 emissions are reduced for all CHP cases compared to their respective base case 

plants. Again, displaced central station emissions for Cases 2 and 3—the two natural gas CHP 

cases with excess power available for export—represent a significant CO2 savings. Total net 

CO2 emissions in Case 2 represent an 87 percent reduction in CO2 emissions compared to the 

natural gas base case. Total plant CO2 emissions for Case 3 are actually less than the 

displaced central station emissions, resulting in a negative (-0.71 pounds per gallon) net CO2 

emissions rate compared to the base case. 

Figure 3. Total Net CO2 Emissions for Dry Mill Ethanol Plants—Pounds/Gallon 

-1 

0 

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

Nat Gas 

Base 

CHP 

Case 1 

CHP 

Case 2 

CHP 

Case 3 

Coal 

Base 

CHP 

Case 4 

Biomass 

Base 

CHP 

Case 5 

Total Net CO2 Emissions, lb/gallon 

Central Station CO2 Plant CO2 Displaced Central Station CO2 

11