combined heat and power - michaels energy heat and power.pdf · 2016-10-11 · combined heat and...

Combined Heat and

Power

May 2013

[client]

[address]

[city] ∣ [state zip]

Michaels No.: x00xx00x

p 608.785.1900 ∣ 400 Main Street, Suite 200 ∣ La Crosse, WI 54601

Combined Heat and Power

Contents

Executive Summary ............................................................................................................. i

Introduction ...................................................................................................................... 1

Combined Heat and Power Initiatives around the Country ..................................................... 2

CHP – Perspective .............................................................................................................. 4

Types of Combined Heat and Power and Cost Effectiveness ................................................... 6

Topping Cycle CHP Plants ................................................................................................ 6

Gas Turbine CHP .......................................................................................................... 6

Internal Combustion Engine CHP ................................................................................... 7

Steam Turbine Topping Cycle CHP ................................................................................. 7

Backpressure Turbine CHP ............................................................................................ 8

Bottoming Cycle CHP Plants ............................................................................................. 9

Demand Side Management Case for CHP ............................................................................10

CHP Versus Conventional Delivery, Cost and Emissions .....................................................12

Fuel Switching Argument .............................................................................................14

Source Fuel Costs .......................................................................................................14

Customer Fuel Cost .....................................................................................................15

Emissions ...................................................................................................................15

CHP Program Framework ...................................................................................................17

All CHP Power Consumed on Site.....................................................................................17

All Heat Rejected by CHP Must be Used ...........................................................................17

Load Factor of 75% or Greater ........................................................................................17

Operate at Capacity During Summer Peak ........................................................................18

Custom Incentives Limited to 2 MW Capacity ...................................................................18

Study Requirement ........................................................................................................18

Works Cited ......................................................................................................................19

Combined Heat and Power Page | i

Executive Summary

Utility’s 2014-2018 Energy Efficiency Plan for its State customers includes a combined heat and

power component to be implemented under the existing custom efficiency program. The

purpose of this study is to briefly summarize the current state of CHP programs as part of DSM

portfolios in the US, discuss eligible types of CHP configurations, demonstrate the benefits of

CHP, and develop a framework for this component of custom efficiency.

Combined heat and power has gained much backing in recent years as a way to save energy,

reduce emissions, and make industry more profitable. A cursory review of issues discussed by

recent CHP stakeholder groups indicates large CHP requiring sales of electricity and/or thermal

energy to other end users is under consideration. This is not the case for Utility’s planned CHP

offering. Instead, Utility’s program will require all energy produced by customer CHP plants to

be consumed on site. This also happens to be most cost effective for customers.

Eligible types of CHP under the Utility program will include topping and bottoming cycle plants.

A topping cycle simply means electricity is extracted from thermal energy produced by burning

natural gas prior to thermal energy being released for facility thermal loads. Topping cycle CHP

includes gas turbines and internal combustion engine driven generators with waste heat used to

make hot water and/or steam for industrial processes. Another topping cycle option is

backpressure turbines, where customers produce high pressure steam to serve their highest

pressure/temperature loads and throttle steam for low pressure distribution systems. Rather

than throttling steam to lower pressures and wasting that potential opportunity to generate

highly valuable electricity, a turbine is installed to extract electricity with an exhaust pressure at

the desired low-pressure steam system setpoint.

A bottoming cycle extracts electricity after heat has been extracted for processes. Some high

temperature processes that may have sufficiently hot exhaust fluids (gasses or steam) include

rubber vulcanizing processes for tire manufacture, and exhaust from glass, steel, and

petrochemical plants. Since extracting electricity from lower temperature is more difficult and

because harnessing and channeling the heat to a power plant is less efficient and costly,

bottoming cycle CHP is considerably less common.

A hypothetical 2 MW CHP plant was analyzed for fuel consumption, cost, and emission

comparisons using three types of CHP, and two cases of purchasing electricity and natural gas

from utilities. One utility case includes purchasing coal-generated electricity. Coal produces

almost 75% of State’s electricity. The other utility case includes a natural gas-fired combined

cycle power plant. Just a few percent of State’s annual electricity is fueled by natural gas, but

forward looking trends indicate natural gas will be the dominant fuel of new power plants

across the country. Therefore, it is prudent to consider natural gas CHP as a comparison to

power purchased made with natural gas.

Results of this analysis are shown in the chart below.

Combined Heat and Power Page | ii

In each case, the cost and emissions comparisons are limited to only the approximate output of

a 2MW CHP plant. I.e., the electricity purchased from utilities or produced by CHP plants is the

same in all cases. The heat made available for processes by CHP plants or produced with on-

site boilers is the same for all cases.

In the conventional cases, since the purchase cost of electricity is assumed to be the same for

coal and natural gas derived electricity, the customer costs are the same for either option. This

is not unreasonable.

Conventional CHP includes the gas turbine and internal combustion engine sources of electricity

and useable heat. Since energy is extracted from combusted fuel ahead of generating

heat/steam for processes in the conventional cases, the overall fuel cost may likely be a bit

lower than the topping cycle using steam turbines. For the topping cycle, steam is first

generated and there are roughly 20% losses associated with the generation of steam.

The waste-heat generated CHP case has the lowest fuel cost since no incremental fuel is

required to generate electricity. However, as previously mentioned, it can be difficult and

expensive to capture and use waste heat for power generation. Each option has tradeoffs of

first cost, efficiency, and fuel cost, as many things do.

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Coal Natural Gas Conventional CHP Backpressure Turbine / Topping Cycle

Waste Heat Power

Conventional Gas and Electric Combined Heat And Power

Ton

s C

O2

Fuel Cost and Emissions for Generation of 13.1 GWH and 92,200 MMBTU Thermal Energy by Delivery Type

Fossil Fuel Cost

Customer Fuel Cost

Total CO2 Tons

Combined Heat and Power Page | iii

The last comparison is emissions. Clearly, CHP is a winner for the environment with lower CO2

emissions across the board. CHP is also beneficial to State, which imports nearly all of its fuel.

Finally, Utility’s CHP framework will include the following requirements:

All heat and power must be generated on site. This avoids many of the national stakeholder issues and is also most cost effective for customers.

The planned load factor of the CHP plant shall be 75% or greater annually. This helps ensure the system is sized to operate nearly fully loaded at all times.

Customers shall plan to operate the plant at 100% capacity during summer peak hours. This helps customers minimize demand and ratchet charges and provides the most benefit to ratepayers.

Incentives are limited to 2 MW of CHP capacity. Although larger plants are eligible, a maximum of 2 MW of CHP contributes to the incentive. This limits incentives to $1.0-$1.5 million per plant, allows for reasonably large plants while not consuming an inordinate portion of the portfolio budget.

A study by an independent consultant or contractor is required for pre-approval. This helps ensure the plant will meet program requirements and is cost effective for customers.

Combined Heat and Power Page | 1

Introduction

Utility’s Energy Efficiency Plan for 2014-2018 includes an opportunity to incorporate combined

heat and power (CHP) into its custom efficiency program. Specifically the EEP states the

following:

The Program also offers incentives for on-site combined heat and power projects that

are properly sized for the customer’s facility, and for which 100 percent of the energy

produced is consumed at the customer’s facility. All customers interested in installing a

combined heat and power system must obtain either a feasibility assessment or a site

assessment conducted by a qualified engineering firm or installation contractor, and

submit the project documentation to Utility for pre-approval.

The objectives of this paper include:

Examining the state of CHP as it relates to demand side management programs in other regions of the country.

Discussing the types of CHP that would be eligible under the program and associated constraints.

Making the case that CHP should be part of electric demand side management programs.

Providing a framework for a combined heat and power component under Utility’s custom efficiency program.


Combined Heat and Power Initiatives around the

Country

Combined heat and power has a lot of stakeholder momentum around the country although to

Utility’s knowledge there are no vibrant CHP programs or portions of programs that are part of

utility or state administered demand side management portfolios.

For the most part, the technology is not new but CHP is gathering force for its beneficial

characteristics which include, in net, virtually 100% conversion of incremental fuel (natural gas)

consumption to valuable electricity while capturing “waste heat” with an efficiency akin to a

conventional commercial or industrial boiler. Additional details for the case for CHP are outlined

below under Demand Side Management Case for CHP.

President Obama, in August of 2012, issued an executive order Accelerating Investment in

Industrial Energy Efficiency, which set a goal of increasing by 50% from 80 GW to 120 GW of

CHP generation by the year 2020. The Department of Energy and Environmental Protection

Agency are actively supporting the order as it will substantially reduce greenhouse gas

emissions.

The State and Local Energy Efficiency Action Network (SEE Action), supported by DOE and EPA

is playing a prominent role in promoting the President’s executive order. SEE Action released a

report in March of 2013, Guide to the Successful Implementation of State Combined Heat and

Power Policies, subtitled, Driving Ratepayer-Funded Efficiency through Regulatory Policies

Working Group.

Data presented in this report indicate there is 590 MW of CHP in State1. However, upon review

of the data, the vast majority of this CHP is in the form of “legacy” coal-fired power plants for

college campuses and food / ethanol production, bio-fuel plants for waste water treatment,

agriculture, and wood products, or it appears to be standby generation for other facilities. In

total, there appears to be only about 15 MW of modern natural-gas fired CHP with gas turbines

or internal combustion engines where the “waste heat” is used continuously.

The SEE Action report indicates that 72% of the nation’s installed CHP capacity is fueled by

natural gas. For State on the other hand, only 3.2% of its CHP is fueled by natural gas. The

vast majority of electrical energy produced by CHP plants in State comes from coal-fired power

plants located at manufacturing facilities and college/university campuses.

Notable issues discussed in the SEE Action report include interconnection standards, excess

power sales, and standby rates. Most of these issues do not apply to Utility’s energy efficiency

plan, which mandates that 100% of generated power be consumed on site. Design of standby

rates discussed in the SEE Action report is a potential issue and the handling of standby rates in

1 http://www.eea-inc.com/chpdata/index.html

http://www.eea-inc.com/chpdata/index.html


other jurisdictions of the country is incorporated into the section Demand Side Management

Case for CHP.

Currently, according to the DSIRE database, there are three states/utilities offering incentive

programs for CHP. The California Public Utilities Commission offers an incentive through the

Self-Generation Incentive Program of 48-50 cents per watt (utility dependent) of generation

capacity for internal combustion engines and gas-turbine CHP. This incentive is valid up to 1

MW and derated from there to 3 MW of generating capacity.

The New Jersey Clean Energy Program offers incentives of $2 per Watt up to 500 kW of

generating capacity, and $1 per Watt between 500 kW and 1 MW of capacity.

Southwest Gas in Arizona also offers an incentive program for CHP. Incentives vary between

40 and 50 cents per Watt depending on the total efficiency of the CHP unit. Other states and

utilities may offer CHP incentives in their renewable energy portfolio. State and utility grant and

loan programs in many cases also are applicable to CHP projects.

Lastly the National Governors Association established its “Policy Academy on Enhancing

Industry through Energy Efficiency & Combined Heat and Power”. The Academy includes policy

makers from five states: Alabama, Arkansas, Illinois, Iowa, and Tennessee. Activities in the

Academy include sharing lessons learned, establishing state action plans, and developing a

report of findings and recommendations. A draft report has been produced and is with the

Governor’s office at this time and due for release in June 2013 and is therefore not available for

incorporation into Utility’s EEP at this time.


CHP – Perspective

Combined heat and power plants are typically perceived as distributed generation with waste

heat recovery. Indeed, a good portion of the recent SEE Action report for CHP policies deals

with interconnections with the power grid, limitations on selling power to other local consumers,

transmission, distribution, and substation issues, and tariff issues. The tariff issues involve

standby power rates, which are utility provider rates that are specifically designed for customers

with large CHP generation. As a backup provider of power, utilities need to maintain

generating, transmission and distribution capacity for these customers and therefore standby

rates are used to avoid other customers shouldering this cost.

While discussion of these factors is not germane to Utility, as this paper will describe below, it

seems these issues demonstrate that CHP as viewed by these policy makers is that of relatively

large power plants in search of demand for heat and in some cases, power to sell. This is not

the intent of the CHP portion of Utility’s custom efficiency program. For Utility’s program, which

promotes the most cost effective applications and designs of CHP for its customers, these issues

are not a factor.

In order for CHP to be cost effective for customers, particularly in the Midwest where electricity

prices are low, there has to be a need for the heat rejection at all times, preferably while power

generation is operating at 100% capacity for maximum return on investment. Therefore,

contrary to popular perspectives, CHP is not a power plant that provides free heat but rather it

is an inexpensive, extremely efficient means of generating electricity for customers that need a

lot of heat, preferably steam, all the time, especially during peak summer periods.

The best candidates for CHP are those that purchase large volumes of natural gas to make

steam and/or hot water all year long, particularly in the summer. When this is the case, CHP

can turn inexpensive thermal Btus into highly valued electrical Btus, virtually one for one, with

no heat loss (adiabatic) in the power generation process. Note that as discussed below, wasted

heat from central power generation plants varies from about 50% for combined cycle natural

gas generation plants to about 70% for steam power plants, regardless of fuel type, but in

State, the dominant fuel source is coal.

With the adiabatic conversion of thermal energy to electrical energy, it is easy to see the merits

of CHP using Energy Information Administration nationwide average prices for industrial natural

gas and electricity prices as shown in Table 1.

TABLE 1: ENERGY COST BY FUEL TYPE

Value of 1,000,000

Btus of:

Natural Gas Electricity

$3.87 $19.63


The types of CHP plants promoted by Utility’s program include precisely this value-added

process, with no heat loss.


Types of Combined Heat and Power and Cost

Effectiveness

The SEE Action report includes two types of CHP – the topping cycle and the bottoming cycle.

As it would infer, the topping cycle extracts electrical energy from a gas turbine, steam turbine,

or internal combustion engine and the heat rejected from these “prime movers” is used for

processes. Topping cycles always require incrementally more fuel, which is converted to

electricity at the customer site, compared to providing heat alone on location and buying power

from the grid.

The bottoming cycle on the other hand is generally a waste-heat-to-power design and may or

may not require incremental heat. In the case of power generation from hot exhaust gases,

there is no incremental heat required. In the case of extracting power from steam before it is

condensed and returned to a boiler, as in a rubber vulcanizing process, it may require more

heat and fuel. This latter arrangement is rare, the explanation for which is beyond the scope of

this paper.

Topping Cycle CHP Plants

There are several specific types of CHP that belong to the larger subset of topping CHP plants.

These include gas turbines, internal combustion engines, steam turbines, and technically,

backpressure turbines, which are great applications for CHP that are rarely mentioned in

literature as a CHP opportunity.

Gas Turbine CHP

Gas turbines are essentially jet engines with a turbine compressor, natural gas fired heat input,

and expansion through a second turbine, which turns a generator to make electricity. Exhaust

gases from these turbines is still very hot, and ideal for making steam. Commercial combined

cycle plants make 1000F, 2,400 psig steam for the steam Rankine-cycle generating portion of

the plant. Microturbines, another option for gas turbine CHP, produce much lower exhaust

temperatures of only about 500F2, and are therefore more efficient as gas turbine generators.

A gas-turbine topping cycle plant is depicted in Figure 1. Tracking the Btus from natural gas to

energy and losses, in this case 20% of the natural gas energy/heat is converted to electricity.

Note that due to the fuel cost ratio, one dollar of natural gas produces one dollar of electricity in

this case and the heat is still available for use and the customer needs this heat anyway.

Turbine exhaust enters a steam generator or waste heat boiler with an operating thermal

efficiency of 80%, like a conventional boiler. The losses are 20% of the remaining 80% left in

the exhaust, resulting in 16% heat rejection (heat loss from turbines and the boiler shell may

2 Industrial Application Guide for Innovative Combined Heat and Power, Energy Solutions Center, January 2004


be one or two percent – negligible). The remaining 64% is useful steam that the customer

would otherwise generate with 80% thermal efficiency in a conventional gas-fired boiler.

FIGURE 1: GAS TURBINE CHP

Internal Combustion Engine CHP

The configuration for an internal combustion engine CHP plant is virtually the same as the gas-

turbine configuration with two exceptions. The first is that the prime mover is the IC engine

rather than a gas turbine of course, but the second issue is considerable and critical. The

second issue is that heat from an IC engine is primarily absorbed from the water jacket, as with

any car, truck, or other, IC engine. This temperature is only about 180F and insufficient for

making steam. However, heat can be extracted from the exhaust (700F-1000F) to make

steam, but recoverable heat in the form of steam is limited to about one third of the total heat

recovery. The rest of the recovered heat would be in the form of ~180F hot water. This can

substantially limit the usefulness and therefore applicability of the IC engine CHP option.

Steam Turbine Topping Cycle CHP

The steam turbine topping cycle generates electricity with a steam turbine, as with a

commercial power plant. For this plant, the customer may have relatively constant demand for

low pressure steam, perhaps 150 psig and lower. This application would include the generation

of higher pressure steam for the purpose of expanding the steam through the turbine to

generate highly valuable electricity, and the exhaust steam is used for the customer’s steam

Gas Turbine

Natu

ral G

as

$1

In

80% Turbine Exhaust

Heat

Steam

16% Loss

64% Steam

Electricity Pays for Natural Gas, 64%

Captured for Process

20% Power

$1 Electricity


loads. An example of this is provided in Figure 2. In this example, the extracted electricity is a

quite low percentage of the energy input. This is because the steam pressures are low for

producing power efficiently, but again, this CHP option produces valuable electricity directly with

thermal energy with virtually no heat loss.

FIGURE 2: STEAM TURBINE TOPPING CYCLE

Backpressure Turbine CHP

Backpressure turbines are often the missing treasure of CHP opportunity, as this technology can

be readily retrofitted into many industrial plants.

Industrial steam plants generate steam for the process and equipment with the highest

required steam pressure. This high pressure steam may represent only a small percentage of

the total thermal load for the plant. Most of the steam system distributed to other equipment is

lower pressure, sometimes considerably lower. Steam pressure is easily reduced with a steam

pressure reducing station, and these are very common in large industrial facilities.

The pressure reducing process (throttling) is adiabatic, but it is irreversible and wastes an

opportunity to generate electricity with no thermal losses. Instead of these pressure reducing

stations, customers can install “backpressure” turbines to expand the steam through a steam

turbine to extract valuable electricity – to the desired lower pressure. The incremental natural

gas required is limited to only the Btus of electrical energy extracted, with virtually no thermal

losses.

According to the DOE’s Advanced Manufacturing Office, “off the shelf” back pressure turbine

generators are available with capacities as low as 50 kW. Prices range from $900/kW for 150

kW and $200/kW for 2 MW systems, and likely depend on pressure available for generation3.

At $400/kW a 1 MW turbine set could produce $526,000 of electricity per year for a first cost of

$400,000.

3 Steam20_turbogenerators.pdf

Natural Gas

$1 In

20% Loss

Turbine

5% Power

$0.25 Electricity

300 psig Steam

75% 100 psig Steam

Generator


Bottoming Cycle CHP Plants

As mentioned previously, the availability of steam generation of electricity from a bottoming

cycle plant is greatly limited, especially for Utility’s customer base. Those cases are limited to

only customers with relatively high temperature/pressure steam loads with a quite high process

steam exhaust available for turning turbines. Therefore, bottoming cycle CHP plants are

essentially limited to waste heat power generation.

Waste heat power generation uses the same power cycle (Rankine cycle) as a steam-turbine

electricity-generating plant, except the working fluid is typically some type of refrigerant that

allows the cycle to operate at lower temperatures.

Power generation and cycle efficiency are a strong function of temperature/pressure at the

turbine inlet. The reason conventional Rankine cycle power plants have a limited efficiency of

30-40% is conventional materials (steel) lose strength at higher temperatures. The reason

combined cycle natural gas power plants are substantially more efficient is the top-end turbine

inlet temperature is over 2000F, which can be withstood by much lower quantities of exotic

materials that make up the expansion turbine that drives the generator. Then exhaust heat is

extracted to make steam for a conventional Rankine-cycle steam power plant.

The power plant cycle with relatively low waste heat temperatures is quite inefficient. Although

the energy source is essentially free, cost effectiveness is impacted as physical material and

equipment sizes get much larger and electrical output per unit of heat rejected drops rapidly at

low temperatures.

Generally speaking, waste heat has to be at least 300F for organic Rankine cycles to operate,

but at this temperature, efficiencies are very low; e.g., 5%. Higher temperature exhaust can

result in substantially greater efficiency to 15-20%, and this may be available with glass,

primary metals, petroleum and chemical manufacturing facilities. One of Utility’s customers has

sufficient temperature and volume of exhaust gas flow to generate 3 MW of power with no

added fuel or emissions. Capturing and channeling this heat to an organic Rankine-cycle power

plant is of course a substantial and expensive barrier, but warrants more investigation.


Demand Side Management Case for CHP

Demand side management programs by their nature affect marginal generating capacity, and

electrical energy consumption – i.e., the next MW of capacity required and the next MWH of

electrical generation required. Therefore, it seems prudent to examine recent past and

projected generation makeup for this exercise.

Nationwide, natural gas is projected to dominate new generating capacity as far into the future

as the Department of Energy forecasts, as shown in Figure 34. Through 2035 natural gas is

expected to account for 60% of the added capacity and electrical generation from natural gas

over the same period is expected to grow by 42% to a share of 28% of total electrical energy

generation.

FIGURE 3: NEW GENERATING CAPACITY BY FUEL TYPE

In 2010 the Energy Information Administration reported that in the period from 2000-2010 that

nearly two thirds of added natural gas capacity was from combined cycle plants with gas

turbine (peaking plants) making up virtually the rest of new natural gas capacity5.

Currently, according to the EPA’s The Emissions & Generation Resource Integrated Database for

2012 (eGRID2012) Technical Support Document and associated data, only a tiny fraction of

4 EIA Annual Energy Outlook 2012 – www.eia.gov/forecasts/aeo/ 5 http://www.eia.gov/todayinenergy/detail.cfm?id=2070

http://www.eia.gov/forecasts/aeo/

http://www.eia.gov/todayinenergy/detail.cfm?id=2070


State’s commercial electricity is produced by natural gas, with only two combined cycle natural

gas power plants. According to the report, these plants combined have a utilization factor of

only about 10%, indicating they are primarily used for peak loads.

Figure 4 shows the energy sources for electrical energy generation for the State with coal

making up almost 75% of electrical generation. FigureFigure 5 shows CO2 emissions per kWh

for the same fuels, for State and the entire country6.

FIGURE 4: POWER GENERATION (KWH) ENERGY SOURCES FROM STATE PLANTS

6 National data from http://www.eia.gov/tools/faqs/faq.cfm?id=74&t=11

Coal

Wind

Natural Gas

Nuclear

http://www.eia.gov/tools/faqs/faq.cfm?id=74&t=11


FIGURE 5: CO2 EMISSIONS BY SOURCE FOR STATE PLANTS

The average coal-fired power plant in the United States has a net efficiency of approximately

32%7. The difference between net and gross is the electrical consumption consumed by the

power plant itself. Net efficiency is representative of power delivered to the grid per unit of

energy input. A typical natural gas combined cycle power plant has a net plant efficiency of

approximately 51%8. Plant net efficiency for both conventional coal and combined cycle

generation varies somewhat depending on a variety of design features and operating

characteristics but for purposes of this paper, these efficiencies are well suited.

Note that although combined cycle plants are a bit less than twice as efficient compared to coal,

the CO2 emissions per unit of electrical energy output are half for combined cycle. This is due

to the makeup of the fuel. Burning natural gas produces a lower fraction of CO2 and a higher

fraction of H2O compared to coal.

CHP Versus Conventional Delivery, Cost and Emissions

Utility conducted a case study for a hypothetical 2 MW CHP plant of various types discussed

above, and compared results to conventional central plant provided power and customer

generated heat with natural gas.

Source fuel (coal or natural gas) energy cost, end user energy cost, and CO2 emissions were

analyzed for producing 13.1 GWH of electricity and 92,200 MMBTU thermal energy for process

loads.

Inputs for this analysis include:

7 Power Generation from Coal, International Energy Agency 8 Natural Gas Combined Cycle Plant, US DOE

0.00 0.50 1.00 1.50 2.00 2.50

Coal

Wind

Natural Gas

Nuclear

All Generation

lb CO2/kWh National

lb CO2/kWh Iowa


1. State’s coal is predominantly sub bituminous from Wyoming’s Powder River Basin with a heat content of 8,800 Btu/lb at a cost of $10.55 per ton9 and a delivery cost of $15 per ton10.

2. Natural gas prices are based on the 12 month trailing average for industrial users ($3.87/MMBtu) and are assumed to be the same for central combined cycle power plants and large industrial users11.

3. Emissions for coal and natural gas conventional power plants are calculated from EPA’s eGRID report, specifically for Iowa.

4. Value of electricity is assumed to be a weighted average $0.06 per kWh. 5. Calculations are based on power and heat generated from a 2 MW CHP plant with a

0.75 load factor, 8760 hours per year. 6. In every case, 13.1 GWH and 92,200 MMBTU are generated for use at the customer

facility.

Results are shown in Figure 6 with discussion points to follow. It must be noted that gas prime

mover (turbines and engines) efficiencies and heat recovery heat exchanger effectiveness

varies and therefore, CHP fuel costs will vary depending on these factors. This is evidenced in

the results.

9 http://www.eia.gov/coal/news_markets/ 10 http://www.eia.gov/coal/transportationrates/trend-coal.cfm 11 http://www.eia.gov/dnav/ng/hist/n3035us3M.htm

http://www.eia.gov/coal/news_markets/

http://www.eia.gov/coal/transportationrates/trend-coal.cfm

http://www.eia.gov/dnav/ng/hist/n3035us3M.htm


FIGURE 6: FUEL COST AND EMISSIONS BY DELIVERY OPTION

Fuel Switching Argument

Fuel switching is a persistent concern for DSM programs and therefore, would be a concern for

CHP as part of a DSM portfolio. Clearly as shown in Figure 6, net natural gas consumption for

CHP derived heat and power is lower than that for power provided by a combined cycle central

plant with 51% efficiency and the status quo boiler steam generating process at the end user

site with 80% efficiency.

Considered another way, each Btu of electrical energy (e.g. 3413 Btu/kWh) is extracted one for

one (100% thermal efficiency) from thermal energy produced by natural gas. This is compared

to a ratio of about 1:2 (50% efficiency) from a combined cycle natural gas plant and 1:3 (33%

efficiency) for a steam plant, mostly regardless of fuel source.

Source Fuel Costs

Source fuels in this analysis include coal and natural gas – fossil fuels that are burned to

generate electricity in central commercial power plants and natural gas burned at customer

sites to generate electricity or process heating. Even using cheap coal for generating electricity

at the central power plant and generating thermal energy on site is likely to have a higher

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20,000

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$200,000

$400,000

$600,000

$800,000

$1,000,000

$1,200,000

$1,400,000

Coal Natural Gas Conventional CHP Backpressure Turbine / Topping Cycle

Waste Heat Power

Conventional Gas and Electric Combined Heat And Power

Ton

s C

O2

Fuel Cost and Emissions for Generation of 13.1 GWH and 92,200 MMBTU Thermal Energy by Delivery Type

Fossil Fuel Cost

Customer Fuel Cost

Total CO2 Tons


source fuel cost than CHP. Compared to CHP, power purchased from a natural gas combined

cycle power plant and at the customer’s site for thermal loads has about 25% higher source

fuel costs.

Customer Fuel Cost

Generating electricity, which is five times more valuable on a Btu basis directly from thermal

Btus is fully demonstrated when comparing customer fuel costs for conventional heat and

power purchases compared to CHP heat and power purchases. Heat and power is generated

on site for less than half the cost of purchasing natural gas and electricity each from the

utility(ies).

Emissions

Combined heat and power produces just over half as much CO2 compared to power generated

from coal power plants, which supply almost 75% of State’s electricity plus site-generated CO2

for producing process steam/heat. Combined heat and power emits about 20% less emissions

than buying power from a natural-gas fired combined cycle plant and generating steam/heat

with natural gas at the customer site.

Lastly, weighted average emissions for all Iowa power generation, including wind and nuclear

with zero emissions was calculated to be 1.67 lb per kWh versus 1.01 lb per kWh for combined

cycle natural gas generation, and 2.22 lb per kWh for coal generation. The results for the

weighted generation emissions compared to CHP are shown in Figure 7. Heat and power

provided by CHP results in 38% less CO2 emissions compared to purchasing “average” kWh

from the grid and meeting thermal loads on site with natural gas boilers.


FIGURE 7: CHP AND WEIGHTED ELECTRIC GENERATION EMISSIONS FOR STATE

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5,000

10,000

15,000

20,000

25,000

Iowa Wtd Average Conventional CHP Backpressure Turbine / Topping Cycle

Waste Heat Power

Conventional Combined Heat and Power

An

nu

al T

on

s C

O2

CO2 Emissions by Source Type for 13.1 GWH Electric and 92,200 MMBTU Thermal


CHP Program Framework

After a cursory review of recent CHP studies, policy issues, and analyzing CHP from

environmental, economic, and resource perspectives, Utility believes CHP is clear winner for its

customers and for State. The Utility CHP component of its custom efficiency program will avoid

most of the policy issues of the national dialogue today while providing the best solution for its

customers. The framework for Utility’s CHP component of custom efficiency includes the

following elements:

All power must be consumed on site

All heat rejection must be used for process and/or space heating The planned load factor shall be at least 75%, annually Customers must plan to operate at 100% CHP capacity at all times during summer on-

peak hours Incentives shall follow custom rebate calculation rules with a limit of 2 MW of installed

capacity An energy study is required for pre approval

Addressing each of these elements one by one:

All CHP Power Consumed on Site

This is consistent with Utility’s original and revised EEP for 2014-2018. Furthermore, this rule

avoids most of the issues stakeholders are having with interconnections, selling power to other

end users, and standby rates.

All Heat Rejected by CHP Must be Used

Cost effectiveness of CHP is at its highest when the CHP plant is sized for heat output that

never surpasses the minimum demand of the facility/plant. Customers are therefore

encouraged to size their CHP plants for the heating load while extracting as much valuable

electricity as possible.

Load Factor of 75% or Greater

Again, CHP is most cost effective when it can be used at all times and at high capacity. If the

system is sized for the minimum thermal load, there are virtually no reasons to not operate the

plant at 100% capacity. Consider that while the thermal supply from the CHP plant will never

exceed customer demand, there are likely only a few customers for which it is possible to

produce more power than is needed on site. Lastly, electrical Btus will always be worth more

than thermal Btus from natural gas regardless of how high gas prices may rise – since natural

gas is a major fuel source for power generation throughout the country.


Operate at Capacity During Summer Peak

The best candidates for CHP will be on seasonal, time of use rates and therefore, it behooves

them to minimize their summer peak demand. A CHP shutdown, planned or otherwise during

the facility’s peak summer usage will hit the customer hard with demand charges and ratchet

clauses all year. This will provide a high level of motivation to maximize electrical output during

on-peak hours.

Custom Incentives Limited to 2 MW Capacity

Custom rebates from Utility are calculated as 1.5 multiplied by the actual energy dollar savings.

Calculating an incentive for CHP-displaced electricity for a 2 MW CHP plant operating with the

above characteristics would result in an incentive of $1.0-$1.5 million. This is historically the

high end of custom rebates for Utility’s largest customers and therefore, seems reasonable for

CHP as well. Note that larger systems will be incentivized but only the fraction that represents

the maximum 2 MW limit will be the basis for the incentive.

Study Requirement

The CHP feasibility study will confirm that the proposed CHP plant meets all the stated program

criteria and also estimated implementation cost and simple payback, which factors into the

incentive calculation. Since CHP is likely to produce some large incentives, it is very important

to have all cost/benefit information available to customers prior to making go / no-go decisions.


Works Cited

Advanced Manufacturing Office. Jan. 2012. Energy Tips: Steam, Steam Tip Sheet #20.

DOE/GO-102012-3409. Washington, DC: U.S. Department of Energy.

Analysis, Inc. & Exergy Partners Corp. Jan 2004. Industrial Application Guide for Innovative

Combined Heat and Power. Prepared for Energy Solutions Center & U.S. Department of

Energy. Washington, DC.

Diem, et. al. 2012. The Emissions & Generations Resource Integrated Database for 2012

(eGRID2012) Technical Support Document. April 2012 EP-D-06-001. Washington, DC:

U.S. Environmental Protection Agency Office of Atmospheric Programs.

Hampson, A,. 2012. Combined Heat and Power Installation Database. http://www.eea-

inc.com/chpdata/index.html. Washington, DC: ICF International. Energy and

Environmental

Hedman et. al. 2013. Guide to the Successful Implementation of State Combined Heat and

Power Policies. March 2013 DOE/EE-0838. Washington, DC: State and Local Energy

Efficiency Action Network.

Jones, et. al. 2010. Power Generation for Coal: Measuring and Reporting Efficiency

Performance and CO2 Emissions. OECD/AEA 2010. Paris, France: IEA Coal Industry

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National Energy Technology Laboratory. 2007. “Natural Gas Combined-Cycle Plant”. Cost and

Performance Baseline for Fossil Energy Plants, Vol. I (May) DOE/NETL-2007/1281.

B_NGCC_FClass_051607.

U.S. Energy Information Administration. 2011. Today in Energy.

http://www.eia.gov/todayinenergy/detail.cfm?id=2070. Washington, DC: U.S.

Department of Energy.

U.S. Energy Information Administration. 2012. Annual Energy Outlook 2012 with Projections to

2035. www.eia.gov/forecasts/aeo/. Washington, DC: U.S. Department of Energy.

U.S. Energy Information Administration. 2012. Coal Transportation Rates to the Electric Power

Sector. http://www.eia.gov/coal/transportationrates/trend-coal.cfm. Washington, DC:

U.S. Department of Energy.



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U.S. Energy Information Administration. 2013. Coal News and Markets.

http://www.eia.gov/coal/news_markets/. Washington, DC: U.S. Department of Energy.

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