Combined Heat and Power (CHP)
Level 1 Feasibility Analysis
Prepared for
Company B
Any town, USA
men?
&EPA COMBINED HEAT AND
ROWER PARTNERSHIP

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Company B
Level 1 CHP Feasibility Study
Combined Heat and Power (CHP)
Level 1 Feasibility Analysis
Company B
Any town, USA
1. Executive Summary
The EPA CHP Partnership has performed a Level 1 Preliminary Economic Analysis of
the installation of a combined heat and power (CHP) system at Company B's facility in
Anytown, USA.1 The purpose of this analysis is to determine whether CHP is technically
appropriate at this site and whether CHP would offer significant potential economic
benefit to Company B, in order for the company to make a decision about whether to
fund a more comprehensive study. We have analyzed the existing electrical and thermal
needs of the site, have gathered anecdotal data regarding the site operations and existing
equipment, and have spoken to site personnel about the current and planned utility plant
needs of the facility. Our results indicate that the site is potentially a good candidate for a
CHP project.
To run an economic analysis of a system with this level of data required the use of
assumptions and averages. This preliminary analysis should therefore be considered an
indicator of technical and economic potential only. The EPA CHP Partnership does not
design or install CHP systems and cannot guarantee the economic savings projected in
this analysis. Where assumptions have been made, we have attempted to be realistic or
conservative. These assumptions will be detailed in the following report and suggestions
will be provided as to the scope of engineering that would be part of a Level 2 Feasibility
Analysis if Company B chooses to proceed to the next step of project development.
The Company B facility in Anytown, USA, has approximately one million square feet of
conditioned space on the campus. Although the operation is single shift, the rigorously
controlled environment of this research facility requires 100% outside air for supply and
roughly 30 air changes per hour. These conditions impose significant chilled water and
hot water requirements for terminal reheat. Medium pressure steam (100 psig) is used
during the day for animal sanitation. The facility has a base electric load of 3500
kilowatts (kW). It is possible that the city of Anytown, USA, could build the facility,
generate power for their system, and sell steam to the Company B campus at a discount.
This analysis looks primarily at the marginal cost of generation (operating costs only—
including CHP system fuel, CHP maintenance costs, and a credit for CHP thermal
output) for the various options considered. It also looks at the impact of the difference in
gas transportation costs imposed by the city of Anytown, USA, and Utility B. The
analysis modeled four gas turbine CHP systems at two natural gas pricing levels—
1 The analysis was performed by Energy and Environmental Analysis, Inc, 1655 N. Fort Myer Drive,
Arlington, VA, 22209. EEA is a technical subcontractor supporting the EPA CHP Partnership.
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Company B
Level 1 CHP Feasibility Study
$8/million British thermal unit (MMBtu) and $11/MMBtu. The systems are sized to meet
the base thermal requirements of the facility so that 100% of the system's thermal output
can be used on site. This approach to CHP system design is the most fuel efficient, most
environmentally beneficial, and usually provides the best return on investment. Two of
the systems evaluated produce power in excess of the facility's base electrical needs. In a
Level 2 analysis, once detailed thermal profiles of the site have been developed, other
system sizes and configurations should be explored. Table 1 summarizes the options that
were studied and the resulting marginal cost of generation.
Table 1 - Summary of Results

Option 1
Option 2
Option 3
Option 4
Gas Turbine
Turbine A*
Turbine B*
Turbine C*
Turbine C*
Number of Turbines
1
1
1
2
Total Capacity (kW)
3,490
3,495
4,550
9,100
Turnkey Price
$5,095,000
$6,750,000
$5,774,000
$9,624,000
Marginal Cost of
Generation at $8/MMBtu
$0.0590/kWh
$0.0538/kWh
$0.0582/kWh
$0.0632/kWh
Marginal Cost of
Generation at $11/MMBtu
$0.0788/kWh
$0.0718/kWh
$0.0770/kWh
$0.0839/kWh
* Turbines A, B, and C represent actual gas turbines. In a customized feasibility analysis, the EPA CHP
Partnership would identify the turbine model and manufacturer.
A number of conclusions can be drawn from the results presented:
•	A CHP system appears to be a viable energy management option for Company B.
A Level 2 study should evaluate the impact of various ownership options for the
CHP system, including having the system completely owned and operated by
Company B or partnering with the city of Anytown, USA, to build the facility and
arrange to buy steam at a discount from the utility.
•	If the power is to be used solely on site, either the Turbine A or the Turbine B gas
turbine systems appear to be viable candidates. The difference in the marginal
cost of generation was not sufficient to rule out either turbine, nor was the
difference in installed costs. Maintenance contract issues, as well as basic
maintainability of each machine, could make a difference in the economics and
should be evaluated in the Level 2 study.
•	Supplementary firing to raise additional steam in the heat recovery steam
generator is important to the overall performance of the Turbine A or the Turbine
B system.
•	If the facility is to be constructed and owned by the utility (or in partnership with
the utility), then the single Turbine C gas turbine system appears to be a viable
choice. Supplementary firing (even at the cost of installing emissions after
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Company B
Level 1 CHP Feasibility Study
treatment2) should be considered for this machine and investigated in the Level 2
study.
•	The option with two Turbine C turbines did not perform as well as the other
options on a marginal cost of generation basis; this outcome is primarily because
the thermal output of this option could be greater than the needs of Company B.
•	Although marginal cost was the primary measure of comparative performance in
this analysis and is most often the determining factor for dispatch decisions, it
should noted that other critical considerations are often included in investment
decisions. These considerations could include capital costs, emissions profile, and
other potential benefits to the site, such as enhanced power reliability.
2 Supplementary firing was not considered for either of the Turbine C options in this analysis because of
the impact on emissions. Turbine C can meet current Anytown, USA emissions standards without after
treatment. The addition of supplemental duct burners, however, might require the use of after treatment.
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Company B
Level 1 CHP Feasibility Study
2. Preliminary Analysis Details and Assumptions
Facility Description
Company B's campus in Anytown, USA, is engaged in research and development. The
facility is based in an area that has a moderate year-round climate. The 70-acre park-like
campus in Anytown, USA, is located within close proximity to several major academic
research institutions and numerous leading-edge companies in the region.
There are approximately one million square feet of conditioned space on the campus.
Although the operation is single shift, the rigorously controlled environment of this
research facility requires 100% outside air for supply and roughly 30 air changes per
hour. These conditions impose significant chilled water and hot water requirements for
terminal reheat. Medium pressure steam (100 psig) is used during the day for animal
sanitation.
Power Requirements - The facility's electric and thermal loads were established by
evaluating 15-minute interval data for gas and electric meters in 2004. Based on this
analysis, the facility has a peak electric demand of approximately 8,000 kW, yearly
average demand of about 4,700 kW, and a base electric load of 3,500 kW. The base
power demand is primarily used to operate the air handlers that provide the 30 air
changes per hour. Figure 1 illustrates the facility's average demand for 2004. From
Figure 1, it can be seen that the minimum average demand occurs in the month of March.
Figure 2 displays interval demand data for the month of March and indicates that the
minimum demand occurred on March 28, 2004. Figure 3 displays the interval demand
data for March 28. Figures 1, 2, and 3 confirm the 3500 kW base load power demand.
Figure 1 - Average Hourly Demand
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Average 3000 	n	
Demand (kW)
2000
1000 —I— — — — —I—I — I—I— — — -
Month
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Company B
Level 1 CHP Feasibility Study
Figure 2 - Interval Demand Data for the Month of March
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Figure 3 - Interval Demand Data for March 28, 2004
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Thermal Requirements - Figure 4 demonstrates the facility's current average hourly
demand for natural gas based on monthly natural gas bills.
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Company B
Level 1 CHP Feasibility Study
Figure 4 - Average Hourly Natural Gas Consumption
35.00
30.00
25.00
Average Gas 2g go
Cosumption
(MMBtu/hr)
15.00
10.00
5.00
0.00
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Month
As described above, natural gas is currently used for hot water (primarily for terminal
reheat) and steam for process cleaning. The process steam is used during daily
operations. Hot water is used to heat supply air to ensure the buildings meet the design
point of 72°F (when necessary). Company B has made the corporate decision to replace
their centrifugal chillers with double effect absorption chillers. Based on weather data
and load data provided by Company B, Dr. John Smith of the city of Anytown, USA,
developed an estimate of the facility's chilled water loads and the steam that would be
required by the double effect absorbers to meet the estimated chilled water load. This
analysis used the chilled water and steam estimates developed by Dr. Smith and overlaid
the steam requirement of the proposed chillers to the steam that is currently required to
supply the hot water and process steam needs for facility. The results (average hourly
aggregate steam requirements) are shown in Figure 5.
Figure 5 - Average Hourly Aggregate Steam Requirements
Steam
Requirement
(MMBtu/hr)
35,000
30,000
25,000
20,000
15,000
10,000
5,000
&
¦ Absorber Requirement
~ Existing Thermal Load



Month
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Company B
Level 1 CHP Feasibility Study
Figure 5 shows that the steam requirement of the absorption chiller fills in demand during
the months when the facility's hot water demand tapers off. This analysis indicates that
there will be a reliable steam demand of at least 17,000 to 20,000 lbs/hour year-round
once the absorption chillers are installed. Table 2 presents the total purchased power and
boiler fuel for the facility with current equipment (including existing electric chillers and
based on 2004 utility data) and for the situation where the existing electrical centrifugal
chillers are replaced by double effect absorption chillers. Annual purchased power is
reduced by approximately 5,730,000 kilowatt-hours (kWh); boiler fuel is increased by
109,500 MMBtu/yr.
Table 2 - Facility Purchased Power and Boiler Fuel Consumption

Current Equipment
(With Electric Chillers)
With Absorption Chillers
Annual Purchased Power (kWh)
40,988,040
35,258,040
Annual Boiler Fuel (MMBtu)
165,892
275,391
Dr. Smith's analysis calculated 24 hour daily averages for chiller operations, which was
considered sufficient for this level of analysis. However, it is our understanding that the
energy management system at the facility prevents chiller operation when the outside air
temperature is below 64°F. Bin temperature data for the area seems to indicate that this
operating regimen would result in virtually no chiller operation in the months of January,
February, November, and December. Chiller operation in the summer would vary from
12 to 16 hours per day. This information needs to be studied much more closely in any
Level 2 analysis to be certain that "needle peaks" for the steam consumption arising from
absorption chiller operations are not masked by averaging chiller operation data. Further
analysis also would help confirm the potential usefulness of chilled water storage to
reduce such steam demand peaks.
Combined Heat and Power Options
Several CHP options based on gas turbine generators were evaluated. Gas turbines have
long been used in CHP applications, and the steam that can be generated from hot turbine
exhaust matches the steam conditions (temperature and pressure) that the Company B
facility currently uses, along with the steam requirements of double effect absorption
chillers. As shown in Figure 6, a gas turbine would generate electric power at the facility.
This power could solely be used on site, or if Anytown's electric utility chose to build the
plant, they could deliver the power to their grid. In the latter case, Company B would
purchase 100% of their power needs from the utility. Hot exhaust is then routed to the
heat recovery steam generator (HRSG). As will be discussed below, two analyzed options
incorporated the use of a duct burner in the turbine exhaust to provide additional steam
beyond what the unfired gas turbines could provide. (The turbine exhaust still has 15%
oxygen sufficient to support further combustion.)
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Company B
Level 1 CHP Feasibility Study
Figure 6 - System Schematic
Hot Water Storage Tank
Steam from the HRSG would be provided to meet three primary thermal demands. The
first demand is heating the hot water that is required for domestic hot water needs and for
terminal reheat in the heating, ventilation, and air conditioning (HVAC) system.
Secondly, it might be useful to have a hot water storage tank3 to provide the system with
a thermal flywheel as indicated in Figure 6. Lastly, steam would also be supplied to the
double effect absorption chillers and for the facility's cleaning requirements.
Gas Turbine Options
Three different gas turbines have been considered in this Level 1 analysis. These are
Turbine A, Turbine B, and Turbine C.4 Table 3 presents the key performance features for
each of these machines.
Table 3 - Candidate Gas Turbines

Turbine A
Turbine B
Turbine C
Net Generating Capacity (kW) each:
3,490
3,495
4,550
Heat Rate (Btu/kWh, HHV):
14,248
13,680
10,290
Electric Generating Efficiency
(HHV):
24.0%
24.9%
33.2%
Duct Firing Capability:
Yes
Yes
No
Unfired Steam Production (lbs/hr):
19,600
20,000
14,100
Fired Steam Production (lbs/hr):
30,400
29,000
N/A
3	The cost of hot water storage was not included in this analysis
4	In a customized feasibility analysis, the EPA CHP Partnership would name actual equipment
manufacturers to form the basis of this analysis.
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Company B
Level 1 CHP Feasibility Study
The four cases included in this analysis consist of the following:
•	Option 1 - One Turbine A (Power used only on site)
•	Option 2 - One Turbine B (Power used only on site)
•	Option 3 - One Turbine C (100% of the power exported)
•	Option 4 - Two Turbine Cs (100% of the power exported)
Table 4 summarizes the key parameters of each proposed CHP option. For the first two
options outlined in the table, an additional variation is considered—supplemental firing in
the HRSG. Supplementary firing will allow the first two options to raise additional steam.
Use of the supplemental burners can be modulated to match HRSG steam output to
hourly steam demand at the facility.
Table 4 -CHP Options

Option 1
Option 2
Option 3
Option 4
Gas Turbine:
Turbine A
Turbine B
Turbine C
Turbine C
Number of Turbines:
1
1
1
2
Total Capacity (kW):
3,490
3,495
4,550
9,100
Supplemental Firing Capability?
Yes
Yes
No5
No
Max Steam, unfired (lbs/hr)
19,600
20,000
14,100
28,200
Max Steam, fired (lbs/hr):
30,400
29,000
na
na
Fuel Consumption, Unfired (MMBtu/hr)
49.7
47.8
46.8
93.6
Fuel Consumption, Fired (MMBtu/hr):
61.4
56.8
na
na
Assumed Availability:
92%
92%
92%
92%
Screening Analysis
Electricity Production
As described above, the baseload electric demand of the plant was verified to be 3,500
kW. Annual plant operating hours are 8,760. The first two CHP options considered were
both assumed to provide 3,490 kW and 3,495 kW respectively. The third option
considered was 4,550 kW and the fourth option considered was 9,100 kW (twice the third
option). For the first two options, all power output could be used on site. For the last two
options, the gas turbines provide power output that exceeds the plant's base load. For
conservatism, the analysis assumes an availability factor of 92% for the turbines,
representing 8,059 run hours per year. Typical gas turbine systems have actual
availabilities of 97 to 98%.
As described in Table 2, total plant power consumption is estimated to be 35,258,040
kWh/yr after conversion of the electric chillers to double effect absorption units; total
needed boiler fuel without CHP is estimated to be 275,390 MMBtu/yr. The total power
5 It is believed that if Turbine C is not supplementary fired, that selective catalytic reduction (SCR) would
not be required. However, adding a supplementary burner would change this. For Turbine A and Turbine
B, SCR would be required as a NOx control measure regardless if the turbines were supplementary fired or
not.
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Company B
Level 1 CHP Feasibility Study
generated, CHP fuel consumed (including for the supplemental HRSG duct burner where
appropriate), and boiler fuel consumed for steam needs not met by the CHP system for
each of the options are shown in Table 5 and Table 6.
Table 5 - Annual CHP Energy Balance (Unfired HRSG Case)

Option 1
Option 2
Option 3
Option 4
Gas Turbine
Turbine A
Turbine B
Turbine C
Turbine C
Number of Turbines
1
1
1
2
Total Generation (kWh)
28,203,667
28,244,074
36,769,824
73,539,648
Purchased Power (kWh)
7,054,373
7,013,966
35,258,040
35,258,040
CHP Fuel Consumed (MMBtu)
401,724
386,267
378,237
756,473
Boiler Fuel Consumed (MMBtu)
73,624
70,257
127,908
26,673
Table 6 - Annual CHP Energy Balance (Fired HRSG Case)

Option 1
Option 2
Option 3
Option 4
Gas Turbine
Turbine A
Turbine B
Turbine C
Turbine C
Number of Turbines
1
1
1
2
Total Generation (kWh)
28,203,667
28,244,074
36,769,824
73,539,648
Purchased Power (kWh)
7,054,373
7,013,966
35,258,040
35,258,040
CHP Fuel Consumed (MMBtu)
440,037
419,937
378,237
756,473
Boiler Fuel Consumed (MMBtu)
22,031
24,311
127,908
26,673
Recommended Activities for Level 2: Assumptions on peak, average, and base electric
loads should be reviewed in detail and specific seasonal and/or daily variations should be
identified and included for system sizing and detailed economic calculations. A detailed
electric profile would enable an accurate analysis of savings and would ensure that the
system is sized correctly for the application. The load profile should also consider any
projected load growth at the facility. As described earlier, a much more thorough analysis
of the facility's chilled water consumption should be included in a Level 2 analysis. This
information would help to confirm that the 3,500 kW baseload demand is unaffected by
the switch from electric chillers to absorption chillers and would also more accurately
estimate total annual power needs at the facility.
Thermal Energy Production
Options 1 and 2 (unfired simple cycle turbines) and Option 3 (single Turbine C) all
produce thermal energy at levels at or below the 17 to 20 MMBtu/hr minimal thermal
demands of the site (including absorption chiller requirements). Boiler fuel requirements,
as shown in Table 5, remain significant in these options—to meet steam needs when
hourly demand is beyond CHP system thermal capacities and when the systems are down
for maintenance. Additional boiler fuel consumption is much lower for Options 1 and 2
with supplemental duct firing (Table 6) because the HRSG can increase steam output to
meet higher peak hourly demands. The boiler fuel consumption in these two cases is
essentially for supplying steam when the CHP systems are down for maintenance.
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Company B
Level 1 CHP Feasibility Study
Similarly, the boiler fuel consumption for Option 4 (the two Turbine Cs) is for meeting
steam demands when the turbines are down for maintenance. The tables do not show,
however, that the average steam output of Option 4 at 29.2 MMBtu/hr often exceeds
maximum hourly steam demands and is therefore underutilized.
Recommended Activities for Level 2: The Company B facility has fairly detailed 15-
minute interval data available with which to measure likely minimum and maximum
steam consumptions. Using monthly average data, while appropriate for this level of
analysis, might mask steam consumption minimums that would lead to the dumping of
thermal energy, which would hurt the project's overall economics. The use of interval
data would prevent such an error. Interval data also should be used to confirm the
usefulness of hot water storage and if useful, the necessary capacity.
Similarly, a much more thorough analysis of the facility's chilled water consumption
should be included in a Level 2 analysis. This analysis would help confirm minimum and
maximum steam requirements, as well as the potential usefulness of chilled water
storage.
Budget Installation Costs
Preliminary budgetary cost estimates were developed for each option and included the
following equipment: turbine/generator, HRSG, electrical switchgear and controls,
mechanical interconnection to the existing thermal system, and necessary emission
control system (SCR for Turbine A and Turbine B).6.Budgetary estimates for each of the
turbine systems were provided by the respective vendors. The Turbine A system and the
Turbine B system were both quoted with duct burners. A discount was estimated based
on in-house data for the lack of such a burner where appropriate for Options 1 and 2. The
budget costs are turnkey and include engineering, labor, and commissioning. Total
installed cost estimates for the six systems are detailed in Table 7 below.
Table 7 - Budgetary Cost Estimates

Option 1
Option 2
Option 3
Option 4
Gas Turbine
Turbine A
Turbine B
Turbine C
Turbine C
Turnkey Price w/Duct Burner
$5,095,000
$6,750,000
$5,774,000
$9,624,000
Deduction for Duct Burner
($250,000)
($250,000)
N/A
N/A
Turnkey Price w/o DB
$4,845,000
$6,500,000
N/A
N/A
Price per kW (w/ DB)
$l,460/kW
$l,931/kW
$l,269/kW
$l,058/kW
Price per kW (w/o DB)
$l,388/kW
$l,860/kW
N/A
N/A
Incremental Maintenance
$0.006/kWh
$0.006/kWh
$0.008/kWh
$0.008/kWh
Recommended Activities for Level 2: Following the electrical and thermal energy
analysis and system size/application decision detailed in the previous sections, substantial
preliminary design engineering (30%) would enable an accurate installation cost to be
6 A fuel gas compressor is not required because there is a high pressure transmission line just across the
street from the plant.
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Company B
Level 1 CHP Feasibility Study
determined for this system. Assumptions about the ability of existing plant systems to be
used for the CHP system need to be confirmed. The requirements and cost of connecting
with a nearby high pressure gas line would also have to be estimated. Installation cost
issues will have the single biggest impact on return on investment for the project.
Emissions
Current emissions standards in Anytown, USA, are expected to require SCR for the
Turbine A and the Turbine B systems. The Turbine C system, if installed without a duct
burner, might be permittable without SCR.
Recommended Activities for Level 2: This analysis did not consider existing emissions at
the Company B facility and how these emissions might impact compliance requirements
for the CHP system. The level 2 analysis should evaluate costs associated with initial and
ongoing environmental compliance and reporting. Once a decision to proceed with the
project has been made, the site should engage qualified environmental consultants to
manage environmental compliance, including confirmation of the anticipated
requirements for emission control and reporting processes, and securing of construction
permits.
Utility Interconnection
Options 1 and 2 would be designed to operate in parallel with the utility and will need to
meet Utility B's interconnection and safety requirements.7 It is anticipated that the power
export options (3 and 4) would have the active participation of the Anytown, USA, utility
in the design and implementation.
Recommended Activities for Level 2: Engage in preliminary discussions with Anytown,
USA,'s municipal utility regarding interconnection and capture all costs associated with
meeting interconnection requirements.
Maintenance
Based on our discussions with vendors, this analysis uses an incremental maintenance
cost for the CHP systems of $0.006/kWh for the Turbine A and Turbine B gas turbines
and $0.008/kWh for Turbine C.
7 "Parallel" with the utility means the on-site generation system is electrically interconnected with the
utility distribution system at a point of common coupling at the site (common busbar) and facility loads are
met with a combination of grid- and self-generated power. Interconnection requires various levels of
equipment safeguards to ensure power does not feed into the grid during grid outages. A parallel
configuration is in contrast to "grid isolated" operation, wherein the CHP system serves either the entire
facility or an isolated load with no interconnection with the utility's distribution system. Grid isolated
systems typically require increased capacity to cover facility peak demands and redundancy for back-up
support.
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Company B
Level 1 CHP Feasibility Study
Recommended Activities for Level 2: A detailed maintenance proposal from the vendor
of the equipment selected in the final design should be provided and associated costs
included in the final economic analysis.
Power Reliability -CHP System as Backup Power
The primary benefit of a CHP system is that it produces power for less money than
separate heat and power. An additional benefit can be the use of the onsite capacity to
provide backup generation in the event of a utility outage. In certain applications, the
value of this additional reliability can outweigh all other factors in the investment
decision.
In order to implement this capability, there are added costs to tie into the existing
electrical systems that are beyond the scope of this level of analysis. Those costs can
include engineering, controls, labor, and materials. The engineering required to analyze
the existing electrical system, determine critical loads, provide a design, and determine
cost to provide backup power from the system can be fairly costly.
The justification for this additional cost should be financial: it pays to do it if there is a
way to account for the benefits in the financial analysis. One simple method is to offset
the turnkey cost of a similarly sized backup generator against the incremental cost of the
CHP system. There are other ways to account for the reliability benefits using
assumptions of avoided catastrophic revenue losses due to utility blackouts. Regardless of
how the benefits are quantified, it is important to provide some estimate that captures
reliability benefits to balance the incremental costs associated with this added capability.
Recommended Activities for Level 2: If the facility is interested in pursuing running the
system in the event of a utility outage, the engineering firm hired to perform the Level 2
analysis should be very experienced in electrical design and use of CHP as a backup
system. Extensive review of the site's existing electrical system and identification of
critical loads should be considered along with the system sizing criteria previously
discussed in order to come up with the optimal system to meet the facility's needs.
Baseline Utility Costs
The objective of this analysis was to calculate the marginal cost of generation of the
various CHP options as a function of the fuel cost. Currently natural gas is transported to
the facility by the Anytown, USA,'s municipal utility. To calculate the appropriate cost of
fuel, the transportation rate of the utility must be added to an estimated natural gas
commodity cost. The commodity cost is estimated by adjusting the 18-month strip at
Henry Hub8 by the approximate basis9 between Henry Hub and the Anytown border. In
addition, for comparison, the cost of fuel was calculated as if the natural gas had been
8	This is a futures contract that would allow a company to buy a specified quantity of natural gas at a single
price for the period of 18 months.
9	The current difference in spot market prices of natural gas at Henry Hub and in Anytown, USA.
EPA CHP Partnership
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Company B	Level 1 CHP Feasibility Study
delivered by the utility at their electric generation transportation tariff. The cost of fuel is
summarized in Table 8.
Table 8 - Cost of Fuel ($/MMBtu)

Anvtown. USA
Utility
Henry Hub 18 Month Strip
$11.53
11.53
Basis to State Border
($3.83)
($3.83)
Transportation Costs
$3.20
$0.20
Totals
$10.90
$7.90
Because this calculation is clearly speculative regarding the calculation of the commodity
costs, the costs used in the analysis were rounded to $11.00/MMBtu and $8.00/MMBtu.
Recommended Activities for Level 2: Gas utilities are often willing to negotiate favorable
gas rates for CHP sites based on their substantial, constant, year-round demand. A minor
reduction in gas rates can have a profound impact on return on investment. Inquiries
should be made into negotiated rates based on the projected volumes of gas consumption
with CHP.
3. Economic Analysis
The results of the economic screening for the CHP options without supplemental duct
burners are shown in Table 9 and graphically in Figure 7. The marginal cost of generation
was calculated for each CHP option. The marginal cost includes operating costs only—
including CHP system fuel, CHP maintenance costs, and any credit for CHP thermal
output for the various options considered.
Table 9 - Marginal Costs of Generation (without supplemental firing)

Option 1
Option 2
Option 3
Option 4
Gas Turbine
Turbine A
Turbine B
Turbine C
Turbine C
Number of Turbines
1
1
1
2
Total Capacity (kW)
3,490
3,495
4,550
9,100
Marginal Cost of Generation
at $8/MMBtu
$0.0627/kWh
$0.0573/kWh
$0.0582/kWh
$0.0632/kWh
Marginal Cost of Generation
at $ 11/MMBtu
$0.0840/kWh
$0.0765/kWh
$0.0770/kWh
$0.0839/kWh
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Company B
Level 1 CHP Feasibility Study
Figure 7 - Marginal Costs of Generation (without supplemental firing)
Marginal Cost
of Power
($/kWh)
$0.0900
$0.0800
$0.0700
$0.0600
$0.0500
$0.0400
$0.0300
$0.0200
$0.0100
$0.0000
~ $8/MMBtu
¦ $11/MMBtu
Turbine A Turbine B Turbine C Two Turbine Cs
CHP Options
Table 10 and Figure 8 present the results for the CHP options with in inclusion of
supplemental HRSG duct firing for Options 1 and 2.
Table 10 - Marginal Cost of Generation (with supplemental firing)

Option 1
Option 2
Option 3
Option 4
Gas Turbine
Turbine A
Turbine B
Turbine C
Turbine C
Number of Turbines
1
1
1
2
Total Capacity (kW)
3,490
3,495
4,550
9,100
Marginal Cost of Generation
at $8/MMBtu
$0.0590/kWh
$0.0538/kWh
$0.0582/kWh
$0.0632/kWh
Marginal Cost of Generation
at $ 11/MMBtu
$0.0788/kWh
$0.0718/kWh
$0.0770/kWh
$0.0839/kWh
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Company B
Level 1 CHP Feasibility Study
Figure 8 - Marginal Costs of Generation (with supplemental firing)
$0.0900
$0.0800
$0.0700
$0.0600
Marginal Cost $Q 050Q
of Power
($/kWh)
$0.0400
$0.0300
$0.0200
$0.0100
$0.0000
~ $8/MMBtu
¦ $11/MMBtu
Turbine A Turbine B Turbine C Two Turbine Cs
CHP Options
The best performing system, based on the marginal cost of generating, was the Turbine B
gas turbine with supplementary firing. The primary reason for this outcome was that
Turbine B is slightly more efficient than Turbine A and with supplementary firing, it
could meet more of the thermal energy requirement than the single Turbine C. The results
for the two Turbine C options varied. The single Turbine C had competitive marginal
generating costs with the unfired simple cycle turbines used in Options 1 and 2. While the
recuperated Turbine C produces much less usable thermal energy per kWh generated than
either of the simple cycle turbines, the higher electric generating efficiency of Turbine C
keeps marginal costs competitive. The greater thermal displacement of Options 1 and 2
when supplemental duct firing is added further lowers the marginal costs of these
options—duct firing results in a $0,003 to $0.005/kWh reduction in marginal generating
costs. The marginal costs of Option 4 (two Turbine Cs) are comparatively high due to the
fact that there are times when the combined thermal output of the two-turbine system is
above the thermal demands of the site and is essentially wasted.
The tables also illustrate that the $3/MMBtu difference in gas costs between the
$8/MMBtu case and $11/MMBtu case results in an almost $0.02/kWh increase in
marginal generating costs across the four options. Detailed summaries of the results are
included in the appendix.
EPA CHP Partnership
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Company B
Level 1 CHP Feasibility Study
4. Conclusions
This Level 1 analysis points to several conclusions:
•	A CHP system appears to be a viable energy management option for Company B.
A Level 2 study should evaluate the impact of various ownership options for the
CHP system, including having the system completely owned and operated by
Company B or partnering with Anytown, USA, to build the facility and arrange to
buy steam at a discount from the utility.
•	If the power is to be used solely on site, either the Turbine A or the Turbine B
systems appear to be viable candidates. The difference in the marginal cost of
generation was not sufficient to rule out either turbine, nor was the difference in
installed costs. Maintenance contract issues, as well as basic maintainability of
each machine, certainly could make a difference in the economics and should be
evaluated in the Level 2 study.
•	Supplementary firing to raise additional steam in the heat recovery steam
generator is important to the overall performance of the Turbine A or the Turbine
B systems.
•	If the facility is to be constructed and owned by the utility (or in partnership with
the utility), then the single Turbine C system appears to be a viable choice.
Supplementary firing (even at the cost of installing SCR10) should be considered
for this machine and investigated in the Level 2 study.
•	The option with two Turbine C turbines did not perform as well as the other
options on a marginal cost of generation basis; this outcome is primarily because
the thermal output of this option could be greater than the needs of Company B.
•	Although marginal cost was the primary measure of comparative performance in
this analysis and is most often the determining factor for dispatch decisions, it
should noted that other critical considerations are often included in investment
decisions. These considerations could include capital costs, emissions profile, and
other potential benefits to the site, such as enhanced power reliability.
10 Supplementary firing was not considered for either of the Turbine C options in this analysis because of
the impact on emissions. Turbine C can meet current Anytown, USA emissions standards without
aftertreatment. The addition of supplemental duct burners may require use of SCR.
EPA CHP Partnership
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Company B
Appendix
Level 1 CHP Feasibility Study
EPA CHP Partnership
18

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Company B
Level 1 CHP Feasibility Study
Company B - $8.00/MMBtu Gas Price Case
Plant Consumption Details
Peak Demand (Annual peak), kW
Average MW Demand, kW
Average Thermal Heating Demand, MMBtu/hr
Average thermal Cooling Demand, MMBtu/hr
Operating Hours	|
Current Annual Power Consumption, kWh
Base Case Annual Power Consumption, kWh
Base Case Annual Thermal Consumption, MMBti
Plant annual power to heat ratio
Estimated Boiler Heater Efficiency %
5,000
4,679
15.15
10.00
iJ60]
40,988,040
35,258,040
220,313
0.6
Based on 2004 electricity usage
Based on 2004 electricity usage
Based on 2004 natural gas usage
Estimated based on converting existing chiller load to double effect absorption
Based on 2004 electricity usage
Based on converting existing chiller load to double effect absorption
Includes heating and cooling loads
Average Gas Cost $/MMBtu
CHP Options
Prime Mover
Turbine Capacity, kW
Number of Turbines
Duct Burner Capability?
CHP System Electric Capacity kW
Electrical Efficiency, HHV
MMBtu/hr Thermal Provided (unfired)
Power to Heat Ratio
System Availability, %
System Hours of Operation
Power Generated Annually, kWh
Thermal Generated Annually, MMBtu
CHP Thermal, MMBtu/yr
Duct Burner Thermal, MMBtu/yr
Capital Cost, $
Capital Costs, $/kW
O&M Cost, $/kWh
Economics	Base System'
Energy Summary
Purchased Power, kWh	35,258,040
Generated Power, kWh	0
Boiler Steam, MMBtu/yr	220,313
CHP Thermal Used, MMBtu/yr
Boiler Fuel, MMBtu/yr	275,391
CHP Fuel, MMBtu/yr
(CHP system + duct burner)
Cost Summary
Boiler Fuel Savings	n/a
CHP Fuel	n/a
CHP O&M	n/a
Total Costs	n/a
Cost per kWh Generated:	n/a
" Base System assumes
existing chiller load converted to
double effect absorption






I $8.00





Turbine A
Turbine A
Turbine B
Turbine B
One
Two
w/duct firing
w/o duct firing
w/duct firing
w/o duct firing
Turbine C
Turbine Cs
3,490
3,490
3,495
3,495
4,550
4,550
1
1
1
1
1
2
Yes
Yes
Yes
Yes
No
No
3,490
3,490
3,495
3,495
4,550
9,100
24.0%
24.0%
24.9%
24.9%
33.2%
33.2%
20.3
20.3
20.7
20.7
14.6
29.2
0.6
0.6
0.6
0.6
1.1
1.1
I 92%|| 92%|| 92%|| 92%|| 92%|| 92%|
8,059
8,059
8,059
8,059
8,059
8,059
28,203,667
28,203,667
28,244,074
28,244,074
36,769,824
73,539,648
202,688
164,050
202,688
167,282
117,987
235,973
164,050
164,050
167,282
167,282
117,987
235,973
38,638
0
35,405
0
0
0
I $5,095,00011 $4,845,00011 $6,750,00011 $6,500,00011 $5,774,40011 $9,624,0001
$1,460
$1,388
$1,931
$1,860
$1,269
$1,058
I $0.006011 $0.006011 $0.006011 $0.006011 $0.008011 $0.00801
Turbine A
Turbine A
Turbine B
Turbine B
One
Two
w/duct firing
w/o duct firing
w/duct firing
w/o duct firing
Turbine C
Turbine Cs
7,054,373
7,054,373
7,013,966
7,013,966
35,258,040
35,258,040
28,203,667
28,203,667
28,244,074
28,244,074
36,769,824
73,539,648
17,625
58,899
17,625
56,205
102,326
21,338
202,688
164,050
202,688
167,282
117,987
198,975
22,031
73,624
22,031
70,257
127,908
26,673
440,037
401,724
421,853
386,267
378,237
756,473
($2,026,879)
($1,614,138)
($2,026,879)
($1,641,076)
($1,179,867)
($1,989,749)
$3,520,298
$3,213,791
$3,374,822
$3,090,139
$3,025,894
$6,051,787
$169,222
$169,222
$169,464
$169,464
$294,159
$588,317
$1,662,641
$1,768,875
$1,517,407
$1,618,528
$2,140,185
$4,650,356
$0.0590
$0.0627
$0.0537
$0.0573
$0.0582
$0.0632
Cost per Generated kWh = total incremental cost of CHP (CHP fuel+CHP 0$M-boiler savings) diveded by kWh generated
EPA CHP Partnership
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Company B
Level 1 CHP Feasibility Study
Company B - $11.00/MMBtu Gas Price Case
Plant Consumption Details
Peak Demand (Annual peak), kW
Average MW Demand, kW
Average Thermal Heating Demand, MMBtu/hr
Average thermal Cooling Demand, MMBtu/hr
Operating Hours
Current Annual Power Consumption, kWh
Base Case Annual Power Consumption, kWh
Base Case Annual Thermal Consumption, MMBtu
Plant annual powerto heat ratio
Estimated Boiler Heater Efficiency %
Average Gas Cost $/MMBtu
CHP Options
Prime Mover
Turbine Capacity, kW
Number of Turbines
Duct Burner Capability?
CHP System Electric Capacity kW
Electrical Efficiency, HHV
MMBtu/hr Thermal Provided (unfired)
Powerto Heat Ratio
System Availability, %
System Hours of Operation
Power Generated Annually, kWh
Thermal Generated Annually, MMBtu
CHP Thermal, MMBtu/yr
Duct Burner Thermal, MMBtu/yr
Capital Cost, $
Capital Costs, $/kW
O&M Cost, $/kWh
5,000
4,679
15.15
10.00
iJ60]
40,988,040
35,258,040
220,313
0.6
Based on 2004 electricity usage
Based on 2004 electricity usage
Based on 2004 natural gas usage
Estimated based on converting existing chiller load to double effect absorption
Based on 2004 electricity usage
Based on converting existing chiller load to double effect absorption
Includes heating and cooling loads
Economics
Energy Summary
Purchased Power, kWh
Generated Power, kWh
Boiler Steam, MMBtu/yr
CHP Thermal Used, MMBtu/yr
Boiler Fuel, MMBtu/yr
CHP Fuel, MMBtu/yr
(CHP system + duct burner)
Cost Summary
Boiler Fuel Savings
CHP Fuel
CHP O&M
Total Costs
Cost per kWh Generated*:
" Base System assumes
existing chiller load converted to
double effect absorption
Base System*
35,258,040
0
220,313
0
275,391
n/a
n/a
n/a
n/a
n/a
o
o





A
B
C
D
E
F
Turbine A
Turbine A
Turbine B
Turbine B
One
Two
w/duct firing
w/o duct firing
w/duct firing
w/o duct firing
Turbine C
Turbine Cs
3,490
3,490
3,495
3,495
4,550
4,550
1
1
1
1
1
2
Yes
Yes
Yes
Yes
No
No
3,490
3,490
3,495
3,495
4,550
9,100
24.0%
24.0%
24.9%
24.9%
33.2%
33.2%
20.3
20.3
20.7
20.7
14.6
29.2
0.6
0.6
0.6
0.6
1.1
1.1
I 92%|| 92%|| 92%|| 92%|| 92%|| 92%||
8,059
8,059
8,059
8,059
8,059
8,059
28,203,667
28,203,667
28,244,074
28,244,074
36,769,824
73,539,648
202,688
164,050
202,688
167,282
117,987
235,973
164,050
164,050
167,282
167,282
117,987
235,973
38,638
0
35,405
0
0
0
5.095

6.75


9.624
I $5,095,00011 $4,845,00011 $6,750,00011 $6,500,00011 $5,774,40011 $9,624,0001
$1,460
$1,388
$1,931
$1,860
$1,269
$1,058
I $0.006011 $0.006011 $0.006011 $0.006011 $0.008011 $0.00801
Turbine A
Turbine A
Turbine B
Turbine B
One
Two
w/duct firing
w/o duct firing
w/duct firing
w/o duct firing
Turbine C
Turbine Cs
7,054,373
7,054,373
7,013,966
7,013,966
35,258,040
35,258,040
28,203,667
28,203,667
28,244,074
28,244,074
36,769,824
73,539,648
17,625
58,899
17,625
56,205
102,326
21,338
202,688
164,050
202,688
167,282
117,987
198,975
22,031
73,624
22,031
70,257
127,908
26,673
440,037
401,724
421,853
386,267
378,237
756,473
($2,786,958)
($2,219,440)
($2,786,958)
($2,256,479)
($1,622,317)
($2,735,905)
$4,840,410
$4,418,963
$4,640,380
$4,248,942
$4,160,604
$8,321,208
$169,222
$169,222
$169,464
$169,464
$294,159
$588,317
$2,222,673
$2,368,745
$2,022,886
$2,161,927
$2,832,446
$6,173,620
$0.0788
$0.0840
$0.0716
$0.0765
$0.0770
$0.0839
Cost per Generatec
kWh = total incremental cost of CHP (CHP fuel+CHP 0$M-boiler savings) diveded by
EPA CHP Partnership
20

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