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Economics of Cogeneration
A Study
by Larry Coyne, P.Eng.
Technology Directorate
Architectural & Engineering Services
Real Property Services
Public Works and Government Services Canada
March 22, 1999
Economics of Cogeneration
Introduction
Cogeneration is the sequential production of two or more forms of useful energy from a
single heat source. Waste is recovered and converted into hot water or steam to meet
building or process heating or cooling requirements. The high efficiencies of these
components, combined with the use of a low cost fuel, result in significant energy cost
savings. Cogeneration sites stabilize energy costs by producing much of their own
electricity, thereby shielding users from the potential volatility of the electricity market.
The traditional economic argument outlined above accounts only for direct project costs
during project evaluation. Society and the environment are left to cope with the physical
and financial effects of by-product emissions. Acid gases (NO×, SO×, and particulate
matter) and its global warming counterpart, greenhouse gas (CO2 and CH4), comprise a
significant portion of process by-products, each detrimental to the environment. The
effectiveness of energy-efficiency as a means of reducing acid and greenhouse gas
emissions can be increased dramatically when monetary allowance is made for the
actions of the waste streams.
By 2000, most provinces in Canada will have deregulated their electricity industries.
When gas and electricity were deregulated in the United States, Australia and Britain,
industrial customers were offered savings of up to 20% in the early stages; average actual
savings, however, were about 12%.
&
Traditional approach
COGENERATION
Sequential production of electricity and heat from
a single fuel source
Economics of Cogeneration
Larry Coyne, Technology Directorate
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Operating Costs
Conventional Plant
Maint.
Capital
Power
Fuel
Operating Costs
With Cogen
Capital
Fuel
Maint
Tunney's Pasture Cogeneration Feasibility Study
Economics of Cogeneration
Larry Coyne, Technology Directorate
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In 1991, PWGSC, in partnership with others, engaged H.A. Simons and Associates to
s
conduct a feasibility study of a cogeneration facility at Tunney’ Pasture CHCP. One of
the most attractive alternatives considered was the installation of a combined cycle
cogeneration with design output of 110 Mwe, which had an 85 Mwe gas turbine with a
pipeline providing steam to the Cliff Street CHP. The following data indicate a positive
cash flow on startup.
(GE Frame 7 DRY; OPTION 5b/5; Cash value in $1,000s)
Project lifespan 20 years
Annual average sales (MW) 84.7
Annual average steam sales (lb/hr) 315,301
Grant $0
Amount financed $70,762
Costs at base date
Capital $82,500
Fixed O&M $3,710/yr
Administration $0
Property tax $0
Insurance $0
Fuel $3.20 MMBTU
Other $0
Table 1. Project Details (1995 Start-up date)
Electricity sales, energy 5.00%
Electricity sales, capacity 3.00%
Steam 6.50%
Fuel 6.50%
Operating costs 5.50%
Construction costs 5.50%
Other revenue 5.50%
Plant performance
Electrical output 741,951 MWh/yr
Steam sales 2,762 MM lb/yr
Gas used 8,632 MM Scf/yr
Table 2. Escalation (Base date 1991)
Electricity 5.76¢/kWh
Steam $4.19/1000 lb
Other $0
Financial data
Equity 25%
Debt 75%
Debt term 10 years
Debt interest rate 12.00%
Discount rate 15.00%
Federal tax 45.00%
Provincial tax 0.00%
CCA 3 years
Investment tax credit 0.00%
Table 3. Revenue projections
Economics of Cogeneration
Larry Coyne, Technology Directorate
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Summer Energy 2.75 ¢/kWh
Capacity 4.38 ¢/kWh
Winter Energy 3.19 ¢/kWh
Capacity 5.45 ¢/kWh
Premium 10.00%
Maintenance Cost 0.005 $/kWh
Table 4. Electrical Revenue ($1995)
Month Electrical Output Steam Sales Gas Used Capacity Factor
MW MWH pph (000) 1000 lb Mscfh MMscf (percentage)
January 109.44 73,281 530 354,888 1392 932 90
February 108.40 65,560 530 320,544 1383 836 90
March 103.70 69,438 524 350,870 1346 901 90
April 92.25 59,778 262 169,776 1005 651 90
May 86.90 58,188 262 175,435 955 639 90
June 83.05 58,816 262 169,776 919 596 90
July 81.10 55,305 262 175,435 900 603 90
August 82.15 55,008 262 175,435 910 609 90
September 85.80 58,514 262 169,776 944 612 90
October 90.30 60,465 262 175,435 988 662 90
November 95.50 61,884 262 169.776 1036 671 90
December 107.10 71,714 530 354,888 1373 919 90
TOTAL 1,126.0 741,951 315,301 2.76E+06 8,632
Average 84.70 985 90
Table 5. Base year data (1991)
Year Total Total Debt Pre-tax Overall Overall
Revenue Expenses Service cash flow cash flow Cash flow
($) ($) ($) ($) (using tax (not using
credits) tax credits)
($) ($)
1993 (11,478) (11,478)
1994 (12,109) (12,109)
1995 57,607 57,655 12,524 4,952 11,524 4,952
1996 60,342 55,217 12,524 5,125 22,015 5,125
1997 63,218 57,944 12,524 5,274 11,239 5,274
1998 66,242 60,845 12,524 5,397 419 5,397
1999 69,421 63,932 12,524 5,489 164 5,489
2000 72,765 67.216 12,524 5,549 (146) 5,549
2001 76,282 70,711 12,524 5,571 (518) 5,571
2002 79,983 74,430 12,524 5,552 (958) 5,552
2003 83,876 78,387 12,524 5,489 (1,474) (644)
2004 87,973 82,598 12,524 5,375 (2,076) (2,076)
2005 92,285 74,555 12,524 17,730 9,751 9,751
2006 96,823 79,322 12,524 17,501 9,626 9,626
2007 101,601 84,395 12,524 17,206 9,463 9,463
2008 106,631 89,794 12,524 16,838 9,261 9,261
Table 6. Summary data
Economics of Cogeneration
Larry Coyne, Technology Directorate
06/04/99 Page 4
Using 1998 steam and electricity consumption produces the results shown in the
following table.
Project Details Revenue Plant Performance Summary
Annual 8.74 Electricity 6.76¢/kWh Electrical 741,951 Total $75,562
average sales (average) output MWh/yr revenue
(MW)
Annual 315,301 Steam $9.36 per Steam sales 2,762 MM Total $61,944
average 1,000lb lb/yr expenses
steam sales
(lb/hr)
Costs at base Other $0 Gas used 8,632 MM Pre-tax cash $13,618
date ($) Scf/yr flow
Capital $82,500 Debt service $12,524
Fixed $3,710
O&M/yr
Admin. $0
Property tax $0
Insurance $0
Fuel $5.10
(MMBTU)
Grant $0
Other $0
Amount $70,762
financed
Table 7. 1998 summary data
It is clear that had this system been installed in 1991, then a saving of $8 million ($13-
$5million) could have been realized in 1998.
Economics of Externals
Throughout the conversion process from fuel to power, waste streams of matter and
energy, and their effects on the environment, should be included in the cost accounting
process. Placing a monetary value on these externals ensures that they are recognized,
and that the many associated factors, which are often ignored, are more clearly
understood.
Historically, society has treated environmental degradation as having zero-cost impact.
Consequently, most improvements have been driven by imposed regulatory constraints.
This is not always the case when it comes to issues involving health and safety. While the
valuation of these impacts is sometimes arrived at through quantitative methods (legal
liability and insurance risk), it is often at the discretion of the decision-makers. In this
sense, this accounting technique will measure the broader cost, which is not reflected in
commodity prices.
It is now apparent that that air, land and water have a significant value. Rising
populations and economic development have the potential to place severe stress on
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regional and global ecosystems and climates. This, in turn, will affect human health, food
sources, lifestyles and property. The costs to society of not preventing increases in air
pollution and greenhouse gas emissions, for example, will likely be very large over the
next century. While a 50-100 year timeframe may not seem significant today, it
represents a very small fraction of the period of human existence. Environmental
considerations in long-term planning will be crucial in mitigating atmospheric
degradation.
Determination of approximate values
A large number of analytical studies have been carried out by many organizations to
explore the range of emissions externals values, although some have not included
greenhouse gas impacts. Environment Canada has been involved in some of these, and
has also prepared some brief internal reports to summarize information on both Full Fuel
Cycle Analysis (J. Prenger 1995) and Environmental Externality Valuation for Emission
Credits for Green Power Procurement (C. Luce 1996).
These studies reveal a wide range of opinion on these issues. The range of costs is very
large (sometimes by an order of 1000) mainly because some impacts are not included, or
because the studies have tried to determine exact, proven values. It is clear, however, that
even if simple, approximate, conservative values are chosen for each major air pollutant,
and these are added together, some important directional changes can be made to project
planning and selection. This approach, then, can indicate common sense solutions to
encourage voluntary industry approaches to sustainable energy development.
The discussion and examples throughout this report assume the following emission costs:
Emission Cost
Sulphur Dioxide $1000/ton
Nitrogen Oxides $1000/ton
Carbon Dioxide $10/ton
Methane $210/ton
Particulates $2000/ton
Case study
The following example illustrates the simplified use of environmental externalities in
project economic evaluation for voluntary initiatives.
An industrial plant derives its electrical energy from a 10 mW, 33% LHV efficient gas
turbine, near a business district with 10 buildings using boilers for their heating needs. It
is assumed that five of these boilers will soon need upgrading for continued operation.
With a GT fuel HHV consumption of 120 GJ/hr, there is approximately 74 GJ/hr of
useful heat rejected. This example assumes that 2/3 (50 GJ/hr) of this energy can be used
for low-pressure steam in the plant, and hot water heating in some of the commercial
buildings to offset their base load boiler use. The required capital costs would be either
$1 million for the commercial boiler retrofits, or $7 million for a heat recovery unit,
Economics of Cogeneration
Larry Coyne, Technology Directorate
06/04/99 Page 6
district energy hot water piping and heat exchangers to the nearby building sites.
Assumptions are:
• 6000 hours of full load GT operation burning $2.16 million gas fuel ($3/GJ)
• one on-site industrial boiler and 5 nearby commercial boilers using 77 GJ/hr of fuel
@ $4/GJ to produce 50 GJ/hr of heat (65% HHV) for 2500 equivalent full loads/yr
• alternative project requires new HRSG steam system and heat exchanger for hot
water production ($2.5 million) and hot water delivery and connection facilities to the
commercial buildings estimated at $10/mWhr (thermal) for connecting head loads,
resulting in $3.2 million capital (existing boilers left on standby)
• added $50,000 for steam cycle O&M; $10,000 fuel for turbine exhaust pressure loss
• GT N0x emissions 1kg/mWhr (DLE), boiler @ 50 g/GJ; C02 is 50 kg/GJ
Without consideration of the externals, the existing operation with two individual
combustion sources would cost about $3 million annually, as compared to new district
energy operation with a $2.8 million cost. This small improvement is often not enough to
spur investment. The $5.7 million capital expenditure on waste heat recovery would
normally offset the $1 million boiler upgrade, and would save $0.7 million in fuel and
O&M costs. This eight-year payback period is generally insufficient today to attract
investors. Consideration of the $116,000 annual externals cost avoidance improves this to
a seven year payback to society.
Incremental Annual Costs ($000) Emissions (tonnes/yr) Externality Total costs
costs ($000)
($000)
Fixed Variable
Fuel O&M
Gas -- 2,160 -- NOx 69.6 556 3,606
turbine CO2 42,300.0
6 boilers 110 770 10 GHG* 6,350.0
@ 77
GJ/hr
GT with 275 2,170 50 NOx 60.0 440 3,297
Heat CO2 33,000.0
Recovery GHG* 4,950.0
Unit
District 352 -- 10
energy
Table 8. Capture of waste heat for district energy
ECONOMICS OF DEREGULATION
By the end of this decade, it is expected that the electric power sector in North America
will have undergone a process of deregulation and restructuring parallel to that
experienced in the natural gas industry, among others, over the past decade. Existing
electric utility generation assets, and even the utilities themselves, will be profoundly
Economics of Cogeneration
Larry Coyne, Technology Directorate
06/04/99 Page 7
affected by power sector restructuring. Ownership of the existing generation capacity,
competition among generation sources, obligation to serve and supply, and many other
issues will be examined and debated as the power sector moves toward a deregulated,
competitive operating environment.
The deregulation of other industries has led to product price reductions. This is expected
to occur in the electricity industry as well, primarily due to increased competition.
Potential electricity price reductions may seem to obviate the need for energy
conservation measures such as cogeneration. However, in their quest for market share,
the competitors may try cut corners. The environmental impacts of such decisions could
lead to increased societal costs.
While end users of electricity can choose their energy providers, it is important to note
that energy providers can choose their customers. Without leverage, end users might be
limited to buying “environmentally insensitive” power or paying spot market prices.
Cogeneration systems provide power generation and distribution capabilities such that
electrical power can be traded when a buyer is one location and excess power is in
another.
CONCLUSIONS
When electricity prices are high or are likely to remain high, cogeneration facilities can
produce significant cost savings. Currently, PWGSC is paying 6.7¢ per kWhr for
electricity and $10 per GJ. These costs can be reduced by up to 50% by the cogeneration
alternative. The key to evaluating the potential savings from cogeneration is to forecast
accurately electrical prices over the next several years. Fuel prices tend to balance out
since they are a significant component in both the historic and cogeneration approaches.
There is uncertainty today in Canada about future electricity prices. The premise of
deregulation is that electricity customers will be free to choose their utility, but the
utilities will be able to choose their customers. A customer with some power-producing
capability will be attractive to the utilities. A customer with no long-term contract with a
utility may have to shop the market and accept randomly fluctuating spot prices. Public
Works and Government Services Canada can create its own power-generating
capabilities by establishing cogeneration plants in its infrastructure. This will enable the
department to sell power to potential buyers in one area, and to buy power in another
location when required.
Most PWGSC energy needs are met by buying electricity from the provincial grid and
burning fuels to supply heating. In some instances it is possible to meet both
requirements by generating electricity on-site and using the waste heat from the process
to provide steam or hot water for building heating loads. This simultaneous production of
two or more forms of energy— from a single primary energy source— makes more
efficient use of fuels and provides economic and environmental advantages.
Economics of Cogeneration
Larry Coyne, Technology Directorate
06/04/99 Page 8
Cogeneration is 2 to 2.5 times more efficient in fuel use than conventional thermal
generation: a gas-fired cogeneration plant will use half, or even less, of the fuel needed
by a thermal power station to produce the same amount of useful energy. This increased
efficiency is possible because the cogeneration plant uses waste heat, while power
stations release it into the environment. As a result, cogeneration results in lower
emissions of atmospheric pollutants, such as the greenhouse gas carbon dioxide, per unit
of useful energy. Natural gas, among all available fossil fuels, maximizes the
environmental advantages of cogeneration.
Pressure on Canada to meet the Kyoto environmental targets may create emissions permit
trading among industries. This practice enables an industry with emissions exceeding its
target to buy emissions permits from another less offending industry. Again, since
cogenerated power is relatively clean, having cogen plants on line would enhance
s
PWGSC’ bargaining position.
REFERENCES
1. H.A. Simons Ltd. “Feasibility Study for Proposed Cogeneration facility at Cliff Street
s
and Tunney’ Pasture CHCP.” 1991
2. Church, Ken. “Externalities and Energy Efficiency. Report for environment Canada,
December 1997.
3. MacRae, Kwaczek, and Reinsch. “Repowering Alberta: Options for Electrical
Generating Units: Economics and Emissions Impacts.” 1996.
Economics of Cogeneration
Larry Coyne, Technology Directorate
06/04/99 Page 9
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