ENERGY MANAGEMENT HANDBOOKS phần 3 ppt

172 ENERGY MANAGEMENT HANDBOOK

data, confi rm selected alternative and fi nally size the

plant equipment and systems to match the application.

Step 3. Design Documentation. This includes the

preparation of project fl ow charts, piping and instru￾ment diagrams, general arrangement drawings, equip￾ment layouts, process interface layouts, building, struc￾tural and foundation drawings, electrical diagrams, and

specifying an energy management system, if required.

Several methodologies and manuals have been de￾veloped to carry out Step 1, i.e. screening analysis and

preliminary feasibility studies. Some of them are briefl y

discussed in the next sections. Steps 2 and 3 usually re￾quire ad-hoc approaches according to the characteristics

of each particular site. Therefore, a general methodology

is not applicable for such activities.

7.2.4.2 Preliminary Feasibility Study Approaches

AGA Manual—GKCO Consultants (1982) de￾veloped a cogeneration feasibility (technical and eco￾nomical) evaluation manual for the American Gas As￾sociation, AGA. It contains a “Cogeneration Conceptual

Design Guide” that provides guidelines for the develop￾ment of plant designs. It specifi es the following steps to

conduct the site feasibility study:

a) Select the type of prime mover or cycle (piston

engine, gas turbine or steam turbine);

b) Determine the total installed capacity;

c) Determine the size and number of prime movers;

d) Determine the required standby capacity.

According to its authors “the approach taken (in

the manual) is to develop the minimal amount of in￾formation required for the feasibility analysis, deferring

more rigorous and comprehensive analyses to the actual

concept study.” The approach includes the discussion

of the following “Design Options” or design criteria to

determine (1) the size and (2) the operation mode of the

CHP system.

Isolated Operation, Electric Load Following—The

facility is independent of the electric utility grid, and

is required to produce all power required on-site and

to provide all required reserves for scheduled and un￾scheduled maintenance.

Baseloaded, Electrically Sized—The facility is

sized for baseloaded operation based on the minimum

historic billing demand. Supplemental power is pur￾chased from the utility grid. This facility concept gener￾ally results in a shorter payback period than that from

the isolated site.

Baseloaded, Thermally Sized—The facility is

sized to provide most of the site’s required thermal

energy using recovered heat. The engines operated to

follow the thermal demand with supplemental boiler

fi red as required. The authors point out that: “this op￾tion frequently results in the production of more power

than is required on-site and this power is sold to the

electric utility.”

In addition, the AGA manual includes a descrip￾tion of sources of information or processes by which

background data can be developed for the specifi c gas

distribution service area. Such information can be used

to adapt the feasibility screening procedures to a specifi c

utility.

7.2.4.3 Cogeneration System Selection and Sizing.

The selection of a set of “candidate” cogeneration

systems entails to tentatively specify the most appro￾priate prime mover technology, which will be further

evaluated in the course of the study. Often, two or more

alternative systems that meet the technical requirements

are pre-selected for further evaluation. For instance, a

plant’s CHP requirements can be met by either, a recip￾rocating engine system or combustion turbine system.

Thus, the two system technologies are pre-selected for

a more detailed economic analysis.

To evaluate specifi c technologies, there exist a vast

number of technology-specifi c manuals and references.

A representative sample is listed as follows. Mackay

(1983) has developed a manual titled “Gas Turbine

Cogeneration: Design, Evaluation and Installation.” Ko￾vacik (1984) reviews application considerations for both

steam turbine and gas turbine cogeneration systems.

Limaye (1987) has compiled several case studies on in￾dustrial cogeneration applications. Hay (1988) discusses

technical and economic considerations for cogeneration

application of gas engines, gas turbines, steam engines

and packaged systems. Keklhofer (1991) has written a

treatise on technical and economic analysis of combined￾cycle gas and steam turbine power plants. Ganapathy

(1991) has produced a manual on waste heat boilers.

Usually, system selection is assumed to be separate

from sizing the cogeneration equipment (kWe). How￾ever, since performance, reliability and cost are very

dependent on equipment size and number, technology

selection and system size are very intertwined evalu￾ation factors. In addition to the system design criteria

given by the AGA manual, several approaches for co-

COGENERATION AND DISTRIBUTED GENERATION 173

generation system selection and/or sizing are discussed

as follows.

Heat-to-Power Ratio

Canton et al (1987) of The Combustion and Fuels

Research Group at Texas A&M University has devel￾oped a methodology to select a cogeneration system for

a given industrial application using the heat to power ra￾tio (HPR). The methodology includes a series of graphs

used 1) to defi ne the load HPR and 2) to compare and

match the load HPR to the HPRs of existing equipment.

Consideration is then given to either, heat or power load

matching and modulation.

Sizing Procedures

Hay (1987) considers the use of the load duration

curve to model variable thermal and electrical loads in

system sizing, along with four different scenarios de￾scribed in Figure 7.14. Each one of these scenarios defi nes

an operating alternative associated to a system size.

Oven (1991) discusses the use of the load duration

curve to model variable thermal and electrical loads in

system sizing in conjunction with required thermal and

electrical load factors. Given the thermal load dura￾tion and electrical load duration curves for a particular

facility, different sizing alternatives can be defi ned for

various load factors.

Eastey et al. (1984) discusses a model (CO￾GENOPT) for sizing cogeneration systems. The basic

inputs to the model are a set of thermal and electric

profi les, the cost of fuels and electricity, equipment cost

and performance for a particular technology. The model

calculates the operating costs and the number of units

for different system sizes. Then it estimates the net pres￾ent value for each one of them. Based on the maximum

net present value, the “optimum” system is selected. The

model includes cost and load escalation.

Wong, Ganesh and Turner (1991) have developed

two statistical computer models to optimize cogenera￾tion system size subject to varying capacities/loads and

Figure 7-14. Each operation mode defi nes a sizing alternative. Source: Hay (1987).

174 ENERGY MANAGEMENT HANDBOOK

to meet an availability requirement. One model is for

internal combustion engines and the other for unfi red gas

turbine cogeneration systems. Once the user defi nes a re￾quired availability, the models determine the system size

or capacity that meets the required availability and maxi￾mizes the expected annual worth of its life cycle cost.

7.3 COMPUTER PROGRAMS

There are several computer programs-mainly PC

based-available for detailed evaluation of cogeneration

systems. In opposition to the rather simple methods

discussed above, CHP programs are intended for system

confi guration or detailed design and analysis. For these

reasons, they require a vast amount of input data. Below,

we examine two of the most well known programs.

7.3.1 CELCAP

Lee (1988) reports that the Naval Civil Engineer￾ing Laboratory developed a cogeneration analysis com￾puter program known as Civil Engineering Laboratory

Cogeneration Program (CELCAP), “for the purpose of

evaluating the performance of cogeneration systems on

a lifecycle operating cost basis.” He states that “selec￾tion of a cogeneration energy system for a specifi c ap￾plication is a complex task.” He points out that the fi rst

step in the selection of cogeneration system is to make

a list of potential candidates. These candidates should

include single or multiple combinations of the various

types of engine available. The computer program does

not specify CHP systems; these must be selected by the

designer. Thus, depending on the training and previous

experience of the designer, different designers may se￾lect different systems of different sizes. After selecting a

short-list of candidates, modes of operations are defi ned

for the candidates. So, if there are N candidates and

M modes of operation, then NxM alternatives must be

evaluated. Lee considers three modes of operation:

1) Prime movers operating at their full-rated capacity,

any excess electricity is sold to the utility and any

excess heat is rejected to the environment. Any

electricity shortage is made up with imports. Pro￾cess steam shortages are made-up by an auxiliary

boiler.

2) Prime movers are specified to always meet the

entire electrical load of the user. Steam or heat

demand is met by the prime mover. An auxiliary

boiler is fi red to meet any excess heat defi cit and

excess heat is rejected to the environment.

3) Prime movers are operated to just meet the steam

or heat load. In this mode, power defi cits are made

up by purchased electricity. Similarly, any excess

power is sold back to the utility.

For load analysis, Lee considers that “demand of the

user is continuously changing. This requires that data on

the electrical and thermal demands of the user be avail￾able for at least one year.” He further states that “electri￾cal and heat demands of a user vary during the year be￾cause of the changing working and weather conditions.”

However, for evaluation purposes, he assumes that the

working conditions of the user-production related CHP

load-remain constant and “that the energy-demand pat￾tern does not change signifi cantly from year to year.”

Thus, to consider working condition variations, Lee clas￾sifi es the days of the year as working and non-working

days. Then, he uses “average” monthly load profi les and

“typical” 24-hour load profi les for each class.

“Average” load profi les are based on electric and

steam consumption for an average weather condition at

the site. A load profi le is developed for each month, thus

monthly weather and consumption data is required. A

best fi t of consumption (Btu/month or kWh/month)

versus heating and cooling degree days is thus obtained.

Then, actual hourly load profi les for working and non￾working days for each month of the year are developed.

The “best representative” profi le is then chosen for the

“typical working day” of the month. A similar proce￾dure is done for the non-working days.

Next an energy balance or reconciliation is per￾formed to make sure the consumption of the hourly

load profi les agrees with the monthly energy usage. A

multiplying factor K is defi ned to adjust load profi les

that do not balance.

Kj

= Emj/(AEwj+ AEnwj) (7.9)

where

Kj

= multiplying factor for month j

Emj = average consumption (kWh) by the user for

the month j selected from the monthly elec￾tricity usage versus degree day plot

AEwj = typical working-day electric usage (kWh),

i.e. the area under the typical working day

electric demand profi le for the month j

AEnwj = typical non-working day usage (kWh), i.e.

the area under the typical non-working day

electric demand profi le for the month j.

Lee suggests that each hourly load in the load

profi les be multiplied by the K factor to obtain the “cor-

COGENERATION AND DISTRIBUTED GENERATION 175

rect working and non-working day load profi les for the

month.” The procedure is repeated for all months of the

year for both electric and steam demands. Lee states that

“the resulting load profi les represent the load demand

for average weather conditions.”

Once a number of candidate CHP systems has

been selected, equipment performance data and the load

profi les are fed into CELCAP to produce the required

output. The output can be obtained in a brief or detailed

form. In brief form, the output consists of a summary of

input data and a life cycle cost analysis including fuel,

operation and maintenance and purchased power costs.

The detailed printout includes all the information of the

brief printout, plus hourly performance data for 2 days

in each month of the year. It also includes the maximum

hourly CHP output and fuel consumption. The hourly

electric demand and supply are plotted, along with the

hourly steam demand and supply for each month of the

year.

Despite the simplifying assumptions introduced by

Lee to generate average monthly and typical daily load

profi les, it is evident that still a large amount of data

handling and preparation is required before CELCAP

is run. By recognizing the fact that CHP loads vary

over time, he implicitly justifi es the amount of effort in

representing the input data through hourly profi les for

typical working and non-working days of the month.

If a change occurs in the products, process or

equipment that constitute the energy consumers within

the industrial plant, a new set of load profi les must be

generated. Thus, exploring different conditions requires

sensitivity analyses or parametric studies for off-design

conditions.

A problem that becomes evident at this point

is that, to accurately represent varying loads, a large

number of load data points must be estimated for sub￾sequent use in the computer program. Conversely, the

preliminary feasibility evaluation methods discussed

previously, require very few and only “average” load

data. However, criticism of preliminary methods has

arisen for not being able to truly refl ect seasonal varia￾tions in load analysis (and economic analysis) and for

lacking the fl exibility to represent varying CHP system

performance at varying loads.

7.3.2 COGENMASTER

Limaye and Balakrishnan (1989) of Synergic Re￾sources Corporation have developed COGENMASTER.

It is a computer program to model the technical aspects

of alternative cogeneration systems and options, evalu￾ate economic feasibility, and prepare detailed cash fl ow

statements.

COGENMASTER compares the CHP alternatives

to a base case system where electricity is purchased from

the utility and thermal energy is generated at the site.

They extend the concept of an option by referring not

only to different technologies and operating strategies

but also to different ownership structures and fi nanc￾ing arrangements. The program has two main sections:

a Technology and a Financial Section. The technology

Section includes 5 modules:

• Technology Database Module

• Rates Module

• Load Module

• Sizing Module

• Operating Module

The Financial Section includes 3 modules:

• Financing Module

• Cash Flow Module

• Pricing Module

In COGENMASTER, facility electric and thermal

loads may be entered in one of three ways, depending

on the available data and the detail required for project

evaluation:

— A constant average load for every hour of the year.

— Hourly data for three typical days of the year

— Hourly data for three typical days of each month

Thermal loads may be in the form of hot water or

steam; but system outlet conditions must be specifi ed

by the user. The sizing and operating modules permit

a variety of alternatives and combinations to be con￾sidered. The system may be sized for the base or peak,

summer or winter, and electric or thermal load. There is

also an option for the user to defi ne the size the system

in kilowatts. Once the system size is defi ned, several

operation modes may be selected. The system may be

operated in the electric following, thermal following or

constantly running modes of operation. Thus, N sizing

options and M operations modes defi ne a total of NxM

cogeneration alternatives, from which the “best” alterna￾tive must be selected. The economic analysis is based on

simple payback estimates for the CHP candidates versus

a base case or do-nothing scenario. Next, depending

on the fi nancing options available, different cash fl ows

may be defi ned and further economic analysis-based

176 ENERGY MANAGEMENT HANDBOOK

on the Net Present Value of the alternatives—may be

performed.

7.4 U.S. COGENERATION LEGISLATION: PURPA

In 1978 the U.S. Congress amended the Federal Power

Act by promulgation of the Public Utilities Regulatory

Act (PURPA). The Act recognized the energy saving

potential of industrial cogeneration and small power

plants, the need for real and signifi cant incentives for

development of these facilities and the private sector

requirement to remain unregulated.

PURPA of 1978 eliminated several obstacles to

cogeneration so cogenerators can count on “fair” treat￾ment by the local electric utility with regard to intercon￾nection, back-up power supplies, and the sale of excess

power. PURPA contains the major federal initiatives

regarding cogeneration and small power production.

These initiatives are stated as rules and regulations

pertaining to PURPA Sections 210 and 201; which were

issued in fi nal form in February and March of 1980,

respectively. These rules and regulations are discussed

in the following sections.

Initially, several utilities—especially those with

excess capacity-were reticent to buy cogenerated power

and have, in the past, contested PURPA. Power (1980)

magazine reported several cases in which opposition

persisted in some utilities to private cogeneration. But

after the Supreme Court ruling in favor of PURPA, more

and more utilities are fi nding that PURPA can work to

their advantage. Polsky and Landry (1987) report that

some utilities are changing attitudes and are even invest￾ing in cogeneration projects.

7.4.1 PURPA 201*

Section 201 of PURPA requires the Federal Energy

Regulatory Commission (FERC) to defi ne the criteria

and procedures by which small power producers (SPPs)

and cogeneration facilities can obtain qualifying status

to receive the rate benefi ts and exemptions set forth in

Section 210 of PURPA. Some PURPA 201 defi nitions are

stated below.

Small Power Production Facility

A “Small Power Production Facility” is a facility

that uses biomass, waste, or renewable resources, includ￾ing wind, solar and water, to produce electric power and

is not greater than 80 megawatts.

Facilities less than 30 MW are exempt from the

Public Utility Holding Co. Act and certain state law

and regulation. Plants of 30 to 80 MW which use bio￾mass, may be exempted from the above but may not

be exempted from certain sections of the Federal Power

Act.

Cogeneration Facility

A “Cogeneration Facility” is a facility which pro￾duces electric energy and forms of useful thermal energy

(such as heat or steam) used for industrial, commercial,

heating or cooling purposes, through the sequential use

of energy. A Qualifying Facility (QF) must meet certain

minimum effi ciency standards as described later. Co￾generation facilities are generally classifi ed as “topping”

cycle or “bottoming” cycle facilities.

7.4.2 Qualifi cation of a “Cogeneration Facility” or a

“Small Power Production Facility” under PURPA

Cogeneration Facilities

To distinguish new cogeneration facilities which

will achieve meaningful energy conservation from

those which would be “token” facilities producing

trivial amounts of either useful heat or power, the FERC

rules establish operating and effi ciency standards for

both topping-cycle and bottom-cycle NEW cogenera￾tion facilities. No effi ciency standards are required for

EXISTING cogeneration facilities regardless of energy

source or type of facility. The following fuel utilization

effectiveness (FUE) values—based on the lower heating

value (LHV) of the fuel—are required from QFs.

• For a new topping-cycle facility:

— No less than 5% of the total annual energy

output of the facility must be useful thermal

energy.

• For any new topping-cycle facility that uses any

natural gas or oil:

— All the useful electric power and half the use￾ful thermal energy must equal at least 42.5%

of the total annual natural gas and oil energy

input; and

— If the useful thermal output of a facility is less

than 15% of the total energy output of the facil￾ity, the useful power output plus one-half the

useful thermal energy output must be no less

than 45% of the total energy input of natural

gas and oil for the calendar. *Most of the following sections have been adapted from CFR18 (1990)

and Harkins (1980), unless quoted otherwise.

COGENERATION AND DISTRIBUTED GENERATION 177

For a new bottoming-cycle facility:

• If supplementary fi ring (heating of water or steam

before entering the electricity generation cycle

from the thermal energy cycle) is done with oil

or gas, the useful power output of the bottoming

cycle must, during any calendar year, be no less

than 45% of the energy input of natural gas and

oil for supplementary fi ring.

Small Power Production Facilities

To qualify as a small power production facility

under PURPA, the facility must have production capac￾ity of under 80 MW and must get more than 50% of its

total energy input from biomass, waste, or renewable

resources. Also, use of oil, coal, or natural gas by the

facility may not exceed 25% of total annual energy input

to the facility.

Ownership Rules Applying to

Cogeneration and Small Power Producers

A qualifying facility may not have more than 50%

of the equal interest in the facility held by an electric

utility.

7.4.3 PURPA 210

Section 210 of PURPA directs the Federal Energy

Regulatory Commission (FERC) to establish the rules

and regulations requiring electric utilities to purchase

electric power from and sell electric power to qualifying

cogeneration and small power production facilities and

provide for the exemption to qualifying facilities (QF)

from certain federal and state regulations.

Thus, FERC issued in 1980 a series of rules to relax

obstacles to cogeneration. Such rules implement sections

of the 1978 PURPA and include detailed instructions to

state utility commissions that all utilities must purchase

electricity from cogenerators and small power producers

at the utilities’ “avoided” cost. In a nutshell, this means

that rates paid by utilities for such electricity must re￾fl ect the cost savings they realize by being able to avoid

capacity additions and fuel usage of their own.

Tuttle (1980) states that prior to PURPA 210, cogen￾eration facilities wishing to sell their power were faced

with three major obstacles:

• Utilities had no obligation to purchase power, and

contended that cogeneration facilities were too

small and unreliable. As a result, even those co￾generators able to sell power had diffi culty getting

an equitable price.

• Utility rates for backup power were high and often

discriminatory

• Cogenerators often were subject to the same strict

state and federal regulations as the utility.

PURPA was designed to remove these obstacles,

by requiring utilities to develop an equitable program

of integrating cogenerated power into their loads.

Avoided Costs

The costs avoided by a utility when a cogeneration

plant displaces generation capacity and/or fuel usage

are the basis to set the rates paid by utilities for co￾generated power sold back to the utility grid. In some

circumstances, the actual rates may be higher or lower

than the avoided costs, depending on the need of the

utility for additional power and on the outcomes of the

negotiations between the parties involved in the cogen￾eration development process.

All utilities are now required by PURPA to provide

data regarding present and future electricity costs on a

cent-per-kWh basis during daily, seasonal, peak and off￾peak periods for the next fi ve years. This information

must also include estimates on planned utility capacity

additions and retirements, and cost of new capacity and

energy costs.

Tuttle (1980) points out that utilities may agree to

pay greater price for power if a cogeneration facility

can:

• Furnish information on demonstrated reliability

and term of commitment.

• Allow the utility to regulate the power produc￾tion for better control of its load and demand

changes.

• Schedule maintenance outages for low-demand

periods.

• Provide energy during utility-system daily and

seasonal peaks and emergencies.

• Reduce in-house on-site load usage during emer￾gencies.

• Avoid line losses the utility otherwise would have

incurred.

In conclusion, a utility is willing to pay better

“buyback” rates for cogenerated power if it is short in

capacity, if it can exercise a level of control on the CHP

plant and load, and if the cogenerator can provide and/

or demonstrate a “high” system availability.

178 ENERGY MANAGEMENT HANDBOOK

PURPA further states that the utility is not obligat￾ed to purchase electricity from a QF during periods that

would result in net increases in its operating costs. Thus,

low demand periods must be identifi ed by the utility

and the cogenerator must be notifi ed in advance. Dur￾ing emergencies (utility outages), the QF is not required

to provide more power than its contract requires, but a

utility has the right to discontinue power purchases if

they contribute to the outage.

7.4.4 Other Regulations

Several U.S. regulations are related to cogenera￾tion. For example, among environmental regulations,

the Clean Air Act may control emissions from a waste￾to-energy power plant. Another example is the regu￾lation of underground storage tanks by the Resource

Conservation and Recovery Act (RCRA). This applies to

all those cogenerators that store liquid fuels in under￾ground tanks. Thus, to maximize benefi ts and to avoid

costly penalties, cogeneration planners and developers

should become savvy in related environmental mat￾ters.

There are many other issues that affect the de￾velopment and operation of a cogeneration project.

For further study, the reader is referred to a variety of

sources such proceedings from the various World En￾ergy Engineering Congresses organized by the Associa￾tion of Energy Engineers (Atlanta, GA). Other sources

include a general compendium of cogeneration planning

considerations given by Orlando (1990), and a manual￾developed by Spiewak (1994)—which emphasizes the

regulatory, contracting and fi nancing issues of cogenera￾tion.

7.5 EVALUATING COGENERATION

OPPORTUNITIES: CASE EXAMPLES

The feasibility evaluation of cogeneration opportunities

for both, new construction and facility retrofi t, require

the comparison and ranking of various options using a

fi gure of economic merit. The options are usually combi￾nations of different CHP technologies, operating modes

and equipment sizes.

A fi rst step in the evaluation is the determination

of the costs of a base-case (or do-nothing) scenario.

For new facilities, buying thermal and electrical energy

from utility companies is traditionally considered the

base case. For retrofi ts, the present way to buy and/or

generate energy is the base case. For many, the base-case

scenario is the “actual plant situation” after “basic” en￾ergy conservation and management measures have been

implemented. That is, cogeneration should be evaluated

upon an “effi cient” base case plant.

Next, suitable cogeneration alternatives are gener￾ated using the methods discussed in sections 7.2 and

7.3. Then, the comparison and ranking of the base case

versus the alternative cases is performed using an eco￾nomic analysis.

Henceforth, this section addresses a basic approach

for the economic analysis of cogeneration. Specifi cally,

it discusses the development of the cash fl ows for each

option including the base case. It also discusses some

fi gures of merit such as the gross pay out period (simple

payback) and the discounted or internal rate of return.

Finally, it describes two case examples of evaluations in

industrial plants. The examples are included for illustra￾tive purposes and do not necessarily refl ect the latest

available performance levels or capital costs.

7.5.1 General Considerations

A detailed treatise on engineering economy is pre￾sented in Chapter 4. Even so, since economic evaluations

play the key role in determining whether cogeneration

can be justifi ed, a brief discussion of economic consid￾erations and several evaluation techniques follows.

The economic evaluations are based on examining

the incremental increase in the investment cost for the

alternative being considered relative to the alternative

to which it is being compared and determining whether

the savings in annual operating cost justify the increased

investment. The parameter used to evaluate the eco￾nomic merit may be a relatively simple parameter such

as the “gross payout period.” Or one might use more

sophisticated techniques which include the time value of

money, such as the “discounted rate of return,” on the

discretionary investment for the cogeneration systems

being evaluated.

Investment cost and operating cost are the expen￾diture categories involved in an economic evaluation.

Operating costs result from the operations of equipment,

such as (1) purchased fuel, (2) purchased power, (3) pur￾chased water, (4) operating labor, (5) chemicals, and (6)

maintenance. Investment-associated costs are of primary

importance when factoring the impact of federal and

state income taxes into the economic evaluation. These

costs (or credits) include (1) investment tax credits, (2)

depreciation, (3) local property taxes, and (4) insurance.

The economic evaluation establishes whether the op￾erating and investment cost factors result in suffi cient

after-tax income to provide the company stockholders

an adequate rate of return after the debt obligations with

regard to the investment have been satisfi ed.

When one has many alternatives to evaluate, the

COGENERATION AND DISTRIBUTED GENERATION 179

less sophisticated techniques, such as “gross payout,”

can provide an easy method for quickly ranking al￾ternatives and eliminating alternatives that may be

particularly unattractive. However, these techniques are

applicable only if annual operating costs do not change

signifi cantly with time and additional investments do

not have to be made during the study period.

The techniques that include the time value of

money permit evaluations where annual savings can

change signifi cantly each year. Also, these evaluation

procedures permit additional investments at any time

during the study period. Thus these techniques truly

refl ect the profi tability of a cogeneration investment or

investments.

7.5.2 Cogeneration Evaluation Case Examples

The following examples illustrate evaluation proce￾dures used for cogeneration studies. Both examples are

based on 1980 investment costs for facilities located in

the U.S. Gulf Coast area.

For simplicity, the economic merit of each alterna￾tive examined is expressed as the “gross payout period”

(GPO). The GPO is equal to the incremental investment

for cogeneration divided by the resulting fi rst-year an￾nual operating cost savings. The GPO can be converted

to a “discounted rate of return” (DRR) using Figure 7.15.

However, this curve is valid only for evaluations involv￾ing a single investment with fi xed annual operating cost

savings with time. In most instances, the annual savings

due to cogeneration will increase as fuel costs increase

to both utilities and industries in the years ahead. These

increased future savings enhance the economics of co￾generation. For example, if we assume that a project has a

GPO of three years based on the fi rst-year operating cost

savings, Figure 7.15 shows a DRR of 18.7%. However, if

the savings due to cogeneration increase 10% annually

for the fi rst three operating years of the project and are

constant thereafter, the DRR increases to 21.6%; if the sav￾ings increase 10% annually for the fi rst six years, the DRR

would be 24.5%; and if the 10% increase was experienced

for the fi rst 10 years, the DRR would be 26.6%.

Example 6: The energy requirements for a large in￾dustrial plant are given in Table 7.3. The alternatives

considered include:

Base case. Three half-size coal-fi red process boilers are

installed to supply steam to the plant’s 250-psig steam

header. All 80-psig steam and steam to the 20-psig deaer￾ating heater is pressure-reduced from the 250-psig steam

header. The powerhouse auxiliary power requirements

are 3.2 MW. Thus the utility tie must provide 33.2 MW

to satisfy the average plant electric power needs.

Case 1. This alternative is based on installation of a

noncondensing steam turbine generator. The unit initial

Table 7.3 Plant Energy Supply System Considerations: Example 6

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Process steam demands

Net heat to process at 250 psig. 410°F—317 million Btu/hr avg.

Net heat to process at 80 psig, 330°F—208 million Btu/hr avg. (peak requirements are 10% greater than

average values)

Process condensate returns: 50% of steam delivered at 280°F

Makeup water at 80°F

Plant fuel is 3.5% sulfur coal

Coal and limestone for SO2 scrubbing are available at a total cost of $2/million Btu fi red

Process area power requirement is 30 MW avg.

Purchased power cost is 3.5 cents/kWh

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Fig. 7.15 Discounted rate of return versus gross payout

period. Basis: (1) depreciation period, 28 years; (2) sum￾of-the-years’-digits depreciation; (3) economic life, 28

years; (4) constant annual savings with time; (5) local

property taxes and insurance, 4% of investment cost;

(6) state and federal income taxes, 53%; (7) investment

tax credit, 10% of investment cost.

180 ENERGY MANAGEMENT HANDBOOK

steam conditions are 1450 psig, 950°F with automatic

extraction at 250 psig and 80 psig exhaust pressure.

The boiler plant has three half-size units providing the

same reliability of steam supply as the Base Case. The

feedwater heating system has closed feedwater heat￾ers at 250 psig and 80 psig with a 20 psig deaerating

heater. The 20-psig steam is supplied by noncondensing

mechanical drive turbines used as powerhouse auxiliary

drives. These units are supplied throttle steam from the

250-psig steam header. For this alternative, the utility tie

normally provides 4.95 MW. The simplifi ed schematic

and energy balance is given in Figure 7.16.

The results of this cogeneration example are tabu￾lated in Table 7.4. Included are the annual energy re￾quirements, the 1980 investment costs for each case, and

the annual operating cost summary. The investment cost

data presented are for fully operational plants, includ￾ing offi ces, stockrooms, machine shop facilities, locker

rooms, as well as fi re protection and plant security. The

cost of land is not included.

The incremental investment cost for Case 1 given

in Table 7.4 is $17.2 million. Thus the incremental cost is

$609/kW for the 28.25-MW cogeneration system. This il￾lustrates the favorable per unit cost for cogeneration sys￾tems compared to coal-fi red facilities designed to provide

kilowatts only, which cost in excess of $1000/kW.

The impact of fuel and purchased power costs

other than Table 7.3 values on the GPO for this example

is shown in Figure 7.17. Equivalent DRR values based

on fi rst-year annual operating cost savings can be esti￾mated using Figure 7.15.

Sensitivity analyses often evaluate the impact

of uncertainties in the installed cost estimates on the

profi tability of a project. If the incremental investment

cost for cogeneration is 10% greater than the Table 7.4

estimate, the GPO would increase from 3.2 to 3.5 years.

Thus the DRR would decrease from 17.5% to about 16%,

as shown in Figure 7.15.

Table 7.4 Energy and Economic Summary: Example 6

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Alternative Base Case Case 1

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Energy summary

Boiler fuel (106 Btu/hr HHV) 599 714

Purchased power (MW) 33.20 4.95

Estimated total installed cost (106 $) 57.6 74.8

Annual operating costs (106 $)

Fuel and limestone at $2/106 Btu 10.1 12.0

Purchased power at 3.5 cents/kWh 9.8 1.5

Operating labor 0.8 1.1

Maintenance 1.4 1.9

Makeup water 0.3 0.5

Total 22.4 17.0

Annual savings (106 $) Base 5.4

Gross payout period (yrs) Base 3.2

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Basis: (1) boiler effi ciency is 87%; (2) operation equivalent to 8400 hr/yr at Table 7-3 conditions; (3) maintenance

is 2.5% of the estimated total installed cost; (4) makeup water cost for case 1 is 80 cents/1000 gal greater than Base

Case water costs; (5) stack gas scrubbing based on limestone system.

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Fig. 7.16 Simplified schematic and energy-balance

diagram: Example 6, Case 1. All numbers are fl ows in

103 lb/hr; Plant requirements given in Table 7.8, gross

generation, 30.23 MW; powerhouse auxiliaries, 5.18

MW; net generation, 25.05 MW.