EPA-901/9-76-006
COST ANALYSIS OF TWO AIR QUALITY
ATTAINMENT STRATEGIES
By
Harbridge House, Inc.
11 Arlington Street
Boston, Massachusetts 02116
15 June 1976
Prepared under
EPA Contract No. 68-01-1561
Task Order No. 5
Prepared for
U.S. Environmental Protection Agency
Region I
Boston, Massachusetts
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EPA-901/9-76-006
COST ANALYSIS OF TWO AIR QUALITY
ATTAINMENT STRATEGIES
By
Harbridge House, Inc.
11 Arlington Street
Boston, Massachusetts 02116
15 June 1976
Prepared under
EPA Contract No. 68-01-1561
Task Order No. 5
Prepared for
U.S. Environmental Protection Agency
Region I
Boston, Massachusetts
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This report has been reviewed by the Environmental Protection
Agency and approved for publication. Approval does not signify
that the contents necessarily reflect the news and policies of the
Environmental Protection Agency.
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TABLE OF CONTENTS
EXECUTIVE SUMMARY
CHAPTER I: INTRODUCTION
A. Background and Approach I- 1
B. The Worcester Area Economy and
Economic Outlook I- 3
C. Financing Options I- 5
1. Financing for Private Industry I- 5
2. Financing for the Public Sector 1-6
D. Organization of the Report I- 7
CHAPTER II: MARGINAL BURNER RETROFIT STRATEGY
A. Background and Approach II- 1
1. Natural Draft Rotary Cup
Burner Characteristics n- 1
2. Types of Costs Considered n- 2
3. Worcester Marginal Burner Inventory n- 4
B. Costing Procedures II- 8
1. Marginal Burner Replacement Costs n- 8
2. Increased Efficiency in Fuel Use 11-10
3. Cost of Capital n-11
4. Depreciation 11-12
C. Analysis and Results 11-12
CHAPTER IE: FUEL TYPE CONVERSION STRATEGY
A. Background and Approach ELI- 1
1. Types of Costs Considered HI- 1
2. Worcester Combustion Source Inventory HI- 4
B. Costing Procedures in- 7
1. Combustion System Modifications m- 7
2. Replacement of Marginal Burners HI- 8
3. Increased Efficiency in Fuel Use Ill- 8
4. Adjustments for BTU Content Ill- 8
5. Adjustments for Residual Preheating HI-10
6. Fuel Oil Prices HI-10
7. Cost of Capital IH-12
8. Depreciation in-12
C. Analysis and Results ni-12
APPENDIX A: SUMMARY OF THE MARYLAND
EXPERIENCE WITH A ROTARY CUP
RETROFIT REGULATION
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EXECUTIVE SUMMARY
In the preparation of its air quality attainment and short-term maintenance
plan, the Massachusetts Department of Environmental Quality Engineering
(DEQE) is evaluationg the feasibility and desirability of implementing two air
quality control strategies. Both strategies have been proposed for application
to the City of Worcester in order to attain national ambient air quality standards
for particulates during the winter months when seasonal loads on combustion
sources contribute to violations. The strategies are as follows:
Replacement of marginal burners with more energy efficient modern
equipment.
Conversion from residual oil to the use of lighter fuels and/or fuels
of lower sulfur content.
Harbridge House, Inc. is assisting DEQE in the evaluation of these strate-
gies by estimating the economic costs to owners of affected combustion sources
that may result from the implementation of one or both measures. This cost
analysis, which is summarized below, is to be subsequently coordinated with the
results of a strategy air pollution control effectiveness analysis which DEQE is
undertaking.
Prior to evaluating the cost associated with each strategy, brief considera-
tion was given to the economic and financial environments in which strategy imple-
mentation would occur.
Worcester's Economy and Economic Outlook
The City of Worcester has undergone an economic reversal during
the year from late 1974 to late 1975 as cyclical trends felt nation-
wide exerted a strong impact on Worcester's durable goods manu-
facturing sector.
As used by Massachusetts DEQE,residual oil includes #6, #5, and #4 fuel oils.
(ii)
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Because of the nature of the durable goods sector (the back-
bone of the Worcester economy), it is expected that recovery
will be gradual with some lag behind other areas of Massachu-
setts and the nation.
Some economic analysts in Worcester believe that signs of
recovery are already apparent, indicating that past levels of
productivity may be regained by 1978.
Financing Options
Depending on the availability and terms, financing options may
provide assistance to owners of facilities subject to strategy
related costs.
Private sector facilities are eligible for loans and programs
offered by the Small Business Administration (SBA) as well as
commercial banking operations. An important criteria for
obtaining a loan is the firm's credit worthiness.
Public facilities, if they cannot fund strategy related expendi-
tures from ope rating funds, are likely to include the extra costs
in a larger bond issue in order to obtain favorable rates and
terms.
Marginal Burner Retrofit Strategy
This strategy proposed replacement of marginal burners, de-
fined in this analysis as natural draft rotary cup burners, with
more energy efficient modern equipment. It has a unique ad-
vantage over a strategy specifying "add on" pollution control
equipment in that a substantial savings may accrue to the owner
in the form of reduced fuel bills.
Costs considered in analysis of this strategy included: equipment
costs and installation of the modern burner, interest and depre-
ciation charges on capital expenditures, fuel savings in gallons and
fuel price in cents per gallon.
DEQE specified acceptable equipment for replacement of marginal
burners. Manufacturer estimates, based on actual experience in
Massachusetts, were used to represent the most likely range of capi-
tal and installation costs.
(iii)
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Private sector financing was conservatively assumed to be
obtained at 10 percent interest over five years, while public
sector funding was assumed to be obtained at a 5.75 percent
rate over a 20-year term.
Equipment costs were inflated to 1978, as directed by DEQE.
A rate of nine percent per year was used based on the histori-
cal wholesale price index for heating equipment and a compari-
son with recently quoted rates in Massachusetts.
Depreciation was based on the straight line method over 25
years assuming no scrap value in the 26th year.
Estimates of fuel savings obtained from manufacturers ranged
from ten percent to 25 percent. In consultation with DEQE, a
15 percent annual savings was assumed in the analysis. This
figure was based on an estimate that current maintenance prac-
tices (unchanged after strategy implementation) include at least
one burner adjustment per year. Current fuel oil prices were
used, as directed by DEQE.
Net annual costs or savings during the first year of strategy
Implementation for all size categories range from a net savings
of $87,500 to a net cost of $75, 900 as shown in Exhibit I.1
Costs will be lower (and savings higher) in all subsequent years.
Net annual costs or savings per site for all size categories range
from a savings of $600 to a cost of $500 per site.
Based on the analytical assumptions, public sector facilities on
average for all size categories will experience a net savings in
the firs.t year ranging from $28,250 to $950. Private sector fa-
cilities, on average for all size categories, will experience a
range of savings/costs from a net savings of $59,250 to a cost
of $76,900.
In the public sector, facilities in the 10 through 50 million BTU
per hour site size categories will experience net savings in the
first year ranging from a total of $2100 to $15,100. Net costs
The range reflects the most likely costs of equipment and installation.
(iv)
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EXHIBIT 1
ESTIMATED NET ANNUAL COSTS OR
SAVINGS OR MARGINAL BURNER
RETROFIT STRATEGY
a
IMIIIIJC
1'ltlVATK
TOTAL
11 to C Million BTU/llour
$3800 - ($400)
($1300)- ($l(i,800)
$2500 -($17,200)
« through 10 Million BTU/llour
($4550)
($2800)
($7350)
- ($11,250)
- ($38,050)
- ($49,300)
10 through 25 Million
llTU/llour
$13,'JOO - $2050
$13,400 - ($34,400)
$27,300 - ($32,350)
25 through 50 Million 50 through 100 Million
IJTU/llour BTU/llour
$15, 100 - $10,550 MONK
$53,700 - $30,750 ($3750) -($18,400)
$««, 800 - $41,300 ($3750) - ($18,400)
Total
$28, 250 - $U50
$59,250 - ($7(i,UOO)
$87,500 - ($75,050)
Figures bracket most likely range. Note; Because of financing assumptions, cost shown represents net annual costs during the first year of
implementation. In subsequent years, cost will be lower (or savings higher). ( ) indicates a net cost.
Source: llarbridge House, Inc. 197(i. See Inhibit 11-4 for more detail on costs and savings.
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will be experienced in the first year by facilities in the site
size categories from 3 to 10 million BTU per hour, ranging
from a total of $400 to $11,300.
In the private sector, net savings are experienced in the first
year by facilities in the 25 through 50 million BTU site size
category, ranging from a total of $53,700 to $30, 800. Net
costs are experienced in all other categories ranging from
a total of $3000 to $38, 000.
Evaluation of the time required before capital investment
and interest charges are fully recovered in annual fuel bill
savings showed that the private sector facilities would re-
quire from two to six years, while the public sector would
require from 5 to 19 years.
e These burner replacement costs are believed to reflect on
overly conservative case largely because of the presence of
stand-by units in the Worcester inventory. DEQE has stated
that implementation of this strategy will provide a mechanism
whereby burners on stand-by boilers may be exempted from
the retrofit requirement.
Fuel Type Conversions Strategy
Although this analysis is addressed as a single strategy, four
alternative fuel conversions are actually considered under two
assumptions regarding the timing of the implementation of the
marginal burner retrofit strategy. The conversions are as
follows:
Conversion of sources burning #6 (1%3) oil to #6 (0. 5%S) oil.
Conversion of sources burning #6 oil to #4 oil.
Conversion of sources in the under 50 million BTU per hour
site size categories burning #6 oil to #2 oil.
Conversion of sources in the under 50 million BTU per hour
site size categories burning #4 oil to #2 oil. (Sources burning
#5 oil are grouped with #4 oil users, as directed by DEQE.)
According to Massachusetts regulations, all sources buring #6
oil are assumed to be burning #6 (1%S) oil.
(vi)
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Although fuel oil type conversions are often considered as
sulfur oxide control strategies, DEQE has considered these
conversions for control of particulates in light of recent evi-
dence indicating a positive relationship between participate
emissions and the viscosity and other qualities of fuel burned,
such as sulfur content.
Each of the above conversions is evaluated assuming prior
implementation of the marginal burner retrofit strategy and
assuming that the strategy has not been implemented. These
assumptions were included to provide DEQE with flexibility
in the strategy effectiveness evaluation.
In the conversions from residual (#4 and #6 oils) to distillate
(#2 oil) certain modifications of the combustion system are
required including replacement of pumps, strainer baskets,
and relief valves, and adjustment of the burner. Manufac-
turer estimates of the costs (based on actual experience in
Massachusetts) were used.
Other cost changes considered included the differential prices
of fuel(current prices as directed by DEQE), differences in
heat content of different grades of oil, oil preheating require-
ments, and in conversions from residual to distillate firing,
(under the assumption of no prior retrofit of marginal burners)
the cost of marginal burner retrofit and resulting fuel savings.
Interest and depreciation charges were also included as appro-
priate.
Because of the coordination with the marginal burner retrofit
strategy implementation, it was assumed that conversions
would take place in 1978. As directed by DEQE, equipment
costs were inflated to that year.
Results (summarized in Exhibit 2) indicate that the conversion
from #4 to #2 oil will be least costly, with total annual costs
ranging from $96,000 to $172, 000 (or $1200 to $2200 per site)
under both assumptions regarding implementation of the mar-
ginal burner retrofit strategy.
The 6 through 25 million BTU per hour site size
categories were found to incur about 70 percent of
total costs in this conversion.
(vii)
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EXHIBIT 2
ESTIMATED TOTAL ANNUAL COSTS OF ALTERNATIVE
FUEL TYPE CONVERSIONS
Assuming Prior Implementation
of Marginal Burner Retrofit
Strategy
Assuming No Prior Implementation
of Marginal Burner Retrofit
Strategy
#6(1%S) to#G(0.5%S)
$413,400
$427,800
#6 to #4
$792,400
$820,400
#G to #2a
$419,200 -
$433,700
$305,700 -
$43 G, 7 00
M to //2a
$127,700 -
$139,500
$ 9G, 000 -
$171, GOO
a
Figures bracket most likely range. Because of capital cost financing assumptions, costs shown are for the
first five years of implementation and will be lower in subsequent years.
Source; llarbridge House, Inc. 197G. See Exhibits III-G and 1II-7 for more detailed breakdowns.
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The conversion from #6 to #4 fuel use was found to be most
costly under both assumptions, with total annual costs rang-
ing from $790,000 to $820,000 (or $13,400 to $13, 900 per
site).
The greater than 100 million BTU per hour site size
category was found to incur about 60 percent of total
costs in this conversion.
Total annual conversion costs from #6 (1%S) to #6 (0.5%S)
and from #6 to #2 ranged from $360,000 to $440, 000 (or
$7000 to $9400 per site) under both assumptions.
In the #6 (1%S) to #6 (0.5%S) conversion the greater
than 100 million BTU per hour site size category was
found to incur 60 percent of the total costs.
In the #6 to #2 conversion, the 10 through 50 million
BTU per hour site size categories were found to incur
about 90 percent of total costs.
An important result of the #4 to #2 conversion under the assump-
tion of no prior retrofit of the marginal burner retrofit strategy
is that fuel costs were found to decrease as a result of strategy
implementation. Consequently, after capital costs are fully amor-
tized (five years for private sector facilities and 20 years for
public sector facilities), a net savings will be experienced.
(ix)
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I. INTRODUCTION
A. Background and Approach
Pursuant to 40 CFR 51.12(a)-(h), as published in the Federal Register of
18 June 1973, and subsequently revised in 8 May 1974 (39 FR 16343), all states
must identify geographic areas which have exceeded or have the potential for ex-
ceeding national ambient air quality standards (NAAQS) within the subsequent ten-
year period. After these designated areas are reviewed, altered (if deemed
necessary), and approved by the Environmental Protection Agency (EPA), each
state is required to undertake a thorough analysis of the impact of growth and de-
velopment on the air quality of the area. Where existing (measured and estimated)
ambient levels of a pollutant exceed NAAQS, the plan is to set forth a control stra-
tegy for reduction of emission levels to the degree necessary for the attainment
and then maintenance of the national standard. Where analysis shows that an area
currently complying with NAAQS will not maintain pollutant levels consistent with
NAAQS over a ten-year period from the date of plan submittal, a state must develop
an effective plan to provide maintenance of air quality standards.
The State of Massachusetts, Department of Environmental Quality Engineer-
ing (DEQE) is in the process of preparing its air quality attainment and short-term
maintenance plan for submission to Region I, EPA. The City of Worcester has
been identified by DEQE as exceeding the particulate standards during the winter
months. Moreover, the agency has concluded that seasonal loads placed on com-
bustion sources are one component of the particulate problem.
In order to attain particulate standards year round in Worcester, the follow-
ing two strategies are being considered by DEQE for inclusion in their 15 May plan
submission.
Replacement of inefficient marginal burners with more energy-efficient
modern equipment.
Conversion of sources using residual fuel oil to lower sulfur content
or lighter fuel oil.
As used by Massachusetts DEQE, residual oil includes #6, #5, and #4 fuel oils,
while distillate oil refers to #2 fuel oil.
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I- 2
In assessing the feasibility and desirability of implementing these strategies, a cost
effectiveness evaluation has been undertaken jointly by Harbridge Rouse and DEQE.
DEQE is evaluating the particulate emission reductions associated with implementa-
tion, while Harbridge House has analyzed the economic implications. This report
details the methodology and results of the Harbridge House effort.
Approaches taken in evaluation of the two strategies differ considerably. On
the one hand, the marginal burner retrofit strategy assessment was aimed at deter-
mining not only the economic costs of burner replacement, but also the annual operat-
ing cost savings resulting from the use of more energy-efficient modern equipment.
These two aspects of the analysis have then been integrated to determine the time
period over which the costs will be recovered. On the other hand, the fuel type con-
version strategy, represents a cost to owners without any significicant economic ad-
vantages. Consequently, this latter analysis focuses solely on incremental fuel-
related expenses and associated capital costs.
Evaluation of the two strategies is similar, however, in that only economic
costs to owners of affected facilities (as opposed to the general public) are evaluated.
Moreover, for both strategies, costs have been aggregated by site (or facility) size
categories in order to reflect various alternative applications of the strategies.
It is important to recognize that the analysis undertaken by Harbridge House
has not been aimed at assessing the financial impact on particular companies of the
costs associated with implementation of the strategies. Clearly, the costs will dif-
ferentially affect owners of facilities which are subject to burner replacement and/or
fuel oil type conversions. Several factors are likely to influence the relative severity
of impact experienced, including industry structure, current, and near-term econ-
omic conditions, and the availability and terms of financing options. In order to
provide some insight into the economic and financial environments in which the pro-
posed strategies would be implemented, the following two sections of this chapter
briefly describe salient aspects of the Worcester area economy and the types of fi-
nancing arrangements potentially available to owners of affected facilities.
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I- 3
B. The Worcester Area Economy and Economic Outlook
Worcester today is the industrial and commercial center of central Massachu-
setts. In 1974 there were 3, 797 firms reporting to the State Division of Employment
Security (DES). These firms employed 82, 701 personnel in 1974 with annual payrolls
totalling $741 million.
The manufacturing sector of the Worcester economy was based historically on
four major industries: wire manufacture (specializing in piano wire), the textile in-
dustry, grinding wheel production, and envelope production. Today, the major manu-
facturing groups in Worcester, in order of their workforce size, are: fabricated metal
products; machinery (excluding electrical); stone, clay and glass products; primary
metal products; printing and publishing; food and kindred products; and leather and
leather products. These firms employed 31,165 persons in 1974 which amounted to
79 percent of the total manufacturing workforce in that year.
The retail and wholesale trade section of the economy showed 285 wholesale
firms in 1974 employing 5,794 persons and 1, 028 retail firms with 12, 807 persons
for that same year. The number of retail trade firms in 1974 was 50 percent fewer
than those recorded in 1972.
During the past year and a half, dramatic changes have occurred in the econ-
omic vitality of the Worcester area. In December 1974, for example, the Worcester
Labor Market Area had the second lowest unemployment rate in the State. Unemploy-
ment averaged below the state-wide average and was equal to the national rate of
7.2 percent. One year later, in December 1975, unemployment had risen to 11.6
percent and was surpassed by only one other area of the State. Moreover, a high
of 14.4 percent unemployment had been experienced in the intervening period (June 1975).
The information described here is based upon discussions with state, regional, and
local economic analysts and planners and upon published sources including: "Massa-
chusetts Profile of Worcester," Massachusetts Department of Commerce and Devel-
opment, March 1976; Annual Manpower Planning Report for the Worcester SMSA.
Massachusetts Division of Employment Security. January 1975: "Area Manpower
Review for the Worcester Labor Market Area." Massachusetts Division of Employ-
ment Security. Winter, 1976; "Manpower Requirements for the SMSA by Occupation
and Industry, 1970-1980," Massachusetts Division of Employment Security, October,
1975.
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I- 4
In addition, over the year from December 1974 to December 1975, non-farm
employment decreased by 3100 persons. This was primarily attributable to a slump
in the durable goods manufacturing sector, which has been hard hit by reduced capi-
tal goods orders. Employment in the consumer goods sector, however, has remained
firm over the year with some increases in textile and leather manufacturing. Both
government employment and employment in the service sector increased slightly,
while all other sectors of non-manufacturing declined except contract construction
which remained the same over that year.
A significant aspect of this recent downturn in the Worcester economy is its
timing with regard to recessionary trends in the nation and in Massachusetts, as a
whole. The New England states traditionally lag behind the nation in experiencing
swings in economic conditions. Moreover, the impact of nationwide trends is usually
more severe in New England as opposed to the rest of the country. The Worcester
area, in addition to lagging behind the nation, also has been found to experience cycli-
cal trends apparent in other parts of New England later than the rest of Massachusetts.
Economic analysts attribute this lag to Worcester's strong durable goods manufactur-
ing base, because orders for investment type goods are placed months and years in
advance of delivery. This "protective shield" against short-term swings in the na-
tional economy, works to Worcester's disadvantage, however, when recessionary
economic forces persist and backlogged orders become depleted.
Apparently, this phenomenon has begun to be felt in Worcester, with the result
that recovery is likely to be more gradual than in other areas. Other sectors nation-
wide will have to recover sufficiently before momentum is built up in the capital goods
market for Worcester's durable manufacturers to regain past levels of productivity.
Nevertheless, there is a feeling among economic analysts that the region is be-
ginning to show signs of coming out of the current recession and that the remainder
of 1976 will show improvements in the area's economy.
Manpower Requirements for the SMSA by Occupation and Industry 1970-1980, Massa-
chusetts Division of Employment Security. October 1975.
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I- 5
Recent forecasts of commercial and industrial activity in Worcester over the next
three to five years are not available. However, if the posture of economic analysts
is correct and a reversal has started to take place, it appears likely that full re-
covery will occur within the time frame of this study.
C. Financing Options
Financing capital expenditures allows the owners of facilities affected by costs
from strategy implementation to spread the costs out over several years. This, in
turn, has the effect of freeing other monies to carry on operations. In this manner,
the availability and terms of financing options can be viewed as a force mitigating the
potential impact of actions which increase capital requirements. There is, however,
at least one caveat to this optimistic view of the role of financing as a mitigating fac-
tor. In particular, facilities which are currently operating close to the margin of
financial feasibility may be unable or unwilling to take on a medium to long-term
financial commitment. Their need for capital may be most pressing in areas unre-
lated to strategy implementation, such that if they can obtain capital expenditure fi-
nancing, combustion system modification would likely be a low-priority for its use.
In order to provide a basis for further exploration of the potential role of fi-
nancing options in providing assistance to owners subject to stragegy related costs,
a brief summary of alternative arrangements open to private and public sector faci-
lities is discussed below.
1. Financing for Private Industry
There currently exist several financing options for private firms facing
capital expenditures from strategy implementation. The most direct case would be
a firm financing these costs out of their operating capital. However, in the case of
firms unable to meet these estimated expenses out of their operating capital, loan
programs do exist which can aid the businessman in meeting these added costs.
a. Small Business Administration Air Pollution Control Program
The SBA provides support and in some cases direct loans to small
businesses to help meet federally mandated air quality regulations. Under
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I- 6
their Air Pollution Control (APC) Program, the SBA may guarantee 90 per-
cent of a bank loan which currently is offered at a maximum interest of
10-1/2 percent annually over a period of ten years. Interest rates could be
obtained below that maximum according to the individual credit worthiness
of the prospective firm applying to a bank.
If bank financing were not available to a firm, a direct SBA loan
could be obtained. The individual firm would have to first submit its plans
for equipment purchase or modification to DEQE for their approval prior to
granting of the loan. The present interest rate on these direct SBA loans
2
is 6-5/8 percent annually over ten years.
b. Private Financing
Also available to a firm is conventional bank financing based
upon current market conditions and the credit worthiness of the prospec-
tive firm. Interest rates and terms would be set by the bank at the time
of application. However, it should be pointed out that a firm unable to
meet the relatively small capital expenditures required by the strategies
(estimated to average below $15, 000) from its operating capital would not
receive the most favorable terms from a bank. Typically, such conven-
tional loans, are made for much larger amounts.
2. Financing for the Public Sector
In the case of a public facility such as a school, the source of funds would
be the municipal budget as financed by municipal bonds. The City of Worcester would
include these added costs in their overall municipal budget for the year (s) in which
these replacements were to be made. Rather than request funds separately for these
Daniel Rich, Loan Officer, Small Business Administration, Boston District Officer.
Telephone interview 16 April, 1976.
2
Ibid.
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I - 7
relatively minor costs, the City would most likely include the costs in a larger bond-
ing issue (or if feasible, fund them out of general operating funds). By including rela-
tively small costs in its overall municipal funding program, the City would be able to
take advantage of a reduced bonding interest rate. Currently, the City of Worcester
rate for municipal bonds is around 5-3/4 percent for a twenty-year term.
D. Organization of the Report
In Chapter I the two air quality control strategies proposed for application in the
City of Worcester have been briefly introduced. Background information regarding the
Worcester economy and economic outlook has been presented to provide some insight
into the environment in which the economic costs, evaluated in subsequent Chapters,
will be incurred. Attention, furthermore, has focused on options which may provide
assistance in financing costs associated with strategy implementation.
Following this presentation, Chapters II and ni define each of the strategies, sum-
marize the methodologies used in the cost evaluations, and describe the results. Chap-
ter II addresses the marginal burner retrofit strategy while Chapter III deals with al-
ternative fuel type conversions. One appendix, included at the end of the report, sum-
marizes the experience of the State of Maryland in implementing a rotary cup burner
retrofit regulation.
Barry Cluff, Municipal Bond Department, First National Bank of Boston. Telephone
interview 16 April, 1976. (As of 1 June 1976 market changes have resulted in a rate
increase to somewhere over 6 percent. Ibid.)
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II. MARGINAL BURNER RETROFIT STRATEGY
A. Background and Approach
The Massachusetts DEQE has proposed an air quality control strategy for par-
ticulates which focuses on replacing marginal burners in combustion systems of all
sizes within the Worcester City limits. A strategy requiring replacement of marginal
burners has a distinct advantage over a control method utilizing add-on pollution con-
trol equipment in that substantial efficiencies in fuel use are likely to be achieved by
burner replacement. Consequently, the benefits of implementation of such a retrofit
strategy are not limited to pollution control effectiveness, but also must include fuel
cost savings to owners of affected facilities.
In order to assess the impact of this strategy, marginal burners have been de-
fined by DEQE as natural draft rotary cup burners. The rationale for this definition
is based on the performance characteristics of these burners, which are briefly de-
scribed below.
1. Natural Draft Rotary Cup Burner Characteristics'1-
The rotary cup burner is designed to throw air off the edge of a rotating
cup into a fast-moving air stream. The oil tends to bleed off the cup in sheets or
strings which are then broken into droplets as the oil is accelerated into the air stream.
Inefficient combustion results from the reliance of natural draft rotary cup burners on
the natural draft of the fire to suck the major portion of the air into the combustion
chamber. In most cases, this means there is insufficient energy intensity brought
to bear on the oil-and-air environment to cause rapid breakup of the oil into very
small particles. Such atomization is necessary for effective combustion and emis-
sion control. Moreover, since there is so little control over the quantity of air in-
troduced into the combustion chamber, substantial energy loss often results as
heated air, unburned oil, and carbon is emitted through the stack.
This discussion is based on Background Information for Proposed Changes in Maryland
Regulations, Maryland State Department of Health and Mental Hygiene, April 1974.
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II- 2
In addition, the degree of atomization of the oil thrown off the rotary cup
is dependent on how well the oil can be expanded in streams which, in turn, is depen-
dent on the viscosity and the surface tension of the oil. As a result, distillate oil
which has a lower viscosity than residual oil (at the same temperature) does not burn
well in natural draft rotary cups. Instead of being strung out and broken into very
small particles, the distillate oil tends to move across the air stream in fairly large
droplets. When this happens, the distillate oil may cross the stream and deposit on
the outer wall for inefficient surface combustion.
Despite these characteristics of inefficient combustion, natural draft ro-
tary cup burners were installed widely in smaller (generally under 15 million BTU
per hour furnace heat input) combustion systems until about 10 or 15 years ago.
Since then, new installations have been declining, but hundreds of old systems still
remain in operation. The choice of natural draft rotary cups in past years can be
largely attributed to their relatively low capital cost, their reliability, and their
relatively simple maintenance requirements. Moreover, during times when oil
price and availability were not significant constraints, more efficient fuel use
and resulting savings in annual operating costs apparently did not provide effec-
tive arguments in favor of a higher capital cost burner.
2. Types of Costs Considered
The major cost to current site owners where natural draft rotary cup
burners are used will be the capital cost for purchase and installation of the new
burner equipment. These capital costs will vary by the size of the burner unit being
installed and by the installation characteristics associated with each unit at a speci-
fic site.
The DEQE provided Harbridge House with specifications of acceptable
burner equipment for replacement of marginal units. Air atomizing burners and
primary modulating rotary cup burners were considered the most likely candidates
for replacement, although consideration was also given to steam atomizing units.
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II- 3
The steam atomizer burners have not been considered in subsequent analysis because
the Worcester inventory did not provide sufficient detail to determine those facilities
that could accommodate the constraints associated with that type of equipment. In
particular, the steam atomizer requires a high pressure system, a full-time attendant
to monitor operation, a source of steam, and some very sophisticated control equip-
ment which results in costs ranging from $30, 000 to over $100, 000 for a single unit.
In addition to the above burner types, DEQE specified that replacement
equipment include modulating firing controls. Monitoring and smoke sensing devices,
however, were not considered as part of the replacement equipment. (These are re-
quired under another regulation.)
Initial discussions with DEQE indicated that at least ten percent of the
units subject to burner replacement should be assumed to require boiler modification
or replacement because of their age. Subsequent discussions with manufacturers,
however, indicated that the costs of boiler modification and the need for boiler re-
placement are very specific to the age and type of boiler and the configuration of the
combustion system layout. Moreover, there is such wide variation in the costs of
boiler modification or replacement (because of the above-cited factors) that manufac-
turers would not venture to estimate even "ball park" figures. Because time and data
limitations did not permit development of more detailed cost estimates in this analysis,
it has been assumed that existing boiler characteristics will not pose costly constraints
on burner installation.
Consideration was also given to the need for increasing the load carrying
capabilities of plant electrical systems as a result of burner replacement. (The re-
placement equipment has higher electrical needs per unit.) Manufacturers noted,
however, that the replacement units would likely have a smaller capacity than the
original marginal burner. This would result in a lower equipment cost than indicated
by a cost figure estimated on the basis of original burner capacity and would also
probably result in no net change in electrical requirements. As a result of this
information, two additional assumptions were made. First, it was assumed that
-------
II- 4
the capital costs of replacement burners would be a function of the capacity of the
old (marginal) burner since data did not permit estimates of the extent or degree
of capacity reductions that would be likely to occur. Secondly, it was assumed
that the electrical requirements (and therefore costs) would not change as a result
of burner replacement.
Based upon discussions with DEQE, it was further assumed that no
change in maintenance practices or other (non-fuel) operating costs would result
from this burner retrofit strategy.
A second cost considered in this analysis is for financing. Since capi-
tal, itself, has a cost either an opportunity cost or a financing cost several
assumptions regarding the provision of capital were made (see Section B). More-
over, different assumptions were made in evaluating the cost of capital to private
concerns as opposed to public sector facilities. The wide variations which can oc-
cur in the financing opportunities within each of these two categories (public and
private) were not addressed in the quantitative analysis; however, a generalized dis-
cussion of financing options is included in Chapter I.
Costs associated with depreciation of capital equipment were also assumed
to be incurred, based upon the consideration that owners put aside enough capital each
year to replace the equipment at the end of its useful life. It is recognized, however,
that depreciation of equipment can provide significant tax advantages to owners. Under
such circumstances (not quantitatively addressed in this study) depreciation may rep-
resent a net benefit of new equipment purchases.
A final significant cost item in this instance a cost savings was the
annual fuel cost savings resulting from the greater operational efficiency of the new
burners. Based upon discussions with burner manufacturing and service representa-
tives and with DEQE staff, it was determined that a reasonable (and conservative)
estimate of fuel conservation would be 15 percent of total current fuel usage.
3. Worcester Marginal Burner Inventory
The Worcester Inventory of combustion sources provided the data base for
specification of the characteristics of sites subject to the marginal retrofit strategy.
-------
II- 5
The inventory data shows, for each site: the number and type of burners; the type
of boiler and burner controls; the rated capacity in million BTU per hour and in
gallons per hour; and the fuel use and type. Because of the anticipated implementa-
tion of the proposed strategies on the basis of the total rated capacities of all
combustion units at a site, manipulation of data in the marginal burner inventory
retained the following site-size categories: 3 to 6 million BTU's per hour;
6 through 10 million BTU's per hour; 10 through 25 million BTU's per hour; 25
through 50 million BTU's per hour; and 50 through 100 million BTU's per hour.
Despite this aggregation in the presentation of results, certain costs, notably the
capital costs of replacement equipment, were found to be a function of individual
unit capacity (rather than total site capacity) and were accordingly evaluated on a
burner-by-burner basis.
A summary of the Worcester rotary cup burner inventory by site, capa-
city, and fuel type is shown in Exhibit II-l.
For the facilities fitted with rotary cups, private ownership is the most
prevalent. There are 108 private sites identified (roughly 72 percent) which currently
use about 10,400 gallons of all fuel oils (roughly 81 percent) in the Worcester mar-
ginal burner inventory. This is compared with 41 public facilities using slightly
over 2300 gallons of all fuel oils. Usage by type shows that half of the total sites,
or 72 out of 149 locations, use #4 oil. Of the total sites, 28 percent use #6 oil and
22 percent use #2.
Significantly, the users of #6 oil account for almost half of the total fuel
volume of all types used; #4 oil was the next most used, while #2 accounted for 13
percent of total fuel usage. The average yearly burner fuel consumption with #6 oil
was 68, 000 gallons for both public and private facilities compared with about 41, 000
gallons of #4 oil and almost 30, 000 gallons of #2 oil. Notably, most of the public
facilities on the inventory use either #4 or #2 oil.
As directed by DEQE, users of #5 fuel oil have been grouped with the #4 fuel oil users.
-------
II- 6
EXHIBIT II-l
SUMMARY OF WORCESTER MARGINAL BURNER INVENTORY
Site Size Categories
3 to 6 Million BTU/hour
Public
Private
Total (% of all size categories)
6 through 10 Million BTU/hour
Public
Private
Total (% of all size categories)
10 through 25 Million BTU/hour
Public
Private
Total (% of all size categories)
25 through 50 Million BTUAour
Public
Private
Total (% of all size categories)
50 through 100 Million BTU/hour
Public
Private
Total (% of all size categories)
TOTAL ALL CATEGORIES
PUBLIC
PRIVATE
TOTALS (%)
Number of Sites
0
3
3 ( 7%)
0
9
9 ( 21%)
1
18
19 ( 44%)
1
7
8 ( 19%)
0
4
4
( 9%)
2 ( 5%)
41 ( 95%)
43 (100%)
No. 6 Fuel Type Used
Number of Mar-
ginal Burners
0
3
3 ( 4%)
0
13
13 ( 15%)
3
32
35 ( 39%)
2
21
23 ( 25%)
0
15
15
( 17%)
5 ( 6%)
84 ( 94%)
89 (100%)
Marginal Burner Fuel
Use (1000 Gallons) Number
0 s
130.4 9
130.4 ( 2%) 17
0 11
547.2 19
547.2 ( 9%) 30
250.0 9
1806.8 12
2056.8 ( 34%) 21
104.1 3
2287.8 1
2391.9 ( 39%) 4
0 0
965.5 0
965.5 0
( 16%)
354.1 ( 6%) 31
5737.7 ( 94%) 41
6091.8 (100%) 72
No. 4 Fuel Type Used
Number of Mar-
of Sites ginal Burners
10
9
( 24%) 19 ( 16%)
21
28
( 42%) 49 ( 41%)
18
24
( 29%) 42 ( 35%)
7
2
( 5%) 9 ( 8%)
0
0
0
( 43%) 56 ( 47%)
( 57%) 63 ( 53%)
(100%) 119 (100%)
Marginal Burner Fuel
Use (1000 Gallons)
249.6
406.0
655.6 ( 13%)
302.3
1449. 1
1751.4 (36%)
750.0
1160.5
1910. 5 ( 39%)
421.0
182.7
603. 7 ( 12%)
0
0
0
1722.9 (35%)
3198.3 ( 65%)
4921.2 (100%)
No.
Number of Sites
4
15
19 ( 55%)
1
7
8 ( 24%)
3
3
6 ( 18%)
0
1
1 ( 3%)
0
0
0
8 ( 24%)
26 ( 76%)
34 (100%)
2 Fuel Type Used
Number of Mar-
ginal Burners
5
16
21 ( 34%)
2
13
15 ( 24%)
15
7
22 ( 35%)
0
4
4 ( 7%)
0
0
0
22 ( 36%)
40 ( 64%)
62 (100%)
Marginal Burner Fuel
Use (1000 Gallons)
120. 1
458.4
578.5 ( 33%)
40.0
329.2
369.2 ( 21%)
129.5
288.4
417.9 ( 23%)
0
409.5
409.5 ( 23%)
0
0
0
289.6 ( 16%)
1485.5 ( 84%)
1775.1 (100%)
Total
Number of Sites
12
27
39 ( 26%)
12
35
47 ( 31%)
13
33
46 ( 31%)
4
9
13 ( 9%)
o
4
4 ( 3%)
41 ( 28%)
108 ( 72%)
149 (100%)
All Types of Fuel
Total Number of
Marginal Burners
15
28
43 ( 16%)
23
54
77 ( 28%)
36
63
99 ( 37%)
g
27
36 ( 13%)
o
15
15 ( 6%)
83 ( 31
-------
n-7
Among burners using #6 oil, most were in the 6 through 50 million BTU
per hour size categories.Of the burners using #6 oil, 95 percent were privately owned
facilities, with public sites found only in the two size categories from 10 through 50
million BTU's per hour. Burners using #4 oil occur in all but the largest size cate-
gory, 50 through 100 million BTU's per hour. These burners are almost equally di-
vided between private and public ownership with most burners in the size range from
3 million through 50 million BTU's per hour. While the greatest number of sites
and burners use #4 oil, only 38 percent of the total oil consumed is. #4. For
#2 oil usage, the ratio of public to private facilities is 35 percent public, with the
smallest size categories having the greatest usage. As with the #4 oil usage, there
are no facilities using #2 oil in the 50 through 100 million BTU category. Of note in
usage of #2 oil is that for the largest size category, 25 through 50 million BTU's per
hour, private facilities with 6 percent of the total number of burners for all #2 usage
consumed over 23 percent of the total #2 oil.
As a-final note, it must be pointed out that the Worcester inventory of oil
burner types, used as the basis for this analysis, does not specify the type of rotary
cup burners in use so that it was not possible to distinguish (marginal) natural draft
rotary cups from primary modulating rotary cups (which are acceptable). More-
over, it was not possible to segregate those burners on stand-by boilers from
those on boilers in regular use. (DEQE anticipates that implementation of the
strategy will provide a mechanism whereby exemptions to the retrofit require-
ment may be provided for stand-by units.) From discussions with DEQE staff,
it was determined that the likelihood of a substantial number of these sites having
the newer rotary cup burner types was small and would, therefore, not significantly
affect the analysis. As discussed in subsequent sections, however, the presence
of stand-by units (which may not have to be replaced) may have resulted in con-
siderable overestimation of replacement costs.
-------
II- 8
B. Costing Procedures
The magnitude of costs assumed for replacement equipment as well as the costs
of capital and depreciation are described below with respect to sources of information
and specific assumptions used in subsequent analysis. It should be noted that in this
analysis, it has been assumed that all replacements are initiated and completed in
1978 based on DEQE's estimate of the earliest feasible year for requiring retrofit com-
pletion.
1. Marginal Burner Replacement Costs
The costs estimated for burner replacement are based upon burner capa-
city ranges. Exhibit II-2 shows the breakdown of burner capacities in gallons per
hour (GPH) and 1978 dollar costs for each size. Capacities taken from the inventory
range from about 5 GPH to a high of 180 GPH with costs estimated in the range from
$3700 to $16, 600. These low-high estimates were determined through interviews with
manufacturers to be representative of replacement cost in Massachusetts. These
equipment costs are further assumed to be relatively competitive between the two
major burner types being considered here: primary modulating rotary cup burners
and air atomizing burners.
At the request of DEQE, the costs were inflated at a rate of 9 percent per
year based on the average annual rate of wholesale price increases from 1969 to 1975
for heating equipment plus two percent to account for future contingencies. The nine
percent figure was considered reasonable in light of some recent electric utility con-
struction price adjustment clauses (in Massachusetts) obtained from DEQE, that were
based on rates in the vicinity of 10 percent per year.
Percentage increase in wholesale prices for heating equipment as follows: 1969
to 1970, 4.9%; 1970 to 1971, 4.4%; 1971 to 1972, 2.3%; 1972 to 1973, 19.0%;
1973 to 1974, 5.9%; 1974 to 1975, 21.7%. Source; U.S. Department of Com-
merce Bureau of Census Statistical Abstract of the United States (1975).
-------
II- 9
EXHIBIT II-2
ESTIMATED COST OF GIL BURNER EQUIPMENT TO
TO REPLACE THE MARGINAL BURNERS OF VARIOUS SIZES
180-
160-
140-
120 _
C 100-
30
60
40J
20J
5-1
$2000 $4000 $6000 $8000 $10.000 $12,000 $14,000 $16,000 $18,000 $20,000
BURNER UNIT COSTS
Source: Harbrtdge House, Inc. 1976.
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11-10
For the capital costs shown in Exhibit II-2, manufacturers estimated
that about 25 percent of the total costs would be required for installation with the
remainder representing equipment costs. Some slight installation cost savings
would be experienced when replacing two or more burners at the same site. These
economies have not been included here, however, because of their relative insig-
nificance with regard to total costs.
In addition, because of the Maryland experience with a rotary cup burner
retrofit regulation (see Appendix A), manufacturers were questioned about the fuel
capabilities of replacement burners. For the types of burners specified above,
manufacturers indicated that no increased cost would be incurred in order to accom-
modate multiple fuel firing capabilities.
2. Increased Efficiency in Fuel Use
Discussions with industry representatives indicated that fuel use effi-
ciencies resulting from replacement of marginal burners with modern equipment
have averaged from 10 to 20 percent, with a substantial portion of facilities obtain-
ing efficiencies as high as 25 percent. Clearly the degree of efficiency resulting
from replacement is a function of both the condition of the marginal burner and the
maintenance applied to the new unit. Consequently, the figure of 15 percent fuel
savings which has been utilized in subsequent analysis, was determined in consulta-
tion with DEQE regarding the Worcester inventory and the typical maintenance prac-
tices of owners. The 15 percent figure is based on the assumption that normal
maintenance includes one burner adjustment per year. (As previously noted, the
cost of this burner adjustment -- $75 to $100 -- has not been considered as an in-
cremental cost resulting from strategy implementation.)
In costing out the fuel savings, current fuel prices were assumed as
directed by DEQE. As described in Chapter IE, the 1976 average prices for #6
oil, #4 oil, and #2 oil are: $0.28; $0.29; and $0.32, respectively. By assuming
current prices, however, it should be noted that the value of future fuel bill savings
is probably understated.
For added flexibility, results are also shown for 10 percent and 5 percent fuel sav-
ings in Exhibits II-3 and II-4.
-------
11-11
3. Cost of Capital
As discussed earlier,costs of capital either opportunity costs or financ-
ing costs will vary according to several separate criteria for the private and public
sectors, respectively.
a. Private Sector
Guidelines of the federal Office of Management and Budget call for
an annual interest rate of 10 percent to be applied in evaluating the benefits of and
costs of programs or projects of a type such as those being considered here. Further
discussions with area bankers and federal loan program officials to determine cur-
rent generalized interest rates and financing procedures found varying rates and financ-
ing periods which might be applied. Bankers interviewed offered their opinions based
upon typical and generalized situations which correspond to the likely cases involved in
this analysis. For example, a bank in Worcester which offers commercial loans to
finance pollution control expenditures proposed an interest rate of 6-3/4 percent avail-
able for five or seven years; the SBA program discussed previously currently has a
rate of 6-5/8 percent for ten years; while a commercial bank in Boston stated a rate
of 10-3/4 percent over three years. Clearly, the range of financing opportunities will
vary according to the credit situation of an individual firm. The lower interest rates
and more favorable financing terms described reflect a firm with sound financial base
and credit, while the higher rates would apply to less sound businesses.
Based upon the financing information obtained, and after discussions
with Massachusetts DEQE, an annual interest rate of 10 percent over a period of five
years was used: This financing rate reflects a conservative estimate of the conditions
which are likely to exist for firms needing to secure commercial financing.
b. Public Sector
For public financing of these burner replacements, similar calcula-
tions were made. The only variation was in the financing applied to the capital.Based
Executive Office of the President, Office of Management and Budget, Circular No. A-94,
Revised, 27 March 1972: Washington, D. C.
-------
11-12
upon discussions with bankers and the City Treasurer's office in Worcester, it was
determined that current bank interest rates for the City's general obligation bonds was
about 5-3/4 percent for a twenty-year issue. For the purposes of this analysis, we as-
sumed this 5.750 rate over a twenty-year term.
Under this procedure, the annual financing payment for year one of
the bond period (as well as subsequent years) were calculated according to current pub-
lic sector financing methods. (The total payment for interest and principal would be
large initially, and then decrease over time.) The amount of the total bond issue would
most likely be larger than simply the cost of retrofitting burners in public facilities
since it would include all public financing projects for an annual or bi-annual period.
However, for purposes of this analysis, we assume the total public financing costs to
reflect only the capital costs involved in burner replacement.
4. Depreciation
Depreciation of the capital cost of equipment was based upon the normal
life expectancy of such equipment from discussions with industry representatives.
Yearly depreciation was assumed as a straight-line value carried out over twenty-
five years. This yearly figure was combined with the yearly capital financing costs to
both the public and private sectors to determine an annual cost to the users. At the
end of its useful life, no scrap value has been attributed to the equipment.
C. Analysis and Results
Harbridge House has utilized two approaches in assessing the costs and savings
resulting from replacement of marginal burners with acceptable burners of improved
efficiency. The first approach derives a payback period for the private and public
sectors based upon the range of total capital costs, including costs for financing,
divided by the annual fuel cost savings occasioned by improved burner efficiency.
This payback time serves as a vehicle for comparison of alternative investment costs
and fuel cost savings in the various size categories. In the second approach, the
-------
11-13
incremental annual expenditures (including principal, interest, and depreciation)
and fuel cost savings resulting from strategy implementation were assessed. This
method has the advantage of providing an estimate of the net annual savings or costs
attributable to burner replacement. Exhibits II-3 and II-4, respectively, illustrate
the method and results of these two analyses.
In Exhibit II-3, the payback period in years is shown for the public sector,
private sector, and their combined payback by site-size category. The total capi-
tal costs include ranges of principal and interest payments based upon the assump-
tions discussed in Section B. The fuel cost savings are constant yearly returns which
are based upon the improved efficiency of the replacement burner operation. Where
the fuel savings return is high relative to capital costs, the payback period is short,
while higher relative capital costs and lower fuel cost savings extend the payback
time.
As indicated in Exhibit n-3, the payback period ranges from two to six years
in the private sector and from five to 19 years in the public sector. Within the pri-
vate sector, the shortest payback periods occur in the 10 through 25 and 25 through
50 million BTU's per hour categories, in which from three to five years and two to
three years, respectively, is required for fuel cost savings to outweigh total costs
of capital and interest. In both of these size groups, costs are recovered prior to
the final payment for financing which occurs in year five. In the other private sec-
tor size categories, the payback occurs in the fourth and fifth years.
As shown in Exhibit n-3, the payback periods in the public sector are gener-
ally longer than in the private sector. This is a direct reflection of the data base,
because the different financing arrangement assumed for public sector facilities
should tend to cause the payback periods to be shorter. In most cases, the pay-
back period occurs within ten years for the public facilities, however, for the
6 through 10 million BTU per hour size category, payback extends to the 14th through
18th years.
Fuel cost savings are shown for increased efficiencies of 15 percent, 10 percent,
and 5 percent. As previously noted the figure of 15 percent has been assumed in
this analysis.
-------
EXHIBIT II-3
ESTIMATED YEARS UNTIL RECOVERY OF EXPENDITURES FOR
MARGINAL BUHNER REPLACEMENT
Total Capital Cost
and Interest-^
(Low High)
Annual Fuel Cost Savings
At 15% At 10% At 5%
Numbers of Years
Until Paybackc
3 to 6 Million BTU/hour
Public
Private
Total
6 through 10 Million BTUAour
Public
Private
Total
10 through 25 Million BTU/hour
Public
Private
Total
25 through 50 Million BTU/hour
Public
Private
Total
50 through 100 Million BTUAour
Public
Private
Total
All Size Categories
Public
Private
Total
$ 141,000
$ 201,000
$ 342, 000
$ 215,400
$ 454,400
$ 609,800
$ 388,700
$ 620, 300
$1,009,000
$ 151,600
$ 298,000
$ 449,600
$ 0
$ 189,500
$ 189, 500
$ 896,700
$1,763,200
$2,659,900
$ 186, 700
$ 268,100
$ 454,800
$ 287,700
$ 606,700
$ 894,400
$ 517,400
$ 826, 800
$1,344,200
$ 201,300
$ 397,200
$ 598, 500
0
$ 252, 800
$ 252,800
$1,193,100
$2,351,600
-- $3,544,700
$ 16,700
$ 45,200
$ 61,900
$ 15,200
$102,300
$117,500
$ 49,600
$156,900
$206, 500
$ 29,100
$122,600
$151,700
0
$ 40,100
$ 40,100
$110,600
$467, 100
$577,700
$ 11,100
$ 30,100
$ 41,200
$ 10,100
$ 68,200
$ 78,300
$ 33,100
$104,600
$137,700
$ 19,400
$ 81,700
$101,100
0
$ 26,700
$ 26,700
$ 73,600
$311,400
$385,000
$ 5, 600
$ 15,100
$ 20,700
$ 5,100
$ 34,100
$ 39,200
$ 16,500
$ 52,300
$ 68,800
$ 9,700
$ 40.900
$ 50,600
0
$ 13,400
$ 13,400
$ 37,000
$155,700
$192,700
8.4
4.4
5.5
14.2
4.4
5.7
7.8
3.8
4.9
5.2
2.4
3.0
4.7
4.7
8.1
3.8
4.6
11.2
5.9
7.3
18.9
5.9
7.6
10.4
5.3
6.5
6.9
3.2
3.9
6.3
6.3
10. 8
5.0
6.1
A Figures (in 1978$) bracket range of likely costs.
B Figures based on 1976 prices and therefore represent minimum potential savings. The 15% savings have been assumed in the analysis.
C Calculated by dividing cost by annual savings. (Based on 15% savings in fuel use.)
Source: Harbridge House, Inc. 1976.
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11-15
EXHIBIT II-4
INVESTMENT SAVINGS ESTIMATE FOR THE PUBLIC AND
PRIVATE SECTORS
3 to 6 Million BTU/Hour
PRIVATE SECTOR
Savings
Annual Fuel Savings $45,200
Costs Low High
Capital Costs (1978$) $ 157,650 $210,300
Financing (capital cost @ 10%
over five years) 40,200 53,600
Depreciation (capital costs over
25 years) 6,300 8,400
Total Annual Costs $46,500 $62,000
Total Savings (Deficit) $ ( 1,300^16,800)
£ $
Average Total Savings (Deficit) by Site ( 50f( 600)
PUBLIC SECTOR
Savings
Annual Fuel Savings $16,750
Costs
Capital Costs (1978$) $87,900 $116,450
Financing in Year One (capital costs @
5-3/4 % interest over 20 years) $ 9,450 $ 12,500
Depreciation (capital costs over
25 years) $ 3,500 $ 4,650
Total Annual Costs $12, 950 $17, 150
Total Savings (Deficit) $ 3,800$ 400
Average Total Savings (Deficit) by Site $ 300$ 50
PUBLIC AND PRIVATE SECTORS
Average Total Savings (Deficit) by Site
o At 15 percent Annual Fuel Savings $ 100 $( 450]
o At 10 percent Annual Fuel Savings $ ( 500 $(1,000
o At 5 percent Annual Fuel Savings $( 1,000 $(1, 600'
6 through 10 Million BTU/Hour
$ 102,350
Low High
> 356, 450 $475, 850
90,900 121,350
14,250 19,050
$105, 150 $140, 400
$[ 2,80of( 38,050)
$( 10of( 1,100)
$ 15,250
$134,250 $179,400
$ 14,450 $ 19,300
$ 5,350$ 7,200
$19,800 $26,400
$( 4,550$ 11,250)
$( 40of( 950)
$( 150) $( 1,050)
$( 1,000)$( 1,900)
$( 1, 800) $( 2,700)
10 through 25 Million BTU/Hour
$156,900
Low High
$486,550 $648,450
124.. 050 165,350
19,450 25,950
$143,500 $191,300
$ 13,400$( 34,400)
$ 400 $( 1,050)
$ 49, 650
$242,350 $322,550
$ 26,050 $ 34,700
$ 9,700 $ 12,900 1
$35,750 $47,600
$13,900 $ 2,050
$ 1,150 $ 150
$ 600 $( 700)
$( 900) $( 2,200)
$(2,400)$( 3,700)
25 through 50 Million BTU/Hour
$ 122,650
Low High
> 233,700 $311,500
59,600 79,450
9,350 12,450
$ 68, 950 $ 91, 900
$53, 700 $30, 750
$ 5,950$ 3,400
$29,050
$94,450 $125,450
$10,150 $ 13,500
$ 3,800 $ 5,000
$13, 950 $18, 500
$15, 100 $10, 550
$ 3,800$ 2,650
$ 5,300$ 3,200
$ 1,400$( 700)
$(2, 500)$(4,600)
50 through 100 Million BTU/Hour
$ 40, 100
Low High
$148,650 $198,300
$ 37,900 $ 50,550
$ 5,950 $ 7,950
$43, 850 $58, 500
$ ( 3, 750) (18, 400)
$( 950$ 4,600)
No Public Facilities in
This Site Category
$ ( 950) $( 4,600)
$ (4,300) $( 7,950)
$ (7,600) $(11,300)
Total for All Size Categories
$467,200
Low High
$1,383, 000$1, 844, 400
$ 352,650$ 470,300
S 55,300$ 73,800
$407,950 $544,100
$ 59,250$( 76,900)
$ 550 $( 700)
$110,700
Low High
$558,950 $743,850
$ 60,100 $ 80,000
$ 22,350 $ 29,750
582,450 5109,750
$28,250$ 950
$ 700 $ 50
$ 600 $ 500
$( 700)$( 1,800)
$(2,000)$( 3,100)
Note: Range of savings (deficit) reflects ranges in capital cost assumptions. The 15 percent fuel savings have been assumed in the analysis.
Source: Harbridge House, Inc. (1976).
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11-16
Because of these longer payback periods, the issue of data base discrepan-
cies becomes important. Sections A and B have introduced two factors which in-
dicate substantial overcapacity in the Worcester inventory. These are: (1) the
tendency of manufacturers in the past to install systems with more capacity than
required and (2) the existence of stand-by units which may not be subject
to replacement. Since capacity determines capital cost requirements for burner
replacement while use determines fuel cost savings, overcapacity in the data base
can result in estimates of substantially longer payback periods than would likely
occur.
Exhibit II-5 illustrates the relationship between capacity and fuel use for
the public and private sectors in the 6 through 10 million BTU per hour size cate-
gory. Also shown is a line of constant slope which represents a rule of thumb
o
for relating capacity to fuel use for normal heating requirements. Underutiliza-
tion in the public sector as compared with the private sector is evident in this size
category. Moreover, the tendency for underutilization in the public sector in all
size categories is indicated by the relationship of fuel savings to capital costs,
which ranges from 9 to 12 percent in public facilities and from 19 to 26 percent in
most private sector size categories. (One private sector size category 25through
50 million BTU per hour has a ratio of 40 percent savings to costs.)
The second approach utilized in this cost analysis is illustrated in Exhibit II-4.
As shown, the yearly breakdown of costs and savings are assessed for each sector
to yield the net annual costs (deficit savings) or savings. Based upon a range of total capi-
tal costs for equipment(in 1978 dollars), annual principal and interest payments are
calculated along with a yearly depreciation value based upon the assumptions dis-
cussed in Section B. These costs are then weighed against the total yearly fuel sav-
ings to arrive at the net annual range of costs or savings for each size category.
Further breakdown by the number of sites affected within each size category allows
an assessment of average individual owner costs or savings by year.
DEQE intends to provide a mechanism whereby stand-by units may be exempted
from the retrofit requirement.
2
Mr. Roland Schmidt, Maryland Bureau of Air Quality and Noise Control. Telephone
interview, 22 April 1976.
-------
H-17
EXHIBIT U-5
RELATIONSHIP OF AVERAGE RESIDUAL FUEL USE
AND MARGINAL BURNER CAPACITY IN WORCESTER INVENTORY
6 THROUGH 10 MILLION BTU PER HOUR
a
<
w
w
ft
z
s
u
w
200,000
175,000
150,000
125,000
100,000
75,000
50,000
25,000
| If
TT
TT
TTT
4-
U4-
i/i
I s i/l
i ' '
\ i i I
I i !
i i i>
I I l\ :
i .. i
i i I i.
I h
i
t / I t I 1 1 I
I i I
TT
1 I i I M I
TT
TT
TT
ZEE
i I I
TTT
±±+
TT
10 20 30
RATED CAPACITY (GPH)
40
50
60
Public Sector Burners.
Private Sector Burners.
Constant Relationship at 3000 hours of use per year.
Note: Individual points are connected for visual clarity only.
Source: Harbridge House, Inc., 1976.
-------
11-18
The analysis shows that for the constant annual fuel savings in each sector,
annual financing costs and depreciation present a mixed picture in terms of net
annual savings estimates. That is, the high range of costs often results in a net
annual deficit, while savings may be experienced in the first year at the low cost
estimates. In the private sector, a deficit is estimated in the size categories
from 3 to 6 million through 10 million BTU's, as well as in the 50 through
100 million BTU category. Significantly, these yearly deficits, when broken
down by the number of sites affected, show typical net annual costs per facility
to range from $50 to $1,000. The one exception is in the largest site size cate-
gory where annual costs per facility could reach $4600. Because of the five-year
term of financing assumed in the private sector, after the fifth year, all those
facilities will experience a net annual savings equal to fuel cost savings minus
depreciation. Moreover, it should be pointed out that savings are shown in sev-
eral private sector categories, most notably in the 25 through 50 million BTU per
hour grouping, where total user savings range between over $50, 000 to over
$30, 000 with comparable individual facility savings in the range of about $6, 000
to $3,500 per site.
In the results for the public facilities, savings are much more pronounced
and widespread across all the size categories. Only one group, the 6 through 10
million BTU category has a net deficit for both the low and high estimates in the
first year and even then, the net deficit per site only ranges from about $400 to
$900. Moreover, because of the financing structure assumed for the public sec-
tor (see Section B), net costs in subsequent years will slowly decrease. The net
savings experienced in other size categories in the first year (ranging from $300
to nearly $4, 000 per site) will similarly increase slowly over the twenty-year
term until only depreciation reduces the annual fuel cost savings.
In summary, then, payback periods in the private sector range from two
to six years, with only one size category (the 25 through 50 million BTU per hour
group) clearly experiencing a net annual savings from the start of replacement
-------
11-19
burner operation. Public sector payback periods range from a low of five years
to a high of 19 years, with the majority of the size categories recovering their
investment within ten years. Net annual savings ranging as high as $4,000 per
site are potentially experienced by all public facility groups in the first year of
implementation except for the 6 through 10 million BTU size category where an
(annually decreasing) net deficit less than $1,000 per site may be incurred.
A summary of the estimated net annual cost or savings in the first year
of implementation of the marginal burner retrofit strategy is shown in Exhibit
H-6. As indicated, the total costs or savings for public and private facilities
in all size categories, range from a net annual savings of $87,500 to a net an-
nual cost of $75, 900. Because of the financing assumptions used in the analysis,
net savings will gradually increase and net costs will gradually decrease in sub-
sequent years. Moreover, the possibility of underutilization in both the public
and private sectors (as previously described with regard to public facilities)
indicates that these estimates may overstate the annual costs and understate the
annual savings of strategy implementation.
-------
III. FUEL TYPE CONVERSION STRATEGY
A. Background and Approach
The Massachusetts DEQE has proposed an air quality control strategy for par-
ticulates which focuses on several alternative changes in the type and characteristics
of fuel oil burned within the Worcester City limits. Although fuel oil type changes are
usually associated with sulfur oxide control strategies, recent evidence has indicated
that particulate emissions during combustion are linked to viscosity and other charac-
teristics of the oil burned, such as sulfur content. A variety of alternative fuel con-
versions has been proposed for evaluation with the purpose of assessing their relative
cost effectiveness in particulate control. Harbridge House has evaluated the economic
costs of the conversions, and DEQE is assessing the particulate emission reduction
associated with each fuel oil type change.
The fuel type conversions evaluated are:
Sources burning #6 (one percent sulfur) oil convert to
#6 (0.5 percent sulfur) oil.
Sources burning #6 oil convert to #4 oil.
Sources burning #6 oil convert to #2 oil. (Facilities less than
50 million BTU per hour only.)
Sources burning #4 oil convert to #2 oil. (Facilities less than
50 million BTU per hour only.)
Currently, Massachusetts requires that the sulfur content of fuel burned in Worcester
not exceed one (1) percent. Although some sources may be burning fuel with less than
one (1) percent sulfur content, specific data in this regard was not available to the
study team. Consequently, in this analysis, fuel costs for #6 (one percent sulfur)
have been applied to all sources currently burning #6. The few sources in the Wor-
cester inventory which burn #5 have been grouped with sources burning #4 fuel oil,
as directed by DEQE.
Each of the above conversions has been assessed according to two assumptions.
First, the costs were evaluated assuming that the marginal burner strategy discussed
-------
Ill- 2
in Chapter II had not been implemented prior to the fuel conversions. Under this
assumption, conversion of sources to #2 fuel oil (distillate) requires replacement
of marginal burners, defined as natural draft rotary cup burners. (Chapter II,
Section A, discusses the problems in burning distillate in natural draft rotary cups.)
Under the second assumption, the costs were assessed under the condition of prior
implementation of the marginal burner replacement strategy. Use of these two as-
sumptions was based on DEQE's need for flexibility in evaluating strategy effective-
ness.
Under the assumption of prior retrofit of marginal burners, the fuel conver-
sion strategy would not be implemented until the effective date of the proposed retro-
fit regulation, or 1978. In order to provide a consistent comparison between the two
analyses of fuel type conversions (with and without prior retrofit), it has further been
assumed that even without prior implementation of the marginal burner retrofit stra-
tegy, the fuel conversion strategy will not be implemented until 1978.
1. Types of Costs Considered
The types of costs which have been assessed are shown in Exhibit III-l.
As indicated, increased efficiency in the use of fuel is considered only when natural
draft rotary cup burners have been replaced. In conversion of other types of burners
from residual to distillate firing,efficient operation of the units was assumed prior to
and after the conversion. (This is consistent with the Chapter II definition of mar-
ginal burners as natural draft rotary cup burners.) Moreover, based on discussions
with DEQE, it was assumed that no change in maintenance practices or other (non-
fuel) operating costs would result from any of the fuel type conversions evaluated.
As indicated in Exhibit III-l, capital costs as well as annual operating
costs are associated with conversions from#6 and#4 oils (residual) to #2 oil (distil-
late). Since capital itself has a cost either an opportunity cost or financing cost
several assumptions regarding the provision of capital for the conversions were re-
quired (see Section B). Moreover, different assumptions were used in evaluation of
the costs of capital to private concerns as opposed to public sector facilities. The
wide variations which can occur within each of these two categories (public and pri-
vate) were not addressed in the quantitative analysis; however, a generalized dis-
cussion of financing options is included in Chapter I.
-------
Ill- 3
EXHIBIT III-l
TYPES OF COST CHANGES CONSIDERED IN
FUEL CONVERSION STRATEGY EVALUATION
Assuming Marginal Burner
Strategy Not Implemented
Combustion system modification
to convert from #6 and #4 to #2
oil.
Replacement of marginal burners
to convert from #6 and #4 to #2
oil.
Adjustment in quantity of fuel
burned for sources requiring re-
placement of marginal burners
to convert to #2 oil.
Assuming Marginal Burner
Strategy Implemented
Combustion system modification to
convert from #6 and #4 to #2 oil.
Adjustment in quantity of fuel
burned for all sources retrofitted
under marginal burner strategy.
Adjustment in quantity of fuel
burned resulting from differences
in BTU content.
Adjustment in quantity of fuel
burned resulting from differences
in BTU content.
Adjustment in quantity of fuel
burned resulting from preheating
requirements for #6 and #4, but
not for #2 oil.
Adjustment in quantity of fuel
burned resulting from preheating
requirements for #6 and #4, but
not for #2 oil.
Differential fuel prices.
Differential fuel prices.
This fuel use savings is not attributed to the fuel conversion strategy under the
retrofit assumption, but instead is represented in the data base.
Source; Harbridge House, Inc. (1976).
-------
Ill- 4
Costs associated with depreciation of capital equipment were also as-
sumed to be incurred, based on the consideration that owners put aside enough capi-
tal each year to replace the equipment at the end of its useful life. It is recognized,
however, that depreciation of equipment can provide significant tax advantages to
owners. Under such circumstances (not quantitatively addressed in this study) depre-
ciation may represent a net benefit of new equipment purchases.
Finally, it should be noted that the issue of availability of fuel oil by
type has not been addressed in this analysis.
2. Worcester Combustion Source Inventory
The Worcester inventory of combustion sources provided data for speci-
fication of the characteristics of sources subject to fuel type conversions. The in-
ventory data shows for each site: the number and type of burners; the type of boiler
and burner controls; the rated capacity in million BTU per hour and in gallons per
hour; and the fuel use and type. Since DEQE anticipates implementing a fuel type
conversion strategy on the basis of the total rated capacities of all combustion
units at a site, manipulation of data in the source inventory retained the following
site-size categories: 3 to 6 million BTU's per hour; 6 through 10 million BTU's
per hour; 10 through 25 million BTU's per hour; 25 through 50 million BTU's per hour;
50 through 100 million BTU's per hour; and over 100 million BTU's per hour. Despite
this aggregation in presentation of results, however, certain costs, such as the com-
bustion system modification costs for conversion from residual to distillate firing,
were found to be a function of individual unit capacity (rather than total site capacity)
and were accordingly evaluated on a burner-by-burner basis.
A summary of residual oil users in the Worcester inventory by size cate-
gory and fuel type is shown in Exhibit IE-2. As shown, 60 percent of the #6 oil is
used by only 10 percent of the facilities in the greater than 100 million BTU per
hour category. The #4 oil is used primarily in the site-size categories from 6 through
25 million BTU per hour, which account for 70 percent of its use and 70 percent of the
facilities using it. Marginal burners, which are important to subsequent analysis be-
cause of the need to replace them in conversions from residual to distillate firing (if
not already done so with prior implementation of the Chapter II strategy), are con-
centrated in the smaller site-size categories. Of the #6 oil users, 65 percent of the
-------
EXHIBIT tII-2
SUMMARY OF RESIDUAL OIL USERS IN WORCESTER
Site Size Categories
Ownership
Less than 6 Million BTU/Hour
Public
Private
-- Total
C through 10 Million BTU/Hour
Public
Private
Total
10 through 25 Million BTU/Hour
Public
Private
Total
25 through 50 Million BTU/Hour
~ Public
Private
Total
50 through 100 Million BTU/Hour
Public
Private
Total
Greater than 100 Million BTU/Hour
Public
-- Private
Total
All Size Categories
Public
Private
Total
Sites
#6
Number %
0
4
4 7%
0
10
10 17%
1
20
21 35%
1
10
11 19%
3
4
7 12%
2
4
6 10%
7
52
59 100%
Total Burners
#4
Number %
8
9
17 22%
10
22
32 41%
9
13
22 29%
3
3
6 8%
0
0
0
0
0
0
30
47
77 100%
#6
Number %
0
4
4 3%
0
15
15 11%
1
42
43 30%
2
29
31 22%
7
19
26 18%
4
19
23 16%
14
128
142 100%
#4
Number %
10
9
19 14%
19
35
54 41%
9
36
45 34%
7
7
14 11%
0
0
0
0
0
0
45
87
132 100%
Marginal
#6
Number %
0
3
3 3%
0
13
13 15%
3
32
35 39%
2
21
23 26%
0
15
15 17%
0
0
0
3
86
89 100%
Burners
#4
Number %
10
a
19 18%
21
28
49 41%
18
24
42 35%
7
2
9 8%
0
0
0
0
0
0
45
74
119 100%
Total Fuel
#6
(1000)
Gallons %
0
158.3
158. 3 1%
0
589.2
589.2 2%
250.0
2862.9
3112.9 11%
104.1
4418.1
4522.2 15%
1574. 0
1522. 0
3096.0 11%
3160.8
13,887.9
17,048.7 60%
5088. 9
23,438.4
28,527.3 100%
Use
«4
(1000)
Gallons %
249.6
406.0
655. 6 12%
302.3
1574.0
1876.3 34%
750.0
1713.8
2463.8 36%
421.0
579.9
1000. 9 18%
0
0
0
0
0
0
1722.9
3866. 7
5589. 6 ion
Marginal
ff6
(1000)
Gallons
0
130.4
130.4
0
547.2
547.2
250.0
1806. 8
2056. 8
104.1
2287.8
2391.9
0
965.5
965. 5
0
0
0
354.1
6144.8
6498.9
Burner Fuel Use
#4
(1000)
% Gallons
249.6
406.0
2% 055. 6
302.3
1449.1
8% 1751.4
750.0
1160.5
38% 1910. 5
421.0
182.7
37% 603.7
0
0
15% 0
0
0
0
1722.9
3198.3
100% 4921.2
%
13%
30%
39%
12%
100%
Source; Harbridge House, Inc. (1976). Based on DEQE's inventory of residual fuel
oil users in Worcester.
-------
Ill- 6
marginal burners are in the 10 through 50 million BTU per hour categories, which
also account for 75 percent of the marginal burner (#6) fuel use. The 6 through 25
million BTU per hour size categories include about 75 percent of the #4 oil-fired
marginal burners and an equal percentage of #4 oil use in marginal burners. As may
be expected, very little #6 fuel oil is used in the 10 million BTU per hour and under
categories and no #4 oil is used in the greater than 50 million BTU per hour cate-
gories.
The breakdown of fuel users by public and private ownership is impor-
tant to subsequent analysis because of the different financing options available to the
two kinds of facilities. Roughly 10 percent of the total number of burners fired by
#6 oil are estimated to be public facilities, while nearly 35 percent of the burners
fired by #4 oil are estimated to be publicly owned. It is also noteworthy that the only
publicly owned burners in the 50 million BTU per hour and under categories are clas-
sified as marginal burners.
One other aspect of the Worcester inventory of residual fuel users is im-
portant to subsequent analysis: the capacities of individual burner units. This con-
sideration is important because the costs of system modification and/or burner re-
placement in the conversions from residual to distillate firing are a function of the
individual unit capacity. In manipulating the data in the Worcester inventory, however,
it became apparent that the rated capacity (in gallons-per-hour or in million BTU per
hour) was often substantially greater than required by the fuel use totals, even after
taking seasonal loadings into account. In more recently installed units, this apparent
overcapacity may be attributable to stand-by units; in older facilities, however, the
actual design specifications used 10 and 20 years ago provided for substantial excess
capacity. Manufacturers interviewed noted that replacement of these older units often
involves an (economical) reduction in the rated capacity with no loss in reliability or
service. As a result of these considerations, the capital cost figures as applied to
the inventory in Section C probably overstate total costs, particularly in the replace-
ment of marginal burners.
-------
Ill- 7
B. Costing Procedures
The types of cost changes specified in Exhibit III-l as well as the costs of
capital and depreciation are described below with respect to sources of informa-
tion and specific assumptions used in subsequent analysis.
1. Combustion System Modifications
Combustion system modifications are required for all sources in the
conversion from residual to distillate firing. Specifically, replacement of pumps,
relief valves, and strainer baskets are likely to be required. In addition, stor-
age tanks would have to be cleaned and burners would have to be adjusted. Based
on discussions with combustion equipment manufacturers, a range of $350 to $750
(1978 dollars) was considered to be representative of the costs associated with
these changes for a unit with a capacity of 50 to 60 gallons per hour (GPH) or about
9-10 million BTU per hour.
At DEQE's request, the manufacturer cost estimates were inflated at
a rate of nine percent per year based on the average annual rate of wholesale price
increases from 1969 to 1975 for heating equipment plus two percent to account for
future contingencies. The nine percent figure was considered reasonable in light
of some recent electric utility construction price adjustment clauses (in Massachu-
setts) obtained from DEQE, that were based on rates in the vicinity of ten percent
per year.
On the average, equipment manufacturers estimated that half of the
modification costs would go for equipment and half would be required for installa-
tion. Clearly the range of costs is wide, with the high cost estimate representing
more than twice the low cost estimate. This is largely due to the variation in the
Percentage increase in wholesale prices for heating equipment as follows:
1969 to 1970, 4.9%; 1970 to 1971, 4.4%; 1971 to 1972, 2.3%; 1972 to 1973,1.9%;
1973 to 1974, 5.9%; 1974 to 1975, 21.7%. Source; U. S. Department of Com-
merce, Bureau of Census. Statistical Abstract of the United States (1975).
-------
Ill- 8
costs of pump replacement on different units. Because the manufacturer estimates
were based on actual modification experience in the New England area, it was con-
sidered appropriate to use this wide range.
Modification costs are a function of unit size. As shown in Exhibit in-3,
however, the cost variation by size is relatively minimal. Installation costs remain
relatively constant over the size ranges, while the cost of equipment increases
slightly as unit size increases.
2. Replacement of Marginal Burners
Costs associated with replacement of marginal burners have been obtained
from the Chapter II analysis for all sources using natural draft rotary cup burners and
fired by residual oil (#6 and #4). These costs are only incurred Ln the conversions
from residual to distillate firing and are only atrributed to the fuel conversion cost
assessment under the assumption that specified no prior implementation of the mar-
ginal burner strategy. When marginal burners require replacement, the costs of
modification are also incurred, since burner replacement alone does not include pump
replacement and other changes required for conversion from residual to distillate
firing.
3. Increased Efficiency in Fuel Use
Increased efficiency in fuel use as a result of the fuel type conversions
was determined to occur only when the costs of marginal burner retrofit are attri-
buted to the fuel strategy, as previously described. As in Chapter II, the increased
efficiency has been estimated at about 15 percent per year (assuming that normal
maintenance includes one burner adjustment per year). These fuel cost savings
are broken out separately in the analysis which is based on the assumption of no
prior implementation of the marginal burner retrofit strategy. When prior imple-
mentation of the retrofit strategy is assumed, the fuel savings are incorporated
prior to evaluation of the fuel conversion costs.
4. Adjustments for BTU Content
The differential BTU content of the fuel types was taken into account
according to the following schedule:
-------
Ill- 9
EXHIBIT UI-3
ESTIMATED COST OF COMBUSTION SYSTEM MODIFICATION
160
140
120
100
pu
O
o
I
u
tz
w
so
60
40
20
S250 S500 S750 S1000
COSTS OF BURNER MODIFICATION
S1250
S1500
Source: Harbridge House Inc. (1976).
-------
HI-10
#6 = 150,000 BTU per gallon
#4 = 144, 000 BTU per gallon
#2 = 140,000 BTU per gallon
These heat content values were obtained from DEQE.
5. Adjustments for Residual Preheating
Conversion from residual to distillate firing obviates the need for pre-
heating the fuel oil. It has been estimated that residual preheating fuel needs ac-
count for about three percent of the total fuel use.1 In this analysis, the three
percent figure has been used to represent fuel savings resulting from conversion
to #2 oil from #6 oil and #4 oil.
6. Fuel Oil Prices
In conjunction with DEQE and Region I, EPA , it was determined that
current fuel oil prices would be used in this economic assessment because of the
extreme uncertainties in estimating future oil prices. Platts Oilgram, a daily pub-
lication, was used to obtain prices of the four types of fuel oil during the first four
months of 1976 as shown in Exhibit HI-4.2 According to the Worcester Regional
DEQE Office, fuel oil used in Worcester is transported via Boston Harbor. The
middle range of the four-month average prices shown in Exhibit III-4 has been
used in subsequent analysis.
Walden Research Corporation. An Evaluation of Control Strategies for Stationary
Fuel Burning Sources in the Thirty Inner Cities and Towns of the Metropolitan Boston
Intrastate Air Quality Control Region, April 1973.
2
A recent DEQE survey of 1976 fuel oil prices in Worcester indicated that the prices
of #4 and #6 oil are subject to considerable variation as a result of discretionary dis-
counts granted by distributors. Average prices based on several quotes for trailer
loads were as follows: #6(1 %S) $. 30 per gallon; #4(1 %S) $. 32 per gallon; #2 $. 33 per
gallon. Because of the minor differences between these average prices and those used
in the analysis, no changes were made in the fuel price assumptions. It should be
noted, however, that use of the prices shown in Exhibit III-4 (rather than the recently
obtained DEQE quotes) yields more conservative results for both strategies.
-------
EXHIBIT HI-4
1976 FUEL OIL PRICES AT
BOSTON HARBOR, BY TYPE
(cents per gallon)
Range of Prices Quoted
Month
January
February
March
April
Four Month Average
Middle Range
#6(1 %s)
26.9-27.0
27.9-28.0
27.9-28.0
27.9-28.0
27. 7-27. 8
27.7
#6(0. 5%3)
27.8-28.1
29.6-29.7
29.6-29.7
29.6-29.7
29. 2-29. 3
29.2
#4(1 %s)
27. 6-30. 1
29.0-30.1
29. 0-30. 1
29. 0-30. 1
28.6-30.1
29.4
#2
30.6-32.2
31.1-32.7
31.6-32.7
30.6-32.7
31.0-32.6
31.8
Source: Platts Oilgram and Price Service. (McGraw Hill Publication) 5 January 1976, 5 February
1976, 4 March 1976, and 2 April 1976.
-------
in-12
7. Cost of Capital
In this analysis, as in the Chapter II evaluation, the private sector has
been assumed to borrow capital for five years at a ten percent rate of interest.
(See Chapter n, Section 3.) Public sector financing has been assumed to be incor-
porated into a large bond issue, with a term of 20 years at a 5.75 percent interest
rate. Because the objective of this analysis is to represent the annual average cost
of strategy implementation, however, the public sector annual payments of princi-
pal and interest were averaged over the twenty-year period. (Actual payments
would likely be large initially, and then decrease over time.)
8. Depreciation
As previously noted, depreciation has been considered in light of monies
set aside annually for replacement of capital equipment at the end of its useful life.
In this analysis, straight line depreciation has been utilized. Modification equip-
ment has been assumed to have a life of ten years based on DEQE's estimate of the
average remaining boiler life in Massachusetts. (Pumps must be replaced when
boilers are replaced.) As in Chapter II, replacement burners were assumed to
have a life of 25 years. At the end of its useful life, no scrap value has been attri-
buted to the equipment.
C. Analysis and Results
The costing procedures were applied to the Worcester inventory of residual
oil fuel users according to the specifications shown in Exhibit III-5. Using this
methodology, the total costs and costs per site for each of the four conversions,
broken down by site size category, are summarized in Exhibits III-6 and III-7.
Exhibit III-6, which shows the costs assuming prior implementation of the
marginal burner retrofit strategy, indicates that the greatest costs in conversion
from one type of residual to another type of residual oil will be borne by the larger
size categories. In particular, the facilities in the greater than 100 million BTU
per hour group will incur more than 60 percent of the total costs. This phenomenon
is a clear reflection of the predominance of #6 residual fuel use in the larger size
-------
ni-is
EXHIBIT m-5
KEY FACTORS DETERMINING COSTS
OF ALTERNATIVE FUEL TYPE CONVERSIONS
With Prior Implementation of
Marginal Burner Retrofit
With No Prior Implementation of
Marginal Burner Retrofit
Conversion from ffi (l%s) to #6 (0. 5%s)
Fuel Consumption Including 15% Savings for
Marginal Burners (in gallons per year)
Prices of Fuel Types (in cents per gallon)
Fuel Consumption (in gallons per year)
Prices of Fuel Types (in cents per gallon)
Conversion from #6 to #4
Fuel Consumption Including 15% Savings for
Marginal Burners (in gallons per year)
Increased Fuel Use from 4% Differential in
BTU Content (in gallons per year)
Prices of Fuel Types (in cents per gallon)
Fuel Consumption (in gallons per year)
Increased Fuel Use from 4% Differential in BTU
Content ( in gallons per year)
Prices of Fuel Types (in cents per gallon)
Conversion from #6 to #2
Fuel Consumption Including 15% Savings for
Marginal Burners (in gallons per year)
Increased Fuel Use from 7% Differential in
BTU Content (in gallons per year)
Decreased Fuel Use from Elimination of
Preheating Needs (in gallons per year)
Prices of Fuel Types (in cents per gallon)
Capital Costs of Modification Including
Interest Charges (in dollars per year)
Depreciation Charge for Modification (in
dollars per year)
Fuel Consumption (in gallons per year)
Increased Fuel Use from 7% Differential in BTU
Content (in gallons per year)
Decreased Fuel Use from Elimination of Preheating
Needs (in gallons per year)
Decreased Fuel Use from 15% Savings in Marginal
Burners (in gallons per year)
Prices of Fuel Types (in cents per gallon)
Capital Costs of Modification Including
Interest Charges (in dollars per year)
Depreciation Charge for Modification (in dollars
per year)
Capital Costs of Marginal Burner Retrofit Including
Interest Charges (in dollars per year)
Depreciation Charge for Retrofit (in dollars per year)
Conversion from #4 to #2
Fuel Consumption Including 15% Savings for
Marginal Burners (in gallons per year)
Increased Fuel Use from 3% Differential in
BTU Content (in gallons per year)
Decreased Fuel Use from Elimination of Pre-
heating Needs (in gallons per year)
Prices of Fuel Types (in cents per gallon)
Capital Costs of Modification Including
Interest Charges (in dollars per year)
Depreciation Charges for Modification (in
dollars per year)
Fuel Consumption (in gallons per year)
Increased Fuel Use from 3% Differential in BTU
Content (in gallons per year)
Decreased Fuel Use from Elimination of Preheating
Needs (in gallons per year)
Decreased Fuel Use from 15% Savings in Marginal
Burners (in gallons peryear)
Capital Costs of Modification Including Interest
Charges (in dollars per year)
Depreciation Charges for Modification (in dollars
per year)
Capital Costs of Marginal Burner Retrofit Including
Interest Charges (in dollars per year)
Depreciation Charges for Retrofit (in dollars per
year)
Source; Harbridge House, Inc. (1976)
-------
EXHIBIT III-6
ESTIMATED TOTAL ANNUAL COST AND ANNUAL COST PER SITE OF ALTERNATE FUEL OIL TYPE CONVERSION
ASSUMING PRIOR IMPLEMENTATION OF MARGINAL BURNER RETROFIT STRATEGY
Fuel Oil Type Conversions
Size Categories
3 to 6 Million BTU per hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
6 Through 10 Million BTU per Hour
Total Annual Cost (percent of total, all sizes
Annual Cost per Site
10 Through 25 Million BTU per Hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
25 Through 50 Million BTU per Hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
50 Through 100 Million BTU per Hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
Greater Than 100 Million BTU per Hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
All Size Categories
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
#6(1%S) to #6(0. 5%s)
$ 2.
$
$ 7.
$
$ 41,
$ 2,
$ 62,
$ 5,
$ 44,
$ G,
$255,
$ 42,
$413,
$ 7,
100 ( 0. 5%)
500
GOO ( 1. 8%)
800
200 ( 10. 0%)
000
500 ( 15.1%)
700
300 ( 10. 7%)
300
700 ( 61.9%)
600
400 (100. 0%)
000
$ 4
$ 1
#6 to*4
, 000 ( 0. 5%)
,000
$ 14,600 ( 1.8%)
$ 1,500
$ 78
$ 3
$119
$ 10
$ 84
$ 12
$490
$ 81
$792
$ 13
, 900 f 10. 0%)
,800
,700 ( 15.1%)
,900
,900 ( 10.7%)
,100
,300 ( 61.9%)
,700
,400 (100.0%)
,400
$ 7
$ 2
$ 30
$0
0
$152
$ 7
$227
$ 20
$419
$ 9
#6 to #2
,900 - $ 8,
,000-$ 2,
,700 - $ 34,
,100 - $ 3,
, 880 - $158,
,300 - $ 7,
, 800 - $232,
,700 - $ 21,
N/A
N/A
N/A
N/A
, 200 - $433,
,100-$ 9,
A
400 ( 2%)
100
400 ( 7%)
400
700 ( 37%)
600
200 ( 54%)
100
700 (100. 0%)
400
#4 to #2A
$ 15,000
$ 900
$ 42,300
$ 1,300
$ 47,000
$ 2, 100
$ 23,400
$ 3,900
$127,700
$ 1,700
-$16,
-$ 1,
- $46,
-$ 1,
-$51,
-$ 2,
- $25,
-$ 4,
N/A
N/A
N/A
N/A
- $139
-$ 1
600 (
000
000 (
400
900 (
400
000 (
200
,500
,800
12%)
33%)
37%)
18%)
(100%)
Figures bracket most likely range. Because of capital cost financing assumptions costs shown are for the first five years of implementation and will be lower in
subsequent years.
NA = Not Applicable.
Source: Harbridge House, Inc. (1976).
-------
EXHIBIT III-7
ESTIMATED TOTAL ANNUAL COST AND COST PER SITE OF ALTERNATIVE FUEL OIL TYPE CONVERSIONS
ASSUMING NO PRIOR IMPLEMENTATION OF MARGINAL BURNER RETROFIT STRATEGY
Fuel Oil Type Conversions
Site Size Categories
3 to 6 Million BTU per Hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
6 Through 10 Million BTU per Hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
10 Through 25 Million BTU per Hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
25 Through 50 Million BTU per Hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
50 Through 100 Million BTU per Hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
Greater Than 100 Million BTU per Hour
Total Annual Cost (percent of total, all sizes)
Annual Cost per Site
All Size Categories
Total Annual Cost (percent of total, all sizes
Annual Cost per Site
#6(l%s) to #6(0. 5%s)
$
$
$
$
$
$
$
$
$
$
2,
8,
46,
67,
6,
46,
G,
$255,
$ 42,
$427,
$ 7,
400 ( 0. 6%)
600
800 ( 2.1%)
900
700 ( 10.9%)
200
800 ( 15.8%)
200
400 ( 10. 8%)
600
700 ( 59. 8%)
600
800 (100.0%)
300
$ 4,
$ 1,
$ 16,
$ 1,
$ 89,
$ 4,
$130,
$ 11.
$ 89,
$ 12,
$490,
$ 81,
$820,
$ 13,
#6 to frl
600 ( 0. 6%)
200
900 ( 2. 1%)
700
500 ( 10.9%)
300
100 ( 15.8%)
800
000 ( 10. 8%)
700
300 ( 59 . 8%)
700
400 (100.0%)
900
#0 to #2A
$ 8, 300 - $
$ 2,100-$
$ 35, 500 - $
$ 3,600-$
10,
2,
47,
4,
$135,900 - $168,
$ 6,500-$ 8,
$186,000 -$209,
$ 16,900 -$ 19,
N/A
N/A
N/A
N/A
$365,700 - $436,
$ 8,000-$ 9,
600 ( 2%)
700
800 ( 10%)
800
900 ( 38%)
000
400 ( 50%)
000
700 (100%)
500
S4 to »2A
$15,900 - $ 27,
$ 900 - $ 1,
$36,100 - $ 66,
$ 1,100 - $ 2,
$32,300 - $ 60,
$ 1,500 - $ 2,
$32,300 - $ 60,
$ 2,000 -$ 3,
N/A
N/A
N/A
N/A
$96,000 - $171,
$ 1,200 - $ 2,
400
600
200
100
300
700
300
000
600
200
( 16%)
( 39%)
( 34%)
(100%)
Figures bracket most likely range. Because of capital cost financing assumptions costs shown are for the first five years of implementation and will be lower in
subsequent years.
NA = Not Applicable.
Source: Harbridge House, Inc. (1976).
-------
in-ie
categories, particularly the greater than 100 million BTU category (which accounts
for about 60 percent of the #6 oil used in the Worcester inventory). A similar pro-
gression in costs as size increases can be seen in Exhibit III-7, which is based on
no prior implementation of the marginal burner retrofit strategy. Both with and
without implementation of the marginal burner retrofit strategy, total annual costs
for conversion from one percent sulfur #6 oil to one-half percent sulfur #6 oil are
in the vicinity of $410, 000 to $430, 000, while average annual costs per site for all
size categories are about $7000 to $7300 (the higher figures represent the assump-
tion of no retrofit). In the conversion from #6 oil to #4 oil, total annual costs are
in the range from $790, 000 to $820, 000, while average annual costs per site for
all size categories are from $13,400 to $13,900 (the higher figures represent the
assumption of no prior retrofit).
In evaluating the cost figures estimated for the conversion from residual to
distillate firing, it is instructive to note the role of fuel costs in determining total
costs. As shown in Exhibit III-8, fuel costs represent from 80 to 97 percent of total
annual conversion costs based on the assumption that the marginal burner retrofit
strategy has been implemented. The variation is accounted for by the interaction
of components of the Worcester inventory with the cost specifications such as fuel
use by type, the BTU content and price differentials in the two proposed conver-
sions, and the number and capacity of units subject to the capital costs of modifi-
cation.
A major difference in the role of fuel costs in determining total costs, how-
ever, is evident in comparing the figures for the alternative assumptions about
implementation of the marginal burner retrofit strategy. Assuming no prior im-
plementation of that strategy, fuel costs represent from 30 to 50 percent of total
costs in the #6 to #2 oil conversion, and actually represent a 30 to 90 percent
savings in the conversion from #4 oil to #2 oil. Variation by size category is
largely related to the number of marginal burners and fuel used in each, by cate-
gory. An important conclusion to be drawn from the fuel cost savings estimated
-------
m-17
EXHIBIT III-8
PERCENTAGE OF FUEL COST
IN TOTAL COST OF CONVERSION
FROM RESIDUAL TO DISTILLATE FIRING
SIZE CATEGORIES With Prior Implementation With No Prior Implementation
of Marginal Burner Retrofit of Marginal Burner Retrofit
3 to 6 Million BTU/hour
6 through 10 Million BTU/hour
10 through 25 Million BTU/hour 95%
25 through 50 Million BTU/hour 97%
#6 to #2
93%
84%
95%
97%
#4 to #2
85%
88%
87%
80%
#6 to #2
32%
23%
33%
53%
#4 to #2
(60%)
(75%)
(89%)
(32%)
( ) indicates a negative percentage.
Source; Harbridge House, Inc. 1976.
-------
iii-is
in the #4 to #2 conversion is that, upon full amortization of the capital costs of
modification and retrofit, a net annual savings will be experienced by the facili-
ties subject to conversion. For the 30 public sector facilities currently using
#4 oil, full amortization will occur after 20 years. (Net savings may actually
occur prior to full amortization for the public facilities because of the commonly
used sliding scale of interest and principal payments which was not taken into ac-
count in this analysis. See Section B) The 47 private facilities currently using
#4 oil will have fully amortized the capital costs after five years based on the
assumptions of this analysis.
Looking at the cost figures in Exhibit III-6 in more detail, it can be concluded
that, with prior implementation of the marginal burner retrofit strategy, total an-
nual costs of the conversion from #6 to #2 oil range from $420,000 to $430, 000,
with the 10 through 50 million BTU per hour size categories bearing more than
90 percent of total costs. The average annual cost per site for all size categories
ranges from $9100 to $9400 (for the first five years). Only the 25 through 50 mil-
lion BTU category shows average annual costs per site significantly above (more
than two times) the average for all size categories.
The total annual costs of conversion from #4 to #2 oil, shown in Exhibit III-6,
with prior implementation of the marginal burner strategy, range from about
$130,000 to $140,000, with the 6 through 25 million BTU size categories bearing
about 80 percent of the costs. Average annual costs per site for the first five
years (all size categories) are from $1700 to $1800. Both the 10 through 25 and
the 25 through 50 million BTU categories show average annual costs per site
greater than this average for all the size categories. The substantial cost differ-
ences in these two residual to distillate conversions, assuming implementation
of the retrofit strategy, appear to be attributable to differences in original fuel
use, fuel use adjustments for BTU content and preheating, and fuel prices.
In Exhibit III-7, it is evident that the conversion from #4 to #2 is also less
costly than the #6 to #2 conversion when it is assumed that the marginal burner
-------
m-19
retrofit strategy has not been implemented. In particular, the total annual cost
of converting from #6 to #2 ranges from $370, 000 to $440, 000, while the #4 to
#2 conversion costs range from a total of $96, 000 to about $170, 000. Again, the
10 through 50 million BTU categories bear the majority of total costs (88 percent)
in the #6 to #2 conversion; while the 6 through 25 million BTU categories bear the
majority of total costs (73 percent) in the #4 to #2 conversion. Average annual
costs per site (first five years only) for all size categories in the #6 to #2 con-
version range from $8000 to $9500, with only the 25 through 50 million BTU
category exceeding (by more than two times) this overall average. In the #4 to
#2 conversion, the average annual cost per site for the first five years in all size
categories is from $1200 to $2200. Both the 10 through 25 and the 25 through 50
million BTU categories exceed this overall average. Again, it is pointed out that
because of financing arrangements, costs will be lower in the sixth year after
implementation in all subsequent years.
A summary of total annual costs for all size categories is shown in
Exhibit in-9 for the four fuel type conversions. As indicated, the conver-
sion from #6 to #4 oil is most costly, while the conversion from #4 to #2
oil is least costly under both assumptions regarding implementation of the
marginal burner retrofit strategy.
-------
EXHIBIT III-9
ESTIMATED TOTAL ANNUAL COSTS OF ALTERNATIVE
FUEL TYPE CONVERSIONS
Assuming Prior Implementation
of Marginal Burner Retrofit
Strategy
Assuming No Prior Implementation
of Marginal Burner Retrofit
Strategy
#6(1%S) to#6(0.5%S)
$413,400
$427,800
#6 to #4
$792,400
$820,400
#6 to #2a
$419,200 -
$433,700
$365,700 -
$436,700
#4 to #2a
$127,700 -
$139,500
$ 96,000 -
$171,600
' Figures bracket most likely range. Because of capital cost financing assumptions, costs shown are for the
first five years of implementation and will be lower in subsequent years.
Source; Harbridge House, Inc. 1976. See Exhibits III-6 and III-7 for more detailed breakdowns.
-------
APPENDIX A
SUMMARY OF THE MARYLAND EXPERIENCE
WITH A ROTARY CUP BURNER RETROFIT
REGULATION
A. The Regulations
Regulations regarding the-use of rotary cup burners were made effective in
the State of Maryland in August 1975. In more lightly developed areas of Maryland,
the regulations prohibit construction of fuel burning equipment fitted with a rotary
cup burner or replacement of a burner with a rotary cup burner. The metropoli-
tan areas of Baltimore and Washington are, in addition to the above prohibition, gov-
2
erned by the following regulation:
A person shall not cause or permit the operation of a rotary cup burner
on fuel burning equipment having a maximum furnace heat input specified
in the following table after the corresponding dates indicated in the table:
Maximum Furnace Heat Input
Million BTU per Hour Effective Date
5.0 or less July 1, 1976
5.0 - 13.0 July 1, 1977
One year before the effective date, a schedule for replacement shall be
submitted to the Department, specifying the location of and date of com-
pletion of replacement for each affected burner.
This regulation specifically exempts fuel oil burning equipment which has been fitted
with a dust collector or for which a dust collector contract has been let prior to
July 1, 1974.
The Maryland regulations do not discriminate among different types of ro-
tary cup burners. Their definition reads, "... a fuel oil burner which employs
Maryland State Department of Health and Mental Hygiene. Regulations Governing the
Control of Air Pollution in Area(s) I, II, V, VI. (As amended through June 17, 1975),
page 15.
2
Maryland State Department of Health and Mental Hygiene. Regulations Governing the
Control of Air Pollution in Area(s) IV, V. (As amended through June 17,1975), page 5.
-------
A- 2
a rotating cup to atomize and mix fuel oil with air for combustion." Moreover, by
not indicating a compliance date for replacement of rotary cup burners having a maxi-
mum furnace heat input greater than 13 million BTUs per hour, the retrofit require-
ment does not apply to those large facilities.
B. Motivation for and Objectives of Rotary Cup Burner Regulations
The primary objectives of the rotary cup burner regulations were (1) to reduce
particulate emissions, and (2) to save energy by more efficient combustion. More-
over, the regulations were intended to accelerate an already apparent trend away from
the use of rotary cup burners in small boilers. This trend is documented in Exhibit A-l
for the residual fired boilers in the Washington and Baltimore metropolitan areas. Ac-
cording to the background information prepared prior to promulgation of the regulations,
the trend away from rotary cup burners resulted from voluntary action taken by indus-
try to remedy complaints of service people regarding the critical adjustment necessary
2
for good combustion and the tendency of the burners to get out of adjustment.
The retrofit exemption for units having already installed dust collectors, was in-
corporated into the regulations because of the need to integrate the retrofit regulations
with other air pollution control requirements. In particular, the regulations which man-
dated the phase-out of rotary cup burners also incorporated (as an unrelated provision)
the elimination of a requirement for dust collectors on small boilers. Consequently,
it appears that the exemption to rotary cup burner retrofit was included so as not to
penalize those units which had voluntarily installed dust collectors prior to the dead-
line for that requirement.
The implicit exemption for units having a heat input greater than 13 million BTU
was included for two reasons. First, rotary cup burners are typically found in small
Maryland State Department of Health and Mental Hygiene. Regulations Governing the
Control of Air Pollution in the State of Maryland. (As amended through June 17,1975).
page 4.
2
Maryland State Department of Health and Mental Hygiene. Background Information for
Proposed Changes in Maryland Regulations, April 1974, page 6.
-------
A-3
EXHIBIT A-l
INSTALLATIONS OF ROTARY CUP BURNERS
IN RECENT YEARS
(Residual Oil Only)
Year
1968
1969
1970
1971
1972
1973
Number of Burners
Washington
Metropolitan Area
37
32
17
2
0
0
Baltimore
Metropolitan Area
9
8
4
1
4
0
Source; Maryland State Department of Health and Mental Hygiene.
Background Information for Proposed Changes in Maryland
Regulations, April 1974.
-------
A- 4
units because of the relative diseconomies associated with their use in larger size
boilers. (Seventy-one percent of the rotary cups in the Baltimore and Washington
metropolitan areas were less than 5 million BTU per hour and 97 percent were less
than 15 million BTU per hour. ) Secondly, the relatively few large units equipped
with rotary cup burners were found to be used in processing operations, primarily
food processing, such that greater care and maintenance of the burners was exer-
2
cised in order to meet the processing specifications.
C. Economic Impact Assessments
Three assessments of the economic costs associated with rotary cup burner
replacements in Maryland have been completed. The first was done in 1974 prior
to promulgation of the regulations and concluded that replacement-of the 1820 rotary
cup burners (in the Baltimore and Washington areas) falling in the 1 to 15 million
BTU range would cost from $8. 6 to $10.0 million dollars. As shown in Exhibit A-2,
replacement equipment costs for burners with a heat input range from 6 to 15 million
BTU were estimated at $7000, while $3000 was used as the cost for replacement units
with heat input from 1 to 5 million BTU. Exhibit A-3 graphically presents the esti-
mated costs, by size, for equipment to replace rotary cup burners.
In this first cost estimate developed by Maryland, the expenditure was regarded
as being "paid back" within a period of about 15 months. Oil prices, at that time
(1974), were assumed to be $0.25 per gallon (residual), and a ten percent saving in the
quantity of oil used was estimated to represent the typical burner efficiency differen-
tial. Investigations conducted to develop the ten percent savings figure, indicated that
some manufacturers claimed energy savings as high as 25 percent and that the oil in-
dustry regarded the savings potential to be as high as 48 percent. The Maryland Bur-
eau of Air Quality and Noise Control accepted the possibility of savings of 25 percent
but used the ten percent figure in the belief that it represented a more average condi-
tion. Exhibit A-4 shows some instances where more spectacular savings were made.
Background Information for Proposed Changes in Maryland Regulations, April 1974.
2
F. Russ Summers, Bureau of Air Quality and Noise Control, Maryland State Depart-
ment of Health and Mental Hygiene. Telephone interview 7 April 1976.
-------
A-5
EXHIBIT A-2
ESTIMATED TOTAL COST OF REPLACING ROTARY CUP BURNERS
IN BALTIMORE AND WASHINGTON METROPOLITAN AREAS
Burner Input Range Equipment Costs
6-15 MBTU/hr.
Baltimore Area (269 @ $7, 000) $1, 870,000
Washington Area (213 @ $7, 000) 1.480.000
$3,350,000
1-5 MBTU/hr.
Baltimore Area (609 @ $3,000) $1, 820, 000
Washington Area (727 @ $3,000) 2.180,000
$4,000,000
Total Equipment Cost (Both Areas) $7,350,000
Estimated Installation Cost 1,200,000
Total Estimated Cost $8,550,000
Source; Background Information for Proposed Changes in Maryland Regulations,
April 1974.
-------
S9000
S8000
S7000
36000
S5000
S4000
CO
O
O
S3000
$2000
$1000
A-6
EXHIBIT A-3
ESTIMATED COSTS OF OIL BURNER EQUIPMENT
TO REPLACE THE ROTARY CUP BURNER OF VARIOUS SIZES
10
15
20
BURNER CAPACITY (10°BTU)
25
30
Source: Maryland Department Of Health arid Mental Hygiene (1974).
-------
EXHIBIT A-4
FURL SAVINGS EFFECTED BY REPLACEMENT OF ROTARY CUP
RESIDUAL OIL BURNERS WITH MODERN AIR ATOMIZING UNITS
Number of
Burners
CONVERSION'
DATS
FSB 72
JUN 68
JUN 73
JUN 73
JUN 73
JUN 73
NOV 69
ANNUAL
CONSUMP.
FCK YR .
RKFCKE
CONVER .
(crnls )
682,268
197,054
52,126
56,504
92,21*4
119,245
1,112,450
DEGREE DAYS
FOR YR. BE-
FORE CONVER.
4196
4227
2820
2820
2820
2820
4332
CONSUMP. PER
DEGREE DAY
(gal/ D. day)
162.6
46.62
18.48
20.04
32.7
42.29
256.79
CONSUMP.
FOll SAME
PERIOD
AFTER
CONVER .
488,255
161,056
44,175
44,176
67,680
85,299
749,669
DEGREE DAYS
FOR SAME
PERIOD AFTER
CONVER .
3921
4130
2607
2607
2607
2607
3822
CONSUMPTION PER
DEGREE DAY
(gal/ D. day)
124.52
39.0
16.95 ;
16.95
25.96
32.72
196.15
SAVINGS
PERCENT
23.4
16.3
8.3
15.4
20.6
22.6
1
23.6
Source: Background Information for Proposed Changes in Maryland Regulations. April 1974. AVBRAGB PER BURNER » 21.3
-------
A- 8
The second economic impact assessment resulted in an estimated cost of
about $16,300,000 for replacement of rotary cup burners in the Baltimore and
Washington areas. Data is not available to account for the substantial increase
over the previous estimate, however, it may be attributable to inclusion of burn-
ers over 15 million BTU per hour input and/or to increased prices. In this as-
sessment, it was noted that most of the rotary cups in the Baltimore and Wash-
ington areas were over five years old and would have to be replaced anyway within
a relatively short time. Based on a ten percent savings in fuel consumed at a
cost of $0.33 per gallon, it was estimated that an average installation (costing
$7000) would pay for itself in about 13 months.
In both of these assessments of the payback period, it is important to recog-
nize that Maryland did not use their actual fuel burner inventory for assessment
of costs and savings. Instead, both costs and savings were based on a typical fa-
cility. Of particular relevance is their use of 3000 hours of operation per year as
a factor to relate combustion unit capacity to fuel use. Engineers in the Bureau of
Air Quality and Noise Control have noted that the figure of 3000 hours has been
used in the heating equipment industry for relating capacity to fuel use. However,
on request by Harbridge House, Maryland officials checked a few sources in their
inventory and found some discrepancies between the 3000 hour per year assumption
and actual fuel use (which was lower) (see Chapter II, Section C).
The third economic assessment was undertaken in February 1976 and consisted
of a survey of cost figures which had been presented as bids for an actual rotary cup
burner. Fifty-three cost figures (including all equipment and installation costs) were
obtained from nine companies. The replacement cost figures were plotted versus
burner input rating in million BTU per hour and divided into four categories accord-
ing to the fuel burning capabilities of the replacement burner. As shown in Exhibit
A-5 the results of the survey indicated a range of costs from $2000 to $12,000 per
burner. Moreover, it was found that most Boards of Education have specified that
school oil burner replacements be able to burn both residual and distillate oil in
light of uncertain fuel supplies. This specification, according to the bid prices shown
-------
-------
A- 10
in Exhibit A-5 may result in costs $2000 to $3000 greater than those associated
with replacement of burners with single fuel oil type capability.
D. Issues Raised in Implementation
Based on its rotary cup burner inventory, Maryland notified affected parties
of the retrofit requirement in writing, indicating the timing for submission of a
compliance schedule and the motivation behind issuance of the regulations. In retro-
spect, individuals at the Bureau of Air Quality and Noise Control note that the poten-
tial for a positive return on investment (through increases in fuel use efficiency)
were not stressed sufficiently in the initial notification thereby creating some need-
less friction in implementing the regulation. Moreover, the wording of the regu-
lation does not specify the components of a compliance schedule. This omission
caused some owners of rotary cups to notify the Bureau that they would comply by
the specified date, without making firm commitments for replacement equipment
and installation.
Perhaps a greater problem relating to the initial stage of implementation, how-
ever, was the discovery on the part of the Bureau that their inventory, by burner
type, was not accurate. Apparently, some owners of rotary cups lacked knowledge
of alternative burner types when registering their facilities and mistakenly reported
their burners as gun pressure or other types of burners rather than rotary cups.
This has resulted in several owners receiving notification of the regulation only a
few months prior to the date upon which the compliance schedule was required. In
that short time period, they found they could not obtain estimates of burner replace-
ment costs from three of the only eight or nine companies serving the Baltimore and
Washington areas.
A similar timing problem was encountered as a result of a delay of ten months
in getting the initial regulation published in the Maryland Register. In particular,
Mr. Roland Schmidt, Division of Compliance, Bureau of Air Quality and Noise Control,
Maryland State Department of Health and Mental Hygiene. Telephone interview
15 April 1976.
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A- 11
the regulation was supposed to become effective in October 1974, but publication
delays resulted in its effective date of August 1975. Roland Schmidt at the Bureau
indicated the need for a one-year period for owners to investigate costs and arrange
for replacement.
In later stages of implementation, the issue of economic hardship has been
in the forefront. Schools, in particular, have claimed that they cannot obtain bud-
get allocations to meet the compliance deadlines. In one county, where 411 rotary
cups are currently installed in school buildings, public officials estimated that it
would take 17 years for them to comply with the regulation. In another county,
however, officials estimated that their 170 rotary cups in school buildings could
2
be replaced over a two-year period.
Other claims of economic hardship have come from private sector establish-
ments which are currently operating on a marginal basis. Some owners of partially
occupied buildings, for example, have said that they simply cannot comply with the
regulation.
These claims of economic hardship are, as yet, unresolved in Maryland. The
public hearing procedure, which is triggered when a facility refuses to sign a com-
pliance plan, has not been started to date. So far, extra months and sometimes an
extra year has been allowed for recalcitrant owners to consider replacements. (This
allowance is also partially due to the previously mentioned timing problems.) Notifi-
cations of violations have also been issued to some facilities.
Another aspect of the compliance issue regards existing rotary cup burners
which are planned to be phased out after the effective date of compliance. The regu-
lation, as written, would require such burners to be replaced. It is expected that
these situations will have to be resolved in the hearing process.
Mr. Roland Schmidt. Telephone interview 15 April 1976.
2 Ibid. .
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TECHNICAL REPORT DATA
(Please read Ins&uctions on the reverse before completing)
1. REPORT NO.
EPA-901/9-76-006
2.
3. RECIPIENT'S ACCESSION-NO.
4. TITLE AND SUBTITLE
COST ANALYSIS OF TWO AIR QUALITY ATTAINMENT
STRATEGIES
5. REPORT DATE
5 June 1976 Date of Issue
6. PERFORMING ORGANIZATION CODE
?. AUTHOR^) Harbridge House, Inc. (Nancy W. Sheldon, Susan
McKittrick, Daniel Garson, Catherine Bragg)
8. PERFORMING ORGANIZATION REPORT NO.
9. PERFORMING ORGANIZATION NAME AND ADDRESS
Harbridge House, Inc.
11 Arlington Street
Boston, Massachusetts 02116
10. PROGRAM ELEMENT NO.
11 .CONTRACT/GRANT NO.
EPA Contract No. 68-01-1561
Task Order No. 5
12. SPONSORING AGENCY NAME AND ADDRESS
U. S. Environmental Protection Agency
Region I
J. F. Kennedy Federal Building
Boston, Massachusetts 02203
13. TYPE OF REPORT AND PERIOD COVERED
Final
14. SPONSORING AGENCY CODE
15. SUPPLEMENTARY NOTES
16. ABSTRACT
As part of the Commonwealth of Massachusetts' Air Quality Maintenance Planning (AQMP)
procedure, this study evaluates the economic costs associated with implementation of two
strategies for attainment and short-term maintenance of particulate standards. Both strate-
gies are proposed for application to the City of Worcester. They are as follows: (i) replace-
ment of marginal burners with more energy efficient modern equipment; and (ii) conversion
of sources using residual oil to the use of lighter fuels and/or fuels of lower sulfur content.
The analysis has included only the economic costs to owners of affected facilities. The study
was prepared in order to subsequently coordinate the results with an air pollution control
effectiveness analysis to be undertaken separately.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
c. COSATI Field/Group
Air Pollution
Economic Analysis
Air Quality Maintenance
Plans Massachusetts
13. DISTRIBUTION STATEMENT
Release Unlimited
19. SECURITY CLASS (This Report)
None
21. NO. OF PAGES
20. SECURITY CLASS (Thispage)
None
22. PRICE
EPA Form 2220-1 (9-73)
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INSTRUCTIONS
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significant bibliography or literature survey, mention it here.
17. KEY WORDS AND DOCUMENT ANALYSIS
(a) DESCRIPTORS - Select from the Thesaurus of Engineering and Scientific Terms the proper authorized terms that identify the major
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EPA Form 2220-1 (9-73) (Reverie)
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