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requirement is prorated. Additional costs incurred in the start-up period
were spread over all production in order to produce a uniform per-barrel
control cost.
The total annual required revenue is utilized to satisfy two major
components: the total annual operating cost, and a component that provides
the necessary return on investment, called the total annual capital charge.
Note that with the DCF approach, profit is based solely on investment;
operating costs are passed straight through as one component of the total
revenue requirement, without addition of any profit element. This is normal
practice for industrial project assessments. • i
To relate an annual capital charge to the correspond!ng, investment,
a "capital charge rate" was used. In practice, there are two types of
capital investment: fixed capital (i.e., physical equipment) -and working
capital (which is nondepreciable investment). The "fixed charge rate"
is defined as the proportion of investment in fixed capital that must be
recovered in a year of normal production in order to provide the required
DCF ROR. The "working capital charge rate" performs a similar function
for the working capital. The total annual - capital charge for, a pollution
control is the sum of the annual fixed capital charge and the annual working
capital charge. :
Fixed charge rates have several economic assumptions embedded in them.
Some of these assumptions are common to all pollution controls, i.e., the
project life and operating (stream) factors, the income tax rate, and the
required DCF ROR. (Although the MIS and Lurgi production schedules build up
at different rates in Years 1 through 7, a single aggregate production
schedule was used for all cost analysis calculations. This appropriately
treats the project as an integrated whole, rather than as two separate
parts.) ;
Other assumptions vary according to the pollution controller group of
controls. These are: the timing of the investment in fixed Capital, the
depreciation period and the investment tax credit details. Consequently,
different fixed charge rates are used for different groups of pollution
controls.* (These rates, as well as the underlying standard economic
assumptions, are listed later in Table 6.2-2.) :
The working capital charge rate depends only on the project life and
operating factors, the timing of the investment in working capital and the
required DCF ROR. Since none of these assumptions varies among controls, the
sam« working capital charge rate is used for each control.
The use of several different fixed charge rates in the same oil shale
PCTM may appear complex. However, since the manuals examine several
alternatives for pollution control, an accurate evaluation of capital
charges is needed. A less accurate approach, such as assuming a single
capital expenditure profile for all controls, could conceivably affect
the per-barrel cost ranking of pollution control alternatives, j
341
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As already indicated, the total annual cost for a control is the sum of
the total annual capital charge and the total annual operating cost. The
total annual operating cost comprises two components. The "direct annual
operating cost" consists of maintenance, operating supplies, operating labor
and utilities. The "indirect annual operating cost" comprises an annual
allowance for property taxes and insurance, any annual by-product credits,
and an allowance for extra start-up costs, i.e., those that are in excess of
the direct annual operating cost prorated in accordance with production. J[t
also includes a credit reflecting a reduction in the Colorado severance tax
that, must be paid, because the cost of each pollution control [reduces the
severance tax liability.* Extra start-up costs and the severance tax credit
are "levelized" to distribute them uniformly over each barrel of shale oil
produced since they do not vary in proportion to production. '(Levelizing
takes a cost that does not vary in proportion to production and finds an
economically equivalent cost that has the same time-profile as production
[see Sections 6.2.3 and 6.4.3].) To summarize:
Total Annual Control Cost = Annual Fixed Capital Charge + Annual
Working Capital Charge + Direct Annual Operating Cost + Indirect
Annual Operating Cost.
For air and water pollution controls, direct annual operating costs are
specified for a normal year of production and are implicitly prorated during
the start-up years. In practice, operating costs during the start-up period
will be higher, but this is allowed for via the extra start-up costs
discussed in Section 6.2.2. The solid waste management costs are developed
in the form of a year-by^year cash flow (see Table 6.1-4) which must be con-
verted into equivalent fixed capital and direct annual operating: costs for a
full production year (see Section 6.2.3 and Table 6.2-3).
The per-barrel control cost is obtained by dividing the total annual
.control cost by the production in a normal (full production) year. (Per-
barrel operating costs and capital charges can be calculated in the same
v/ay.) The detailed algorithms for these calculations and for determining
fixed and working capital charge factors are given in Section 6.4,1.
6.2.2 Economic Assumptions Used in Total Cost Calculations
To transform engineering cost data provided in Section 6.1.2 into total
annual capital charges, total annual operating costs, and total annual or
The distinction between the two components of operating cost is made for
convenience in performing the calculations and is not fundamental. The
direct annual operating cost is comprised of basic cost elements, whereas
the indirect annual operating cost comprises a series of adjustments that
are influenced by other factors, such as tax assumptions. Direct annual
operating costs for each control are given in Tables 6.1-1, 6.1-2, 6.T-3
and 6.2-3. Indirect annual operating costs for all controls are calculated
using a standard algorithm (see Section 6.2.2), except for any by-product
credits which are given in Tables 6.3-4 and 6.3-5.
342 :
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per-barrel control costs, a number of economic assumptions were made. Most
of these assumptions are listed in Table 6.2-1, and Table 6.2-2 summarizes
those assumptions that vary from control to control. The values given In
these two tables are the standard values, known as the "standard economic
assumptions," which have been used for the cost analyses presented in the
oil shale PCTMs. Some of these are varied in the sensitivity analyses which
are used to show how control costs change in response to alternative economic
assumptions and to changes in the engineering costs.
Where appropriate, the standard economic assumptions arie discussed
below. Others are discussed in connection with the sensitivity analyses in
Section 6.3.2. ,
Timing of Control Capital Expenditures—
Table 6.2-2 includes the fixed capital expenditure profiles for each
category of control. A construction schedule was developed by DRI based on
data supplied by Cathedral Bluffs Shale Oil Company (November ;14, 1980).*
Engineering judgment was then used to determine when the pollution controls
would be procured and installed, incorporating the impact of payments made
during off-site fabrication. In general, capital expenditures on controls
tend to be incurred later than those for most retort construction activities,
since the controls are usually among the last items to be installed.
An unusual factor in this PCTM is that completion of the five trains of
MIS retorts takes place over four years, while completion of the: eight Lurgi
retorts occurs over a period of five years (see Section 1, Table 1.4-1).
Since a separate air pollution control unit is associated with each MIS
retort train or Lurgi retort, this means that the individual units will be
placed in service over a period of four or five years. Therefore, deprecia-
tion is similarly apportioned for calculation of fixed charge factors. In
contrast, all water management equipment, except the kettle evaporators, will
be placed in service prior to the operation of the first retort, i Consequent-
ly, the same timing is used for all water management controls, leading to a
single capital recovery factor for all water controls other than the kettle
evaporators.**
* These data do not necessarily represent the current plans of the Cathedral
Bluffs Shale Oil Company. '•
**In other oil shale PCTMs4 site water management equipment (e.g., clari-
fiers) has been assumed to be installed early in the construction schedule,
whereas other water management equipment (e.g., the ammonia recovery unit)
has been assumed to be installed at the same time as the retort air pol-
lution controls. :
i
343
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TABLE 6.2-1. SUMMARY OF STANDARD COST AND ECONOMIC ASSUMPTIONS
Assumptions
COST ASSUMPTIONS. ;
• Base Year: Mid-1980 dollars \
• Basic Labor Rate: $11.00/hr* ' ;
• "Loaded" Labor Rate*: $30.00/hr :
• Fixed Capital Costs: 25% engineering and construction overhead and 3% contractor's fee included*
• Contingency Allowances: 20%, all fixed capital costs* i
0%, roost operating costs*
20%, solid waste direct operating costs
ECONOMIC ASSUMPTIONS
• Project Life: 30 years, including 7-year start-up period |
• Normal Output: 117,100 Barrels per Calendar Day (BPCD) ',
• Proportion of Normal Output During Start-up Period:
Year 1 - 2% Year 5-68%
Year 2 - 10% Year 6-77% ;
Year 3 - 28% Year 7-80%
Year 4 - 47% Years 8-30 - 100% ;
• Approach: Discounted Cash Flow Evaluation (DCF)* ',
« Discount Factors: Discrete,* year-end basis ;
« Method: Determination of Revenue Requirement .to provide specified DCF ROR*
• Technique: Annual Capital Charge plus Annual Operating Cost 1
• Required OCF ROR: 12% (100% Equity Basis)* j
« Cost Escalation: None (constant dollar evaluation)*
* Combined State and Federal Income Tax Rate: 48%* i
* Depreciation: Method - Sum-of-Year's Digits*
Period - 16 years, most items*
10 years, solid waste area
5 years, mobile equipment
0 Investment Tax Credit: 20%, most items* .
13 1/3%, mobile equipment
«> Additional Start-up Costs-.(spread over Years 1-7): 3% of fixed capital, plus 50% of a normal year's
direct operating cost ••-••••
» Working Capital: 30 days' total operating cost (excluding by-product credit), plus 60 days' by-product
credit . '. . .
« Annual Allowance for Property Taxes and Insurance: 3% of fixed capital
» Colorado Severance Tax: Credit allowed ;
« Timing of Investment: Initial fixed capital expenditures can occur in Years -3 through +5;
expenditures and tax considerations for each control are phased in accordance with the construction
and initial operation of each control (see Table 6.2-2 for schedules)
» Corporate Financing: Tax credits and allowances can be passed through to a parent company that can
benefit from them immediately, without waiting for the project to become profitable*
o Federal Depletion Allowance: Does not affect pollution control-costs i
•* These methods and factors are in accordance with the recommendations, dated April 22, 1980, of EPA's
ad hoc synfuels cost committee. '
Source: DRI. • ;
344
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Assumptions for Taxation*--
Depreciatlon. All oil shale PCTMs used a 16-year depreciation period
for most assets. This corresponds to the mid-point of the IRS1 Asset
Depreciation Range (ADR) guidelines for oil refineries. In practice, many
companies would use the lower end of the ADR range, which is 13 years;
however, it has been found that this would make very little difference in the
results of the analysis. |
Some equipment clearly qualifies for a shorter life. Controls associ-
ated with processed shale disposal, such as embankments and water impound-
ments, were regarded as mining equipment, for which a 10-year idepreciation
period was used. A 5-year depreciation period was used for the mobile
equipment, and it was assumed that this equipment was replaced five times
during the project life. ;
The depreciation method used for all taxation calculations was the
Sum-of-the-Year's Digits method.
Investment Tax Credit (ITC). A basic 20% ITC was used for jail items in
accordance with the Energy Tax Act of 1978 (PL 95-618). The mobile equipment
has a depreciation period of only 5 years, so the credit is reduced by
one-third, to 13 1/3 percent. !
Where payments for a control extend over more than one year, the tax
credit can be taken as the capital is expended, in accordance with the IRS1
progress payments rule. Otherwise, it is taken when the asset is: placed into
service. i
Income tax rate. A combined State and Federal tax rate of 48% was used.
In practice, Colorado has a 5% tax rate, so the effective percentage rate
should be: 5 + ([1 - 0.05] x 46) = 48.7%. The error introduced by using 48%
is negligible. ; •
Depletion allowance. The Federal depletion allowance has not been
incorporated into the calculation of taxes. The justification for this is as
follows. The percentage depletion allowance is 15% on the- "gross income"
from an oil shale property. In this case, since the sales or transfer price
of shale oil (and, hence, gross income) is independent of pollution control
costs, the depletion allowance will not affect those costs. However, there
is a limitation that the percentage depletion allowance cannot exceed 50% of
* All analyses were conducted prior to enactment of the Economic Recovery Tax
Act of 1981 (PL 97-34). As far as an oil shale project is concerned, the
main impact of this act is to permit very rapid depreciation under the
Accelerated Cost Recovery System (ACRS). Using ACRS, most property would
be depreciated over 5 years and mobile equipment would be depreciated over
3 years. A rough estimate of the effect of the provisions of the Economic
Recovery Tax Act of 1981 on the pollution control costs is given In
Section 6.3.1* !
347
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the taxpayer's taxable Income from the property, computed without allowance
for depletion. Since pollution control costs reduce the taxable income,
they could affect the depletion allowance if it was limited under the above
rule, and this would then be a cost attributable to pollution control. While
this might well be the case in a start-up year, it appears that this limit
is unlikely to apply during a normal year's operation. This is because
the complete project's total annual operating costs are a low proportion
of its total annual costs, including capital-related costs (DRI calculations
based on data provided by Cathedral Bluffs Shale Oil Company [November 14,
1980]). :
Hence, the .impact of the Federal percentage depletion allowance on
pollution control costs has been disregarded. This may introduce minor
errors during start-up years, but complete project cost data are not publicly
available to permit the effect to be calculated. Cost depletion, which might
at times be taken instead of percentage depletion, is clearly irrelevant to
pollution control costs.
Other Assumptions— ;
- i
DCF ROR. Twelve percent (per year) was used as a standard assumption
(see Section 6.3.2). i .
Project life and start-up profile.* The MIS-Lurgi project1 is unusual
in that there is a very long build-up period of seven years before full out-
put is reached. (This slow build-up largely results from the nature of MIS
retort construction. Retort development occurs continuously, arid it is not
feasible to bring all trains of MIS retorts into production at the same
time.) For this reason, a project life of 30 years, i.e., 23 years of full
production, was used.** Furthermore, the production build-up profile is not
concurrent between the MIS retorting and the surface (Lurgi) retorting, as
the latter generally achieves a smaller proportion of its ultimate capacity
in any one year. ;.
The production schedule for the MIS-Lurgi project is given in
Table 6.2-1. This schedule involves a change of mining plan in Year 8, which
results in a significantly higher grade of shale being fed to the Lurgi
retorts.t However, only seven out of eight Lurgi retorts will;be operated
at any time. In Year 8, the MIS operations change from operating four out of
five trains at any one time to operating all five simultaneously.'. All equip-
ment associated with the MIS operations is designed 25% oversize,; which in an
emergency would permit four trains of process and control equipment to handle
the normal output of five trains. Because of this redundancy,; evaluations
* This section is based on data provided by the Cathedral Bluffs Shale Oil
Company (November 14, 1980); however, these data do not necessarily repre-
sent the company's current plans.
!
**C.f. 20 years in total for the PCTMs on other oil shale processes.
t This is termed the "Phase II mining plan" in the Cathedral Blujffs project.
348
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have been made, as proposed by Cathedral Bluffs, without incorporating any
additional operating (stream) factor for normal production years (i.e.,
Year 8 and beyond).*
Components of Annual Indirect Operating Costs—
i
The annual indirect operating cost is composed as follows: ;
Annual property tax and insurance
+ Extra start-up costs (levelized)
- Severance tax credit (levelized) :
- Annual by-product credit (if any).
i
Property tax and insurance allowance. The annual indirect operating
cost includes 3% of the fixed capital cost as an allowance for property tax
and insurance. This value was selected by DRI after review of a wide variety
of sources.
!
Extra start-up cost. The total extra start-up cost (which i£ treated as
an operating cost, as opposed to being capitalized) is derived frbm the fixed
capital and direct annual operating costs. The capital-related component is
3% of the fixed capital cost as an allowance for "fix it" 'costs. The
operating cost-related component, which is 50% of a normal year's direct
operating cost, allows for hiring and training employees before production
commences and for higher unit costs during the start-up period.
A standard value for the extra start-up cost for surface retorting
plants with a 2-year* start-up period was selected by DRI after a review of
several sources, including estimates for TOSCO II (Nutter and Waitman, 1978)
and Paraho (Pforzheimer and Kunchal, March 24, 1977) plants. This value was
3% of fixed capital cost and 20% of a normal year's direct operating cost.
Because of the long start-up period for the MIS-Lurgi project, the operating
cost-related portion was increased from 20 to 50 percent. This is in reason-
able accord with the developer's estimate (based on DRI analysis of data
supplied by the Cathedral Bluffs Shale Oil Company [November 14, 1980]). The
extra start-up cost was assumed to be incurred over the 7 start-up years but
is levelized to spread it uniformly over every barrel of oil produced (see
Sections 6.4.1 and 6.4.3). :
Severance tax credit. Under Colorado HB 1076, enacted' in 1977,
severance tax is levied on the production of a commercial oil shale facility
at the rate of 4% of the "gross proceeds" for surface retorted oil, reduced
to 3% for oil produced by in situ methods. "Gross proceeds" is defined as
the value of the oil shale at the point of severance and is calculated by
subtracting Costs (e.g., retorting and mining) from the gross sales income.
* Other oil shale PCTMs use a 90% operating factor (i.e., the ratio of actual
annual production to maximum production based on continuous operation at
full output) in normal production years.
349
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Since pollution controls add to costs, they reduce the gross proceeds by a
corresponding amount. Hence, a credit for severance tax not paid should be
deducted from the pollution control costs. ;
While operating costs are clearly allowable in calculating gross
proceeds, return on capital does not appear to be (the statute refers to
allowing "...costs, including direct and indirect expenditures for:
(a) equipment and machinery "). Hence, when this credit is! calculated,
the capital charge must be replaced by some form of amortization. For this
analysis, the severance tax credit calculations are based on| direct and
indirect annual operating costs, plus 5% of the fixed capital cost to provide
a crude capital amortization.
In applying this credit, allowance was also made for exemptions to the
tax for the first 10,000 barrels per day of production and for plants that
have not achieved 50% of their design capacity, together with reduced rates
of tax in the early years. The credit is levelized in order to achieve a
uniform per-barrel cost. The methodology utilized (LFAC2 in Sefction 6.4.1)
is not precise, but since the severence tax correction is typically less than
2% of the total annual or per-barrel control cost (see Secition 6.2.4),
further refinement is not justified.* :
By-product credits. The by-product credit (if any) for each control is
shown in Tables 6.3-4 and 6.3-5. (There are no salable by-products from
solid waste management.) By-product values of $110 per ton for ammonia,
$30 per long ton for sulfur, and $32 per barrel for oils were used.
i
At present, there is no significant market for sulfur in the Rocky
Mountain Region; in the past, shipping costs to move recovered sulfur to a
chemical complex could have been greater than its delivered value. However,
the price of high quality sulfur has gone up substantially in recent years,
reaching values as high as $129 per long ton (U.S. DOI, August 1981). High
demand for sulfur is projected through the year 2000 (Rangnow and Fasullb,
September 28, 1981). Hence, a nominal $30 per long ton has been included for
recovered sulfur. However, if in the future a sulfuric aci<$ plant and
fertilizer complex are developed in the area, the values of by-product sulfur
and ammonia would be raised. ' • ~ j
- i
Working Capital— i
The working capital associated with a control was taken as:one month's
total operating cost plus three months' byproduct credit. This is equiv-
alent to be one month's total operating cost disregarding the by-product
* Since this analysis was conducted, the Colorado Legislature hasiamended the
severance tax legislation pertaining to oil shale. While the basic rate
for aboveground retorting is unchanged, the various exemptions discussed
above are reduced, and the reduced rate for in situ retorting is elimi-
nated. This will result in plants paying slightly more severance tax,
which marginally increases the severance tax credit, thereby marginally
(less than 1%) reducing the pollution control cost. ;
350
-------
credit, plus two months' by-product credit. Two months' by-product credit
represents one month's inventory and one month's receivables. These values
were selected by DRI after review of a variety of data sources.
Working capital is advanced in accordance with the direct annual oper-
ating cost plus the extra start-up cost, as follows:
Year 1
Year 2
Year 3
Year 4
Year 5
Year 6
Year 7
Year 8
Percentage
of Normal
Output
2%
10%
28%
47%
Extra Start-up Cost
as Proportion of a
Annual Operating
Cost Relative to
Normal Year's Direct a Normal Year's
77%
80%
100%
Operating Cost
5%
10%
10%
10%
5%
5%
5%
50%
Operating Cost
7%
20%
38%
57%
73%
82%
85%
100%
Working
Capital
Increment
100%
Seven percent of the total working capital is advanced in Year 1 because
the annual operating cost comprises 2% of the normal year's direct annual
operating cost and there is a 5% extra start-up cost. In Year 2, the direct
annual operating cost is 10% of a normal year, but the extra start-up cost is
also' 10% of the direct annual operating cost, for a total of;20 percent.
This is 13% more than in Year 1, so 13% of the total working capital is
advanced in this year. And so on until Year 8, by which time all the working
capital has been advanced. Working capital is recovered in Year 30.
The working capital charge rate (RW) is calculated in a similar way to
a fixed charge rate .(see Sections 6.4.1 and 6.4.2). For 12% iDCF ROR and
normal project-timing assumptions, RW = 21.80%. ;
' '
6.2.3 Solid Waste Management Costs ' '.
Throughout this manual a distinction is made between fixed capital costs
and annual operating costs. The importance of this distinction is related to
the treatment for determining income tax liability. Operating costs can be
claimed as an expense in the year in which they are incurred, whereas a fixed
capital cost must be depreciated over the period for which the asset is
expected to be used. The effect of classifying a cost as an operating cost
rather than a capital cost is to reduce the tax liability in any given year.
For air and water pollution controls, the distinction between fixed
capital and annual operating costs is unequivocal. For solid waste manage-
ment costs which are developed in the form of year-by-year cash flows
(Table.6.1-4), the distinction is less clear. Costs that occur in only
Year 1 (the runon catchment dam and low-level outlet) or Years 1, 2 and 3
(the runoff catchment embankment) were treated as fixed capital Costs, while
those that continue for 25 or more years were considered as operating costs.
351
-------
Costs that occur at the end of the project (e.g., revegetation) were also
treated as operating costs, since there is no remaining project life over
which to depreciate them. ;
Since the solid waste management operating costs are not proportional to
production, they were "levelized" to transform them into equivalent direct
annual operating costs that are proportional to production, so that they can
be treated in the same way as other direct annual operating costs. Level-
izirig involves determining the annual cost that is proportional to production
and which-has the same present value (for a given DCF ROR) as the irregular
operating cost stream. Further explanation and an example are provided in
Section 6.4.3. Costs designated as fixed capital were not levelized.
Table 6.2-3 presents the solid waste management fixed capital costs
and direct annual operating costs (levelized at 12% DCF ROR) derived from
Table 6.1-4. !
TABLE 6.2-3. FIXED CAPITAL AND DIRECT ANNUAL OPERATING COSTS
FOR SOLID WASTE MANAGEMENT i
Activity
Fixed
Capital Cost
($000's)
Direct Annual.
Operating Cost
($000's/yr)
a
SURFACE HYDROLOGY
Runon Catchment Dam and
Low-level Outlet
Runoff Catchment Embankment
'Runoff Collection System
SURFACE STABILIZATION
Dust Suppression
Grubbing, Stripping and Clearing
Reclamation and Revegetation
4521
460£
51
1,948
! 483
250
a
The direct annual operating costs are levelized with respect to'production
at 12% DCF ROR. i
Spent in first year of production, Year 1.
c Spent uniformly in Years 1-3.
Source: DRI.
352
-------
6.2.4 Control Cost Example
Table 6.2-4 provides an example of the composition of the various
elements of per-barrel cost for a single major pollution control, the Stret-
ford system. Per-barrel costs follow identical proportions to annual costs.
i
i
TABLE 6.2-4. PER-BARREL COST BREAKDOWN FOR STRETFORD SYSTEM
(Standard Economic Assumptions, Case Study B)
Cost Category
Cents/Barrel
Percentage of Total
Fixed Capital Charge
Equity Return (12% ROR)
Income Taxes Paid
Investment Tax Credit
84.3
23.7
(16.9)
91.1
55.0
15.4
(11.0)
59.4
Working Capital Charge
1.3
0.9
Direct Operating Costs
Maintenance
Operating Supplies
Operating Labor
Cpoling Water
Steam
Electricity
10.0
8.8
21.9
1.3
6.0
6.5
5.7
14.3;
0.8
4.0;
48.0
31.3
Indirect Operating Costs
Taxes and Insurance
Extra Start-up Costs
Severance Tax Credit
By-product Credit
TOTAL COST
9.3
3.2:
(1.5)
Source: DRI.
353
-------
It can be seen that the fixed capital charge amounts to 59.4% of the
total cost, whereas the working capital charge is only 0.9% of; the total
cost. It is interesting to note that the fixed capital charge! is almost
entirely return on equity, as the investment tax credit (20% of fixed capital
cost) almost offsets the income tax liability over the project life when both
are discounted at 12%, which is the specified DCF ROR. This illustrates the
effect of the time-value of money, as the tax credit is given before produc-
tion commences, whereas the regular tax liability is weighted toward the
later years of the project.
The direct operating costs for the Stretford system make up 31.3% of the
total cost. Operating labor (14.3%) is the largest component, followed by
maintenance, operating supplies and utilities (electricity and steam).
The indirect operating costs amount to 8.4% of the total cost for this
control, of which 9.3% results from the cost of property tax and insurance.
There is a by-product credit of 2.6% of the total cost, and the extra
start-up costs and the severance tax credit are 3.2% and 1.5%, respectively,
of the total. ;
These cost proportions for the Stretford system are typical ofi those for
air pollution controls. However, for some controls, the indirect operating
cost or even the per-barrel control cost can become negative where there is a
significant by-product credit.
Water pollution control costs tend to be less capital-intensive, i.e.,
the ratio of the total annual capital charge to the total annual i operating
cost is lower. This is because some controls have high utility costs.
Solid waste management costs are different in that they are: basically
either a fixed capital cost or a direct annual operating cost, but not both
for a given control. This reduces working capital and indirect annual
operating costs, respectively, to essentially zero.
6.3 COST ANALYSIS RESULTS
The methodology used to develop the data presented in this section is
identical to a complete discounted cash flow evaluation; that is,; it solves
for the annual or per-barrel revenue required to provide the specified return
on the investment (DCF ROR) associated with a control. This revenue require-
ment is known as the total annual or per-barrel control cost. The cost
methodology is outlined in Section 6.2, and further details are provided in
Section 6.4.1. !
Three control items—proper maintenance of valves and pumps, floating
roof oil storage tanks, and the MIS absorber/cooler—have relatively large
by-product credits which lead to negative total annual costs (ij.e., total
annual cost credits). Although these items might consequently not be con-
sidered pollution controls, the costs of all three have been included in the
total cost of air pollution control. The net credits associated wHh proper
maintenance and floating roof oil storage tanks combined represent a very
small proportion (less than 0.4%) of the total air pollution control cost.
354 !
-------
The net credit for the MIS absorber/coolers, however, is quite large (29% for
Case Study A and 37% for Case Study B of the total air control cost under
standard economic assumptions). In some of the more severe sensitivity
analyses considered in Section 6.3.2, the total cost for the MIS
absorber/cooler actually becomes positive (as increased annual capital
charges become large enough to offset the annual by-product , credit for
recovered shale oil). This is one reason for including the cost of the MIS
absorber/cooler in the total pollution control cost. •
i
6.3.1 Results for the Standard Economic Assumptions*
The term "standard economic assumptions" is used to describe the normal
economic assumptions presented in Tables 6.2-1 and 6.2-2. The majority of
these assumptions are in reasonable accord with normal engineering and
economic evaluation practices. The most critical economic assumption is that
of 12% required DCF ROR. This figure was adopted for the oil shale PCTMs and
would be appropriate for a mature industry, but it is probably low for a
pioneer plant at this time (see Sections 6.2.1 and 6.3.2 for a discussion of
factors influencing the selection of a DCF ROR).
Table 6.3-1 provides a summary of pollution control costs developed
using the standard economic assumptions for the two case studies considered
in this manual. Table 6.3-2 provides additional detail based on the control
groupings listed in Table 6.3-3. Note that total costs for solid waste
management are not provided. A complete solid waste management plan for the
MIS-Lurgi project has not been proposed. As a result, cost estimates are
available for particular items only, and no estimate of the total 'solid waste
management cost can be made at this time. ;
* As already mentioned, this analysis was developed prior to enactment of the
Economic Recovery Tax Act of 1981. The rapid depreciation (ACRS) permitted
by this act would significantly reduce the values of the fixed charge
factors, especially for normal ("pass through") financing as opposed to
stand-alone financing. ;
For standard economic assumptions, very rough estimates of the decreases in
total annual control costs are as follows:
Air controls: 20-25% decrease on aggregate.
Water controls: 5% decrease on aggregate.
Solid waste mgt.: 0-15% decrease, depending on item. ;
The large effect on the aggregate cost for air controls arises from the MIS
absorber/cooler credit.
As an alternative assumption, if the energy portion (10%) of the investment
tax credit were allowed to expire at the end of 1982, the combined effect
of this and ACRS would be to cause small increases in total annual control
costs.
355
-------
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357
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TABLE 6.3-3. CONTROL GROUPINGS
Group Designation Specific Controls
Air Pollution Control \
Particulate Control: Fabric filters, water and foam sprays,
• electrostatic precipitators, venturi
v/et scrubber.
i
Retort Gas Treatment: Stretford, flue gas desulfurization,
MIS absorber/cooler. :
Miscellaneous Air: Ammonia storage tanks, catalytic
converters, floating roof oil storage
tanks, maintenance of valves, pumps,
etc.
Water Pollution Control . j
Condensate Treatment: API oil/water separator, Phbsam-W
ammonia recovery unit, retort water
stripper, multimedia gravity filtra-
tion unit, kettle evaporators.
Miscellaneous Water: Mine water clarifier,* boiler feed-
water treatment,* cooling water treat-
ment,* equalization pond, runoff oil/
water separator. ;
«•*••-' '" I*. ' ' ll"1' •''" " •"" "'"-'• '." •"•"'" "" ""• '•"• '•''!' "••••" '• • -—•—•••"••••I iii ii.ii.i •!..•! in.1.1.in.ii.ii in -- ii mi.i. '.nil IIMII 'i 11' i ..n nto ,.'11 Jiii.iii. . i .1 .H...I .1 •..»*...—^.—
* These technologies could be considered as part of the process rather than
pollution control.
Source: DRI.
Table 6.3-1 shows that the total fixed Capital cost for air pollution
control equipment ranges from $464 million (Case Study B) to $485 million
(Case Study A), while the total air control cost ranges from $1.33 per
barrel (Case Study B) to $1.70 per barrel (Case Study A). The fixed capital
cost for water pollution control is nearly identical for both case studies,
totaling approximately $78 million. Total water pollution control costs are
also virtually identical—$1.72 per barrel for Case Study A and $1.75 per
barrel for Case Study B.
Table 6.3-1 also compares the per-barrel cost of pollution control to an
assumed $32 per-barrel value for shale oil.* For air pollution control, the
* Other prices for the value of shale oil are used in the other oil shale
PCTMs, reflecting quality differences.
358
-------
proportion is 5.3% for Case Study A and 4.2% for Case Study B. Total water
pollution control costs represent about 5.5% of the $32 per-barrel value of
shale oil.
i
The works^gate value of $32 per barrel (mid-1980 dollars)^for the MIS
and Lurgi shale oils was based on two sources: a developer's estimate of $29
per barrel (Cathedral Bluffs Shale Oil Co., November 14, 1980), and a study
by Peat, Marwick, Mitchell & Co. (September 1980) which derived current
values for shale oil. This study concluded that the per-barrel value of
shale oil (at the project site) was $31.50 to $32.50 for surface retorted oil
and $34.50 to $35.50 for MIS retorted oil. In no case was upgrading in-
volved.
It is generally anticipated that the real price of oil will increase in
the future. Hence, the value of $32 may be considered to be a conservative
estimate because it does not include any element of escalation;relative to
the general level of prices. For example, if oil prices were to. escalate at
only 2% per annum relative to general cost levels (which can be! expected to
include pollution control costs), the real value of shale oil|would reach
almost $58 per barrel (in mid-1980 dollars) by the year 2010, i.e., at the
end of the 30-year project life.
If Case Study A and Case Study B are compared (see Table!6.3-2), the
major difference between them is in the gas treatment. Case Study A uses
Flue Gas Desulfurization (FGD), whereas Case Study B uses a Stretford unit to
desulfurize the retort gases prior to their combustion. Both fixed capital
and total annual operating costs for the Stretford unit (Case Study B) are
lower than for the FGD unit (Case Study A).
Water treatment controls and cost are virtually identical for Case
Studies A and B. Case Study B has marginally greater fixed capital and total
annual operating costs due to somewhat larger kettle evaporators.i
Cost Details—
Full cost details for each air and water pollution control (using
standard economic assumptions) are presented in Tables 6.3-4 and 6.3-5. As
already noted, three items—the MIS absorber/coolers, proper maintenance of
valves and pumps, and floating roof oil storage tanks—were found to have
negative total annual costs. In these cases, the annual by-product credits
were large enough to more than offset the total annual capital charges and
total annual operating costs. These items were, nevertheless, incorporated
into the total air pollution control 'costs. !
Table 6.3-6 presents the costs of six solid waste management item;;.
Of the six, dust suppression ($2.1 million total annual control cost or
4.8 cents per barrel) and grubbing, stripping and clearing (|0.5 million
total annual cost or 1.2 cents per barrel) are the most costly items. Both
of these items are primarily operating expenditures (zero fixed capital
cost). The only solid waste management items with fixed capital costs are
the rundn catchment dam and low-level outlet and the runoff catchment
embankment (totaling $0*9 million in fixed capital, but representing only
359
-------
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0.4 cents per-barrel control cost). The per-barrel figures are somewhat
more than doubled if expressed with respect to Lurgi retorted shale, but
are still small in comparison to the costs of air and water pollution
controls. However, it should be remembered that these costs represent
only a portion of a total cost associated with a complete solid waste
management operation.
6.3.2 Sensitivity Analyses
This section explores the sensitivity of the results to changes in the
engineering costs and economic assumptions. In general, only a single change
from the standard economic assumptions was made in each case, enabling the
impjict of this change to be isolated. Table 6.3-7 summarizes 'the changes
made for each case, while Table 6.3-8 displays the fixed and working capital
charge rates used to calculate per-barrel control costs. Per-barrel pollu-
tion control costs, expressed as a percentage of a $32 per-barrel shale oil
value for both case studies, are given in Table 6.3-9. Table 6.3"10 provides
additional detail for the absolute per-barrel control costs and includes per-
centage changes from the standard economic assumptions. Comparative results
for Case Study A for the various sensitivity analyses arie presented
graphically in Figures 6.3-1 and 6.3-2. No sensitivity analysis has been
performed on the solid waste management costs, as only partial cost estimates
v/ere available. Each sensitivity analysis is discussed below. '••
Twenty Percent Increase in Fixed Capital Costs— ',
Cost escalation is always a problem with pioneer plants because of the
numerous uncertainties (Merrow, September 1978; Merrow, Chapel ahd Worthing,
July 1979). A 20% increase is not at all unreasonable despite the inclusion
of a 20% contingency in the fixed capital cost estimates. ;
Table 6.3-10 shows that the effect of a 20% increase in fixed capital
costs varies significantly among the control groups. Retort gas treatment,
which is capital-intensive, shows a greater percentage increase (32% for Case
Study A and 41% for Case Study B) than water pollution control, which is
operating cost-intensive (only 5% increase for both case studies). The cost
of particulate and miscellaneous air controls increases by 17% fbr both case
studies. ;
Overall, the difference in the total cost increase for air pollution
control between the two case studies is not large, since both case studies
are equally capital-intensive. Relative to results under the standard
economic assumptions, the increase in total air pollution control cost is
28 to 36%, or 47 to 50 cents per barrel. These results indicate that the air
pollution controls are fairly capital-intensive. In contrast, the increase
in the total water pollution control cost is relatively small in both
percentage (5%) and absolute terms (9 to 10 cents per barrel), ks the water
pollution controls are not capital-intensive.
362
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TABLE 6.3-9. SENSITIVITY ANALYSES EXPRESSED AS
A PERCENTAGE OF SHALE OIL VALUE
Per-barrel Control Cost as a
Percent of $32/Barrel Shale Oil Value
Air
Sensitivity Analysis
Standard Economic Assumptions
20% Increase in Fixed Capital Costs
20% Increase in Direct Operating Costs
66.7% Increase in Utilities Costs
80% of Planned Output
20-year Project Life
Delayed Start-up
15% DCF ROR
Stand-alone Financing
Stand-alone Financing at 15% DCF ROR
Combined Assumptions*
Combined Assumptions with
Stand-alone Financing*
A
5.3
6.9
5.9
6.2
7.6
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8.0
6.4
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17.7
B
4.2
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16.0
Water
A ;
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B
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6.1
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7.2
8.1
* Combined assumptions are 20% increase in fixed capital costs, 15% DCF ROR
arid delayed start-up.
Source: DRI.
!
Twenty Percent Increase In Operating Costs— '•.
Operating costs are often better defined than capital costs, which is
v/hy an operating cost contingency is not normally included in the direct
annual operating costs. However, there are many reasons why operating costs
could be higher than anticipated. For example, regional shortages of skilled
labor could result in higher wages and reduced productivity. Also, labor
costs may escalate faster than other costs. Maintenance costs could be
higher than expected, and both utility requirements and utility unit costs
could deviate from expectations. ' ! .
For air pollution controls, the overall effect of an increase in direct
annual operating cost is much less than that of the same percentage increase
in fixed capital cost. For a 20% increase, the retort gas treatment cost
increases by 19 cents per barrel (13%) for Case Study A and }5 cents per
366 !
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barrel (14%) for Case Study B. Total air pollution control costs increase by
15 to 20 cents per barrel, or 12 percent. The costs of water pollution
control, which are more operating cost-intensive, increase by 28 to 29 cents
per barrel, or 17 percent. Once again, the difference in increase in cost
between case studies is small.' ;
i
66.7% Increase In Utilities Costs— ;
Operation of various controls requires inputs of electricity and steam.
Under standard economic assumptions, electricity is valued at;3 cents per
kW-hr, and it is assumed that steam is generated at a cost of $3/MMBtu.
The electricity charge of 3 cents per kW-hr may very likely underestimate
the true cost of power purchased from the grid (should this prove necessary)
as it is a compromise value between plants that can sell power and those
that must purchase power (see Section 6.1.1). The MIS-Lurgi ifacility is
expected to be self-sufficient in power, but it is conceivable that excess
electricity may be available for export. However, to allow for the pos-
sibility that a power plant is not built, a 5 cents per kW-hr rate (a 66.7%
increase) was considered. At the same time, the price of steam was also
increased by 66.7%, as the standard rate for this input of $3/MMBtu may also
prove to be conservative. Three dollars per million Btu is a typical 1980
value used for heat inputs in engineering studies, but no detailed cost
evaluation was conducted for this manual. Hence, the steam cost must be
considered uncertain. •
The results indicate that utility costs constitute a major component
of pollution control costs. Water pollution control costs show a dramatic
increase, rising 51$ (88 to 89 cents per barrel). This increase can be
attributed to the large quantities of steam required to operate the kettle
evaporators, ammonia recovery unit and retort water stripper. The in-
creases in air pollution control cost are less dramatic. The retort gas
treattment cost increases by 19% (28 cents per barrel) for Case Study A
and by only 7% (8 cents per barrel) for Case Study B. Case Study A dis-
plays the greater increase because the FGD unit uses much larger quantities
of steam and electricity than does the Stretford system in Case Study B.
Particulate and miscellaneous air control costs increase only ,6% (2 cents
per barrel). Total air control cost increases by 17% for Case Study A
and 7% for Case Study B. i
The absolute cost of pollution controls ranges from $1.43 to $1.99 per
barrel for air controls and from $2.60 to $2.64 per barrel for water manage*
ment. The severe increases in the total cost for water pollution control
suggest that further analysis of the cost of steam would be desirable.
Uncertainty about the cost of electricity does not have a major influence on
control costs, so whether the project buys from or sells to the electrical
grid is not an important issue.
Eighty Percent of Planned Output— i
A frequent problem with pioneer process plants is that they fail to
achieve their planned output. Occasionally they produce more. When a plant
fails to reach its planned output, the annual fixed capital charges must be
372
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spread over reduced output, and the direct annual operating costs decrease by
a lesser proportion than the output because some components (such as main-
tenance) are virtually unchanged. .
For the case of a plant which achieves only 80% of planned output, it
was assumed that direct annual operating costs fall to 90% of the full
production costs. Production in the start-up years and by-product credits
were prorated to 80% of the standard values.
Overall, the results are fairly severe, with the capital-intensive
controls showing the greatest increases. Retort gas treatment costs increase
by 48 to 60% (63 to 68 cents per barrel). Particulate and miscellaneous air
control costs increase by 24% (7 cents per barrel). Total air pollution
control cost increases 44% (75 cents) for Case Study A and 52% (69 cents) for
Case Study B. The less capital-intensive water pollution control costs
increase 17% (30 cents per barrel). '.
Twenty-Year Project Li fe—
A shorter project life might occur because of technological obsolescence
or some other currently unanticipated reason.* There is little doubt that
the oil shale reserves on Tract C-b are adequate for the planned 30-year
life. For most projects, extension of the life beyond 20 years has very
little effect on the total costs because the later years are so heavily
discounted.
This case examines the impact of reducing the life to 20 years. Over-
all, the effects of this change on control costs are relatively, mild. Once
again, the more capital-intensive air control Costs show the largest in"
creases. The total air pollution control cost increases 17% (28 cents per
barrel) for Case Study A and 20% (26 cents per barrel) for Case Study B. The
total water pollution control cost increases by only 4% (6 to 7 cents per
barrel) for both case studies. ! .
Delayed Start-up— I
i
Because of the time-value of money implicit in the discounting proce-
dure, anything that delays or curtails production raises annual capital
charges and, hence, the per-barrel control cost; conversely, anything that
accelerates or extends production reduces the costs. '
For this analysis, production is halted for two years (Years 3 and 4)
and then follows the normal build-up profile displaced by two years. (The
project life remains at 30 years, as this is likely to be determined by tech-
nological obsolescence.) This profile corresponds to the scenario that the
plant initially starts production according to schedule; then, a;t the end of
A 20-year life was recommended for the oil shale PCTMs. However, because
of the exceptional 7-year start-up period, it was considered inappropriate
to use a 20-year life for this cost evaluation rather than the 30-year life
proposed by the developers of the Cathedral Bluffs project.
373
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Year 2 (which would correspond to only 20 months' actual operation), the
plant is closed down because serious operational problems have developed and
must be solved, which takes two years. Fortunately, not all the fixed
capital has been expended by the end of Year 2; only two MIS retort trains
and one Lurgi plant are operational, but construction has started on several
others.
The effects of this case are moderately severe. Total air pollution
control costs increase by 33 to 40% (53 to 55 cents per barrel). The water
pollution control cost for both case studies shows only a small 6% increase
(11 cents per barrel), as water management costs are dominated by the large
operating cost of the kettle evaporators. !
Fifteen Percent DCF ROR--
The minimum acceptable DCF ROR used in a project feasibility study is
normally not divulged by developers and, in any event, is influenced by
alternative investment opportunities and other factors. However, there is
broad confirmation that a rate between 12% and 15% per annum (in constant
dollars) is appropriate for evaluating oil shale projects (Denver Research
Institute, etal., July 1979; also see Merrow, September 1978).! This ROR,
which is called a "hurdle rate," is higher than the return that a company
actually earns on its capital for a number of reasons. First, it is an
unfortunate fact of life that many projects earn less than the projected rate
becciuse things do not work out as expected. This is only partly offset by
the few that do better than anticipated. Second, project evaluations do not
usually include such costs as R and D, exploration and reserve acquisition;
also, they may not include recovery of some general corporate expenses.
i
The single most important factor that influences the required DCF ROR is
the perceived riskiness of the project. A high risk project is,expected to
pass a higher ROR hurdle than a low risk project. Some of the types of risks
that; might be subjectively taken into account in selecting a minimum accept-
able DCF ROR for a mining project in the U.S. include:
• Unproven technology (and, hence, uncertain equipment costs);
• Geologic uncertainty; :
• Very large investments in relationship to total corporate assets;
• Rapid inflation in some cost components;
• Long construction and start-up periods; :
• Market uncertainty; •
* Regulatory uncertainty (leading to delays or added costs); and
• Difficult working conditions or adverse socioeconomic impacts
leading, to manpower problems.
For any first generation commercial synfuel plant, all the above factors
are present, with the possible exception of geologic uncertainty. At this
time, most of these factors are strongly present in oil shale projects.
374 ';
-------
The MIS-Lurgi plant is particularly susceptible to these risks because of its
complex technology and extended start-up schedule. :
The standard economic assumption is 12% DCF ROR, which is probably the
lowest acceptable ROR for a private enterprise shale oil plant with proven
technology. For a pioneer plant of this type, industry is likely to require
at 'least 15% ROR, unless it wishes to "buy into" a new industry. Of course,
if another party (e.g., the Federal government) were prepared to share the
risk in some way, the required ROR would be reduced. Even though some of the
risks listed above do not apply to pollution controls, industry does not
perceive environmental costs to be separable from the total project. Hence,
all components of a project, including pollution controls, must earn the
specified DCF ROR. '
Increasing the required DCF ROR from 12 to 15% has a substantial effect
on the costs. Once again, capital-intensive controls are ! those most
affected—for example, retort gas treatment costs rise by 56 to 72% (75 to
79 cents per barrel). Particulate and miscellaneous air controls increase
by 24% (7 cents per barrel). The increase in total air pollution control
costs, relative to standard economic assumptions, ranges from 51% for Case
Study A to 61% for Case Study B (or 86 and 81 cents, respectively). The
total water pollution control cost shows a moderate 12% increase (20 cents
per barrel). ;
Stand-alone Financing— !
The term "stand-alone financing" is used to describe a project in which
investment tax credits and allowances for depreciation cannot be passed
through to a parent company (or companies) which can benefit from them
immediately. (These benefits are treated as negative income |tax in con-
ducting the alternative "pass-through" form of project evaluation which is
used under the standard economic assumptions.) Instead, it is necessary for
the project to become profitable before the tax benefits can be obtained. It
is difficult to determine when this might occur because it requires a de-
tailed knowledge of the overall project economics; in any event, the timing
of the benefits 'will be affected by the selling price of the shale oil.
However, it is known that some of the developers are assuming stand-alone
financing for their evaluations since it more closely reflects their tax
positions than does pass-through financing. |
To determine the approximate effect of substituting stand-alone
financing for pass-through financing, it was assumed that no investment tax
credit or depreciation could be claimed until the fifth year of production
(in which output averages 68% of a full production year). This assumption
was based on examination of the cash flow analysis for an MIS plant
presented in a recent oil shale tax study (Peat, Marwick, Mitchell & Co.,
September 1980). It must be emphasized that this assumption i's very sim-
plistic (and probably conservative), since the relevant details in the tax
study were significantly different from those assumed in this manual. As
expected, the effect was the greatest for the capital-intensive control
groups. The overall effect was to increase total air pollution control costs
by 21 to 26% (34 to 36 cents per barrel) and total water pollution control
375 ;
-------
costs by 5% (8 to 9 cents per barrel). A more refined calculation might
yield substantially greater increases, especially if a low value was used for
the price of shale oil, thereby reducing profitability. ;
The effect of stand-alone financing was also evaluated at|l5% DCF ROR,
using the same assumptions as above. This probably comes closer to a devel-
oper's evaluation. In this case, the increases in costs are quite substan-
tial, ranging from $1.32 to $1,39 per barrel (82 to 99%) for all;air controls
and 33 cents per barrel (19%) for water pollution control.
Combined Cases—
/r
Two combined cases were evaluated using the components already dis-
cussed. However, ft is not sufficient to construct these analyses by simply
combining the results from the earlier findings, so new analyses were
developed. The two cases are as follows: :
Combined assumptions
• 20% increase in fixed capital costs
• Delayed start-up
• 15% DCF ROR ;
• Everything else as standard economic assumptions.
Combined assumptions with stand-alone financing
» 20% increase in fixed capital costs
• Delayed start-up
• 15% DCF ROR
• Stand-alone financing
• Everything else as standard economic assumptions.
i
These combined cases are intended to be quite plausible adverse
scenarios (i.e., 20% increase in fixed capital costs and delayed start-up)
looked at from industry's viewpoint (i.e-,', 15% DCF ROR, with; or without
stand-alone financing, depending on the company).
The results clearly indicate that, if everything else remained the same,
these cases would constitute disasters for the MIS-Lurgi project,; since total
project costs would respond in a.similar way to pollution control' costs. The
most capital-intensive control group (retort gas treatment) increases in cost
by between 172 and 220% ($2.30 to $2.42 per barrel) for regular (pass-;
through) financing and by between 258 and 330% ($3.43 to $3.62 per barrel)
for stand-alone financing. Overall, the increase in total air pollution
control cost ranges from 154 to 187% for the regular (pass-through) case and
from 233 to 283% for the stand-alone case.
Total water pollution control costs rise approximately 32% for the
regular case and 48% for the stand-alone case. The absolute level of
376
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pollution control costs ranges from $3.83 to $4.31 per barrel for all air
controls and from $2.27 to $2.30 for water pollution control for the regular
(pass-through) case. For the combined assumptions with stand-alone
financing, absolute control costs are $5.11 to $5.66 per barrel for air and
$2.!>6 to $2.59 for water. These results represent a more than1 tripling of
the absolute cost of air pollution controls.
• • i
Summary—
Returning to Table 6.3-9, it can be seen that total air pollution
control costs are roughly 4 to 5% of the assumed $32 per-barrel value for
shale oil under the standard economic assumptions. Total water pollution
control costs are about 5.5% of the value of the oil. !
With respect to air pollution controls, only the last three sensitivity
analyses (stand-alone financing at 15% DCF .ROR and the two sets: Of combined
assumptions) produce dramatic increases in cost. For stand-alone financing
at 15% DCF ROR, total per-barrel costs increase to between 8 and 10% of the
shale oil value. For combined assumptions, air control costs increase to
between 12 and 14% of the oil value, while for combined assumptions with
stand-alone financing, the air control costs rise to between 16 and 18% of
the oil value. The more capital-intensive air control costs| tend to be
greatly affected by the sensitivity analyses which adversely impact annual
capital charges. The cost of the MIS absorber/cooler causeis the total
operating cost for all air controls to be negative, with the result that
changes in capital charges are magnified when translated to per-barrel
control costs. In all instances, Case Study B remains the lower cost option
for air pollution control due to the lower fixed capital and direct annual
operating costs associated with the Stretford system, as oppose
-------
instance (the 66.7% increase in utility costs) do water pollution control
costs become substantially larger than air pollution control costs.
Figures 6.3-1 and 6.3-2 split the control costs into a per-barrel
capital charge and a per-barrel total operating cost. These figures
effectively illustrate the response of capital-intensive controls (air) vs.
operating cost-intensive controls (water) to the different sensitivity
analyses. Note that the total operating cost is always negative for air
pollution controls.
6.4 DETAILS OF COST ANALYSIS METHODOLOGY "\
6.4.1 Cost Algorithms !
This section provides the algorithms used to calculate total annual and
per-barrel control costs and capital charge factors.
Calculation of Total Annual and Per-barrel Control Costs—
The total annual cost (TC) of each item considered for pollution control
is the sum of the total annual operating cost (TOC) and the annual capital
charge (CC). That is: !
TC = TOC + CC
and . TOC = DOC + IOC
where: DOC = Direct annual operating cost
IOC = Indirect annual operating cost
and CC = (FCC x RF) + (WC x RW)
where: FCC = Fixed capital cost
WC - Working capital
RF = Fixed charge factor ;
RW = Working capital charge factor
The cost per barrel (CPB) is the total annual cost divided by the normal
annual production, i.e.: !
CPB = TC -r (BPCD x 365) '
where: BPCD = Barrels per calendar day
This corresponds to a 100% operating factor in normal years, as explained
earlier. ;
The derivation of each cost component is explained below. j
Direct annual operating cost. DOC is a data input derived from the
engineering cost analysis. It is the annual cost for a normal year and is
taken from one of the basic data Tables 6.1-2 through 6.1-4 or 6.2~3.
378
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Indirect annual operating cost. The indirect annual operating cost
(IOC) is calculated as follows:
IOC = TIA + ESC - STC - BP
where: TIA = Annual tax and insurance allowance ;
ESC = Annual extra start-up costs (levelized—see below)
STC = Annual severance tax credit (levelized--see below)
BP = Annual value of by-products
BP is an input generated from stream data and shown in one of the tables in
Section 6.3, and: ;
TIA = 0.03 x FCC
ESC = (0.03 x FCC + 0.50 x DOC) x LFAC1 '
STC = 0.04 x [(DOC + ESC + TIA - BP) + 0.05 x FCCJ x LFAC2
LFAC1 and LFAC2 are levelizing factors that spread ESC and STC uniformly
over all units of production. LFAC2 also makes adjustments for the severance
tax exemptions allowed for low production and allows for the reduced rate for
underground production. These factors are as follows: ',
OJ£ + n ?n r 1 + l 4
1+r "^ L(l+r)2 (1+r)3
LFAC1 = —
0^02 0^10 0.28 0^47 0.68 0.77 0.80 rCl+rr7'
• 1+r (1+r)2 (1+r)3 (1+r)4 (1+r)5 (1+r)6 (1+r)7 L
where: N = last year of production (= 30 in most analyses)
r = Discount rate = OCR ROR :
This levelizing factor distributes the seven annual components of the
extra start-up cost uniformly over each unit of production throughout the
project's entire life.
LFAC2 = BPC° - *M°° x ri-«:Si42£°w
i
1 . 0-47 1 . 0.68 . 3 . 0.77 . 0.80 . r(l+r)~7 - (l+r)"N-
8 (1+r)4 2 (l+r)s 4 (1+7)6 (1+T)7 L^ iT^ •*
X —• 1 r— . i' ' i ' '. __>* . ;•
[Same denominator as in LFAC1] |
where: BPCD = Barrels per calendar day i
* 69,040 -f 117,000 is the proportion of below-ground production.
379
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A numerical example of a levelizing calculation is given in Section 6.4.3.
Capital costs. Fixed capital cost (FCC) is an input taken from one of
the data tables. Working capital (WC) is calculated as follows:
I
WC = 1/12 x TOC + 1/4 x BP ''..'•
Capital Charge Factors—
The fixed charge factor equation is: :
N
I [(1 + r) n x (K - T x D - C )]
n=J n n n ;
RF =
N
(1 - T) I [(1 + r)"n OJ
n=l n
where: Kn = Capital expenditure in year n (2 K = 11000)
C = Investment credit in year n
Dn = Depreciation in year n :
0,, = Operating income in year n (0 = 1.000 in a normal
n year) n
r = DCF ROR (= discount rate) ;
T = Tax rate
i
N = Last year of project
J = First year of project (i.e., -3)
*
Note that the first year of production is Year 1.
, ' , i
The same equation is used to determine the working capital charge factor
(RW), except that the Dn and Cn terms are omitted.
6.4.2 Example Calculation of a Fixed Charge Factor
Table 6.4-1 provides an example of the calculation of a fixed charge
factor. The data used are for MIS surface facilities, using standard eco-
nomic assumptions (see Table 6.2-2).
The following is an explanation of the calculations in the table.
Expenditures are shown negative, while income (and taxes avoided) is shown
positive. Column [2] is a schedule of capital expenditures to be made over a
seven-year period, totaling an arbitrary $1,000. (Unit value is used in the
equation above.) Columns [3], [4], and [5] deal with allowances associated
with this capital expenditure. Column [3] is a schedule of depreciation,
commencing in Year 1 when the first part of the asset is placed into service.
The irregular series in this column occurs because there are five retort
380 ;
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381
-------
trains, placed Into service in four different years. Column [4] gives the
value of the depreciation allowed to the company. This value is the income
tax not incurred as a consequence of the depreciation deduction, and it is
48% of Column [3]. Column [5] is the 20% investment tax credit Available in
each year a capital expenditure is made. (This is a direct credit against
tax and does not have to be multiplied by the tax rate.)
I
Column [6] represents the income stream resulting from the $1,000
investment (Column [2]). Income in a normal, full production year is desig-
nated by "l.OOx." Since income is proportional to production, and production
in the start-up years is less than full production, the first seven years of
•income are appropriately reduced, e.g, , 0.02x in Year 1, O.lOx in Year 2,
Q.28x in Year 3, etc. Column [7] shows the residual income to the company
after income tax is paid on the income in Column [6]. :
The 12% discount factors in Column [8] are used to generate: the present
values in Columns [9], [10], [11] and [123. After summing the columns of
present values of after- tax income, depreciation allowance, investment tax
credit, and capital expenditure, an equation is constructed to determine the
gross income which must be generated by the $1,000 of capital to achieve a
12% DCF ROR; thus:
2.7168X = 925.36 - 220.04 - 185.08
i
= [12] - [io] -
therefore: x = = 191.49
(x represents the gross income in a full production year that "is
necessary to provide the specified DCF ROR, 12%, on $1,000 of fixed
capital.)
hence: RF = - = 19.15%
6.4.3 Cost Levelizing Calculations
i
While most direct operating costs vary in proportion to plant output,
the operating costs for solid waste management do not. For example, the cost
of the runoff collection system is a uniform annual cost, starting in Year 1
and finishing in Year 25. To spread these costs in a pattern consistent with
production over the 30-year project life, these operating costs are trans-
formed into an annual figure for a normal year, and this figure'can then be
used with the standard methodology above. This is done by calculating a
"levelized cost" for a normal year's production. This technique is also used
to spread the extra start-up cost and severance tax credit uniformly over
shale oil production. i
382
-------
A "levelizing factor" is used to make this transformation. The fol-
lowing equation shows how a levelizing factor is used to arrive at a
levelized cost (i.e., a stream of payments having the same profile as produc-
tion), given the present value of a nonuniform stream of payments:
Levelized Cost = I(Presenf Va]fe! ofca j;ost stream^
Levelizing Factor
By dividing the levelized cost by a normal year's output, a cost per unit of
production is derived.
The equation for calculating the levelizing factor (LF) is:
S . :
I P = PVFA - 3
Lh PV™(r,N) J
where: LF = Levelizing factor :
PVFA, N-. = Present value factor of a uniform series of
' payments for N years ;
PVF, . = Present value factor of a single payment in
tr'nj year n \
r = Discount Rate = DCF ROR
N = Number of production years
S = Number of years in the start-up period i
n = Any specific year in the start-up period
L = The proportion of normal output during any given
start-up year; the series of L values Constitutes
the "start-up profile" n :
The second term on the right-hand side of the above equation is an
adjustment to the uniform series represented by the first term. The comple-
ment of the L figure (i.e., that portion of each start-up year which is
less than full production) is discounted, summed, and then subtracted from
the uniform series. Since the start-up years have high present values, the
effect of subtracting this term has a substantial impact on the levelizing
factor. Because the levelizing factor is the denominator in the equation
which determines the levelized cost (and, hence, the unit cost), this adjust-
ment term raises the per^-barrel cost. |
Cost Levelizing Example—
To illustrate the concept of cost levelization, a calculation of the 12%
DCF ROR levelizing factor used for this manual is presented below:
383
-------
Proportion of
Year Normal Output (l_n) PVF @ 12% (1-L > x PVF
1 0.02 0.8929 0.8750
2 0.10 0.7972 0.7175
3 0.28 0.7118 0.5125
4 0.47 0.6355 0.3368
5 0.68 0.5674 0.1816
6 0.77 0.5066 0.1165
7 0.80 0.4524 0.0905
8 )
I > 1.00 3.4914 O.boOO
30 ' '
8.0552 2.8304
Hence: LF,_.,^ N=3Q yrg) = 8.0552 - 2.8304 = 5.2248
(Note that all present values are expressed with respect to Year p.)
This factor is the same as the denominator in the levelizing expressions
L.FAC1 and LFAC2. ;
As an illustration of a levelizing calculation, consider the runoff
collection costs. The "engineering cost" (Table 6.1^5) is $34,000 per year
for Years 1 through 25.
The present value of these costs, expressed with respect to Year 0, is
calculated as follows:
'ear
1
2
3
Expenditure
$34,000
34,000
34,000
PVF @ 12%
0.8929
0.7972
0. 7118
Present Vali
$ 30,359
27,105
24,201
25 34,000 0.0588 1.999
$266,665
Thus, $266,665 is the present value of all the runoff collection costs.
To turn this into a cost that is distributed uniformly with respect to
output, it must be divided by LF(r = 12%j N = 30 years),
Therefore, Level i zed Cost = = $51,038
Thus, $51,038 (rounded to $51,000 in Table 6.2-3) is the annual cost in
a normal production year that is equivalent to the irregular cost profile
384
-------
given above. This direct annual operating cost can be used in conjunction
with the algorithms given in Section 6.4.1 for calculation of total annual
control cost and per-barrel control cost, whereas the irregular stream of
expenditures from which it was derived cannot be used with the standard cost
methodology. j
i
In summary, cost levelization redistributes a cost series that is not
proportional to production over the project life in such a way as to yield an
equivalent series that is proportional to production and has the same
economic value. !
385
-------
-------
SECTION 7
DATA LIMITATIONS AND RESEARCH NEEDS
A number of limitations associated with stream characterization and
pollution control technology performance were identified in the data base
during the preparation of the Pollution Control Technical Manual for the
combined MIS and Lurgi oil shale retorting processes. It is important that
users of this manual be aware of these limitations. It is also important
that these limitations be addressed prior to development of an oil shale
facility of the magnitude analyzed in this manual and proposed1by Cathedral
Bluffs Shale Oil Company (e.g., 62,000 TPSD oil shale mined and 117,000 BPSD
shale oil produced). "
7.1 DATA LIMITATIONS
The descriptions of the MIS and Lurgi retorting processes and
information regarding applicable control technologies, performance, and costs
used to prepare this manual were obtained from reports on the :operation of
pilot MIS and Lurgi retorts, vendor descriptions, and: engineering
calculations used in conjunction with experience transferred from analogue
industries such as the petroleum, utility, and mineral mining industries
which utilize similar control technologies. Until "hands on" experience is
obtained from commercial-scale oil shale operations, these sources constitute
the best available data base. However, the limitations of this data base
should be clearly understood. Pilot retorts were built and operated
primarily to improve process design and not for demonstrating operation of a
commercial-sized retort with attendant pollution control systems. Many
pollution control systems have never been pilot tested with an oil shale
retort. Even for those control systems that were pilot tested, often the
data collected have been very limited.
To date, the only MIS retorting experience is comprised of the operation
of one small (Room 3E) and three large^sized (Rooms 4, 5 and 6) MIS experi-
mental retorts processed by Occidental Oil Shale, Inc., and the data from
some laboratory-scale testing. Two more large-sized retorts (Rooms 7 and 8)
have been processed recently, but the new data are not yet available.
Although the large experimental retorts have been comparable in size to that
planned for the commercial retorts, they have been burned on an individual
basis (with the exception of Rooms 7 and 8 which have been processed
jointly). By contrast, 96 retorts in an operating panel will :be processed
simultaneously for the commercial-scale production. A scale-up of this
magnitude is likely to involve some design modifications which could produce
changes in the stream compositions, flows, and performance of the control
technologies. :
387 ',
-------
The primary experience with Lurgi retorting involves two 'pilot plants
(5 tons/day and 25 tons/day) and several laboratory-scale retorts operated in
West Germany during the past few years. Shales from Tract C-b, Tract C~a,
and the Colony mine in Colorado have been processed recently, and the
available data from these tests have been used in this manual. ^A full-sized
Lurgi retort is expected to process 8,800 TPSD of raw shale, and seven of
these retorts will be needed to produce 48,000 BPSD of shale oil. Again,
this represents an enormous scale-up of the pilot retorts; therefore,
improvements in the retort design and operating parameters may be inevitable,
resulting in some uncertainty about the performance of control technologies.
Variations in the grade of the shale also introduce modifications to the
operating parameters and, hence, the data. The MIS field retorts have been
operated at Logan Wash, while the commercial operation is iplanned for
Tract C-b, which is located several miles north of the Logan Wash site. The
grade of shale at the two sites is significantly different—15.6 gpt at Logan
Wash compared to 26.7 gpt at Tract C-b. Furthermore, the mineralogy of the
two sites is different, i.e., Tract C-b is higher in pyrites. During a
recent MIS burn at Tract C-a, which is located in the vicinity of Tract C-b,
up to 4% by volume H2S and 1,500 ppmv COS were measured in the off-gas
(Sklarew, et a!., February 1981). It is likely that the shale at Tract C-b
may also produce an off-gas containing higher amounts of sulfur compounds
than measured at Logan Wash. Again, this may translate into an uncertainty
in control performance.
Given the potential problems associated with process scale-up and
variations in the quality of the shale, a linear extrapolation! of the data
from pilot operations may not be entirely applicable to a commercial
operation or to other development sites; therefore, a direct transfer of the
information must be made with caution. Also, the MIS retorting operations
will likely be more sensitive to site-specific hydrologic conditions.
It should also be noted that, to date, the MIS and Lurgi pilot plants
have primarily consisted of the retorts only. The Room 6 MIS experiment did
include an absorber/cooler to recover light.oils from the off-gas, but it was
sized to handle only 15% of the flow from a single MISS retort. A
thermosludge boiler, or kettle evaporator, was also employed to raise steam
from the retort water. Other pollution control ^technologies:(e.g., FGD,
Stretford, Phosam-W, steam stripper) that form the basis for a complete plant
as proposed by Cathedral Bluffs (see Sections 2 and 3) have not yet been
tested with the MIS and Lurgi processes (the recent Room 7 and 8 burn at
Logan Wash included testing of the Stretford process and steam stripper, but
data on these technologies are not yet available). Therefore, actual control
technology performance and compatibility with the two retorting processes
have not been documented. : .
The fact that the processing streams have been measured in terms of
major constituents only is an additional limitation. Information on minor
constituents, which may be of concern from an operational as well as an
environmental viewpoint, is not well documented. Examples of such
constituents include regulated and nonregulated pollutants (e.g., trace
388
-------
elements, specific organics, Inorganics), all of which can have an impact
upon the choice and operation of downstream control.
Assessing the limitations of existing data sources was :an important
by-product resulting from the preparation of this manual. Since the best
available information on each subject was selected, this manual represents
the best currently available data base on the MIS and Lurgi processes; also,
within the limitations of available data, it accurately estimates the control
efficiencies achievable. ;
7.2 RESEARCH NEEDS '.
The limited potential for the transfer of control technology from pilot
. and semi-works retorting tests and from analogue industries to cpmmercial oil
shale operations emphasizes a genuine need for research in certain areas of
oil shale processing and pollution control. This need is strengthened by the
fact that, even with several years of experience, the oil shale industry is
still in an early state of development.
While it is recognized that further research will be essential in all
phases of oil shale commercialization, the major areas of data uncertainty
regarding characterization of streams and control technology performance, as
revealed during preparation of the MIS-Lurgi PCTM, are identified in
Table 7.1-1. The status of the information is presented according to the
development stage of the source and technology. The specific information
sources are also identified. A reliability or confidence ranking is assigned
to the data for each stream and technology based on a subjective evaluation
of the direct applicability of the data to a commercial-scale MIS-Lurgi
facility. Some salient features and caveats in the information base are
noted, and specific research needs are identified to overcome; some of the
data limitations. ;
389
-------
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SECTION 8
REFERENCES j
Adams, C.E. and W.W. Eckenfelder, eds. 1974. Process Design Techniques for
Industrial Waste Treatment. Associated Water and Air Resources Engi-
neers, Environmental Press, Nashville, Tennessee.
American Petroleum Institute. 1969. Manual on Disposal of Refiinery Wastes,
Volume on Liquid Wastes. API, New York. :
American Petroleum Institute. March 1978. A New Correlation of NH3, C02 and
H2S Volatility Data From Aqueous Sour Water Systems. Publication
No. 955. API, New York.
Ashland Oil, Inc. and Occidental Oil Shale, Inc. February 1977: Oil Shale
Tract C-b: Modifications to Detailed Development Plan.
Ashland Oil, Inc. and Occidental Oil Shale, Inc. October 1977. Prevention
of Significant Deterioration; Application to U.S. Environmental Protec-
tion Agency, Region VIII.
Ashland Oil, Inc. and Shell Oil Company. February 1976. Oil Shale
Tract C-b: Detailed Development Plan and Related Materials. 2 vols.
Barduhn, A.J. September 1967. The Freezing Processes for Desalting Saline
Waters. Progress in Refrigeration Science and Technology, Proceedings of
the International Congress of Refrigeration, 12th, Madrid. Vol. 1,
37-55. ;
Battelle, Columbus Laboratories. October 1978. Control of NOx'Emission by
Stack Gas Treatment. EPRI FP-925. Final report prepared for the
Electric Power Research Institute, Palo Alto, California.
Beychok, M.R. 1967. Aqueous Wastes from Petroleum and Petrochemical Plants.
John Wiley and Sons, Surrey, England. ;
Calmon, C. and H. Gold. 1979. Ion Exchange for Pollution Control. 2 vols.
CRC Press, Boca Raton, Florida. ;
Cathedral Bluffs . Shale Oil Company. November 14, 1980. Proposal for
Financial Assistance in the Form of a Loan Guarantee; Volume V.
Submitted to U.S. Department of Energy in response to Solicitation
DE-PS60-81RA50480. ;
405
-------
Cheremisinoff, P.M. and F. Ellerbusch. 1978. Carbon Adsorption Handbook.
Ann Arbor Science, Ann Arbor, Michigan.
Colony Development Operation. 1977. Prevention of Significant Deteriora-
tion; Application to U.S. Environmental Protection Agency, Region VIII.
Colony Development Operation. March 1980. Application to Colorado Mined
Land Reclamation Board for Solid Waste Disposal Permit. ;
Denver Research Institute/Water Purification Associates/Stone and Webster
Engineering Corporation. July 1979. Predicted Costs of Environmental
Controls for a Commercial Oil Shale Industry. U.S. Department of Energy
Report No. COO-5107-2.
i
Dravo Corporation. February 1976. Handbook of Gasifiers and Gas Treatment
Systems. FE-1772-11. Final Report, Task Assignment No. 4, Engineering
Support Services. Submitted to the U.S. Energy Research and Development
Administration.
Electric Power Research Institute. April 1980. Economic and Design Factors
for Flue Gas Desulfurization Technology. EPRI CS-1428.
Fox, J.P., D.E. Jackson and R.H. Sakaji. 1980. Potential Uses of Spent
Shale in the Treatment of Oil Shale Retort Waters. 13th Oil Shale
Symposium Proceedings, Colorado School of Mines, Golden, Colorado.
Fox, J.P., K.K. Mason and J.J. Duvall. 1979. Partitioning of Major, Minor
and Trace Elements During Simulated In Situ Oil Shale Retorting. 12th
Oil Shale Symposium Proceedings, Colorado School of Mines, Golden,
Colorado.
i
Girvin, D.C., T. Hadeishi and J.P. Fox. June 1980. Use of Zeeman Atomic
Absorption Spectroscopy for the Measurement of Mercury in Oil Shale
Gases. Oil Shale Symposium: Sampling, Analysis and Quality Assurance,
March 26-28, 1979, Denver, Colorado. EPA-600/9-80-022. U.S. Environ-
mental Protection Agency. [
Gulf Oil Corporation and Standard Oil Company. (Indiana). March 1976. Rio
Blanco Oil Shale Project: Detailed Development Plan,' Tract C-a.
4 vols. Submitted to U.S. Department of the Interior, Geological
Survey, Area Oil Shale Supervisor. :
Hart, J.A. June 11, 1973. Waste Water Recycled for Use in Refinery Cooling
Towers. Oil and Gas Journal. 71(24):92-96.
Hicks, R.E., et al. June 1979. Wastewater Treatment in Coal' Conversion.
EPA-600/7-79-133. U.S. Environmental Protection Agency. •
Hicks, R.E. and L. Liang. January 1981. A Study of Reverse Osmosis for
Treating Oil Shale In Situ Wastewaters, Final Report. DOE/LC/10089-5.
U.S. Department of Energy. ;
406
-------
Hicks, R.E. and I.E. Wei. December 1980. A Study of Aerobic Oxidation and
Allied Treatments for Upgrading In Situ Retort Waters, Final Report.
DOE/LC 10097-1. U.S. Department of Energy. !
Humenick, M.J. 1977. Water and Wastewater Treatment: Calculations for
Chemical and Physical Processes. Marcel Dekker, New York.
1 !
Jones, B.M., R.H. Sakaji and C.G. Daughton. August 1982. Physicochemical
Treatment Methods for Oil Shale Wastewater: Evaluation1 as Aids to
Biooxidation. 15th Oil Shale Symposium Proceedings, Colorado School of
Mines, Golden, Colorado. i
Kohl, A.L. and F.C. Riesenfeld. 1979. Gas Purification. 3rd ed. Gulf
Publishing Company, Houston, Texas.
Krisher, A.S. August 28, 1978. Raw Water Treatment in the CPI. Chemical
Engineering. 85(19):78-98.
LouckSj R.A. November 1979. Occidental Vertical Modified In Situ Process
for the Recovery of Oil from Oil Shale: Phase I, Final Report, Parts 1
and 2 for U.S. Department of Energy. \
Mai Ion, R.G. January 1980. Preparation and Injection of Grout from Spent
Shale for Stabilization of Abandoned In Situ Oil Shale Retbrts. Third
Annual Oil Shale Conversion Symposium, Denver, Colorado.
Marnell, P. September 1976. Lurgi/Ruhrgas Shale Oil Process,> Hydrocarbon
Processing. 55(9):269-271.
McWhorter, D.B. 1980. Reconnaissance Study of Leachate Quality from Raw
Mined Oil Shale—Laboratory Columns. EPA-600/7-80-181. U;S. Environ-
mental Protection Agency.
Mercer, B.W., A.C. Campbell and W. Wakayima. May 1979. Evaluation of Land
Disposal and Underground Injection of Shale Oil Wastewaters. U.S.
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