-------
Table VII-5
CAPITAL INVESTMENT FOR 800-MW COAL-FIRED POWER PLANT WITH FGD
Investment
Plant Section ($ Million) Percent
Steam generators 133 27
Turbine generators and
associated equipment 86 18
Coal handling equipment 7 1
Stack 5 1
Other mechanical equipment, heating, etc. 12 2
Piping 49 10
Controls and instrumentation 12 2
Electrical equipment 12 2
Electrical bulk materials 38_ _8_
Subtotal Power Facilities 354 71
Electrostatic precipitator and ash handing 66 14
FGD system 72 15
Subtotal 492 100
Engineering and home office service,
including fees 54
Total Plant Facilities Investment 546
Land 5
Interest during construction 90
Organization and start-up expenses 27
Working capital 6_
Total Capital Investment 674
VII-11
-------
Table VII-6
OPERATING COSTS AND REVENUE REQUIREMENTS
FOR 800-MW COAL-FIRED POWER PLANT WITH FGD (35% LOAD FACTOR)
$ Million/Year
Operating Cost
Raw materials
Coal at $12.30/tonne
($11.20/ton) delivered 16
Lime at $39/tonne
($35/ton) 1
Maintenance materials __4
Total Raw Materials 21
Sludge disposal at $10/tonne
($97ton) 2
Labor
Operating and supervision 2
Maintenance 4
Administrative, support, and burden 4
Total Labor 10
a
Fixed costs
Administrative expense 6
Property taxes and insurance 7
Depreciation _H
Total Fixed Costs 24
Mills/kWh
6.5
0.4
1.6
8.5
0.8
0.8
1.6
1.6
4.0
2.4
2.9
4.5
9.8
Total Annual Operating Costs
57
23.1
Return on rate base and income tax"
30
12.2
Revenue Required for Electricity at Busbar
87
35.3
Assumes plant is 50% depreciated after 15 years of base-load
operation, and is then reassigned to intermediate load service.
VII-12
-------
The cost of electricity shown here is based on current construction
costs and a capacity factor (35%) typical of a cycling plant. In addi-
tion, the initial capital cost of the plant is assumed to be 50%
depreciated after 15 years of baseload service before reassigning the
plant to intermediate load service in the 1990s. The remaining
investment value of the plant is then depreciated over 30 years of
intermediate load service, and the yearly capital recovery factor is
reduced by one-half to reflect the reduced rate base. Therefore, the
capital recovery cost per unit of electricity will not change compared
to that for a baseload plant, since the annual capital recovery charges
and the load factor have both been reduced by a factor of two.
Figure VII-2 shows the sensitivity of the cost of electricity to
the delivered cost of coal and the capital cost of the plant.
D. Coal Gasification Plant
Table VII-7 shows the investment cost for each section of the SNG
ft ^ fi
manufacturing process for a plant making 7.8 x 10 nm (275 x 10 scf)
per day of SNG. Less than half of the required investment is for main
process plants; the majority (58%) of the investment is for support
facilities.
Operating costs and revenue required for the Hygas installation are
shown on Table VII-8. With a regulated utility rate basis, SNG is esti-
mated to be produced at a cost of $2.90 per GJ ($3.06 per million Btu).
Only ammonia is assumed to have a by-product value. If a large western
coal gasification industry were to develop, the remotely located by-
product sulfur is not expected to have a large market. Figure VII-3
shows the SNG price sensitivity to changes in coal price and in the
capital requirements of the process plants.
E. Coal Liquefaction Plant
Table VII-9 shows the details of the estimated capital investment
o
cost for an H-Coal plant producing 7,950 m per day (50,000 barrels
VII-13
-------
I
H-
•c-
I
0
UJ
fe
o
u
60
50
40
M 30
20
10 —
DELIVERED COAL COST - dollar per ton
10
15
10
DELIVERED COAL COST - dollar per tonne
I I
15
20
50
75 100 125
PLANT CAPITAL COST - percent of base case
150
175
FIGURE VII-2. SENSITIVITY OF THE COST OF ELECTRICITY TO PLANT CAPITAL
COST AND DELIVERED COAL COST
-------
Table VII-7
INVESTMENT REQUIRED FOR A 7.8 x 106 nm3 (275 x 106 scf)
PER DAY SNG PLANT BASED ON THE HYGAS PROCESS
Plant Section
Coal storage & reclaiming
Coal grinding
Coal slurry pumping
Gasification
Raw gas quench
Shift
Acid gas scrubbing
Methanation
Water reclamation
Sulfur recovery
Solids disposal
SNG drying
Steam & utilities
Water systems
Oxygen plant
General facilities
Contractor fees
Initial catalyst and chemicals
Investment
($ Million)
14
18
27
47
20
33
113
30
61
63
9
1
143
18
47
71
79
9
Percent
2
2
3
6
2
4
14
4
8
8
1
-
18
2
6
9
10
1
Total Plant Facilities Investment
803
100
Land
Interest during construction
Paid-up royalties
Working capital
Start-up costs
2
132
2
13
40
Total Capital Investment
992
VII-15
-------
Table VII-8
OPERATING COSTS AND REVENUE REQUIREMENTS FOR A 7.8 x 106 nm3
(275 x 10& scf) PER DAY SNG PLANT BASED ON THE HYGAS PROCESS
Operating Costs
Raw materials
Cents/GJ
$ Million/Year (Cents/10 Btu)
Coal at $6.69/tonne ($6.08/ton)
Water
Catalyst and chemicals
Maintenance materials
Total Raw Materials
38
1
4
16
64
44 (47)
1 (1)
5 (5)
19 (20)
69 (73)
Labor (including payroll burden)
Operating & supervision
Maintenance
Administrative and support
Total Labor
Fixed costs
Administrative expense
Property tax & insurance
Depreciation
Total Fixed Costs
Total Annual Operating Cost
Return on rate base & income tax3
Total Revenue Required
Sources of Revenue
SNG
By-product ammonia at $165/tonne
($150/ton)
3
16
4
4 (4)
18 (19)
5 (5)
23
255
256
4
255
27 (28)
16
20
49
85
167
88
19 (20)
23 (24)
56 (59)
98 (103)
194 (204)
101 (107)
295 (311)
290 (306)
_5 (51
295 (311)
20-year average values.
VII-16
-------
M
4.0
3.5
t 3.0
to
1
I
e>
CO
u. 2.5
O
LU
CO
5 2.0
UJ
CO
CO
1.5
1.0
50
I
COAL COST — dollar per ton
6 8
10
12
I
I
6810
COAL COST — dollar per tonne
I
I
12
75 100 125
PLANT CAPITAL COST - percent of base case
150
14
175
14
4.0
3.5
3
o
3.0 §
.o -a
I
O
z
CO
u.
O
2.0 ,_
CO
O
O
1.5
FIGURE VII-3. SENSITIVITY OF THE COST OF SNG TO PLANT CAPITAL COST AND COAL COST
-------
Table VII-9
CAPITAL INVESTMENT FOR A 7,950 m3 (50,000 bbl) PER DAY PLANT
PRODUCING DISTILLATE FUEL OIL FROM COAL BY THE H-COAL PROCESS
Investment
Plant Section ($ Million) Percent
Coal storage, handling, and preparation 45 5
Slurry preparation 17 2
Hydrogenation section 130 14
Product separation and fractionation 40 4
Steam reforming hydrogen 23 3
Partial oxidation hydrogen 170 19
Oxygen 50 5
Sulfur and ammonia recovery 85 9
Utilities and steam 180 20
General facilities 80 9
Contractor fees 9J) 10
Total Plant Facilities Investment 910 100
Land 2
Interest during construction 149
Paid-up royalties 2
Working capital 16
Start-up costs 46
Total Capital Investment 1,125
VII-18
-------
Table VII-10
CAPITAL INVESTMENT FOR A 7,630 m3 (48,000 bbl) PER DAY PLANT
PRODUCING NAPHTHA AND FUEL OIL FROM COAL BY THE H-COAL PROCESS
Investment
Plant Section ($ Million) Percent
Coal storage, handling, and preparation 45 5
Slurry preparation 17 2
Hydrogenation section 130 13
Product separation and fractionation 40 4
Steam reforming hydrogen 23 2
Partial oxidation hydrogen3 180 19
Oxygena 54 5
Sulfur and ammonia recovery3 87 9
Utilities3 190 20
General facilities3 84 9
Naphtha hydrotreater3 18 2
Contractor fees 95 10
Total Plant Facilities Investment 963 100
Land 2
Interest during construction 158
Paid-up royalties 2
Working capital 17
Start-up costs 48
Total Capital Investment 1,190
3Plant sections changed due to addition of naphtha hydrotreater.
VII-19
-------
per day) of distillate fuel oil. Table VII-10 gives the cost of the
same plant with the additional facilities necessary to hydrotreat the
naphtha portion of the product so that it is suitable for steam
reforming. The remainder of the distillate product (200-495°C or
400-925°F) is assumed to be sold as fuel oil. The added cost of
hydrotreating the naphtha includes the expanded oxygen plant, partial
oxidation gasifier, sulfur and ammonia recovery, and utilities, as well
as the cost of the hydrotreating plant. These new and expanded plant
sections add $65 million, or about 5.8%, to the base liquefaction plant
capital investment.
Tables VII-11 and VII-12 give the operating costs and revenue
requirements for fuel oil production without and including the naphtha
hydrotreating step. When producing only fuel oil the required revenue
is $3.02 per GJ ($3.19 per million Btu). If the naphtha is to be hydro-
treated for steam reforming, the non-naphtha distillate is assumed to be
sold as a by-product at $2.84 per GJ ($3.00 per million Btu). The cost
of hydrotreated naphtha is then $3.77 per GJ ($3.97 per million Btu).
Figure VII-4 shows the sensitivity of distillate fuel oil cost to
the cost of feed coal and to the capital cost of the process plant.
Figure VII-5 shows the sensitivity of hydrotreated naphtha to the cost
of feed coal and to the credit allowed for by-product fuel oil.
F. Gas Pipeline
The estimated investment required for an 81-cm (32-in.) gas pipe-
line is shown in Table VII-13. Cost for physical equipment and instal-
lation is $480 million, and total capital investment including equip-
ment, land, interest during construction, and working capital is
$548 million. Investment costs vary widely depending on construction
difficulty. The midwestern location for the pipeline in this study
should allow relatively easy construction because the route should not
pass through urban areas, mountainous areas, or very rocky soil. Table
VII-14 gives the operating costs and revenue required for the SNG
VII-20
-------
Table VII-11
OPERATING COSTS AND REVENUE REQUIREMENTS FOR A 7,950 m3
(50,000 bbl) PER DAY PLANT PRODUCING DISTILLATE FUEL OIL
FROM COAL BY THE H-COAL PROCESS
Operating Costs
Raw materials
Cents/GJ
$ Million/Year (Cents/10 Btu)
Coal at $6.69/tonne
Water
Catalyst and chemicals
Maintenance materials
Total Raw Materials
Labor (including payroll burden)
Operating & supervision
Maintenance
Administrative and support
Total Labor
Fixed costs
Administrative expense
Property tax and insurance
Depreciation
Total Fixed Costs
Total Annual Operating Cost
f%
Return on rate base and income tax
Total Revenue Required
Sources of Revenue
Distillate fuel oil
By-product ammonia at $165/tonne
20-year average values.
49
3
10
18
80
28
304
298
6
304
50 (53)
3 (3)
10 (11)
18 (19)
81 (86)
5
18
5
5 (5)
19 (20)
5 (5)
29 (30)
18
23
55
96
204
100
19 (20)
23 (24)
56 (59)
98 (103)
208 (219)
101 (107)
309 (326)
302 (319)
__7 (71
309 (326)
VII-21
-------
Table VII-12
OPERATING COSTS AND REVENUE REQUIREMENTS FOR A
7,630 m3 (48,000 bbl) PER DAY PLANT PRODUCING
NAPHTHA AND FUEL OIL FROM COAL BY THE H-COAL PROCESS
Operating Costs
Raw Materials
Cents/GJ
$ Million/Year (Cents/10 Btu)
Coal at $6.69/tonne
Water
Catalyst and chemicals
Maintenance materials
Total Raw Materials
Labor (including payroll burden)
Operating & supervision
Maintenance
Administrative and support
Total Labor
Fixed Costs
Administrative expense
Property tax and insurance
Depreciation
Total Fixed Costs
Total Annual Operating Cost
Return on rate base and income tax
Total Revenue Required
Sources of Revenue •
Hydrotreated naphtha at $3.77/GJ
($3.97/106 Btu)
By-product fuel oil at $2.84 GJ
($3.00/106 Btu)
By-product ammonia at $165/tonne
20-year average values.
49
3
12
Jl
83
29
166
147
7
320
51 (54)
3 (3)
12 (13)
20 (21)
"86
5
19
5
5 (5)
20 (21)
5 (5)
30 ( 31)
19
24
59
102
214
106
320
20
25
62
107
224
111
335
(21)
(27)
(65)
(113)
(237)
(117)
(354)
174 (184)
153 (162)
8 (8)
335 (354)
VII-22
-------
N>
UJ
D
CO
a
u.
o
fc
o
u
4.0
3.5
2.5
2.0
1.5
50
COAL COST - dollar per ton
6 8
10
12
I
I
14
6 8 10
COAL COST — dollar per tonne
I I
12
75 100 125 150
PLANT CAPITAL COST - percent of base case
14
4.0
3.5
£
c
o
3.0
a.
a
m
2.52
CO
2.0 a
fe
8
1.5
FIGURE VII-4. SENSITIVITY OF THE COST OF DISTILLATE FUEL OIL TO
PLANT CAPITAL COST AND COAL COST
-------
5.5
5.0
4.5
% 4.0
I
I
Q
UJ
3.5
CC
O
3.0
2.5
o
fc
o
o
2.0
1.5
1.0
I
2.0
COAL COST - dollar per ton
6810
12
I
I
I
I
2.5
I
6810
COAL COST - dollar per tonne
3.0
I
12
14
14
5.5
5.0 =
m
o
•D
4.0 |
I
Q_
•J C
3.5
Q
UJ
!c
3.0
DC
Q
2.5
2.0
1.5
3.5 dollar per million Btu
I
I I I
2.5 3.0 3.5
BYPRODUCT FUEL OIL CREDIT- dollar per GJ
FIGURE VII-5. SENSITIVITY OF THE COST OF HYDROTREATED NAPHTHA TO
PLANT CAPITAL COST AND BYPRODUCT FUEL OIL CREDIT
VII-24
-------
Table VII-13
CAPITAL INVESTMENT FOR A 81-cm (32-in.) DIAMETER GAS
TRANSMISSION PIPELINE — 1,300 km (800 mi)
Investment
Cost Component ($ Million) Percent
Line pipe 151 32
Pipe coatings 9.9 2
Valves 7.4 2
River and road crossings 0.2
Cathodic protection 0.2 —
11 compressor stations 107 22
Miscellaneous 9.2 2
Communications and metering 3.5 ^
Subtotal for Materials 296 62
Pipeline construction 116 24
Compressor station construction 27.2 6
Engineering design 37.3 8
Survey and mapping 2.5 1^
Subtotal for Services 183 38
Total for Construction of Pipeline 480 100
Land (right of way) and damages 6.4
Interest during construction 54.8
Working capital 7.5
Total Capital Investment 548
VII-25
-------
Table VII-14
OPERATING COSTS AND REVENUE REQUIREMENTS FOR AN 81-cm (32-in.)
DIAMETER GAS PIPELINE — 1,300 km (800 mi)
Operating Costs
Raw materials
Cents/GJa
$ Million/Year (Cents/10 Btu)
SNG fuel at $2.90/GJ
($3.06/million Btu)
Maintenance materials
Total Raw Materials
Labor (including payroll burden)
Operating and supervision
Maintenance
Administrative and support
Total Labor
Fixed costs
Administrative expense
Property tax and insurance
Depreciation
Total Fixed Costs
Total Annual Operating Costs
Return on rate base and income tax
Total Revenue Required
Source of Revenue
Delivered SNG
62
_4
66
10
12
17
39
110
48
158
158
26 (27)
_1 OJ
27 (28)
2
2
1
5
1
1
1
2
(1)
(1)
—
(2)
4 (4)
5 (5)
_2 O)
16 (17)
45 (47)
19 (20)
64 (68)
64 (68)
Totals may not equal sum of numbers in column because of rounding
errors.
VII-26
-------
pipeline. The $0.64 per GJ ($0.68 per million Btu) required revenue
assumes:
o Utility financing.
o $2.90 per GJ ($3.06 per million Btu) price for SNG at the
gasification plant.
o Thirty-year project and tax lives.
Figure VII-6 shows the sensitivity of required revenue to the
parameters of SNG price and pipeline capital cost.
Figure. VII-7 shows the sensitivity of gas transmission cost to
economies of scale. The costs for the 81-cm (32-in.) diameter pipeline
chosen as an example in this report could be significantly changed if a
different diameter pipeline were used. Moreover, existing pipelines
that are fully depreciated could offer transportation service at consid-
erably reduced prices. As shown on Table VII-14, the cost of delivering
SNG in a newly capitalized pipeline is $0.64 per GJ, but an older system
with no capital charges or income tax would have a cost of $0.36 per GJ.
If an existing system were also of larger diameter (say 122 cm), the de-
livered cost would drop to about $0.26 per GJ.
G. Liquids Pipeline
o
The 15,900 m (200,000 barrel) per day liquid pipeline is smaller
in diameter (51 cm) than the SNG pipeline (81 cm), so that the liquid
pipeline is less expensive than the SNG line. In addition, the liquid
pipeline uses pumping stations rather than more expensive compressor
stations. Estimated investment costs for the liquid pipelines are shown
in Table VII-15. Total capital investment is $309 million for a
1,300-km (800 mi) pipeline.
Table VII-16 shows the operating cost and revenue requirements for
fuel oil pipeline shipments. A cost is included for diesel oil to fuel
VII-27
-------
1.2
1.0
SNG COST - dollar per 106 Btu
2.0 3.0 4.0 5.0 6.0
7.0
T
1 r
1.2
1.0
13
&
,. 0.8
_n
1
I
0.6
cc 0.4
eo
BASE CASE
1.0
10
o
0.8
CO
O
0.6
CO
CO
CO
0.4 <
I-
CO
0.2
0.2
0.0
I
0.0
1.0
2.0 3.0 4.0 5.0
SNG COST - dollar per GJ
6.0 7.0
50
75 100 125
PIPELINE CAPITAL COST - percent of base case
150
FIGURE VII-6. SENSITIVITY OF SNG TRANSMISSION COST TO
PIPELINE CAPITAL COST AND SNG COST
VII-28
-------
4.0
8 12 16 20
I I
PIPELINE DIAMETER - in.
24 28 32 36
40 44 48
1 T
3.5
3.0
o
Z 2.5
O
E 2.0
tn
<
a
UJ
< 1.B
UJ
1.0
BASE CASE
0.5
I
I
20
40
60 80
PIPELINE DIAMETER - cm
100
120
FIGURE VII-7. EFFECT OF PIPE DIAMETER ON SNG TRANSMISSION COSTS
(1300 km Distance)
VII-29
-------
Table VII-15
CAPITAL INVESTMENT FOR A 51-cm (20-in.) DIAMETER
COAL LIQUIDS PIPELINE — 1,300 km (800 mi)
Cost Component
Line pipe
Pipe coating
Valves
Cathodic protection
Miscellaneous
Communication and metering
Subtotal for Materials
Pipline construction
10 pump stations construction
Engineering
Survey and mapping
Subtotal for Services
Total for Construction
of Pipeline
Land (right of way) and damages
Interest during construction
Working capital
Total Capital Investment
Investment
($ Million)
80.4
5.7
2.4
0.2
7.5
5.4
102
98.0
22.4
22.2
2.4
145
247
4.0
25.3
33.1
309
Percent
33
2
1
—
3
2
41
40
9
9
1
59
100
VII-30
-------
Table VII-16
OPERATING COSTS AND REVENUE REQUIREMENTS FOR A
51-cm (20-in.) DIAMETER LIQUIDS PIPELINE -- 1,300 km (800 mi)
Cents/GJ
$ Million/Year (Cents/106 Btu)
Operating Costs
Raw materials
Diesel fuel for pumps 6.9
Maintenance materials 0.2
Total Raw Materials 7.1
Labor (including payroll burden)
Operating and supervision 1.6
Maintenance 2.0
Administrative and support 0.7
Total Labor 4.3
Fixed costs
Administrative expense
Property tax and insurance
Depreciation
Total Fixed Costs
Total Annual Operating Costs 31.6
Return on rate base and income tax
Total Revenue Required 62.5
Source of Revenue
2 (2)
2 (2)
0.5 (0.5)
1 (1)
4.9
6.2
9.1
20.2
31.6
30.9
1
1.5
2
5
8
8
(1)
(1.5)
(2)
(5)
(8)
(8)
Fuel Oil
62.5
15 (16)
15 (16)
VII-31
-------
the pump drivers that must be purchased from a source external to the
pipeline operation. The total cost of shipping coal-derived distillate
fuel oil is $0.15 per GJ ($0.16 per million Btu).
When coal-derived naphtha and fuel oil are sent through the same
pipeline, the shipping costs change slightly because of the difference
in heating value between the two products. The cost of shipping naphtha
is $0.16 per GJ ($0.17 per million Btu), while that of the fuel oil is
$0.14 per GJ ($0.15 per million Btu).
As in the SNG pipeline case, a larger diameter liquid pipeline
would lower the naphtha and fuel oil shipping cost on a heating value
basis. Figure VII-8 shows the sensitivity of fuel oil shipment cost to
the capital cost of the pipeline.
H. Liquid Fuel Distribution
Important factors that determine the cost of transporting distil-
late fuel by train are shipping distance, car size, number of cars per
train, terrain, train speed, and loading and unloading times. Represen-
tative costs of transporting fuel by unit train are shown in Figure
VII-9. These costs are based on 37,850-liter (10,000-gallon) tank cars,
100 cars per train, and 56 km-per-hour (35 mph) average train speed.
Costs include standing time for loading and unloading and empty back-
haul. The annual capital charges are assumed to be 20% of the invest-
ment. The resulting capital charges account for 15% of the shipping
cost, with operating and maintenance costs making up the remaining 85%.
Costs of trucking naphtha are shown in Figure VII-10. A
34,000-liter (9,000-gallon) truck, operating at an average road speed of
64 km per hour (40 mi per hour), with a one-stop delivery and empty
backhaul, is assumed. Capital charges account for 40% of the trucking
cost based on a 30% annual charge rate, and operating and maintenance
costs make up the remaining 60% of trucking costs. Trucks with smaller
VII-32
-------
0.30
0.30
0.25
o 0.20
8
I °-15
w
CO
X
HI
0.10
O
o
BASE CASE
0.25
0.20
3
4->
CO
fc
a
O
O
0.15 55
CO
CO
0.05
0.10
0.05
cc
O
I
I
50
75 100 125
PIPELINE CAPITAL COST - percent of base case
150
FIGURE VII-8. SENSITIVITY OF LIQUID FUEL TRANSMISSION
COST TO PIPELINE CAPITAL COST
VII-33
-------
0.8
200
DELIVERY DISTANCE - miles
400 600
800
3
I
k_
JO
1
I
oc
2
en
<
tr.
<
cc
0.4
0.2
I
I
0.8
1
0.6 I
£
u
JO
o
0.4
0.2
£
8
o
a.
cc
200
400
600
800
1000 1200
1400
1600
DELIVERY DISTANCE - km
FIGURE VII-9. RAILROAD TANK CAR TRANSPORT COSTS (Fuel Oil)
VII-34
-------
capacity, lower operating speed, and making more deliveries will have
higher trucking costs than those indicated in Figure VII-10.
To estimate the cost of distributing distillate fuel via train to a
centralized combined-cycle power plant and of distributing naphtha to
dispersed 26-MW fuel-cell power plants requires that assumptions be made
about the relative distances of these facilities from the pipeline ter-
minus. A reasonable assumption is that the pipeline terminates near any
of the three cities under consideration — Omaha, Des Moines, or Kansas
City. Because fuel-cell power plants would be located near load
centers, the distribution of naphtha by truck would involve relatively
short distances. If an average distance of 40 km (25 mi) is assumed,
the cost of distributing naphtha would be about $0.07 per GJ ($0.07 per
million Btu). To this distribution cost must be added the cost of
storing the naphtha at the bulk storage terminal prior to delivery.
This cost has been estimated to be about $0.01 per GJ ($0.01 per million
Btu). Thus, the total storage and delivery cost of naphtha is about
$0.08 per GJ ($0.08 per million Btu).
If the combined-cycle power plant is assumed to be centrally
located with respect to the three cities, a distance from the bulk
terminal to the plant of about 160 km (100 mi) would be reasonable. The
total cost of shipping distillate fuel via railroad tank cars (including
storage costs) would then be approximately $0.12 per GJ ($0.12 per
million Btu).
Because of the low cost of shipping liquid fuels compared to their
production costs, it is clear that large changes in the assumed shipping
distances will not significantly affect the delivered cost of these
fuels.
I. Gas Distribution
The costs of distributing natural gas from large interstate pipe-
lines to individual customers vary widely around the country. A number
VII-35
-------
I
U>
0.4
0.3
I
[2 0.2
8
o
o
oc 0.1
25
50
DELIVERY DISTANCE - miles
50 75 100
I
100 150
DELIVERY DISTANCE - km
125
200
150
T
0.4
0.3
TJ
0.2 £
o
0.1 {£
250
FIGURE VII-10. TANK TRUCK TRANSPORTATION COSTS (Naphtha)
-------
of key variables, including density of the distribution network and age
of equipment, are important in determining these costs. Because of the
many possible variables, it is more appropriate to use actual costs of
gas distribution rather than to attempt to derive such costs from esti-
mates of capital and operating costs.
Historically, the cost of transmitting and distributing natural gas
has been a large fraction of the total cost of gas paid by residential
customers. From 1971 to 1975 the average wellhead price of natural gas
3
increased from 0.643 to 1.57 cents per nm (18.2 to 44.5 cents per
o
1,000 scf). During the same period the average residential price
3
increased from 4.06 to 6.11 cents per nm ($1.15 to $1.73 per
o
1,000 scf). The difference between the wellhead and selling price is
the cost of gas transmission and distribution; it increased from
3.43 to 4.52 cents per nm3 ($0.97 to $1.28 per 1,000 scf). Thus, gas
transmission and distribution costs are large and have been increasing,
although not nearly so rapidly as wellhead gas prices.
The cost of distributing gas, as opposed to the total cost of
transmission and distribution, can be derived from data given in the
2
American Gas Association publication, Gas Facts. The distribution
costs can be approximated as the difference between the price of gas
paid by local gas utilities to pipeline companies (gas sold for resale)
and the price by residential, commercial, or industrial customers. To
determine costs specific to the region of interest, we used data from
the West North Central states, which encompass Omaha, Des Moines, and
Kansas City.
In 1975 the average price paid for natural gas by gas utilities was
$0.66 per GJ ($0.70 per million Btu). The average prices paid by resi-
dential and commercial customers were $1.30 and $1.04 per GJ ($1.37 and
$1.10 per million Btu), respectively. Therefore, the cost of distribu-
ting gas to residential and commercial customers may be estimated at
$0.54 and $0.38 per GJ ($0.57 and $0.40 per million Btu). Assuming that
distribution costs increased at about the same rate from 1975 to 1977 as
VII-37
-------
they did from 1971 to 1975 (about 7% per year), the 1977 cost of dis-
tributing natural gas in the West North Central states would be $0.62
per GJ ($0.65 per million Btu) for residential customers and $0.44 per
GJ ($0.46 per million Btu) for commercial customers.
In subsequent cost calculations the cost of distributing natural
gas to dispersed 26-MW fuel-cell power plants will be assumed to corre-
spond most nearly to that of distributing gas to large commercial
customers.
J. Combined-Cycle Power Plants
The capital investment required for a 270-MW combined-cycle power
plant is shown in Table VII-17. The total capital cost of $86.1 million
represents an investment of $319 per kW of installed capacity. This
total includes the cost of fuel treatment for the coal derived distil-
late fuel oil and of advanced gas turbines.
The cost of generating electricity in intermediate load operation
(35% capacity factor) is shown in Table VII-18, based on a delivered
cost of H-Coal distillate of $3.29 per GJ ($3.47 per million Btu). The
high cost of this fuel results in fuel-related costs of nearly half the
cost of generating electricity. The total cost of electricity from the
combined-cycle plant is 46.9 mills per kWh.
Figure VII-11 displays the sensitivity of the cost of electricity
to the cost of distillate fuel and the plant capital investment.
K. 26-MW Fuel-Cell Power Plant (SNG)
Manufacturing costs for the molten carbonate fuel-cell power plant
were estimated using the bases discussed below. These bases apply to
both the System 2 and System 3 dispersed site power plants. The
VII-38
-------
Table VII-17
CAPITAL INVESTMENT FOR A 270-MW COMBINED-CYCLE POWER PLANT
USING DISTILLATE FUEL FROM THE H-COAL PROCESS
Investment
Plant Section ($ Million) Percent
Fuel preparation 2.4 3
Gas turbine-generator sets 20.0 27
Waste heat boilers 4.7 6
Steam turbine-generator set 15.0 20
Process mechanical equipment 5.9 8
Electrical equipment 6.5 9
Civil and structural 5.8 8
Piping and instrumentation 4.2 6
Engineering & home office services 6.8 9
Miscellaneous 3.1 4
Total Plant Facilities Investment 74.4 100
Land 0.3
Interest during construction 6.0
Organization and start-up expenses 3.9
Working capital 1.5
Total Capital Investment 86.1
VII-39
-------
Table VII-18
OPERATING COSTS AND REVENUE REQUIREMENTS FOR A
270-MW COMBINED-CYCLE POWER PLANT USING DISTILLATE
FUEL FROM COAL (35% LOAD FACTOR)
Operating Costs $ Million/Year Mills/kWh
Raw materials
H-Coal distillate @ $3.29 per GJ
($3.47 per million Btu)
delivered 19.6 24.2
Water 0.1 0.1
Maintenance materials 1.2 1.4
Labor
Operating and supervision 0.6 0.7
Maintenance 1.7 2.1
Administrative and support 0.5 0.6
Fixed costs
General administrative expenses 1.5 1.8
Property taxes and insurance 1.9 2.3
Depreciation 4.2 5.1
Return on rate base and income tax 7.5 9.1
Total Revenue Required 38.8 46.9
Source of Revenue
Electric Power 38.8 46.9
VII-40
-------
80
1.0
DISTILLATE FUEL COST - dollars per 106 Btu
2.0 3.0 4.0 5.0
6.0
7.0
T
T
T
70
60
1
fc 50
a
I
0 40
£
uj
LU
li.
° 30
20
10
I
I
1.0
2.0 3.0 4.0 5.0
DISTILLATE FUEL COST - dollars per GJ
I
I
6.0
7.0
50
75 100 125
POWER PLANT CAPITAL COST - percent of base case
150
FIGURE VII-11. SENSITIVITY OF COST OF ELECTRICITY TO POWER PLANT
CAPITAL COST AND DISTILLATE FUEL COST
VII-41
-------
following system components are included: fuel-cell trailer; reformer
module; equipment module; condenser (E-7); and power conditioner. Those
modular assemblies are designed to be transported to the plant site,
installed on concrete pads, and interconnected with preassembled sec-
tions of piping and ductwork.
1. Fuel-Cell Trailer Cost
The shippable fuel-cell trailer, rated at 3.34 MW, contains
eight stacks. Fabricated from structural steel, it is enclosed by
corrugated steel panels. The stack cost estimates are based on the
molten carbonate fuel-cell design described by UTC in the EGAS pro-
3
gram. Supplementary information was obtained from recent ERG
reports. The estimates were based on calculations of actual quan-
tities of raw materials used to fabricate the components. Current cost
of raw materials, in the form expected to be used, were obtained from
vendor contacts. Fabrication costs were then determined by multi-
plying the material cost by a manufacturing cost factor, which was
selected based on the production rate and the degree of automation
envisioned for the manufacturing facility. The factors reflect manu-
facturing value added, including direct and supervisory labor plus other
manufacturing burdens (e.g., maintenance and inventory costs).
The accuracy of this type of estimate mainly depends on the
assumptions made concerning the design configuration, such as material
thickness and the selection of the materials. The application of
incorrect manufacturing cost factors presents a lesser risk because they
tend to fall within a fairly predictable range for all manufacturing
facilities operating at high production rates. It can safely be assumed
that profitable businesses will employ the most advanced methods in
order to remain competitive.
The fuel-cell stack components and vendor quotes for materials
costs are listed in Table VII-19. The estimated cost of an individual
VII-42
-------
80
DISTILLATE FUEL COST - dollars per 106 Btu
1.0 2.0 3.0 4.0 5.0 6.0 7.0
~l I 1 1 1 1 T
70
60
I
E
I
ID
111
i
50
40
30
20
10
I
1.0
2.0 3.0 4.0 5.0
DISTILLATE FUEL COST - dollars per GJ
I
I
6.0
7.0
50
75 100 125
POWER PLANT CAPITAL COST - percent of base case
150
FIGURE VII-11. SENSITIVITY OF COST OF ELECTRICITY TO POWER PLANT
CAPITAL COST AND DISTILLATE FUEL COST
VII-41
-------
following system components are included: fuel-cell trailer; reformer
module; equipment module; condenser (E-7); and power conditioner. Those
modular assemblies are designed to be transported to the plant site,
installed on concrete pads, and interconnected with preassembled sec-
tions of piping and ductwork.
1. Fuel-Cell Trailer Cost
The shippable fuel-cell trailer, rated at 3.34 MW, contains
eight stacks. Fabricated from structural steel, it is enclosed by
corrugated steel panels. The stack cost estimates are based on the
molten carbonate fuel-cell design described by UTC in the EGAS pro-
3
gram. Supplementary information was obtained from recent ERG
reports. The estimates were based on calculations of actual quan-
tities of raw materials used to fabricate the components. Current cost
of raw materials, in the form expected to be used, were obtained from
vendor contacts. Fabrication costs were then determined by multi-
plying the material cost by a manufacturing cost factor, which was
selected based on the production rate and the degree of automation
envisioned for the manufacturing facility. The factors reflect manu-
facturing value added, including direct and supervisory labor plus other
manufacturing burdens (e.g., maintenance and inventory costs).
The accuracy of this type of estimate mainly depends on the
assumptions made concerning the design configuration, such as material
thickness and the selection of the materials. The application of
incorrect manufacturing cost factors presents a lesser risk because they
tend to fall within a fairly predictable range for all manufacturing
facilities operating at high production rates. It can safely be assumed
that profitable businesses will employ the most advanced methods in
order to remain competitive.
The fuel-cell stack components and vendor quotes for materials
costs are listed in Table VII-19. The estimated cost of an individual
VII-42
-------
00
Component
Table VII-19
FUEL-CELL STACK COMPONENTS
Dimensions, cm (in) Materials Weight/cell, kg (lb) Cost, $/kg ($/lb)
Source
Electrolyte 100.3 x 100.3 x 0.089 40% Li A102 0.89
tile (39.5 x 39.5 x 0.035) 21* Li2C03 0.92
39% K2C03 0.86
Total Tile Weight: 2.62
Anode
Cathode
Cathode
collector
Anode
collector
Cell
separator
92.2 x 92.2 x 0.076 Ni Powder 2.51
(36.3 x 36.3 x 0.030)
(56% Porosity)
92.2 x 92.2 x 0.038 Ni Powder 1.26
(36.3 x 36.3 x 0.015
(56% Porosity)
100.3 x 100.3 x 0.152 304 SS 0.75
(39.5 x 36.3 x 0.060)
Stock Thk - 0.010
(0.004)
92.2 x 92.2 x 0.102 304 SS 0.69
(36.3 x 36.3 x 0.040)
Stock Thk - 0.010
(0.004)
100.3 x 100.3 x 0.102 304 SS 1.14
(39.5 x 39.5 x 0.040)
Total Cell Weight: 9.02
Stack end 120.6 x 120.6 x 7.6 430 SS
plates (47.5 x 47.5 x 3)
Stock Thk - 0.952
(0.375)
Tie rods (16) 1.9 (0.75) Diam. 430 SS
Springs (16) — 302 SS
Total Stack Weight:
(1.95)
(2.03
(1.90)
(5.88)
(5.53)
(2.77)
(1.64)
(1.51)
(2.51)
(19.84)
6.16
1.94
0.51
2.88
352 (775)/stack 1.78
81 (178)/stack 1.78
109 (240)/stack 2.16
5,141 (11,311)
(2.80)
(0.88)
(0.23)
Lithium Co.
(America)
(1.31) (Average)
5.94 (2.70) International
Nickel
5.94 (2.70) International
Nickel
4.27 (1.94) Rodney Metals
4.27 (1.94) Rodney Metals
4.27 (1.94) Rodney Metals
(0.81) U.S. Steel
(0.81) U.S. Steel
(0.98) U.S. Steel
-------
fuel-cell trailer is $359,000, as shown in Table VII-20. The piping,
wiring, enclosure, and assembly material cost was arbitrarily based on
an assumed structure weight of 3,270 kg (7,200 Ib), costed at $2.20/kg
($l/lb). The assigned cost factor of 3.0 reflects a less automated,
more labor-intensive, manufacturing operation.
Table VII-20 shows that the costliest items are the fuel-cell
components, which make up 87.5% of the total. To minimize labor costs,
the most advanced production machinery would have to be used. The
capital investment for this facility has not been estimated, but it
would probably be quite high.
Table VII-20
FUEL-CELL TRAILER COST SUMMARY
Total
Raw Material Mfg. Cost Mfg. Cost Costb
% Total
Componenta Cost, $1000
Electrolyte
tile
Anode
Cathode
Collectors
Separators
End plates
Tie rods
Springs
Miscellaneous0
Total
31.4
60.9
30.5
24.9
19.9
5.0
1.2
1.9
7.2
182.9
Factor
1.2
0.6
0.6
1.2
1.2
1.3
0.6
0.6
3.0
$1000
37.7
36.6
18.3
29.9
23.8
6.5
0.7
1.1
21.6
176.2
$1000
69.1
97.5
48.8
54.8
43.7
11.5
1.9
3.0
28.8
359.1
Trailer Cost
19.2
27.2
13.6
15.3
12.2
3.2
0.5
0.8
8.0
100
Eight stacks/trailer.
b
Total cost = raw material + manufacturing cost.
c
Piping, wiring, enclosure, and assembly.
VII-44
-------
Considerable manufacturing development effort will be required
for the electrolyte tile production facility. A major problem area will
be tile cracking, unless a flexible tile configuration can be developed.
Electrolyte tiles are currently manufactured in a noncontinuous process.
Lithium aluminate powder is mixed with finely ground lithium and potas-
sium carbonate. The mixture is then placed in a mold, compressed, and
fired in a furnace. Ultimately, a completely automated production
facility should be used, similar to those developed for electrode manu-
facture. At present, sintered nickel electrodes are manufactured
commercially in a continuous 30-cm (12-in.) wide strip using a slurry
method for applying the nickel powder to a nickel-plated steel sub-
strate. Material cost at present is 50% of the total manufactured
cost. The manufacturer hopes to increase this to 75% with improved
methods.
Fabrication of collectors and separators will be fairly
straightforward. The collectors can be formed in large stamping
presses, which would require some handling of individual pieces. A
continuous roll forming production line could be used, which could
result in a cost factor lower than the assumed 1.2. The separator,
however, is a more complex component and will always require more
labor. It consists of an outer frame containing metal seal surfaces and
fuel manifolding, welded to the cell separating sheet. This con-
figuration will require handling of more than one part and seam welding
to join the parts together.
The assumed thicknesses of the electrolyte tile (0.089 cm),
collectors (0.010 cm), and separators (0.010 cm) are reasonably opti-
mistic projections, based on the current status of molten carbonate
fuel-cell design. The latter are fabricated from 304 stainless steel.
If corrosion of the stainless steel parts requires that they be replaced
by nickel, their material cost will almost double. Using nickel should
not affect the manufacturing cost, however, and would only increase the
total cost by 14%.
VII-45
-------
A comparatively small portion of the total cost (12.5%) is for
the stack hardware, structures, and enclosure. The production rates of
these items are too low to justify highly sophisticated and automated
machinery — thus a higher manufacturing cost factor was used.
Developing the manufacturing technology for fabricating most
components should not be difficult. The exception to this may be the
manufacture of the electrolyte tile. A more flexible electrolyte
structure is needed and perhaps can be developed.
2. Reformer Module Cost
The cost of the reformer module was calculated from Exxon data
on cylindrical-type reformer furnaces. The total material and labor
costs were determined for the fabrication of a single unit. A direct
labor rate of $9/hr was assumed and a factory overhead rate of 200% was
used. A learning factor of 0.9 was then applied to the labor cost to
determine the average cost per unit for 400 modules. Eighty percent of
the cost of the reformer is for the reactor and heat exchanger tubing
and manifolding. Stainless steel is required throughout because of the
high operating temperature. The total cost of the reformer is $504,000,
of which 43% is the cost of the heat exchangers (E-l through E-4).
3. Equipment Module Cost
The equipment module cost was determined by calculating the
total F.O.B. cost of heat exchangers, blowers, electric motor drivers,
and other components based on Exxon cost data and discussion with
vendors. The cost breakdown is shown in Table VII-21. The use of
canal-type recuperators for exchangers E-5 and E-6 resulted in substan-
tial cost reduction.
VII-46
-------
Table VII-21
EQUIPMENT MODULE COST BREAKDOWN
Item Cost, $1000
Exchanger E-5 9.6
E-6 58.2
ZnO guard bed 3.0
Knockout drum 1.5
Blower B-l 12.3
B-3 44.9
B-4 20.6
B-5 21.0
P-l 2.5
Module fabrication 55.0
Total Equipment Module Cost 228.6
4. Condenser Cost
The condenser section, exchanger E-7, consists of two bays of
air-fin heat exchangers, 3.4 x 9.2 m (11 x 30 ft). Each bay has two
fans. The cost of these units ($15,000 per bay) was determined from
Exxon cost data. Each bay would be shipped to the power plant site and
erected on concrete piers.
5. Power Conditioning Costs
Projected costs of power conditioning equipment have been
reported by Westinghouse. They vary from $50 to $70/kW, depending on
the input DC voltage. An average cost of $60/kW was assumed for this
s tudy.
VII-47
-------
6. Total Power Plant
Total installed costs were estimated for the base case
System 2 power plant. Total manufactured costs were calculated by
summing the costs for each system component. Installation-related costs
were then estimated. Here, site preparation costs include grading and
installation of access roadways, but not the cost of land. No cost
allowance was made for buildings and similar facilities, because the
system is assumed to operate unattended.
Other indirect costs were estimated as 40% of total manufac-
tured cost and 25% of total installation costs. These indirect costs
reflect general and administrative expense, taxes and insurance,
interest on investment, sales and marketing expense, return on invest-
ment, and contingencies, if any. Architect and engineering charges are
not explicitly detailed. Also, escalation and interest charges during
construction were not included. Site preparation and installation time
for the modular power plant is assumed to be short.
A breakdown of the estimated power plant cost is given in
Table VII-22. Total installed cost for the base-case system is
$12,530,000, equivalent to $522/kW of net output (24.0 MW). This value
is higher than expected, but substantial investment cost reduction is
possible.
The ultimate optimization of any power plant is a complex
trade-off between investment charges and fuel charges, reflecting
constraints placed on the system. The power plant here has been
constrained to meet a heat rate of 7,910 kJ/kWh (7,500 Btu/kWh) and to
be water-conservative. If those constraints were relaxed, investment
costs and the cost of delivered energy could be reduced.
For example, in many locations, the amount of water necessary
for reforming is readily available from local supplies and total water
conservation would not be necessary. Water requirements are about
VII-48
-------
Table VII-22
NOMINAL 26-MW FUEL-CELL POWER PLANT COST ESTIMATE
Item
No. in
System
8
Fuel-cell trailer
Reformer/heat exchanger
package
Equipment module
Condenser (E-7)
Power conditioner and
switchgear 4
Electrical wiring, controls
and instrumentation
Total Manufactured Cost
Site preparation
Freight and insurance
Mechanical structures,
foundations and piping
Total Installation Costs
Other indirect costs + profit3
Total Power Plant Installed Cost
Unit
Cost,
$1000
359.1
402
Total
Cost,
$1000
2,873
4
4
4
504
228.6
60
2,016
914
240
1,608
534
8,185
481
82
294
857
3,488
12,530
Taken as 40% of total manufactured cost + 25% of total installation costs,
VII-49
-------
0.57 liter/kWh (0.15 gal/kWh). In the tricity study region, 1 kWh is
worth 30-50 mills. Water consumption would only add 0.07 mills/kWh, a
negligible amount. As a result, E-2, the knockout drum, blower B-2, and
the water recycle pump could be eliminated, and the size of E-5 could be
decreased. Fuel cell performance and the heat exchange characteristics
of exchanger E-5 would also be affected; thus, although it is not clear
exactly what the final cost of electricity will be, the investment cost
can be lowered.
As explained earlier, slightly higher heat rates are also
cost-effective. For example, the base-case design voltage was chosen as
0.8 V per cell. A decrease to 0.787 V per cell increases the current
density and reduces the number of fuel-cell modules by 19%. Further-
more, because more waste heat is available, the temperature-driving
forces in the reformer and heat exchangers E-l, E-2, E-3, and E-4 are
larger, so less heat transfer surface would be required. That would
noticeably reduce investment cost. The resulting increase in heat rate
would increase the fuel cost by only 1.6%.
The combined effect of relaxing the constraints will clearly
lower the optimum cost of electricity, primarily by lowering the invest-
ment cost. However, the exact calculation of that optimum would require
substantial additional effort, requiring analysis of several cases.
Molten carbonate fuel-cell technology is at an early stage of
development, but performance improvements and cost reductions can be
projected for most system components. These expected reductions will
result from current and future R&D programs and system optimization
studies. The impact of these potential improvements was assessed by
assuming the following:
o Improved fuel-cell designs, resulting in a 50% increase in
current density, hence power density, at the design cell
voltage.
o A 15% reduction in the quantity of materials used in stack
construction.
VII-50
-------
o Cost reductions for specific components, including:
Reformer/heat exchanger package 25%
Equipment module 15%
Condenser (E-7) 10%
Power conditioner 20%
Electrical wiring, etc. 15%
o A 15% reduction across-the-board in installation-related costs.
Simultaneous achievement of all cost reduction projections
would lower the installed cost of the System 2 power plant by 27% from
$522/kW to $380/kW. The optimistic projection is listed in Table
VII-23, along with the additional capital requirements for a completely
installed and operating plant.
Operating and maintenance (O&M) costs for operating the power
plant must also be estimated. Firm bases for such estimates are not
available. Periodic stack replacement costs could range from
0.2 to 0.4 cent/kWh, excluding replacement labor costs. This estimate
assumes 40,000 hr operating life at full-rated load (24.0 MW). Fuel
conversion catalyst replacement costs should be low. Equipment
maintenance and replacement costs should also be low, reflecting, say, a
20-year expected life. Thus, total O&M costs could be taken as
0.5 cents/kWh. Finally, local ordinances may require attended operation
of fuel-cell power plants.
The cost of producing electricity from the nominal 26-MW
fuel-cell power plant is shown in Table VII-24. The delivered cost of
SNG is based on the production, pipeline, and distribution costs
presented in previous sections. Capital-related charges are based on
the optimistic power plant costs given in Table VII-23. The O&M cost is
that discussed in the preceding paragraph.
VII-51
-------
Table VII-23
OPTIMISTIC COST PROJECTION FOR NOMINAL 26-MW FUEL-CELL POWER PLANT
Total
Cost,
Item $1000
Fuel-cell trailer 1,628
Reformer/heat exchanger
package 1,512
Equipment module 777
Condenser (E-7) 216
Power conditioner 1,286
Electrical wiring, controls,
and instrumentation 454
Total Manufactured Cost 5,873
Site preparation 409
Freight and insurance 59
Mechanical structures,
foundations, and piping 250
Total Installation Costs 718
Other indirect costs + profit 2,529
Total Power Plant Installed Cost 9,120
Land 20
Interest during construction 460
Working capital 240
Start-up costs 90
Total Capital Investment 9,930
VII-52
-------
Table VII-24
OPERATING COSTS AND REVENUE REQUIREMENTS
FOR A NOMINAL 26-MW FUEL-CELL POWER PLANT
Operating Costs
SNG fuel at $3.98/GJ
($4.20 per million Btu)
Operation and maintenance
Administrative expense
Property taxes and insurance
Depreciation
Total Annual Operating Costs
Return on rate base and income tax
Total Revenue Required
$Mi 11ion/Year
2.22
0.37
0.18
0.23
0.48
3.48
0.87
4.35
Mills/kWh
30.2
5.0
2.4
3.1
6.5
47.2
11.8
59.0
Sources of Revenue
Electric power
4.35
59.0
Figure VII-12 shows the sensitivity of the cost of electricity
to changes in fuel costs and power plant capital costs. Use of the
capital costs estimated in Table VII-22 would increase the cost of
electricity to 69.4 mills/kWh.
L. 26-MW Fuel-Cell Power Plant (Naphtha)
Investment cost estimates for the System 3 power plant were made
based on the detailed evaluation of System 2 component costs. Adjust-
ments were made to reflect differences in size and performance. A
breakdown of the reformer package cost is given in Table VII-25.
VII-53
-------
90
1.0
2.0
SNG COST - dollar per 106 Btu
3.0 4.0 5.0
6.0
7.0
80
70
E
I 60
>
o
cc
o
01
m 50
o
40
OPTIMISTIC CASE
30
20
_L
1.0
2.0 3.0 4.0
SNG COST - dollar per GJ
5.0
6.0
7.0
50
75 100 125
POWER PLANT CAPITAL COST - percent of optimistic case
150
FIGURE VII-12. SENSITIVITY OF THE COST OF ELECTRICITY TO POWER
PLANT CAPITAL COST AND SNG COST
VII-54
-------
Table VII-25
COST BREAKDOWN OF NAPHTHA REFORMER PACKAGE
Cost Item Total Manufactured Cost, $1000
Reformer tubes 135.0
Exchanger tubes
E-l 73.0
E-2 81.7
E-3 51.9
E-4 120.5
Tube manifolds 190.8
Catalyst 19.3
Burner 22.4
Structures 116.2
Total 806.2
The cost of the reformer package is high compared with reformer cost
estimates reported in the literature because it contains heat exchangers
E-l to E-4, which make up 57% of the total cost. The reformer portion
alone would cost about $35/kW for either System 2 or 3.
A summary of component costs for the equipment module is shown in
Table VII-26. The reduction in the size of heat exchanger E-6 accounts
for the lower cost of the equipment module, compared with System 2. The
cost for both systems was reduced by replacing the shell and tube heat
o
exchangers E-5 and E-6 by canal type units, which cost around $161/m
($15/ft2) compared to $592/m2 ($55/ft2) for the shell and tube
configuration.
A breakdown of the estimated plant cost is given in Table VII-27
(see Section VII-K for costing approach). Total installed cost for the
non-optimized base-case System 3 power plant is $13,740,000, equivalent
to $537/kW of net output (25.6 MW). This bottom-line cost is about the
VII-55
-------
Table VII-26
EQUIPMENT MODULE COST BREAKDOWN
Component Total Manufactured Cost, $1000
Exchanger
E-5 14.0
E-6 46.5
Blowers:
B-l 13.3
B-3 47.0
B-4 21.0
\
B-5 23.0
B-6 0.5
Shift reactor 2.0
Hydrodesulfurizer 2.0
ZnO bed 2.5
Pump: P-l 2.8
Knockout 1.7
Module fabrication 53.4
Total 229.7
VII-56
-------
Table VII-27
NOMINAL 26-MW FUEL-CELL POWER PLANT COST ESTIMATE
Item
No. in
System
8
Fuel-cell trailer
Reformer/heat exchanger
package
Condenser (E-7)
Equipment module
Power conditioner and
switchgear 4
Electrical wiring, controls
and instrumentation
Total Manufactured Cost
Site preparation
Freight and insurance
Mechanical structures,
foundations, and piping
Total Installation Costs
Other indirect costs + profit3
Total Power Plant Installed Cost
Unit
Cost,
$1000
284
75
Total
Cost,
$1000
2,296
4
4
4
806
75
230
3,225
300
920
1,710
560
9,011
505
90
308
903
3,830
13,740
Taken as 40% of total manufactured cost + 25% of total installation costs.
VII-57
-------
same as that estimated for the System 2 power plant. The reformer
package cost for the naphtha system is higher. However, this is
counter-balanced by a much lower fuel-cell trailer cost, resulting from
the selection of a lower design voltage that yields higher power density:
o System 2 (SNG): 0.8 V/cell @ 120 mA/cm2 =96.0 mW/cm2
o System 3 (Naphtha): 0.78 V/cell @ 165 mA/cm2 = 128.7
mW/cm2
As before, opportunities exist for major cost reduction in the
System 3 power plant. The impact of future improvements in cell design
and performance and systems concepts was assessed, using the projected
cost reduction factors presented in Section VII-K. Here, it was assumed
that improved cell design would result in an increase in power density
of 40%, rather than 50%. The power density estimated for System 3
already reflects improvements due to the selection of a more favorable
design point.
Simultaneous achievement of all cost reduction projections would
lower the installed cost of the System 3 power plant by 25%, from
$537/kW to $404/kW. The optimistic projection is shown in Table
VII-28.
As with System 2, plant O&M costs are assumed to be about
0.5 C/kWh, based on a target stack life of 40,000 hr and routine
catalyst bed replacement.
The cost of producing electricity from the power plant is shown in
Table VII-29, based on the optimistic capital cost estimate and a load
factor of 35%. The cost of delivered naphtha includes production, pipe-
line, and truck delivery costs.
Figure VII-13 shows the sensitivity of the cost of electricity to
fuel costs and capital costs. If the capital cost estimate given in
Table VII-27 is used, the cost of electricity increases to
69.9 mills/kWh.
VII-58
-------
Table VII-28
OPTIMISTIC COST PROJECTION FOR NOMINAL 26-MW FUEL-CELL POWER PLANT
Item
Fuel-cell trailer
Reformer/heat exchanger package
Equipment module
Condenser (E-7)
Power conditioner
Electrical wiring, controls,
and instrumentation
Total Manufactured Cost
Site preparation
Freight and insurance
Mechanical structures,
foundations, and piping
Total Installation Costs
Other indirect costs + profit
Total Power Plant Installed Cost
Land
Interest during construction
Working capital
Start-up costs
Total Capital Investment
Total
Cost,
$1000
1,394
2,419
782
270
1,368
476
6,709
432
67
262
761
2,874
10,340
20
520
140
100
11,120
VII-59
-------
Table VII-29
OPERATING COSTS AND REVENUE REQUIREMENTS
FOR A NOMINAL 26-MW FUEL-CELL POWER PLANT
Operating Costs $l>000/Year Mills/kWh
Naphtha fuel at $4.01/GJ
($4.23 per million Btu) 2.33 29.7
Operation and maintenance 0.39 5.0
Administrative expense 0.21 2.7
Property taxes and insurance 0.26 3.3
Depreciation 0.55 7.0
Total Annual Operating Costs 3.74 47.7
Return on rate base and income tax 0.98 12.5
Total Revenue Required 4.72 60.1
Sources of Revenue
Electric power 4.72 60.1
VII-60
-------
90
1.0
NAPHTHA COST - dollars per 106 Btu
2.0 3.0 4.0 5.0
6.0
7.0
1 T
80 —
70
60
o
E
U.
O
8
50
40
OPTIMISTIC CASE
BASE CASE
30
20
I
I
1.0
2.0 3.0 4.0 5.0
NAPHTHA COST - dollars per GJ
6.0
7.0
50
75 100 125
POWER PLANT CAPITAL COST - percent of optimistic case
150
FIGURE VII-13. SENSITIVITY OF THE COST OF ELECTRICITY TO POWER
PLANT COST AND NAPHTHA COST
VII-61
-------
M. Electricity Transmission and Distribution
As in the case of gas distribution, the cost of transmitting and
distributing electricity varies widely, and it is extremely difficult to
construct such costs for a particular situation. However, average costs
of transmission and distribution (T&D) can be computed from numerous
statistics. Using these statistics we calculated T&D costs for two
cases. The first represents a typical utility situation in which
electricity is generated in central power stations, transmitted via high
voltage power lines to substations, from which it is distributed to
individual residences. The second case represents the situation in
which electricity is generated in dispersed fuel-cell power plants that
are connected at the substation level, thus eliminating a substantial
part of the transmission cost (interties to the rest of the grid are
still required for reliability, however). Distribution is the same as
in the first case.
The T&D cost is paid by residential customers in two components.
The first is a fixed monthly charge that represents fixed costs to the
utility that are not related to the amount of electricity used —
metering, power poles, billing, and so on. The second is more or less
proportional to the amount of electricity used. These components can be
estimated by examining statistics of the Federal Power Commission
(FPC) and the Edison Electric Institute7 (EEI). According to EEI
statistics the average residential cost of T&D in 1975 was 15.7 mills
per kWh. In the same year, the average residential use of electricity
was 681 kVJh per month. Therefore, the average monthly T&D charge was
$10.67.
The average fixed charges for residential customers may be deter-
mined from data on average monthly residential bills compiled by the
FPC. Using the average of data for January 1, 1975 and applying
least squares analysis to nationwide average electric bills as a func-
tion of the electricity used, the following formula may be derived:
VII-62
-------
C = $3.59 + $0.0286 E (1)
where C is the monthly charge for electricity and E is the amount of
electricity used in kWh. (Analysis of data for utilities in Kansas
City, Omaha, and Des Moines yields a result not significantly different
from the above formula.) Thus, the average monthly fixed charge of
$3.59 accounts for about one-third of residential T&D costs. The
remaining portion that is included in the term proportional to the
amount of electricity used may be calculated as follows:
Since the total average month T&D charge is $10.67, the following
equation must be satisfied:
$10.67 = $3.59 + 681 y (2)
where y is the portion of the electrical rate that represents T&D
charges. Solving this equation yields y = $0.0104/kWh. Thus, the
national average charge for T&D in 1975 can be represented as:
CT&D = $3'59 + $0-0104 E (3)
Using FPC statistics for monthly electrical bills on January 1,
1977 to update Equation 1, we arrive at the following formula:
C = $3.57 + $0.0345 E (4)
Thus, while the fixed portion of residential electricity charges re-
mained essentially unchanged between 1975 and 1977, the variable portion
increased by 21%. To determine the 1977 equivalent of Equation 3, one
must know the proportion of the increase in the variable charge rate due
to generation cost increases and that due to T&D cost increases.
According to EEI, fuel costs alone accounted for 40% of the increase in
the average cost of all electricity in 1975, and 50% in 1976. EEI
figures also show that the average cost of electricity was 2.70
cents/kWh in 1975 and 3.22 cents/kWh in 1977- Using an average
VII-63
-------
percentage increase due to increased fuel costs of 45%, the net increase
due to fuel costs alone was 0.45 (3.22 - 2.70) = 0.23 cents/kWh. Thus,
of the increase in variable charge rate for residential electricity of
(3.45 - 2.86) = 0.59 cents/kWh, 0.23 cents can be attributed to fuel
cost increases. The remaining 0.36 cents must be accounted for by other
generation and T&D cost increases.
The most straightforward way of allocating cost increases is to
scale them according to the ratio of the T&D and generation (minus fuel
costs) components of the variable electricity charge rate in 1975. The
T&D component was previously determined to be 1.04 cents/kWh. The
generation component is then (2.86 - 1.04) = 1.82 cents/kWh. In 1975,
fuel costs accounted for 0.93 cents/kWh of the cost of electricity, on
the average. Therefore, nonfuel generation costs were
(1.82 - 0.93) = 0.89 cents/kWh. Allocating the nonfuel 1975-1977 cost
increase of 0.36 cents/kWh to variable T&D and nonfuel generation in the
ratio of 1.04/0.89 results in a variable T&D cost increase of 0.19
cents/kWh and a nonfuel generation cost increase of 0.17 cents/kWh.
Thus, the cost equation for monthly residential T&D charges for 1977 is:
CT & D = $3'57 + $0.0123 E (5)
The average monthly electricity use per residential customer in 1977 was
729 kWh, so that the average T&D cost was increased 9.5% over 1975:
CT&D = (3'57 + °-0123 x 729)/729 = 1.72 cents/kWh.
Equation 5 represents the average cost of T&D for the typical
utility situation (Case 1) discussed at the beginning of this section.
To calculate the costs appropriate to a distribution of electricity from
dispersed fuel-cell power plants, Equation 5 must be broken into
components of transmission and distribution, and estimates of transmis-
sion cost savings applied to the transmission component.
Q
Bottaro and Baughman have estimated the average national break-
down of residential T&D costs per kWh as follows:
VII-64
-------
Transmission: 32.2%
Distribution: 50.5
General: 17.3.
The "general" category applies to office and overhead expenses that can-
not be allocated specifically to transmission or distribution. Applying
these percentages to the average residential T&D cost of 1.72 cents/kWh
in 1977 results in the following charges:
Transmission: 0.55 cents/kWh
Distribution: 0.87
General: 0.30.
By convention, we have allocated the fixed portion of the monthly charge
rate in Equation 5 to distribution. This part amounts to $3.77/729 =
0.49 cents/kWh on the average. The remaining 0.38 cents/kWh
distribution charge must then be included in the variable portion of
Equation 5, as must the transmission and general charge components.
The savings in transmission charges resulting from employing dis-
persed fuel-cell power plants may be obtained from the work of Wood et
o
al. They estimated that the total capital cost of transmission
installed between 1975 and 1985 would be $166/kW of new generating
capacity, including $26/kW for transmission substations and $40/kW for
subtransmission. They also estimated that for every kW of fuel-cell
capacity that replaces a kW of central station capacity, $29-36/kW of
transmission costs could be saved if the fuel-cell power plants were
connected on the low voltage side of transmission-supplied substations
(appropriate for 26-MW fuel-cell power plants). Using the convention of
g
Bottaro and Baughman, subtransmission lines are included in the
distribution system. Therefore, of a total of $126/kW investment for
transmission, $29-36/kW or 23-29% of transmission capital costs can be
saved by employing dispersed fuel cells.
VII-65
-------
According to Bottaro and Baughman's statistics, 0.51 cent/kWh of
average transmission costs are equipment related. Thus, if about 25% of
these costs can be saved, the resulting savings is 0.13 cent/kWh. Thus,
the T&D cost equation appropriate for dispersed fuel-cell power plants
is Equation 5 with 0.13 cents/kWh subtracted from the variable portion
of the rate, or
$3.57 + $0.0110 E. (6)
The above calculations have used national average data on T&D costs
rather than data for the West North Central states. However,
examination of Bottaro and Baughman's results broken down on a regional
basis indicates that the figures for the West North Central states are
very close to the national average.
N. 100-kW Fuel-Cell Power Plant
Cost estimates were prepared for the 100-kW power plant based on
the equipment specifications discussed in Section IV-E. Costs were
estimated by determining the actual quantities of raw materials used to
fabricate the components. Current costs of these materials in the form
expected to be used were obtained from vendor contacts. Quotes were
based on large quantity purchases. Fabrication costs were determined bj
multiplying the raw material cost by a manufacturing-cost factor, which
was selected according to the production rates involved and the degree
of automation envisioned for the manufacuring facility. The production
rate for cells was assumed to be sufficient to justify the development
and utilization of continuous fabrication processes for the cell compo-
nent parts.
The cost breakdown for fuel-cell stacks is given in Table VII-30.
Total stack cost for the 100-kW power plant is estimated at $20,000.
Catalyst cost is a major factor, based on the initial acquisition cost
of platinum.
VII-66
-------
Table VII-30
FUEL-CELL STACK COSTS
(Production Rate = 1,000 Systems/Year)
Component/Configuration
Catalyst - Platinum
Total loading/cell -
0.001 g/cm2 (0.002 Ib/ft2)
Electrode support layers
Graphite fiber paper -
0.024 g/cm2 (0.05 lb/ft2)
Electrolyte matrix
Silicon carbide fiber -
0.039 g/cm2 (0.08 lb/ft2)
Bipolar plate - carbon/
phenolic resin -
0.44 g/cm2 (0.9 lb/ft2)
Cooling cartridge - carbon plate
with copper tube grid
Stack hardware - end plates,
manifolding, tie rods
Total
Raw
Material
Cost,
$1,000
9.3
2.5
1.07
0.62
0.54
0.71
Mfg.
Cost
Factor
0.05
0.6
0.6
1.5
1.5
1.4
Mfg.
Cost,
$1.000
0.47
1.5
0.64
Total
Cost,
$1,000
9.77
4.0
1.71
14.74
0.93
0.82
0.99
1.55
1.36
1.70
5.35
20.09a
aTotal for 100-kW power plant (4 stacks).
VII-67
-------
The cost of the catalyst is obviously dependent on the base price
of platinum, which fluctuates. The price of $6/g, used for this study,
includes a processing charge of $0.39/g over a base material price of
$5.61/g. At least 80% of this material cost could be reclaimed when the
cell stacks are replaced.
Graphite fiber paper is the major cost component in the electrode
support substrate. According to one vendor contact (Stackpole Carbon
Co.), today's price of $88/kg ($40/lb) inludes a processing charge of
$18 to 22/kg ($8 to 10/lb), for a total market of 1.1 million kg
(0.5 million Ib) per year. A future price of $62 to 66/kg
($28 to 30/lb) could be expected if the market increased to
9 to 11 million kg (4 to 5 million Ib) per year. Other applications,
such as graphite-filled automobile body panels, are expected to help
achieve this forecast market.
Low-cost methods are presently being developed for producing sili-
con carbide fibers for the electrolyte matrix. Ultimately, the cost of
these fibers is expected to approach $13.20/kg ($6/lb), but this is an
optimistic projection. This study assumes a cost of $17.60/kg ($8/lb)
for silicon carbide.
The bipolar plates are produced by a compression molding process
using a mixture of graphite and phenolic powders. This relatively high
cost procedure results in a rather high manufacturing cost, even though
the raw material cost is low — $0.90/kg ($0.41/lb).
The total stack cost is reasonable and not overly optimistic. The
estimated cost is somewhat higher than reported by ERG, primarily be-
cause of the following reasons:
o Selection of a lower cell performance characteristic and
design point, yielding a power density of 727 W/m2
(67.6 W/ft2). This increased the required cell area by 33%.
o Use of a higher current value for platinum catalyst cost.
VII-68
-------
o Incorporation of cooling grids costing $6.60 each, as part of
the circulating coolant system for heat recovery from the
stack.
Clearly, improvements in catalyst utilization and projected cell per-
formance are prime areas for cost reduction.
The final cost estimate for the 100-kW power plant is shown in
Table VTI-31. The estimate is based on large quantity purchases of raw
materials. Major components such as fuel-cell stacks, reformers, and
heat exchangers could be manufactured in separate facilities or pur-
chased. All components are assembled into a single unit at an assembly
plant at an assumed production rate of 1000 units/yr. This facility
would include areas for fabrication and welding of steel structures, and
a small assembly line. System piping and wiring could be fabricated.
The total manufacturing cost is estimated to be $46,610, which is
equivalent to $466/kW output at rated power. The projected FOB selling
price is $65,254 or $652/kW, assuming a mark-up of 40% for other in-
direct expenses and profit.
The nonoptimized base-case design study used conservative estimates
of fuel-cell performance. The impact of future optimization and per-
formance improvement programs on system cost was assessed. The
optimistic projection would be consistent with the later stages of the
assumed 1980-2000 time frame established for this study. Cost reduc-
tions might be needed if systems are to meet the 40,000-hr life goal.
Major improvements can be projected in the area of fuel-cell stack
design, construction, and performance including:
o A reduction in platinum catalyst loading to 0.75 mg/cm2
(0.0015 lb/ft2), together with a doubling of current density
(at 0.65 cell voltage) to 224 mA/cm2 (208 amp/ft2). In
effect, only two stacks would be required for the 100-kW power
plant.
o A 15% reduction in the quantity of materials used in stack
construction.
VII-69
-------
Table VII-31
COST SUMMARY FOR 100-kW POWER PLANT
Unit
Fuel-cell stacks
Reformer
Heat exchangers
E-1A
E-1B
E-2A
E-2B
E-3
E-4
E-5
E-6
E-7
E-8
Blower B-l
Pumps
P-l
P-2
H.T. shift
Cat. G-3A
L.T. shift
Cat. G-66A
Inverter
Instrumentation
Enclosure
Piping, wiring, miscellaneous
Assembly & test
Total Manufacturing Cost
Other indirect costs + profit (40%)
F.O.B. selling price
Freight and insurance
Installation
Total Installed Cost
Cost ($)
20,000
3,800
400
120
150
200
80
1,500
5,700
400
300
600
1,600
240
40Q
300
600
200
1,120
6,000
400
800
500
1,200
46,610
18,644
65,254
650
2.500
68,400
VII-70
-------
o A 15% reduction across-the-board in the manufactured cost of
the reformer, shift converters, heat exchangers and miscel-
laneous cost items (e.g., instrumentation).
o A 20% cost reduction for the DC/AC inverter and associated
power conditioning equipment.
Simultaneous achievement of all cost reduction projections would
lower the FOB price of the 100-kW power plant by 34%, from $652 to
$430/kW. Additional savings could be expected if platinum catalyst
recovery and recycle is carried out. The optimistic projection is
listed in Table VII-32.
Table VII-32
OPTIMISTIC COST PROJECTION OF ADVANCED 100-kW POWER PLANT
Unit Cost ($)
Fuel-cell stacks (2) 8,050
Reformer 3,230
Heat exchangers 8,032
Blower 1,600
Pumps 640
Shift converters 1,887
Inverter 4,800
Miscellaneous3 «/./= =
Total Manufacturing Cost
Other indirect costs + profit (40%)
FOB selling price
Freight and insurance
Installation
Total Installed Cost
Instrumentation, enclosure, piping, wiring, assembly, and testing.
VII-71
-------
This study has focused on costs associated with manufacturing a
single 100-kW power plant product line. If market surveys show that
larger power plants are required, some further cost reduction might
occur, based on capacity factor scale-up relationships, e.g., the 0.6
factor rule. Alternatively, added multiples of 100-kW units might be
installed. This approach would probably be most cost-effective, after
system reliability and redundancy factors are analyzed.
O&M costs for operating the 100 kW power plant also must be esti-
mated, but firm bases for such estimates are not available. Periodic
stack replacement material costs could range from 0.2 to 0.5 c/kWh,
assuming 40,000-hr operations at full rated level (100 kW). Fuel con-
version catalyst replacement costs should be low. Equipment maintenance
and replacement costs should also be low, reflecting, say, a 15-year
expected life. Finally, local ordinances may require attended operation
of total energy power plants.
The cost of producing electricity and heat from the 100-kW power
plant depends strongly on the particular application in which it is
used. Table IV-33 illustrates a particular case in which the load
factor for electricity production is 35%, and 75% of the recovered heat
can be utilized, with an assigned value of $2.84/GJ ($3.00 per million
Btu). The actual costs for the application in System 5 must be deter-
mined from a calculation of annual heat and electricity use. That
calculation is carried out is Chapter VIII. Figure VII-14 shows the
sensitivity of the cost of electricity to load factor and hot water
credit.
0. Hot Water Distribution System
The cost of the system for delivering 82°C (180° F) hot water
from the 100-kW fuel-cell power plant to 20 townhouses represents a sub-
stantial portion of the total energy supply cost for the housing complex.
Table VII-34 shows a breakdown of those costs, which have been estimated
VII-72
-------
Table VII-33
OPERATING COSTS AND REVENUE REQUIREMENTS FOR A 100-kW
FUEL-CELL POWER PLANT WITH HEAT RECOVERY
(35% Load Factor; 75% of Recovered Heat Utilized)
Operating Costs
SNG fuel at $4.16/GJ
($4.39 per million Btu)
Operation and maintenance
Administrative expense
Property taxes and insurance
Depreciation
Total Annual Operating Costs
Return on rate base and income tax
Total Revenue Required
Sources of Revenue
Recovered heat at $2.84/GJ
Electric power at 70.1 mills/kWh
Total
$1,OOP/Year
14.4
1.5
0.9
1.1
2.3
20.2
4.0
24.2
2.7
21.5
24.2
Mills/kWh
46.9
5.0
3.0
3.7
7.5
65.8
13.0
78.8
8.7
70.1
78.8
VII-73
-------
100
1.0
HOT WATER CREDIT - dollars per 106 Btu
2.0 3.0 4.0 5.0
T
6.0
~T
7.0
90 —
I
t- 80
I
t
O 70
u.
O
fe
8
60
LOAD FACTOR
50
40
1.0
2.0 3.0 4.0 5.0
HOT WATER CREDIT - dollars per GJ
6.0
7.0
0.20
0.25
0.30
0.35
LOAD FACTOR
0.40
0.45
0.50
FIGURE VII-14. SENSITIVITY OF THE COST OF ELECTRICITY TO LOAD
FACTOR AND HOT WATER CREDIT
VII-74
-------
Table VII-34
CAPITAL INVESTMENT REQUIRED FOR A SYSTEM THAT DELIVERS
82°C (180°F) HOT WATER TO TWENTY TOWNHOUSES
Investment
Cost Component ($1,000) Percent
Materials
5-cm diameter pipe (46m) 0.25
3-cm diameter pipe (850m) 2.9 5
2-cm diameter pipe (610m) 1.2 2
Pipe fittings 14.5 24
Pipe insulation (1510m) 4.4 7
Pumps (2) 4.5 8
Compression tank 0.42 1
Hot water coils - space heating (20) 4.5 8
Hot water coils - DHW (20) 3.0 5
Total Materials 35.7 60
Labor 8.6 15
Other (permits, trenching, etc.) 2.5 4
Subtotal Direct Costs 46.8 79
Overhead (15% of direct costs) 7.0 12
Profit (10% of direct costs & overhead) 5.4 9
Total Capital Investment 59.2 100
VII-75
-------
using standard construction cost estimation procedures. The size of the
piping, fittings and valves was based on a maximum hot water flow rate
of 1.40 liter/sec (22.1 gal/min) from the fuel-cell heat recovery system.
Included in the cost of the system are the costs of the heating coils
that transfer heat from the hot water stream to the DHW tank and to the
space heating air in each residence. The single most costly expense
category is pipe fittings. This includes the valves that control the
flow of hot water from the fuel cell to the residences and back, and all
elbows, connectors, and so on. Total cost of the heat delivery system,
$59,200, is higher than that of the fuel-cell power plant, and amounts
to nearly $3,000 per residence.
The annual ownership cost of this system is assumed to be borne by
the owners of the townhouses, and is shared equally among the 20 resi-
dences. Financing is assumed to be included in home mortgages of the
individual owners. Financing terms are as follows: 20% down payment,
with the remaining 80% financed over 30 years at 10% interest. The
annual cost of such a loan (principal repayment plus interest) is given
by the following formula:
P i
(1 + i)n - 1
where C is the annual cost, P is the principal, i is the interest rate,
and n is the term of the loan in years. For a principal
P = 0.80 x $2,960 = $2,368, and the loan terms given above, the
homeowner's annual cost is $251. To obtain the average annual cost, the
down payment of $592 is averaged over the 30-year term of the loan, or
$20 per year. The average annual cost, per residence, of the heat
delivery system is therefore $271.
P. Gas Furnace and Air Conditioner
The costs of the gas furnace and air conditioner that supply heat-
ing and cooling to the residences described in Section IV-A are based on
VII-76
-------
published estimates of the costs of the specific models discussed.10
Included are estimates of the cost of duct work for delivering the
heated or cooled air to the various rooms of the residence and venting
for the exhaust gases from the furnace.
The total installed cost of the gas furnace/air conditioning system
is shown in Table VII-35. The equipment costs are based on the whole-
sale price typically paid by a building contractor. The total cost in-
cludes labor for installing the equipment plus the contractor's overhead
and profit.
The annual homeowner's cost of owning this equipment, based on the
considerations discussed in the previous sections, amounts to $195. In
addition, Westinghouse has estimated the annual average maintenance
cost of the equipment to be $99 per year, based on statistics compiled
by gas and electric utilities. Therefore, the total yearly cost of
owning and maintaining this heating and air conditioning system is $294.
Table VII-35
CAPITAL COST FOR A RESIDENTIAL HEATING AND COOLING
SYSTEM — GAS FURNACE AND AIR CONDITIONER
Cost Component Investment, $ Percent
Equipment
Gas furnace (70 MJ/hr) 225 11
Air conditioner (32 MJ/hr) 498 23
Duct work 704 33
Subtotal Equipment 1,427 67
Labor 257 12
Subtotal Labor & Equipment 1,684 79
Overhead (15% labor & equipment) 253 12
Profit (10% labor, equipment & overhead) 194 9
Total Capital Investment 2,131 100
VII-77
-------
Q. Heat Pumps
The costs of the advanced heat pumps described in Sections IV-B and
IV-E were estimated by Westinghouse using a heat pump model that costed
each component individually, then added the cost of all components to
obtain the total. The total installed costs of the two heat pumps
are shown in Table VII-36. As before, the equipment costs are based on
those paid by a building contractor.
Annual average ownership costs for the heating and cooling systems
are $231 for the 26.0-MJ/hr (24,600-Btu/hr) system and $194 for the
19.3-MJ/hr (18,300-Btu/hr) system. Based on heat pump statistics
gathered by electric utilities, Westinghouse estimates the yearly
average maintenance cost to be $120 for either heat pump. Thus, the
total annual maintenance and ownership costs are $351 and $314 for the
26.0-MJ/hr and 19.3-MJ/hr systems, respectively.
Table VII-36
CAPITAL COSTS FOR RESIDENTIAL HEATING
AND COOLING SYSTEMS ~ HEAT PUMPS
26 MJ/hr Heat Pump 19.3 MJ/hr Heat Pump
Cost Component Investment, $ Percent Investment, $ Percent
Equipment
Heat pump
Duct work
Subtotal Equipment
Labor
Subtotal Equipment
& Labor 1996 79 1679 79
Overhead (15% of labor &
equipment) 299 12 252 12
Profit (10% of labor,
equipment & overhead) 230 9 193 9
Total Investment 2525 100 2124 100
VII-78
1138
621
1759
237
45
25
70
9
844
598
1442
237
40
28
68
11
-------
R. References—Chapter VII
1. R. P. Stickles, et al., "Assessment of Fuels for Power Generation
by Electric Utility Fuel Cells," Electric Power Research Institute
Report 318 (October 1975).
2. American Gas Association, "Gas Facts, 1975" (1976).
3. J. M. King, Jr., "Energy Conversion Alternatives Study - United
Technologies Phase II Final Report," NASA CR 134955, FCR-0237
(October 19, 1976).
4. S. Abens, et al., "High Temperature Molten Carbonate Fuel-Cells,"
Fourth Quarter Technical Progress Report E-3-4 (March 1977) and
Fifth Quarter Technical Progress Report E-3-5 (July 1977).
5. P. Wood, "AD/DC Power Conditioning and Control for Advanced
Conversion and Storage Technology," EPRI 390-1-1 (August 1975).
6. Federal Power Commission, "Monthly Electric Utility Bills" (January
1, 1976 and January 1, 1977).
7. Electrical World, various issues.
8. M. L. Baughman and D. J. Bottaro, "Electric Power Transmission and
Distribution Systems Costs and Their Allocation," IEEE
Transactions on Power Apparatus and Systems, p. 782 (May-June 1976).
9. W. Wood, M. P. Bhavaraju, and P. Yatcko, "Economic Assessment of
the Utilization of Fuel Cells in Electric Utility Systems,"
Electric Power Research Institute Report EM-336 (November 1976).
10. H. S. Kirschbaum and S. E. Veyo, "An Investigation of Methods to
Improve Heat Pump Performance and Reliability in a Northern
Climate," Electric Power Research Institute Report EM-319 (January
1977).
VII-79
-------
VIII. THERMAL AND ELECTRICAL LOAD CALCULATIONS
To complete the analysis of the five systems, the energy use char-
acteristics of the residences described in Chapter IV must be known.
Those residences are the ultimate users of the energy supplied by the
other system components. The determination of their annual energy con-
sumption will allow the costs, energy use, and environmental impacts of
the systems to be appropriately scaled for comparison.
As discussed in Chapter III, our study focuses on the heating and
cooling components of residential energy use. That emphasis is reason-
able, because approximately 60% of residential energy use in the United
States is for heating and cooling. Also, because the energy demand for
heating and cooling varies widely with the time of day, those portions
of the residential energy load tend to contribute substantially to the
utility's "intermediate load" electricity demand, which is the type of
load that the electricity generating components of the systems are de-
signed to meet.
In addition to the heating and cooling demand, the demand created
by other loads in the residences — lights and appliances — must be
known for two reasons. First, the cost per kWh of electricity to the
customer will depend on the total monthly electricity use. Second, in
System 5, the amount of heat supplied by the fuel-cell power plant, and
thus the amount of heat required of the heat pumps, will depend on the
total electrical load of the residences.
The electrical loads we used for lights and appliances are
statistical averages. The heating and cooling loads, however, and their
resultant electricity demand, have been determined on the basis of the
following information: (1) the daily temperature variations in the
VIII-1
-------
Omaha-Des Moines-Kansas City region during a typical year; (2) the
thermal response of the residences to those variations; and (3) the
performance of the heating and cooling equipment as a function of
temperature and the thermal demands of the residence. In the following
sections, the use of those pieces of information to calculate final
residential energy demand is described.
A. Light and Appliance Loads
The electrical loads generated by lights and appliances in a resi-
dence are a function of the number and types of appliances, the number
of occupants, their living pattern, and so on. Although those factors
vary substantially from one household to the next, the quantities of
interest to utilities, as well as to this study, are the average loads
determined by the characteristics of multiple households. Such statis-
tical information is readily available.
The average light and appliance loads will be characterized for the
three types of residences described in Chapter IV. The first, which
will be called Residence 1, is supplied by System 1. It uses both gas
and electricity. In addition to a gas furnace, it is assumed to have a
gas range and water heater. All other appliances are electric, and in-
clude an air conditioner, clothes washer and dryer, refrigerator/freezer,
television, dishwasher, and other small appliances such as a toaster and
food mixer.
The second type of residence, called Residence 2, is supplied by
Systems 2, 3, and 4. Residence 2 is all-electric, and in addition to
having a 26.0-MJ/hr (24,600-Btu/hr) heat pump for heating and cooling,
it employs an electric water heater and range. The use of lights and
other appliances is the same as for Residence 1.
Residence 3, which is supplied by System 5, is similar to Residence 2
except that it employs a smaller heat pump (19.3 MJ/hr or 18,300 Btu/hr)
VIII-2
-------
and its domestic hot water (DHW) is supplied entirely by heat recovered
from the fuel-cell power plant; therefore, no electric water heating is
required.
The components of electricity consumption, by lights and appliances
as well as monthly totals, for the three types of residences are shown
17
in Table VIII-1, as determined from national statistics. ' Those
figures do not include air conditioner or heat pump loads — they will
be determined in following sections.
To determine the ability of the System 5 fuel-cell power plant to
respond to the electrical and thermal loads of the townhouses, one must
know the variations in the light and appliance loads of Residence 3 with
the time of day. Those load variations have been previously esti-
3
mated, and are shown in Figure VIII-1. The loads shown are the
average hourly loads per residence. The actual load profile for an
individual residence would look considerably different, having many
abrupt changes in load as various appliances were turned on and off.
The load profile in Figure VIII-1 is seen to be at a minimum of
0.27 kW in the late night and early morning hours when only the refrig-
erator and perhaps one or two small lights are using power. Peak
demands of 2.83 and 2.46 kW occur during the hours of 9-10 a.m.
Table VIII-1
MONTHLY LIGHT AND APPLIANCE ELECTRICAL
LOADS FOR THREE TYPES OF RESIDENCES
Electricity Use (kWh/Month)
Residence 1 Residence 2 Residence 3
Source
Lights 145 145 145
Water heater — 380
Range — 100 100
Other appliances 490 490 490
Total 635 1,115 735
VIII-3
-------
o
o
3
LIGHTS AND APPLIANCES
10
I
6§
m
Q
•i
12M 1 23456789 10 11 12N1 234 567 89 10 11 12M
AM PM
TIME OF DAY
CD
<
FIGURE VIII-1. VARIATION IN HOURLY AVERAGE LIGHT AND APPLIANCE LOADS AND DHW DEMAND WITH
TIME OF DAY - RESIDENCE 3
-------
and 7-8 p.m., respectively, when the bulk of domestic activities are
taking place.
Also shown in Figure VIII-1 is the DHW demand profile, which will
also be required in the supply/demand calculations for System 5.
B. Daily Temperature Variations
Data on temperature variations for most cities can be obtained from
the Environmental Data Service of the National Oceanic and Atmospheric
Administration. Temperatures are reported every 3 hours, every day of
the year. In addition, daily and monthly averages are reported, as well
as daily extremes, along with various statistical temperature data. To
determine typical seasonal heating and cooling requirements, one must
examine temperatures averaged over many years. Table VTII-2 shows the
normal monthly average temperatures for the period 1941-1970 for Des
Moines, Omaha, and Kansas City.
Table VIII-2
NORMAL MONTHLY AVERAGE TEMPERATURES, °C (°F)
Month
January
February
March
April
May
June
July
August
September
October
November
December
Kansas City
-2
0
5
12
18
23
26
25
20
14
6
1
.3
.6
.1
.8
.3
.3
.0
.2
.4
.8
.4
.7
(27
(33
(41
(55
(65
(73
(78
(77
(68
(58
(43
(32
.8)
.1)
.2)
.0)
.0)
.9)
.8)
.4)
.8)
.6)
.6)
.3)
_e
-2
2
11
17
22
25
24
19
13
4
-2
Omaha
.2
.2
.8
.3
.2
.3
.1
.2
.1
.3
.4
.2
(22.
(28.
(37.
(52.
(63.
(72.
(77.
(75.
(66.
(55.
(40.
(28.
6)
0)
1)
3)
0)
2)
2)
6)
3)
9)
0)
0)
Des Moines
-7
-4
1
9
16
21
23
22
17
12
3
-3
.0
.3
.1
.7
.1
.4
.9
.9
.9
.4
.2
.9
(19.4)
(24.2)
(33.9)
(49.5)
(60.9)
(70.5)
(75.1)
(73.3)
(64.3)
(54.3)
(37.8)
(25.0)
VIII-5
-------
Temperatures for Omaha are a reasonable average of temperatures for
the three cities. Therefore, in all further calculations, only
temperature data for Omaha was used. Monthly temper- ature data for
Omaha for the 10 years including 1966, 1968, and 1970-77 were analyzed
to find particular months that were most representative of normal
monthly conditions (statistics for 1967 and 1969 were not
available). Both monthly average temperatures and monthly heating (or
cooling) degree-days were compared to obtain the best match. Occasion-
ally, when two months were very similar, other data such as monthly min-
imum and maximum temperatures were compared. The results of the match-
ing procedure are shown in Table VIII-3, in which the normal monthly
temperatures and heating (or cooling) degree-days for Omaha are compared
with the average temperatures and degree-days for the actual months
chosen as the best match. Those months are indicated by the year in
which they occur.
Table VIII-3
COMPARISON OF NORMAL MONTHLY CONDITIONS WITH
ACTUAL MONTHLY CONDITIONS OF MONTHS CHOSEN AS "BEST MATCH"
Actual Conditions
Heating
(Cooling)
Average Degree-
Year Temperature (°C) Days (°C)
Normal Conditions
Heating
(Cooling)
Average Degree-
Month Temperature (°C) Days (°C)
January
February
March
April
May
June
July
August
September
October
November
December
-5.2
-2.2
2.8
11.3
17.2
22.3
25.1
24.2
19.1
13.3
4.4
-2.2
730
576
481
217
(48)
(131)
(210)
(186)
(61)
167
417
637
1975
1968
1971
1974
1972
1975
1970
1970
1977
1974
1966
1966
-5.3
-2.6
2.9
11.4
16.9
22.5
25.2
24.6
19.7
12.9
4.5
-2.1
728
603
474
211
(41)
(134)
(214)
(210)
(58)
167
412
629
VIII-6
-------
Table VIII-3 shows that the conditions of the actual months chosen
very closely match the normal temperature condition. Those months are
assumed to constitute a "typical" year for Omaha, and the daily temper-
ature variations were used to calculate heating and cooling loads.
C. Thermal Response of the Residences
Daily temperature data can be used to calculate heating and cooling
loads if the thermal characteristics of the residences are known. A
method for calculating those loads has been developed by Westinghouse
(its report may be referred to for details of the derivation of the
method.) Basically, the thermal response of the residence is calculated
by using an electric circuit analog to derive the appropriate response
functions. The difference between external and internal temperatures is
analogous to voltage, heat flow is analogous to current, and thermal
conductivity and heat capacity are analogous to electrical conductivity
(the reciprocal of resistance) and capacitance, respectively.
The result of that analysis for heating loads is given in Equations
1-3, as follows:
QL<*) " Qavg + AQL(t) (1)
QL(t) = GX ATa(t) + G1(a2 - «i) /Q ATa(t')dt' + C (2)
C = - G! /2* ATa(t)dt - d ( a2 ~ Oil) /2ndt /O ATa(t')dt' (3)
24 ° 24
-°2
48
In Equation 1, QT(t) is the heating load in kJ/hr (or Btu/hr) as a
LI
function of the time of day, t (in hours); Qavg is the daily average
heating load calculated using the average daily temperature and the heat
VIII-7
-------
loss equation discussed in Chapter IV, and AQ (t) is the variable
portion of the heating load to be calculated by Equations 2 and 3. In
Equation 2, G., a., and Ot2 are thermal parameters of the resi-
dence, AT is the difference between the temperature at t and the
Q.
daily average temperature, and C is a constant of integration to be
calculated by Equation 3. In Equation 3, C^ is another thermal
parameter of the residence, T is the daily average temperature of
the day for which the heating load is being calculated, and T .is
the average temperature of the previous day.
It can be seen from Equations 1-3 that calculating the daily aver-
age heating load by integrating over the 24-hour period will result in
exactly Q , modified slightly by the addition of the third term in
Equation 3. That term represents the long-term thermal storage capacity
of the residence. It will also average to zero, however, if the calcu-
lation is carried out over a successive period of days — say, for a
month. Thus, for calculating monthly and seasonal heating loads, it is
clear that the use of Q is sufficient to provide the needed infor-
mation to an acceptable level of accuracy. Recall that for Residences 1
and 2, Q& is given by:
Qavg = 39,900 - 360 Tflvg kJ/hr (4)
or
(Qavg = 37'800 ~ 61° Tavg
where T a is the average daily temperature in C or F. For
Residence 3, the heating load is:
Qavg = 23,800 - 230 T kJ/hr (5)
or
(Qavg = 22'600 - 39° Tavg Btu/hr>-
Because of the complicated relationship between heating load, electrical
load, and electrical and heating supply for the Residence 3 case, one
must consider whether daily average calculations can effectively repre-
VIII-8
-------
sent the averaged effect of hourly load variations. This question is
discussed in the following section.
The calculation of cooling loads is considerably more complicated
than the calculation of heating loads; not only does temperature vary
throughout the day, but so does solar heat input (insolation) and latent
heat infiltration (the latent heat content of humid outside air entering
the house). However, several simplifying assumptions can make the task
easier. First, most of the cooling load is registered during summer
afternoons. Therefore, figures for average summer afternoon insolation
and relative humidity provide reasonable estimates of solar heating and
latent heat infiltration.
Second, the daily average cooling load can be estimated in a way
similar to that for the heating load. Instead of the average daily tem-
perature, however, the average temperature is used for the hours during
which cooling is required. The parameters that contribute to the cool-
ing loads for Residences 1, 2, and 3 are shown in Table VIII-4. The
heat input from people and appliances is similar to that used to calcu-
late heating loads. The heat input from latent heat infiltration was
calculated using a technique given in the ASHRAE handbook, and is
based on an average moisture content of 0.0131 kg HO per kg of air
for exterior air (average summer afternoon conditions for Omaha), 0.0117
kg Ho per kg of air for interior air (corresponding to 26 C wet
bulb interior temperatures). The figures for sensible heat input (via
heat transfer through the walls and infiltration of warm air) and solar
heat input were derived in the Westinghouse report .
Using the parameters listed in Table VIII-4 to calculate the
cooling load as a function of exterior temperature results in the
following equation for Residences 1 and 2:
or
Qavg = 380 Tavg- 43,800 kJ/hr (6)
(Qavg « 650 Tavg - 41,600 Btu/hr)
with Tavg expressed in °C or °F, as appropriate.
VIII-9
-------
To calculate the design cooling loads discussed in Chapter IV, the
moisture content corresponding to the 97.5% temperatures for Omaha
(34°C or 93°F dry bulb and 26°C or 78°F wet bulb) was used —
0.0175 kg HO per kg of air. Use of that quantity yields latent heat
infiltration of 5,700 kJ/hr (5,400 Btu/hr) for Residences 1 and 2 and
2,850 kJ/hr (2,700 Btu/hr) for Residence 3.
The seasonal heating and cooling loads may now be calculated for
Residences 1, 2, and 3 by using the equations developed in this section
and the temperature data for a "typical" year for Omaha. The heating
season is assumed to extend from October 1 through April 30, and the
cooling season from May 1 through September 30. The seasons overlap
somewhat (i.e., some heating is required in May and September, and some
cooling is required in April and October), but it is small and may be
ignored.
Calculation of heating loads is straightforward. The daily average
temperature is used to calculate the daily average heat load for each
day in which the average temperature is below 17°C (62°F) for Resi-
dences 1 and 2, and below 14°C (58°F) for Residence 3. Those are
the temperatures at which the internal heat sources (people, lights, and
appliances) are sufficient to maintain the interior temperature at 21°C
(70 F); above those temperatures the heating load is zero. The daily
average heating loads are then multiplied by 24 and summed over the num-
ber of days in the month to obtain the total monthly heating loads.
Table VIII-4
COMPONENTS OF THE COOLING LOAD — OMAHA SUMMER AFTERNOON CONDITIONS
Component Residences 1 and 2 Residence 3
Heat input from
people, lights,
& appliances 4,960 kJ/hr (4,700 Btu/hr) 4,960 kJ/hr (4,700 Btu/hr)
Solar heat input 3,380 kJ/hr (3,200 Btu/hr) 840 kJ/hr (800 Btu/hr)
Latent heat
infiltration 1,390 kJ/hr (1,310 Btu/hr) 700 kJ/hr (660 Btu/hr)
Sensible heat
input 380 kJ/hr-°C 240 kJ/hr-°C
(200 Btu/hr-c-F) (125 Btu/hr-°F)
VIII-10
-------
The calculation of cooling loads is slightly more complicated.
Only those portions of the day during which the external temperature
exceeds 26 C (78 F) are used in the calculation. The recorded tri-
hourly temperatures are examined to determine the number of hours
during which the temperature exceeded 26°C. The average temperature
during those hours is used to calculate the average cooling load using
Equations 6 and 7. The cooling load is then multiplied by the number of
hours during which the temperatures exceeded 26°C to obtain the total
daily cooling load. The daily cooling loads are then summed to obtain
the cooling loads for each month.
The calculated results for heating and cooling loads are shown in
Table VIII-5. The heating load for either type of residence far exceeds
the cooling load. Thus, the use of heat pumps that are optimized for
heating performance (as described in Chapter IV) is fully justified.
Month
October
November
December
January
February
March
April
Total
May
June
July
August
September
Total
Table VIII-5
SUMMARY OF HEATING AND COOLING LOADS BY MONTH
Residences 1 and 2
Residence 3
Heating Load, GJ
3.52 (3.34)
10.1 (9.62)
16.1 (15.3)
19.0 (18.0)
15.5 (14.7)
11.8 (11.2)
4.80 (4.55)
(Million Btu)
1.32 (1.25)
5.22 (4.95)
9.00 (8.53)
12.6 (11.9)
8.67 (8.22)
6.28 (5.95)
2.00 (1.90)
80.9
(76.7)
45.0 (42.7)
Cooling Load, GJ (Million Btu)
1.03
2.91
5.17
4.48
0.73
(0.98)
(2.76)
(4.90)
(4.25)
(0.69)
0.69 (0.65)
1.92 (1.82)
3.40 (3.22)
2.95 (2.80)
0.49 (0.46)
14.3 (13.6)
9.44 (8.95)
VIII-11
-------
D. Energy Consumption for Heating and Cooling
The final step in the sequence outlined at the beginning of the
chapter is to calculate the response of the heating and cooling equip-
ment to the heating and cooling loads derived in previous sections, and
ultimately to calculate the energy consumed by that equipment. For
Residences 1 and 2, the calculations are relatively straightforward.
The energy consumed by the gas furnace is simply equal to the heating
load divided by the thermal efficiency of the furnace, which is 0.60
(see Chapter V). For the heat pump operating in the heating mode, the
heating load is compared to the heat output of the heat pump at a given
temperature. If the heating capacity of the heat pump exceeds the
heating load, the heat pump will be operating only part of the time.
The fraction of the time the heat pump is on is called the duty factor.
The average electricity demand by the heat pump (in kW) is equal to its
electricity demand at the temperature in question multiplied by the duty
factor.
When the heating load exceeds the capacity of the heat pump, sup-
plemental electric resistance heating must be used to make up the dif-
ference. The heat pump operates continuously and consumes power at its
rated capacity at the temperature in question. The resistance heaters
will consume power at an average rate that will equal the difference
between the heating load and the heat supply of the heat pump. The
total power demand is the power demand of the heat pump plus the average
power demand of the resistance heaters.
Calculation of power demand for the heat pump operating in the
cooling mode and the air conditioner is similar, except that when the
cooling load exceeds the cooling capacity, the duty factor is 1.0 and
the air conditioner or heat pump power demand is equal to its rated
demand at the temperature in question. That is a consequence of there
being no "supplemental cooling capacity." In practice, that means that
at temperatures above the balance point of the cooling device, the inte-
rior temperature of the residence cannot be maintained at the "set" tem-
perature, but will actually be somewhat higher.
VIII-12
-------
In principle, the calculations described above should be carried
out for every hour of the heating and cooling seasons to determine the
total electricity consumption. However, because the heat pump and air
conditioner are reasonably close to being linear in their electricity
demand as a function of temperature, the use of daily average tempera-
tures closely approximates actual energy use.
The heat pump and air conditioner average power demands were used
in conjunction with the daily average temperature data for Omaha's
"typical" year to compute the monthly electricity use for each type of
residence.
Table VII-6 shows the monthly electricity use for heating and
cooling and the total seasonal electricity use, including light and
appliance use of 635 kWh/month for Residence 1, and 1,115 kWh/month for
Residence 2.
Table VIII-6
ELECTRICITY CONSUMPTION FOR HEATING AND COOLING (kWh)
Residence 1
Month
October
November
December
January
February
March
April
Seasonal Total
Month
May
June
July
August
September
Seasonal Total
Annual Total
Heating
27
79
125
148
121
92
37
629
Cooling
137
384
690
594
96
1,901
2,530
L&Aa
635
635
635
635
635
635
635
4,445
L&A
635
635
635
635
635
3,175
7,620
Total
662
714
760
783
756
111
672
5,074
Total
772
1,019
1,325
1,229
731
5,076
10,150
Residence 2
Heating
292
1,025
2,293
2,968
2,108
1,307
413
10,406
Cooling
107
307
552
471
73
1,510
11,916
L&A
1,115
1,115
1,115
1,115
1,115
1,115
1.115
7,805
L&A
1,115
1,115
1,115
1,115
1,115
5,575
13,380
Total
1,407
2,140
3,408
4,083
3,223
2,422
1,528
18,211
Total
1,222
1,422
1,667
1,586
1,188
7,085
25,296
aL&A = light and appliances.
VIII-13
-------
For Residence 1, the electricity used for heating is only that
consumed by the gas furnace's electric fan motor. The total con-
sumption of natural gas (or SNG) by the furnace is 135 GJ (128 million
Btu) over the entire heating season.
The calculation of heating energy use is a more difficult task for
Residence 3 than for Residences 1 and 2 because of the strong functional
relationship between temperature, heating load, and electrical load. To
explore that relationship, we calculated the variations in those param-
eters over a 24-hr day. We considered two major independent variables
— the exterior temperature, and the light and appliance electrical
load. The variations in temperature are taken from the temperature data
for the Omaha "typical year", and the light and appliance loads are
shown in Figure VIII-1. The DHW demand shown in that figure was an
important input to our calculation.
To calculate the heating load that must be met by a combination of
the heat pump and fuel-cell recovered heat, Equations 1, 2, and 3 were
used with the appropriate thermal constants for Residence 3. We inte-
grated those equations numerically, so that heat loads could be calcu-
lated over a 24-hr period.
In addition to the temperature, heat load, DHW load, and light and
appliance electrical load, the inputs required for the program are the
functions that relate heat pump input and output to temperature, fuel-
cell heat recovered to electrical load, and heat transfer efficiency to
heat pump output and fuel-cell heat recovered. The first three are ob-
tained from data presented in Chapters IV and V, and the fourth is ob-
tained from the manufacturer's literature on the Trane WC-18 heating
coil (see Section V-P). The four functions were represented by alge-
braic expressions that were fitted to numerical data.
With all the above inputs formulated, we calculated hourly average
electrical loads, heat pump duty factors, and the amount of recovered
fuel-cell heat delivered to the space heating system. The operation of
the program is described in Appendix C.
VIII-14
-------
The amount of recovered fuel-cell heat available when only lights
and appliances are operating are illustrated along with the DHW demand
in Figure VIII-2. The figure shows that there will always be sufficient
recovered fuel-cell heat to supply all DHW needs for the residences in
System 5, even when the only electrical load is the basic light and
appliance load. Additional heat recovered from the fuel-cell power
plant beyond that required to meet DHW demand will be used to satisfy
the space heating load. When there is no space heating load, the extra
heat is discharged to the atmosphere.
As an example of the performance of the 100-kW fuel-cell power
plant and associated equipment in meeting the electrical and thermal
loads of 20 townhouse residences, as well as of the computational pro-
gram discussed previously, the coldest day of the "typical" year for
Omaha was chosen. The highest electrical demand of the heating season
occurs on that day, so that the capability of the 100-kW fuel-cell power
plant to meet that demand for 20 residences must be determined. The
actual temperature data were for January 12, 1975. On that day the tem-
perature ranged from -23°C (-9°F) to -13°C (8°F) with an average
temperature of -17 C (1.5 F). Figure VIII-3 shows the variation in
temperature with time of day along with the hourly average heating loads
for Residence 3 calculated using Equations 1, 2, and 3. The heating
load closely follows the temperature, with the peak load of 24.8 MJ/hr
(23,490 Btu/hr) occurring at 6-7 a.m. That heating load must be met by
a combination of recovered fuel-cell heat, heat pump output, and elec-
tric resistance heat.
The program that calculates the performance of the energy supply
system for the townhouses was run using the temperature data and heating
loads shown in Figure VIII-3. The results are illustrated in Figures
VIII-3 and VIII-4. Figure VIII-3 shows the portion of the heating load
per residence that is_met by heat recovered from the fuel-cell power
plant. Over the 24-hr period, that amount is 234 MJ (221,600 Btu), or
42% of the total heating load of 558 MJ (529,100 Btu); in addition, the
fuel-cell power plant supplies 44.9 MJ (42,500 Btu) of DHW demand.
VIII-15
-------
13
12
10
HI
Q
cr
o
a.
a.
en
UJ
I
i i i i i r
n i i r
I
12M 1
I I
i r
I I
J L
FUEL CELL HEAT AVAILABLE
12,000
10,000
8000
6000
.n
D
Q
<
III
Q
cr
o
_
D-
<
LU
4000
2000
567
A.M.
10 11 12N 1 2
TIME OF DAY
6
P.M.
8 9 10 11 12M
FIGURE VIII-2. DHW DEMAND RELATIVE TO FUEL CELL HEAT AVAILABLE FROM OPERATION OF LIGHTS AND APPLIANCES
-------
u
V15
UJ
cc
I-
LU
a.
UJ
-25
10
-5
-10
UJ
UJ
D.
w
<
M
H
H
25
I 20
IT 15
O
D
<
jj? 10
O
UJ
I
12M 1
HEAT SUPPLY
25,000
20,000
15,000
3
m
10,000
5,000
6
AM
10 11 12N 1
TIME OF DAY
6
PM
10 11 12M
FIGURE VIII-3. HOURLY AVERAGE TEMPERATURE, HEATING LOAD, AND SUPPLY OF RECOVERED FUEL CELL HEAT
FOR RESIDENCE 3 ON THE COLDEST DAY OF THE YEAR
-------
I I I I I I I i r
i i i
i i i
I
H-'
OO
I
0
3
_i
o
(E
O
21-
TOTAL ELECTRICAL LOAD
ELECTRIC RESISTANCE
HEATERS
LIGHTS AND APPLIANCES
12M 1 23456789 10 11 12N 1 23456789 10 11 12N
AM PM
TIME OF DAY
era
(D
<
FIGURE VIII-4. HOURLY AVERAGE ELECTRICAL LOADS FOR RESIDENCE 3 ON THE
COLDEST DAY OF THE YEAR
-------
Figure VIII-4 shows the hourly average electrical load per resi-
dence, categorized according to lights and appliances, heat pump, and
electrical resistance heat. The figure clearly shows that the average
electrical load does not exceed the 5 kW per residence capacity of the
fuel-cell power plant. However, peak concident electrical demand could
exceed the 5 kW capacity during high demand periods, because the loads
in Figure VIII-4 are hourly averages rather than actual instantaneous
loads.
To determine whether the calculation discussed above would be
required for each day of the heating season to arrive at accurate
monthly and seasonal electricity consumption for System 5, the daily
averages of the heating and electrical loads presented above were com-
pared to those derived from daily average temperature, heating load,
light and appliance load, and DHW demand. Average light and appliance
load and DHW demand of 1.01 kW and 1,870 kJ/hr (1,770 Btu/hr), respec-
tively, along with the average temperature of -17°C (1.5°F) and
space heating load of 23.2 MJ/hr (22,000 Btu/hr), were used to calculate
the following daily average parameters:
o Average electrical load: 3.20 kW
o Recovered fuel-cell heat delivered to the space heating system:
9,810 kJ/hr (9,300 Btu/hr).
The corresponding parameters derived by averaging the hourly values
calculated previously are 3.04 kW and 9,740 kJ/hr (9,230 Btu/hr). These
results, as well as others obtained from daily temperature data for less
severe temperature conditions, indicate that the use of daily average
values in the calculation of average electrical loads and recovered
fuel-cell heat supply yield acceptable agreement (generally within 5%)
with values calculated from 24-hour data. Therefore, the daily average
method was used to calculate monthly and seasonal electricity consump-
tion and fuel-cell heat utilization for the townhouse residences.
Figure VIII-5 shows the heating system electrical load (heat pump
plus electric resistance heaters) and recovered fuel-cell heat delivered
VIII-19
-------
5.0
-20
-10
10
TEMPERATURE - °F
20 30
40
50
60
25
I
N>
O
4.0
SPACE HEATING
ELECTRICAL LOAD
3.0
<
O
O
111
2.0
1.0
DELIVERED
FUEL CELL
HEAT
-30
-20
-10 0
TEMPERATURE - °C
10
20
.*
15 I
t-
Q
uu
DC
10
LU
Q
20
FIGURE VIII-5. VARIATIONS IN AVERAGE SPACE HEATING ELECTRICAL LOAD AND
DELIVERED FUEL CELL HEAT WITH EXTERNAL TEMPERATURE
-------
to the heating system as a function of external temperature. They are
based on an average light and appliance load of 1.01 kW and a DHW load
of 1,870 kJ/hr (1,770 Btu/hr). The electrical load curve shows a
leveling in slope at about 9°C (48°F). That is the point at which
recovered fuel-cell heat is sufficient to supply the heating load of the
residences. Above that point the only electricity requirement is the
0.21 kW consumed by the heat pump fan motor, which must be on whenever
space heat is required. Both curves are remarkably linear considering
the complicated functional relationship between the various system
parameters.
To calculate cooling season energy requirements, the same method
was employed as for Residences 1 and 2, because recovered fuel-cell heat
does not enter into the calculation. To check the peak cooling demand
against the capacity of the 100-kW power plant, temperatures for the
hottest day of the "typical" year (represented by July 1, 1970) were
used to calculate hourly electrical loads. The results of that calcula-
tion are shown in Figure VIII-6. Again, the peak of the average hourly
demand of lights and appliances plus heat pump operating in the cooling
mode does not exceed the 5 kW per residence capacity of the fuel-cell
power plant.
Using the methods discussed above, the monthly and seasonal heat-
ing, cooling, and total electrical consumption for Residence 3 were cal-
culated, along with the amount of recovered fuel-cell heat utilized to
meet the heating load. The results of those calculations are shown in
Table VIII-7. Total use of recovered fuel-cell heat for space heating
is 22.7 GJ (21.5 million Btu) for the heating season. In Section VIII-B
the seasonal heating load for Residence 3 was given as 45.0 GJ
(42.7 million Btu). Therefore, recovered fuel-cell heat supplies 50% of
the total space heating requirement in addition to the total yearly DHW
requirement of 16.3 GJ (15.5 million Btu).
VIII-21
-------
40
O
I
LU
DC
35
O.
30
I i i I
105
100
i
<
95
90
85
80
75
tc.
D
5
UJ
I
to
N5
I
33
O
3
£2
O
III
12M 12 3456789 10 11 12N 1
AM
234 56 789 10 11 12M
PM
FIGURE VIII-6. HOURLY AVERAGE TEMPERATURE AND ELECTRICAL LOAD FOR RESIDENCE 3
ON THE HOTTEST DAY OF THE YEAR
-------
The annual electricity consumption for Residence 3 is 12,790 kWh.
The annual load factor of 0.292 for a 100-kW power plant supplying 20
townhouses is obtained by dividing 20 times 12,790 kWh by the electrical
capacity of the fuel-cell power plant (100 kW x 8,760 hr = 876,000 kWh).
This is somewhat lower than the 0.35 load factor assumed for other types
of power plants in this study. However, it is a reasonable value for a
power plant that is expected to meet all the electrical requirements of
a limited number of residences, ranging from minimum to peak loads.
Table VIII - 7
RESIDENCE 3 ELECTRICITY CONSUMPTION AND FUEL-CELL HEAT UTILIZATION
Utilization of
Recovered Fuel-Cell Heat (GJ)
Electricity Consumption (kWh)
Month
October
November
December
January
February
March
April
Seasonal
Total
DHWa
1.36
1.36
1.36
1.36
1.36
1.36
1.36
9.52
Space Heating Total
1.10
3.12
4.43
4.98
4.06
3.46
1.51
22.7
2.46
4.48
5.79
6.34
5.42
4.82
2.87
32.2
Heating
98
342
598
756
620
415
118
2,947
L&AD
735
735
735
735
735
735
735
5,145
Total
833
1,077
1,333
1,491
1,355
1,150
853
8,092
May
June
July
August
September
Seasonal
Total
Annual
Total
1.36
1.36
1.36
1.36
1.36
6.80
16.30
.36
.36
22.7
1.36
1.36
1.36
6.80
39.0
69
201
375
324
51
735
735
735
735
735
804
936
1,110
1,059
786
1,020 3,675 4,695
3,967 8,820 12,787
aDHW = domestic hot water.
L&A = light and appliances.
VIII-23
-------
E. References—Chapter VIII
1. Gordian Associates, Inc., "Evaluation of the Air-to-Air Heat Pump
for Residential Space Conditioning," Federal Energy Administration
Report FEA/D-76/340 (April 1976).
2. Stanford Research Institute, "Patterns of Energy Consumption in the
United States," Office of Science and Technology (January 1972).
3. Hittman Associates, Inc., "Residential Energy Consumption - Single
Family Housing," Department of Housing and Urban Development Report
HUD-HAI-2 (September 1975).
4. U.S. Department of Commerce, National Oceanic and Atmospheric
Administration, Environmental Data Service, "Local Climatological
Data — Omaha, Nebraska."
5. H. S. Kirschbaum and S. E. Veyo, "An Investigation of Methods to
Improve Heat Pump Performance in a Northern Climate," Electric Power
Research Institute Report EM-319 (January 1977).
6. American Society of Heating, Refrigerating, and Air Conditioning
Engineers, Handbook of Fundamentals (New York 1972).
VIII-24
-------
IX. COMPARATIVE ANALYSIS
Because the cost, efficiency, and environmental parameters for the
various system components have been determined, the overall performance
of each of the five systems can now be analyzed and compared. The sub-
sequent analysis in this chapter compares the relative merits of the
systems rather than measuring them against some absolute standard of
performance. However, to establish a benchmark against which the other
systems can be compared, System 1 is considered to be closest to the
current energy supply situation; other systems are assessed as having
advantages or disadvantages compared to System 1.
All costs, energy consumption, and environmental impacts are ex-
pressed in terms of the total heating and cooling supplied to the resi-
dences. The unit of measure is 1 GJ (0.948 million Btu) of heating and
cooling. A summary of the overall advantages and disadvantages of the
systems is presented in Chapter X.
A. Energy Efficiency
The overall energy efficiencies of each of the five systems are
determined by the thermal efficiency factors presented in Chapter V.
For several system components, however, efficiencies were calculated as
a function of percent of rated load (fuel-cell power plants, combined
cycle power plants) or as a function of exterior temperature (heat
pumps, air conditioners). Therefore, seasonal or annual average ef-
ficiencies are used to evaluate overall system performance. Annual or
seasonal consumption of electricity required to meet the annual heating
and cooling loads (or cooling load alone) can be used to determine the
average coefficient of performance (COP)for the heat pumps and air
IX-1
-------
conditioner. From the heating and cooling loads and electricity con-
sumption calculated in Chapter VIII, the annual average COPs are as
follows:
o Residence 1: air conditioner; COP = 2.09
o Residence 2: heat pump; COP =2.22
o Residence 3: heat pump; COP = 2.22.
For the 26-MW fuel-cell power plants and the combined cycle power
plant, we assume the annual average load factor to be 0.35. However,
the variation in load that results in this average cannot be readily
determined. For example, the power plant could be operating at full
load 35% of the year and be shut off for the remaining 65%. An infinite
number of variations in load could average to 35%. However, because the
plants are intended for intermediate cycling duty, they will operate at
less than the rated load for a substantial period of time. Moreover,
they will probably be shut down for a number of hours each day during
nonpeak hours. Therefore, the average load factor during operation will
be somewhere between 0.35 and 1.0. Based on the heat rates and load
factors given in Chapter V, we have chosen the following nominal average
heat rates:
o 26-MW fuel-cell power plant (SNG) - 7,600 kJ/kWh
(7,200 Btu/kWh)
o 26 MW fuel-cell power plant (naphtha) - 7,400 kJ/kWh
(7,000 Btu/kWh)
o Combined-cycle power plant - 7,200 kJ/kWh (6,800 Btu/kWh).
Because the 100-kW fuel-cell power plant is designed to meet all
electricity requirements of the townhouse complex, it has a fairly low
load factor — 0.292 — as determined in Chapter VIII. Because the
power plant must operate continuously, and therefore have many hours of
operation during low load periods, that load factor probably represents
a true average load factor for the power plant. From the variation in
electricity and heat generation efficiencies with load factor presented
IX-2
-------
in Chapter V, the average efficiencies can be determined. The average
efficiency is 0.30 for electricity conversion, and 0.36 for heat gen-
eration, assuming an average load factor of 0.292.
Using the average energy efficiency factors presented above, the
overall system efficiencies for heating and cooling residences were
determined (see Figures IX-1 through IX-5). The figures are drawn so
that the energy supplied from one component to the next is shown beside
the line connecting the components. Any external energy requirement is
shown beside the system component that requires it, with a small arrow
indicating input to that component. The efficiency of each component is
shown within the box that represents the component.
The representation of System 5 in Figure IX-5 is slightly different
than the others. It shows 25.7 GJ of heat supplied to the space heat
delivery system from the 100-kW fuel-cell power plant. Only part of
that heat (12.8 GJ) is coproduced with the generation of electricity to
supply the heat pump. The remainder (12.9 GJ) is coproduced with the
generation of electricity for lights and appliances. However, the
figure shows only the fuel supply to the power plant needed to produce
power for the heat pump. That is because electricity is required for
lights and appliances even with no heat demand, and, after DHW demand is
met, the excess heat generated by the power plant would be rejected to
the atmosphere if there were no heating load. Because a heating load
does exist, however, heat that would have been wasted is used effec-
tively to reduce the electricity required by the heat pump. Therefore,
the energy efficiency for heating and cooling is based on the incre-
mental electricity consumption by the heat pump assuming that the light
and appliance as well as the DHW loads constitute the base system demand.
To clarify the energy supply and demand picture for System 5,
Figure IX-6 shows the annual flows of energy per residence, including
light and appliance and DHW demand.
IX-3
-------
0.5 GJ
7.3 GJ
29.4 GJ
UNIT TRAIN
1.0
29.4 GJ
COAL-FIRED
POWER PLANT
0.34
2780 kWh
ELECTRICITY
DISTRIBUTION
0.91
1901 kWh
AIR
CONDITIONER
2.09
COAL MINE
227 GJ
629 kWh
198 GJ
COAL
GASIFICATION
PLANT
0.74
147 GJ
GAS PIPELINE
0.92
135 GJ
GAS
DISTRIBUTION
1.0
135 GJ
GAS FURNACE
0.60
14.3 GJ
80.9 GJ
14.3 + 80.9
ENERGY EFFICIENCY = = 0.41
227 + 7.3 + 0.5
FIGURE IX-1. ANNUAL ENERGY FLOWS AND ENERGY EFFICIENCY
FOR SYSTEM 1
IX-4
-------
4.4 GJ
COAL MINE
i
137 GJ
COAL
GASIFICATION
PLANT
0.74
1
102 GJ
GAS PIPELINE
0.92
1
93.4 GJ
r
GAS
DISTRIBUTION
1.0
i
93.4 GJ
r
26-MW
FUEL CELL
POWER PLANT
0.47
1
12,290 k
F
ELECTRICITY
DISTRIBUTION
0.97
i
1 1 ,920 k
HEAT PUMP
2.22
95.2 GJ
ENERGY EFFICIENCY ' = 0.67
I <5 / ' 4.4
FIGURE IX-2. ANNUAL ENERGY FLOWS AND ENERGY
EFFICIENCY FOR SYSTEM 2
IX-5
-------
4.5 GJ
0.5
0.1
COAL MINE
142 GJ
COAL
LIQUEFACTION
PLANT
0.64
90.9 GJ
LIQUIDS
PIPELINE
1.0
90.9 GJ
NAPHTHA
DISTRIBUTION
1.0
90.9 GJ
26-MW
FUEL CELL
POWER PLANT
0.49
12,290 kWh
ELECTRICITY
DISTRIBUTION
0.97
11,920 kWh
HEAT PUMP
2.22
95.2 GJ
ENERGY EFFICIENCY
95.2
142 + 4.5 + 0.5 + 0.1
0.65
FIGURE IX-3. ANNUAL ENERGY FLOWS AND ENERGY EFFICIENCY
FOR SYSTEM 3
IX-6
-------
4.6 GJ
0.6
0.1
COAL MINE
i
143 GJ
r
COAL
LIQUEFACTION
PLANT
0.66
i
94.3 GJ
LIQUIDS
PIPELINE
1.0
i
94.3 GJ
r
FUEL OIL
DISTRIBUTION
1.0
i
94.3 GJ
COMBINED
CYCLE
POWER PLANT
0.50
i
13.100 k
ELECTRICITY
DISTRIBUTION
0.91
i
11.920 k
1
HEAT PUMP
2.22
95.2 GJ
ENERGY EFFICIENCY
95.2
143 + 4.6 + 0.6 + 0.1
0.64
FIGURE IX-4. ANNUAL ENERGY FLOWS AND ENERGY EFFICIENCY
FOR SYSTEM 4
IX-7
-------
2.2 GJ
COAL MINE
69.9 GJ
COAL
GASIFICATION
PLANT
0.74
51.7 GJ
GAS PIPELINE
0.92
47.6 GJ
GAS
DISTRIBUTION
1.0
47.6 GJ
100-kW
FUEL CELL
POWER PLANT
0.30
3967 kWh
25.7 GJ
HEAT PUMP
2.22
HEAT
DELIVERY
0.88
31.7 GJ
22.7 GJ
ENERGY EFFICIENCY = 31'7 + 22-7 = Q ?5
69.9 + 2.2
FIGURE IX-5. ANNUAL ENERGY FLOWS AND ENERGY
EFFICIENCY FOR SYSTEM 5
IX-8
-------
ELECTRICITY
(L & A)
31.8 GJ •*•
ELECTRICITY
14.3 GJ
HEAT PUMP
SNG
153.4 GJ
WASTE HEAT
52.2 GJ
100 kW
FUEL CELL
POWER PLANT
UNUSED HEAT
16.2 GJ
RECOVERED
HEAT
55.2 GJ
HEAT
DELIVERY
DHW
16.3 GJ
31.7 GJ
SPACE HEATING
AND COOLING
22.7 GJ
SPACE HEATING
FIGURE IX-6. TOTAL ANNUAL ENERGY FLOWS (PER RESIDENCE) FOR FUEL
CELL POWER PLANT SUPPLYING TOWNHOUSES
IX-9
-------
Based on heating and cooling only, System 5 has the highest overall
energy efficiency — 0.75. System 1 has the lowest efficiency at 0.41.
Systems 2, 3, and 4 are comparable, although System 2 has a slight
advantage at 0.67.
Overall, Systems 2 through 5 are considerably more efficient
(greater than 50%) than System 1, primarily because of the high effici-
encies of the advanced electricity generating technologies and the use
of heat pumps rather than the gas furnace. The advantages in recovering
fuel-cell heat in System 5 are clearly demonstrated, although they are
not dramatic; the efficiency is just 12% greater than System 2, the next
most efficient system. Even though heat is recovered from the 100-kW
phosphoric acid fuel cell, the electricity generating efficiency of the
26-MW molten carbonate fuel cell is 50% higher. This high efficiency,
combined with an efficient heat pump to generate space heating, consi-
derably reduces the advantage of recovering heat from a low electrical
efficiency phosphoric acid fuel cell. Optimizing of the relative
amounts of heat and electricity generated by the 100-kW fuel cell (de-
termined by the actual heat and electrical loads it is expected to meet)
would result in higher system efficiency. However, such an optimization
was beyond the scope of this study.
B. Economics
1. Cost of Heating and Cooling
The cost of providing heating and cooling to the residences
can be readily calculated using cost factors developed in Chapter VII
and the energy consumption estimates derived in Chapter VIII. The
figure of merit to be used in comparing the five systems is the cost of
providing 1 GJ of heating and cooling, which is derived by dividing the
annual cost of providing heating and cooling by the total annual heating
and cooling load. The annual cost of heating and cooling is the sum of
the fixed annualized cost of heating and cooling equipment plus the cost
of gas and/or electricity consumed by the equipment.
IX-10
-------
The costs derived by this method represent the true incre-
mental cost to the consumer of obtaining heating and cooling from each
of the five systems. These costs would never appear on the gas or
electric bill of a customer as shown here, of course, because new
sources of gas or electricity supply are integrated into the supply
system, and the customer sees only the average cost of supplying gas or
electricity from all sources in the system.
The costs of the various system components derived in Chapter
VII may be used directly as shown, except that the cost of electricity
transmission and distribution must be derived using Equations VII-(5)
and VII-(6), and the cost of electricity from the 100-kW fuel-cell power
plant is somewhat different than that shown in Table VIII-34 because of
differing load factors and because recovered heat is not explicitly
credited.
The costs of electricity transmission and distribution for
each of the residences are based on the total electricity consumption
shown in Chapter VIII and calculated using Equations VII-(5) and
VII-(6). Those costs are as follows:
o Residence 1 - 16.5 mills/kWh (System 1)
o Residence 2 - 12.7 mill/kWh (Systems 2 and 3)
o Residence 3 - 14.0 mills/kWh (System 4).
The annual average costs of heating and cooling for each of
the five systems are shown in Tables IX-1 through IX-5. The cost shown
next to each system component is the cumulative cost of energy supplied
by the component. The heating and cooling cost calculation is
summarized at the bottom of each table.
Not surprisingly, System 1 has the lowest cost of heating and
cooling because it employs the most conventional technology and has the
fewest energy conversion steps. Furthermore, even though it is the
least efficient system, the cost of the coal that the system uses is so
IX-11
-------
low ($0.33/GJ) that the effect of low efficiency on the final cost of
heating and cooling is not significant. (The cost of coal contributes
only $0.79 to the total heating and cooling cost of $10.10/GJ).
Table IX-1
COST OF HEATING AND COOLING FOR SYSTEM 1
Coal Mine $0.33/GJ
Unit train $0.61/GJ
Coal-fired power plant $9.81/GJ
(35.3 mills/kWh)
Electricity transmission $15.40/GJ
and distribution (55.3 mills/kWh)
Coal gasification plant $2.90/GJ
Gas pipeline $3.54/GJ
Gas distribution $4.16/GJ
Air Conditioner/gas furnace $294/yr
Cost of heating = $294 + 1,901 kWh/($0.0553/kWh) + 135 GJ ($4.16/GJ)
and cooling 95.2 GJ
= $10.1/GJ
Table IX-2
COST OF HEATING AND COOLING FOR SYSTEM 2
Coal mine $0.33/GJ
Coal gasification plant $2.90/GJ
Gas pipeline $3.54/GJ
Gas distribution $3.98/GJ
26-MW fuel-cell power plant $16.40/GJ
(59.0 mills/kWh)
Electricity distribution $20.40/GJ
(73.5 mills/kWh)
Heat pump $351/yr
Cost of Heating and Cooling = $351 + 11,920 kWh ($0.0735/kWh)
95.2 GJ
= $12.90/GJ
IX-12
-------
Table IX-3
COST OF HEATING AND COOLING FOR SYSTEM 3
Coal mine $0.33/GJ
Coal liquefaction plant $3.77/GJ
Liquids pipeline $3.93/GJ
Naphtha distribution $4.01/GJ
26-MW fuel-cell power plant $16.70/GJ
(60.1 mills/kWh)
Electricity distribution $20.80/GJ
(74.7 mills/kWh)
Heat pump $351/yr
Cost of Heating and Cooling = $351 + 11.920 kWh ($0.0747/kWh)
95.2 GJ
= $13.00/GJ
Table IX-4
COST OF HEATING AND COOLING FOR SYSTEM 4
Coal mine $0.33/GJ
Coal liquefaction plant $3.02/GJ
Liquids pipeline $3.17/GJ
Fuel oil distribution $3.29/GJ
Combined-cycle power plant $13.00/GJ
(46.9 mills/kWh)
Electricity transmission and distribution $18.20/GJ
(65.5 mills/kWh)
Heat Pump $351/yr
Cost of Heating and Cooling = $351 + 11,920 kWh ($0.0655/kWh)
95.2 GJ
= $11.90/GJ
IX-13
-------
Table IX-5
COST OF HEATING AND COOLING FOR SYSTEM 5
Coal mine $0.33/GJ
Coal gasification plant $2.90/GJ
Gas pipeline $3.54/GJ
Gas distribution $4.16/GJ
100-kW fuel-cell power plant $24.2/GJ
(87.1 mills/kWh)
Heat pump $314/yr
Heat delivery system $271/yr
Cost of Heating and Cooling* = $314 + $271 + 3,970 kWh ($0.0871/kWh)
70.7 GJ
= $13.20/GJ
* Includes DHW
The heating and cooling costs of Systems 2 and 3 are
comparable primarily because the cost of delivered fuels for the power
plants are nearly identical. Although coal-derived naphtha is much more
expensive to produce than SNG, the transport and distribution costs of
SNG are much higher than for naphtha.
The heating and cooling cost for System 4 is about 8% lower
than for Systems 2 and 3, primarily because of the lower fuel and
capital costs for the combined-cycle power plant. That difference is
partly offset by higher T&D costs and transmission losses, but not
enough to raise the final heating and cooling cost to the level of those
of the fuel-cell systems.
The cost of heating and cooling for System 5 also includes the
costs of supplying DHW because the heat recovery and delivery systems
are designed to provide both space heating and hot water, and their
costs cannot be readily separated. On this basis, the cost of heating
and cooling for System 5 are marginally higher than for Systems 2 and 3,
although that result is, of course, sensitive to the nature of loads
supplied by the fuel-cell power plant.
IX-14
-------
To determine the effects of load variations on the cost of
heating and cooling, those costs were determined for heating loads both
higher and lower than the Residence 3 loads derived in Chapter VIII.
The cooling load was allowed to vary with the heating load in a linear
fashion, and all other variables were held constant, including DHW load,
light and appliances loads, and power plant electrical load factor.
Holding the electrical load factor means, in effect, that the number of
residences supplied by the power plant will vary inversely with the
heating load. The annualized cost of the heat pump was allowed to vary
with the heating load while the cost of the heat delivery system, per
residence, was held constant. Finally, the quantity of heat supplied by
the fuel cell per kWh, along with the heat pump performance character-
istics, were assumed to be the same as in the Residence 3 base case.
The results of the sensitivity calculations are shown in
Figure IX-7. The cost of heating and cooling is displayed as a function
of both the annual heating load and the ratio of heating load to light
and appliance load. The light and appliance load constitutes the base
electrical demand, which determines how much of the heat is available
for space heating and DHW.
Figure IX-7 clearly shows the effect of increasing heating
load on the system economics. In particular, a heating load equal to
that of Residence 2 (80.9 GJ per year) results in a heating and cooling
cost of $11.50/GJ, which is less than Systems 2, 3, or 4. Overall, the
cost of heating and cooling varies from +17% to -14% of the base case
over a range of 0.5 to 2.0 times the base case heating load.
One difficulty in comparing the heating and cooling costs of
System 5 with those of the other systems is that the fuel-cell power
plant in System 5 supplies all electricity for the residences. In
Systems 1 though 4, the light and appliances loads are presumed to be
supplied by grid electricity (and some gas in System 1), which costs
about $0.04/kWh in 1977 prices, while the light and appliance loads in
System 5 are supplied by expensive electricity from the fuel-cell power
IX-15
-------
20
18
RATIO OF HEATING LOAD TO LIGHT AND APPLIANCE LOAD - MJ/kwh
4 6 8 10 12 14
16
18
16
8
o
Q
<
CD 14
Z
111
I
12
8
10
t
I
\
\
I
I
10
20
30 40 50 60
HEATING LOAD - GJ
70
80
90
FIGURE IX-7. VARIATION IN THE COST OF HEATING AND COOLING WITH HEATING LOAD - SYSTEM 5
-------
plant. To provide a more uniform comparison of System 5 with the other
systems, the total annual energy costs of Residence 3 were determined,
as supplied by Systems 1 through 5.
To calculate the total annual energy costs for Systems 2
through 4 supplying Residence 3, the light and appliance load for
Residence 3 was increased from 8,820 to 13,350 kWh per year to account
for DHW demand, and the heat pump load was increased from 3,967 to
6,967 kWh per year to account for the fact that recovered fuel-cell heat
would not be available. For System 1, the light and appliance load of
Residence 3 was reduced by 1,200 kWh per year because of the absence of
the electric range. Gas consumption by appliances included 32.9 GJ per
year for DHW and 11.1 GJ for the gas range. Furthermore, the figures
for consumption of gas and electricity for heating and cooling were
adjusted to account for the lower loads of Residence 3 relative to
Residence 1.
The average grid price of electricity for Systems 1 through 4
was determined from total electrical loads and Equations VII-(4), (5),
and (6). The average gas price for supplying DHW and range loads for
System 1 was assumed to be the 1977 average of about $2.00/GJ. The
annualized cost of heating and cooling equipment was reduced to account
for the lower heating and cooling loads of Residence 3.
With the assumptions discussed above, the following total
annual energy supply costs for Residence 3 as supplied by Systems 1
through 5 were calculated:
o System 1 cost = $250 + 75 GJ ($4.16/GJ)
+ 44 GJ ($2.00/GJ) + 1,605 kWh (0.0553/kWh)
+ 7,620 kWh ($0.0391/kWh)
= $1,040
o System 2 cost = $314 + 13,348 kWh ($0.0366/kWh)
+ 6967 kWh ($0.0739/kWh)
= $1,320
IX-17
-------
o System 3 cost = $314 + 13,348 kWh ($0.0366/kWh)
+ 6,967 kWh (0.0751/kWh)
= $1,330
o System 4 cost = $314 + 13,348 kWh ($0.0366/kWh)
+ 6,967 kWh ($0.0661/kWh)
= $1.270
o System 5 cost = $314 + $271 + 12,787 kWh ($0.0871/kWh)
= $1,700
System 5 is not economical in terms of supplying the total
energy requirements of Residence 3 compared with other systems. The
high cost of System 5 is partly caused by the low power plant load
factor, partly by the high cost of the heat delivery system, and partly
by the use of the fuel-cell power plant to supply electricity to the
residences at all times, even when the heat demand is very low.
The optimum arrangement for System 5 would be to use grid
electricity during periods of low heat demand and to use electricity
from the fuel-cell power plant when the heat demand is high. The
appropriate mix would have to be determined through an optimization
procedure that is beyond the scope of this study.
Moreover, the 100-kW power plant in System 5 cannot be
expected to meet any conceivable load by itself, even if it is designed
to meet the largest average load in a typical year. Excursions above
the power plant rated load could readily occur on cold winter days.
Also, during extreme temperature periods, the total load could be well
in excess of design capacity. The only feasible solutions are for the
residences to be connected to the utility grid as a backup in high
demand periods, or to have a load management system in which noncritical
appliances (such as clothes dryers) would be automatically shut off
during high demand periods. In the former case, the residences would
have to pay a utility hook-up charge of about $3.57 per month (according
to Equation VII-(4)) even when no power was consumed, which would add
about $0.19/GJ to the cost of heating and cooling or $42.80 per year to
the total annual residential energy cost. An additional cost would also
be incurred for a load management system, although such a cost was not
determined in this study.
IX-18
-------
2. Capital Intensiveness
Another measure of the relative economic attractiveness of the
five systems is the amount of capital required to install the various
system components. Because capital may be considered a scarce resource,
the capital intensiveness of the systems will measure the relative ease
of initially establishing the systems, which is independent of the
life-cycle system cost that was calculated in the previous section.
The unit appropriate for measuring the capital intensiveness
of Systems 1-5 is the capital required to provide 1 GJ of heating and
cooling per year, which may be calculated by using the component energy
flows displayed in Figures IX-1 through IX-5, along with the capital
intensiveness for each system component. However, the calculation of
component capital intensiveness is complicated somewhat; two figures may
be derived: (1) the amount of capital investment required per unit of
peak energy output, and (2) the capital required per unit of average
energy output. For the systems under consideration in this study, the
capital investment per unit of average energy output will be used,
because, by and large, the systems components are not sized to meet peak
system demands and are effectively decoupled from one another. For
example, the output from the coal gasification plant is fairly constant
in time, while the output of the fuel-cell power plant that it supplies
fluctuates daily and even hourly. The inherent storage capacity of the
natural gas transport and distribution system, plus the varying demands
of other users of SNG, effectively eliminate such demand fluctuations in
the coal gasification plant output, and peak demands have relative
little effect on the plant's capacity. That argument is not strictly
true for each system component — for example, the 100-kW fuel-cell
power plant is sized to meet the peak electricity demand of the
townhouse in an average year. However, because the argument is
generally applicable, the average energy outputs will be used for all
systems components for consistency.
IX-19
-------
The resulting figures for capital intensiveness of the system
components are shown in Table IX-6. Those figures are based on the
total capital investments presented in Chapter VII and the yearly energy
output of the system components. In some cases, capital investments
were not explicitly given in Chapter VII, and the capital intensiveness
was estimated using the data at hand. For example, the capital inten-
siveness of gas distribution was estimated by assuming that 90% of gas
distribution charges are capital-related (the same proportion as for the
gas pipeline) and by using a capital recovery factor of 18% per year
(typical for utility economics). The figure for the coal-fired power
plant represents one-half of the initial investment because the plant is
assumed to be 50% depreciated when it is assigned to intermediate-load
duty.
Table IX-6
CAPITAL INTENSIVENESS OF THE SYSTEM COMPONENTS
Component Capital Intensiveness
Coal mine $0.41 per GJ/yr
Unit train $0.53 per GJ/yr
Coal-fired power plant $1,210 per kW (avg.)
Coal gasification plant $11.40 per GJ/yr
Coal liquefaction plant (fuel oil) $11.40 per GJ/yr
Coal liquefaction plant (naphtha) $12.60 per GJ/yr
Gas pipeline $ 2.20 per GJ/yr
Liquids pipeline $ 0.74 per GJ/yr
Liquid fuel distribution (fuel oil) $ 0.09 per GJ/yr
Liquid fuel distribution (naphtha) $ 0.11 per GJ/yr
Gas distribution
Residential $3.10 per GJ/yr
Commercial $2.20 per GJ/yr
Combined-cycle power plant $911 per kW (avg.)
26-^IW fuel-cell power plant (SNG) $1,180 per kW (avg.)
26-MW fuel-cell power plant (naphtha) $1,240 per kW (avg.)
Electricity transmission and
distribution
Central power plant $550 per kW (avg.)
Dispersed power plant $490 per kW (avg.)
100-kW fuel-cell power plant $1,570 per kW (avg.)
Gas furnace $11.00 per GJ/yr
Air conditioner $86.60 per GJ/yr
26-MJ/hr heat pump $26.50 per GJ/yr
Residence 3 heating and cooling system $71.90 per GJ/yr
IX-20
-------
The figures for capital intensiveness presented in Table IX-6
were combined with the energy flows shown in Figures IX-1 through IX-5
to obtain the total capital intensiveness per GJ/yr of heating and
cooling for each of the five systems (see Tables IX-7 through IX-11).
The trends are similar to those displayed in the cost of heating and
cooling calculations shown in Tables IX-1 through IX-5. The capital
intensiveness of System 1 is the lowest of the five, as expected.
Systems 2 through 4 are comparable, with System 4 having about a 10%
advantage over system 2. The capital intensiveness of System 5 is much
higher than that of any other system, primarily because of the high
investment required for the heat delivery system. If heating and
cooling equipment, the cost of which is borne by the consumer rather
than the utilities, is excluded from the calculations, System 5 has the
lowest capital intensiveness of any system. Therefore, System 5 would
be very attractive to the utilities because of the initial investment
Table IX-7
CAPITAL INTENSIVENESS FOR SYSTEM 1
($ per GJ/yr of Heating and Cooling)
Coal mine $0.98
Unit train 0.17
Coal-fired power plant 4.02
Electricity transmission
and distribution
Air conditioner
Coal gasification plant
Gas pipeline
Gas distribution
Gas furnace
Total
IX-21
-------
Table IX-8
CAPITAL INTENSIVENESS FOR SYSTEM 2
($ per GJ/yr of Heating and Cooling)
Coal mine $ 0.59
Coal gasification plant 12.10
Gas pipeline 2.18
Gas distribution 2.16
26-MW fuel-cell power plant 17.30
Electricity transmission
and distribution 7.04
Heat pump 26.50
Total $67.87
Table IX-9
CAPITAL INTENSIVENESS FOR SYSTEM 3
($ per GJ/yr of Heating and Cooling)
Coal mine $ 0.61
Coal liquefaction plant 12.00
Liquids pipeline 0.71
Naphtha distribution 0.10
26-MW fuel-cell power plant 18.20
Electricity transmission
and distribution 7.04
Heat pump 26.50
Total $65.10
IX-2 2
-------
Table IX-10
CAPITAL INTENSIVENESS FOR SYSTEM 4
($ per GJ/yr of Heating and Cooling)
Coal mine $ 0.62
Coal liquefaction plant 11.30
Liquids pipeline 0.73
Fuel oil distribution 0.09
Combined-cycle power plant 14.30
Electricity transmission
and distribution 7.87
Heat pump 26.50
Total $61.40
Table IX-11
CAPITAL INTENSIVENESS FOR SYSTEM 5
($ per GJ/yr of Heating and Cooling)
Coal mine 0.41
Coal gasification plant 8.33
Gas pipeline 1.49
Gas distribution 2.09
100-kW fuel-cell power plant 10.10
Heat pump/heat delivery 71.90
Total 94.30*
Includes DHW for this system only.
IX-23
-------
required. However, the consumer would be discouraged from participating
in such an arrangement because of the large initial equipment cost.
C. Environmental Impact
The environmental aspects of the system components were analyzed in
Chapter VI. Those analyses can be used to develop enviromental impact
profiles of the five systems. Qualitative judgments play an important
role in comparing the systems because an absolute quantitative ranking
of the systems is generally not possible, nor would it necessarily be
desirable.
1. Pollutant Emissions
The emissions of air and water pollutants and solid wastes
developed in Chapter VI for system components were used to calculate the
total emissions for the five systems. So that the systems could be
compared on an equivalent basis, the emissions were normalized on the
basis of pollutants emitted per GJ of heating and cooling. These
quantities are shown in Tables IX-12 through IX-16. Because the unit of
reference is 1 GJ of heating and cooling, the amount of energy issuing
from each component is generally greater or less than that amount, de-
pending on the various component efficiencies, and is shown in
parentheses below the name of each system component.
A dash in any column means that none (or an insignificant amount)
of that pollutant is produced. The entries in each pollutant emission
column have not been added to obtain total emissions per GJ of heating
and cooling, primarily, because emissions from the various system
components take place in different geographical regions and the
resulting pollutant burden to the environment must be examined in each
location. Also, point sources (e.g., coal gasification plant) occur
over a relatively small geographical area, while other emissions are
spread over a large area (e.g., unit trains). The resulting pollutant
burdens to the environment are considerably different depending on the
nature of the source.
IX-24
-------
Ul
Table IX-12
POLLUTANT EMISSIONS ASSOCIATED WITH SYSTEM 1
(g Per GJ of Heating and Cooling)
Coal Mine
(2.38)*
Air Pollutants
S02 0.38
HOX 6.4
Part.** 0.21/19
HC 0.36
CO 1.1
PAH 1.8 x 10-5
Sb —
As —
Be —
Cd —
Pb —
tt« — —
**g
Se —
Zn —
Water Pollutants
Suspended Solid 0.76
Oil and Grease —
Iron 0.013
Manganese 0.0026
Copper —
Chlorine —
Solid Waste —
Electricity
Unit Train Power Plant T&D
(0.30)* (0.102)* (0.093)*
0.80 28
5.0 91
0.36/_ 1.8/4.2
1.3 2.2
1.8 7.3 —
2.2 x 10"5 8.4 x 10-5
~ 2.2 x 10-*
1.2 x 10-5
8.1 x 10-5 _
6.0 x 10-*
4.6 x 10-3
1.4 x 10-3
7.1 x 10-4
7.1 x 10-3
0.71
— 0.35
0.024
_ _ —
0.024 —
4.6 x 10-4
— 1,900 —
Air Coal Gasifi- Gas
Conditioner cation Plant Pipeline
(0.15)* (1.54)* (1.42)*
33 0.033
•75 17
— / 3 Li
4.3/18 0.85/-
4.9 1.4
6.3 6.8
3.8 x 10-* 5.4 x ID"5
1.4 x 10-*
8.* x 10-6
— 5.0 x 10-5
3.8 x 10-*
2.9 x 10-3
8.8 x 10-*
4.5 x 10-*
4.5 x 10-3
__ —
—
13,000
Gas Gas
Distribution Furnace
(1.42)* (0.85)*
0.36
49
6.1/.
— 4.9
12
6.2 x 10~4
— —
—
—
—
— —
--
—
—
GJ supplied by the system component per GJ of heating and cooling.
**Fine particulates/coarae participates.
-------
Table IX-13
POLLUTANT EMISSIONS ASSOCIATED WITH SYSTEM 2
(g Per GJ of Heating and Cooling)
Air Pollutants
S02
NOX
Part.**
HC
CO
PAR
Sb
As
Be
Cd
Pb
Hg
Se
Zn
Water Pollutants
Suspended Solid
Iron
Manganese
Solid Waste
Coal Mine
(1.44)*
0.23
3.9
0.13/11
0.22
0.67
1.1 x 10-5
-
-
-
—
—
-
—
-
0.46
0.0076
0.0016
—
Coal Gasifi- Gas Gas Fuel-Cell Electricity
cation Plant Pipeline Distribution Power Plant Distribution Heat Pump
(1.06)* (0.980)* (0.980)* (0.464)* (0.450)* (1.0)*
23 0.022
52 12 — 5.3 x 10-7
3.0/12 0.59/-
3.4 0.97
4.3 4.7
2.6 x 10-* 3.7 x 10-5
9.6 x 10-5
5.8 x 10-6
3.4 x 10-5
2.6 x 10-4
2.0 x 10-3
6.1 x 10-*
3.1 x 10-*
3.1 x 10-3
_
-
-
8,900
*GJ supplied by the system component per GJ of heating and cooling.
**Fine particulates/coarse particulates
IX-26
-------
N>
Table IX-14
POLLUTANT EMISSIONS ASSOCIATED WITH SYSTEM 3
(g per GJ of Heating and Cooling)
Coal Mine
(1.49)*
Air Pollutants
S02 o.24
»°x 4.0
Part.** 0.13/12
BC 0.23
CO 0.69
PAH 1.1 x 10-5
Sb —
Aa
Be
Cd —
Pb —
Hg
Se
Zn
Water Pollutants
Suspended Solid 0.48
Iron 0.0079
Manganese 0.0016
Solid Haste —
Coal
Liquefaction Liquids Naphtha Fuel-Cell Electricity
Plant Pipeline Distribution Power Plant Distribution Heat Pump
(0.954)* (0.954)* (0.954)* (0.464)* (0.450)* (1.0)*
29 0.55 0.11
95 8.4 0.71 1.1 x 10-5 — _
1.9/21 0.61/_ 0.052/.
2.1 0.67 0.19
7.3 1,8 1.2 — — —
1.5 x 10-4 2.8 x 10-5 6.i x ifl-6
2.0 x 10-4 — — — — _-
1.1 x 10-5
7.5 x 10-5 _
5.5 x 10-4 _ _. _ „ _
4.2 x 10-3 _
1.3 x 10-3
6.4 x 10-4
6.4 x 10-3 _
_
—
—
8,800
*GJ supplied by the system component per GJ of heating and cooling.
**Fine particulates/coarse particulates.
-------
Table IX-15
POLLUTANT EMISSIONS ASSOCIATED WITH SYSTEM 4
(g per GJ of Heating and Cooling)
Coal Mine
(1.50)*
Air Pollutants
S02 0.24
NOX 4.0
Part.** 0.13/12
HC 0.23
CO 0.69
PAH 1.1 x 10-5
Sb
As
Be
Cd
Pb —
Hg
Se
Zn
Water Pollutants
Suspended Solid 0.48
Oil and Grease —
Iron 0.0080
Manganese 0.0017
Copper
Chlorine
Solid Waste
Coal
Plant Pipeline
(0.990)* (0.990)*
29 0.57
95 8.7
1.9/21 0.63/.
2.1 0.70
7.3 1.9
1.5 x 10-4 2.9 x 10-5
2.0 x 10-4
1.1 x 10-5
7.5 x 10-5
5.5 x 10-4
4.2 x 10-3
1.3 x 10-3
6.4 x 10-*
6.4 x 10-3
—
-
—
-
-
—
8,800
Combined-
Distribution Power Plant T & D Heat Pump
(0.990)* (0.495)* (0.450)* (1.0)*
0.32 46
2.1 122
0.15/. 24/_
0.55 12
0.76 12
4.9 x 10-6 2.3 x 10-3
1.5 x 10-3
6.9 x 10-3
1.6 x 10-3
4.8 x 10-3
0.016
2.3 x 10-*
1.7 x 10-3
0.076
2.9
— 1.4
0.10
„
0.10
1.5 x 10-3
—
*GJ supplied by the system component per GJ of heating and cooling.
IX-28
-------
Table IX-16
POLLUTANT EMISSIONS ASSOCIATED WITH SYSTEM 5
(g per GJ of Heating and Cooling)
Coal Mine
(1.28)*
Air Pollutants
S02 0.20
NO, 3.4
Part.** 0.11/10
HC 0.19
CO 0.59
PAH 9.7 x 10-6
Sb —
As
Be
Cd —
Pb
Hg
Se
Zn
Water Pollutants
Suspended Solid 0.41
Iron 0.0068
Manganese 0.0014
Solid Waste
Coal
Gasification Gas
Plant Pipeline
(0.951)* (0.875)*
20 0.02
46 10
2.7/11 0.52/_
3.0 0.86
3.9 4.2
2.3 x 10-4 3.3 x io-5
8.6 x 10-5
5.2 x 10-6
3.1 x 10-5
2.3 x 10-*
1.8 x 10-3 —
5.4 x 10-4 ~
2.8 x 10-4
2.8 x 10-3
__ «
__
__
8,000
Heat Pump
Gas Fuel-Cell and
Distribution Power Plant Heat Recovery
(0.875)* (0.978)* (1.0)*
—
6.3
—
4.2
—
—
__
__
__
—
__
__
—
__
__ __
__
__
__ — — —
**,
*GJ supplied by the system component per GJ of heating and cooling.
'Pine particulates/coarse particulates.
IX-29
-------
To account for such factors, the pollutant emissions from the
systems components were classified into three categories — (1) those
emitted in the mine or near-mine region, (2) those emitted during
transport to the end-use region, and (3) those emitted in the end-use
region. The resulting assignment of system components to each category
is shown below:
o Category 1 - coal mine, coal gasification plant, coal
liquefaction plant
o Category 2 - unit train, gas pipeline, liquids pipeline
o Category 3 - coal-fired power plant, combined-cycle power
plant, fuel-cell power plants, liquid fuel
delivery, gas furnace
Although the emission of pollutants in each category can be
considered separately, an overall emission parameter for each pollutant
for an entire system is desirable. Such parameters can be formulated if
appropriate weighting factors can be assigned for pollutant emissions in
each category. Weighting factors should be chosen on the basis of the
likely effects of pollutant emissions on human health and the
environment in each category.
First, because the emissions from Category 2 are dispersed, they
should be weighted relatively less than the emissions from Categories 1
or 3. The gas and liquids pipelines have 10 or 11 separate emission
sources spaced at about 80 km (50 mi), whereas the unit train emissions
are continuous. Because emissions from different pipeline pumping
stations are unlikely to interact, the total emissions can be assigned a
weighting factor of about 1/10. This factor will also be applied to the
unit train emissions to equalize all components in Category 2.
The relative weighting of Categories 1 and 3 is complex and
difficult. On one hand, Category 3 emissions could be weighted higher
because (1) the Omaha-Kansas City-Des Moines region is much more highly
populated than the Powder River Basin, and therefore the human exposure
to a given pollutant release will be greater, (2) additional pollutant
emissions will exacerbate an existing urban pollution problem, and (3)
IX-30
-------
the highly productive agricultural environment of the region could be
adversely affected, whereas the Powder River Basin has low agricultural
productivity. On the other hand, Category 1 emissions could be weighted
higher because (1) the Powder River Basin is a near-pristine environment
that should be protected from significantly increased pollutant levels,
(2) the growth in energy production in the region will substantially
increase the population that will be exposed to pollutants, and (3) such
growth will result in pollutant levels and control problems now facing
more urbanized areas.
Because of these considerations, there is no clear-cut choice for
weighting Category 1 emissions with respect to Category 3 emissions.
Furthermore, no quantitative method can be used to assign weighting
factors with any degree of confidence. Therefore, we decided to weight
the two categories equally. That choice does not mean that the impacts
of pollutant emissions in the two regions will be the same. Rather, it
acknowledges that the differences in impacts are not resolvable within
the scope of this study.
The weighted pollutant emissions that result from application of
the weighting factors discussed above are shown in Table IX-17.
Those emissions can be used to compare the overall environmental impact
of the five systems. However, to fully account for the relative effects
of the various pollutants emitted from the systems components, some
standard that serves as a measure of those effects must be used. Such
standards, and their use in arriving at relative system rankings, are
discussed below.
a. Air Pollutants
Although ambient air quality standards have been set for
SO-, NO , CO, hydrocarbons and particulates, those for PAH and trace
*The weighted emissions are equal to (Category 1 emissions plus one-tenth of
Category 2 emissions plus Category 3 emissions) divided by 2.1.
IX-31
-------
Table IX-17
GEOGRAPHICALLY WEIGHTED POLLUTANT EMISSIONS FOR THE FIVE SYSTEMS
(g per GJ of Heating and Cooling)
System 1
System 2
System 3
System 4
System 5
Air Pollutants
S02
NOX
Part.*
HC
CO
PAH
Sb
As
Be
Cd
Pb
Hg
Se
Zn
Water Pollutants
Suspended Solid
Oil and Grease
Iron
Manganese
Copper
Chlorine
Solid Waste
29.4
106
6.9/19.6
6.0
13.1
5.3 x 10-4
1.7 x 10-5
9.7 x 10-6
6.2 x 10-5
4.7 x 10-4
3.6 x 10-3
1.1 x 10-3
5.5 x 10-4
5.5 x 10-3
0.70
0.17
0.018
1.2 x 10-3
0.011
2.2 x 10-4
7,100
11.1
27.2
1.5/11.0
1.8
2.6
1.3 x 10-*
4.6 x 10-5
2.8 x 10-6
1.6 x 10-5
1.2 x 10-*
9.5 x 10-*
2.9 x 10-*
1.5 x 10-*
1.5 x 10-3
0.22
—
0.0036
7.6 x 10-5
—
—
*,200
14.0
47.9
1.0/15.7
1.2
4.5
8.1 x 10-5
9.5 x 10-5
5.2 x 10-6
3.6 x 10-5
2.6 x 10-*
2.0 x 10-3
6.2 x 10~*
3.0 x 10-*
3.0 x 10-3
0.23
—
0.0038
7.6 x 10-*
—
—
4,200
36.0
107
12.5/15.7
7.1
10.0
1.2 x 10-3
8.1 x 10-*
3.3 x 10-3
8.0 x 10-*
2.7 x 10-3
9.6 x 10-3
7.3 x 10-*
1.1 x 10-3
3.9 x 10-2
1.6
0.67
0.051
8.1 x 10~*
0.048
7.1 x 1004
4,200
9.6
27.0
1.4/10.0
3.6
2.3
1.2 x 10-*
4.1 x 10-5
2.5 x 10-6
1.5 x 10-5
1.1 x 10-*
8.6 x 10-*
2.6 x 10~*
1.3 x 10-*
1.3 x 10-3
0.20
—
0.0032
6.7 x 10-*
—
__
3,800
*Fine particulates/coarse particulates.
IX-32
-------
elements still need to be determined. Fortunately, occupational
exposure standards have been developed by the Occupational Safety and
Health Administration (OSHA) and have been recommended by the American
Conference of Governmental Industrial Hygienists (ACGIH) and the
National Institute for Occupational Safety and Health (NIOSH) for nearly
all pollutants of interest (see Table IX-18). The standards are
designed to protect workers who are continuously exposed for 8 hours per
day, 40 hours per week. The allowable concentrations for occupational
exposure tend to be somewhat higher than those that are designed to
protect the general public. While these standards do not provide a
direct measure of the environmental impacts of pollutants, they do
provide a basis for assessing the relative effects of pollutants on
human health.
Table IX-18
OCCUPATIONAL EXPOSURE STANDARDS FOR TOXIC POLLUTANTS
TIME-WEIGHTED AVERAGES (mg/m3)
Pollutant
S02
N02
Particulates
Hydrocarbons
CO
PAH
Sb
As
Be
Cd
Pb
Hg
Se
Zn
ACGIH
Recommendation
13
9
55
0.5
0.5
0.002
0.05
0.15
0.05
0.2
5.0
OSHA
Standard
13
2.4-10
(coal dust)*
400
(naphtha)
55
0.5
0.5
0.002
0.1
0.2
0.2
5.0
NIOSH
Recommendation
350
(alkanes)
39
0.002
0.04
0.15
0.05
5.0
^Respirable fraction.
IX-33
-------
Unfortunately, no occupational standards for PAH or any compound
included in this category currently exist. However, several of those
compounds are well known carcinogens and, in particular, exposures to
benzo(a)pyrene (BaP) has been correlated with excess lung cancers in
coke-oven workers and those in similar occupations. Such correla-
tions indicate that significant effects begin to occur at levels between
o
0.00001 and 0.001 mg/m . Given that BaP is only one of a number of
PAH compounds that may be contributing to lung cancer, and that total
3
PAH emissions are of interest here, a standard of 0.001 mg/m for
total PAH provides very roughly the same level of protection as those
standards listed in Table IX-18.
The standards shown in Table IX-18 will be used to define
the relative hazards of the pollutants listed. No attempt will be made
to attain an absolute measure of the impacts of the various system com-
ponents, and indeed, the standards were not designed to be used in such
a fashion.
Using the standards shown, weighting factors representing
the relative hazards of the various pollutants were developed (see Table
IX-19). The factors are simply the inverse of the occupational exposure
standards, but because of the roughness of the measure of relative
hazard, the factors are given to only one significant figure. There are
no standards for particulates as such, just for respirable coal dust.
However, using this analog for a particulate standard is reasonable when
deriving a weighting factor. Having the same weighting factor for
SO , NO , and particulates is also reasonable, especially
considering that the National Ambient Air Quality Standards for those
pollutants are about the same, that is, annual average values of 80,
100, and 75 mg/m for S02, N02, and particulates, respectively.
The weighting factors shown in Table IX-19 were
multiplied by the geographically weighted air pollutant emissions in
Table IX-17 and divided by the sum of the weighting factors to arrive at
a hazard-weighted air pollutant emission factor for each of the five
systems (see Table IX-20). They clearly indicate that Systems 2 and 5
IX-34
-------
Table IX-19
WEIGHTING FACTORS FOR THE RELATIVE HAZARDS
OF AIR POLLUTANTS
Pollutant Weighting Factor
PAH 1,000
Be 500
Hg 20
Cd 20
Pb 6
Se 5
Sb 2
As 2
Zn 0.2
so2 o.i
N02 0.1
Particulates 0.1
CO 0.02
Hydrocarbons 0.003
Table IX-20
HAZARD-WEIGHTED AIR POLLUTANT EMISSION FACTORS
FOR THE FIVE SYSTEMS
System 1 0.0097
System 2 0.0027
System 3 0.0042
System 4 0.013
System 5 0.0026
IX-35
-------
have the least air pollution impact; Systems 1 and 4 have the highest
and System 3 lies in between.
b. Water Pollutants
The emission of water pollutants by the five systems
occurs from only two sources — the coal mine and power plant wastewater
discharge. Neither of these is a major source of toxic water
pollutants, and the pollutants that are emitted must meet EPA effluent
guidelines. To achieve a simple ranking of the systems, it is not
necessary to derive weighting factors as was done for air pollutants
because the relative ranking of the systems is the same for each
pollutant listed in Table IX-17- Examination of Table IX-17 indicates
that System 4 has the highest water pollution impact, System 1 has the
next highest, Systems 2 and 3 are comparable, and System 5 has the
lowest.
c. Solid Waste
With the exception of System 1, the only sources of solid
waste in the five systems are the coal gasification and liquefaction
plants. Even in System 1, only 13% of the solid waste originates from
the coal-fired power plant. The remainder is from coal gasification.
It would be extremely difficult to assess the relative hazard of the two
types of waste. Both contain coal ash and char, FGD solids, and sludge
from the biological oxidation ponds. If the wastes are properly
disposed of, they present little environmental hazard. The main source
of concern is the possibility of toxic materials leaching from the waste
piles into aquifers, as discussed in Chapter VI. Again, the different
types of waste cannot be distinguished in terms of their potential for
leaching. The method of disposal and the properties of the disposal
site will probably have more bearing on the likelihood of leaching than
the composition of the waste.
IX-36
-------
Thus, no weighting factors were applied to the quantities
of solid waste produced by the systems. Therefore, according to Table
IX-17, System 1 clearly has the largest solid-waste impact, System 5 has
the least, and Systems 2, 3, and 4 are identical, with a somewhat higher
impact than System 5.
2. Land Use, Noise, and Aesthetics
Several other environmental factors should be considered when
comparing the five systems. For purposes of analysis, those factors are
categorized as land use, noise, and aesthetics.
a. Land Use
To assess the effect on land use, the amount of land
occupied or disturbed by the systems to produce the energy required for
heating and cooling residences was calculated. An appropriate measure
of land use is the area occupied or disturbed multiplied by the length
of time it is effectively removed from other purposes such as agri-
culture, housing, recreation, or wildlife support and plant habitat.
For facilities such as coal conversion plants, it is the area occupied
multiplied by the lifetime of the facility. For activities such as coal
mining, it is the area disturbed multiplied by the length of time from
mining to final reclamation. To compare the five systems, all such
measures are normalized to the energy output of the facility or activity
and ultimately to the heating and cooling supplied to residences, with
2
the impact factor measured in m -year/GJ.
Systems components that have significant effects on land
occupancy or disturbance are shown in Table IX-21. The scaling factors
are based on estimates of the land occupied by energy conversion faci-
lities, land disturbance, and right-of-way quantities presented in
Chapter VI, and on the following assumptions: (1) Four years are
IX-37
-------
required for complete reclamation of land disturbed by coal mining; (2)
land disruption from pipeline construction persists for 2 years; (3) the
land disruption from electricity transmission is based on a figure of
0.5 km (0.3 mi) of new transmission lines required per megawatt of added
2
generating capacity in Missouri, Nebraska, and Iowa, and on a
right-of-way of 30 m (100 ft). The right-of-way is assumed to be
o
disturbed for 2 years, while the land occupied by the towers (50 m
per tower with towers spaced every 0.3 km) is disturbed for the
lifetime of the line.
The right-of-way factor shown in Table IX-21 is
appropriate for central generating facilities. For dispersed fuel-cell
power plants, it should be multiplied by 0.75 to reflect the reduced
transmission requirements discussed in Section VII-M.
Using the factors presented in Table IX-21 and the energy
efficiency quantities shown in Figures IX-1 through IX-5, the land use
per GJ of heating and cooling can be calculated for the five systems
(see Table IX-22).
Table IX-21
LAND USE FACTORS FOR SYSTEM COMPONENTS
Component Land Use, (m^-yr/GJ)
Coal mine 0.018
Unit train 0.0053
Coal-fired power plant 0.12
Coal gasification plant 0.023
Coal liquefaction plant 0.021
Gas pipeline 0.011
Liquids pipeline 0.0062
Combined-cycle power plant 0.045
26-MW fuel-cell power plant 0.0081
Electricity transmission 0.057
IX-38
-------
Table IX-22
TOTAL LAND USE FOR THE FIVE SYSTEMS
(m2-year/GJ of Heating and Cooling)
System 1 0.11
System 2 0.084
System 3 0.076
System 4 0.10
System 5 0.055
Systems 1 and 4 require the greatest land use, followed
by Systems 2, 3, and 5, with System 5 needing only one-half the land of
Systems 1 and 4. We have made no judgments as to the relative value of
land in the regions encompassed by the five systems. Such complex
considerations are beyond the scope of this study. In practice, the
actual siting of the components of energy sytstems, and therefore the
nature of the land that is disturbed, will result from trade-offs among
economic, environmental, and social factors that will be very
site-specific.
b. Noise
The noise characteristics of the system components as
they affect the general public were identified in Chapter VI. Although
many components are very noisy, not all of them need be heard by the
public. Large centralized facilities such as coal mines and coal
conversion plants are generally located sufficiently far from
residential, commercial, and recreational areas so that significant
noise levels are not disturbing. On the other hand, equipment such as
locomotives and fuel delivery trucks pass near or through populated
areas, and thus expose large numbers of people to high noise levels.
The main sources of obtrusive noise and their average
noise levels are summarized in Table IX-23. An urban residential
IX-39
-------
background noise level of 48 dBA is considered average (see Table
VI-17). Against such a background, transmission lines and fuel-cell
power plants are relatively modest sources of additional noise. In
quiet suburban residential areas with background noise levels of 38 dBA,
their noise levels would be much more noticeable and could result in
some speech masking and sleep disturbance. The noise emitted from
trains and tank trucks, however, would obviously be the most
objectionable, because it is many times higher than background levels,
even in the noisiest urban areas. However, transmission-line and
fuel-cell power plant noise is more or less continuous, but that from
trains and trucks is intermittent.
The most useful way to compare the noise impact of the
five systems is to determine the number of major noise sources contained
in each system. Thus, System 5 has the lowest impact because it has
only one low-level noise source (the 100-kW fuel-cell power plant).
System 2 has two low-level noise sources (transmission line and
fuel-cell power plant) and therefore has the next highest impact.
Systems 1 and 4 both have one high-level and one low-level noise
source. Finally, System 3, with one high-level and two low-level noise
sources, has the greatest impact, although it is only marginally greater
than Systems 1 and 4.
Table IX-23
SOURCES OF INVOLUNTARY EXPOSURE TO HIGH NOISE LEVELS
Source Noise Level (dBA)
Transmission lines 55
Fuel-cell power plants 55
Unit trains 90-100
Tank trucks 88
IX-40
-------
c. Aesthetics
Evaluation of the aesthetic impacts of the five systems,
even on a relative basis, is difficult because of the many value judg-
ments involved and the lack of quantitative bases of comparison. Fur-
thermore, the systems and their components are so similar that, with few
exceptions, broad aesthetic differences among the systems are not
readily discernible.
One noticeable aesthetic impact, however, is the visible
plume caused by the emission of coarse particulates from the operation
of some system components. (See Tables IX-12 through IX-16.) Although
such emissions have relatively little health impact, they degrade visi-
bility near the sites of system components that emit coarse particu-
lates. Such degradation constitutes a major aesthetic impact.
The relative impact of coarse particulate emissions from
each system can be evaluated by consulting Table IX-17, which presents
the geographically weighted emissions of air pollutants from each
system. According to that table, System 5 has the lowest impact, with
emissions lower by a factor of two than System 1, which has the highest
impact. System 2 has slightly higher emissions than System 5, and the
emissions of Systems 3 and 4 are equal, both being about midway between
Systems 1 and 5.
Another significant aesthetic impact of the five systems
is caused by electrical transmission lines, which are perhaps the most
extensive and noticeable aspect of the entire electrical energy system,
including its associated fuel cycle. The use of dispersed power plants
in Systems 2, 3, and 5 significantly reduces this impact. In principle,
System 5 can avoid the use of transmission lines entirely, but in prac-
tice the residences may have to be connected to the electrical grid to
ensure reliability; such a connection implies the use of some trans-
mission facilities.
IX-41
-------
The use of dispersed 26-MW power plants does not
eliminate electrical transmission entirely because interties with the
rest of the utility system are needed. As discussed in Chapter VII,
however, the requirement for transmission facilities can be reduced on
the order of 25% compared to centralized generating facilities as
represented by Systems 1 and 5.
Finally, siting dispersed fuel-cell power plants in
urban/residential areas has aesthetic implications. Such plants will be
a departure from the usual mix of homes, apartment buildings, commercial
buildings, shopping complexes, schools, parks, and so on. However, the
plants will be fairly unobtrusive, consisting of clusters of rectangular
structures about 3 m (10 ft) in height. The use of proper landscaping
and site design should mitigate any unattractive features.
D. System Performance
All the systems analyzed in this study are based on advanced coal
conversion and/or electricity generation technologies that have yet to
be proven in commercial-scale operation. The cost, efficiency, and
environmental analyses of the systems are based on the assumption that
the performance goals set by the developers of the technologies would be
achieved in practice, and that they would be capable of performing as
specified in the applications set forth in Chapter IV. The implication
of those assumptions is that the systems would be less efficient, more
costly, and more environmentally intrusive than our analyses have shown
if those performance goals were not met.
In addition to those obvious effects, the desirability of
implementing the systems will be strongly affected by considerations of
reliability, lifetime, and performance characteristics of the major
components. Thus, it is reasonable to ask what effect such
considerations will have on the relative attractiveness of each of the
five systems, and to what extent uncertainties about those
characteristics will affect the implementation of the systems.
IX-42
-------
In examining those aspects of the systems, we need address only
those components that represent truly new technologies. Other
components, such as pipelines, transmission lines, and coal mines, have
well known characteristics, and their performance parameters have been
established by many years of use. Therefore, little additional light
can be shed on their contribution to the overall effectiveness of the
systems.
All the systems contain either an advanced coal gasification or
coal liquefaction facility (Hygas and H-Coal) which utilize
second-generation technologies with attractive characteristics that
could be commercially available in the 1990s. Extensive programs,
funded by the Department of Energy and private groups, are now under way
to prove those technologies at the pilot and demonstration plant stages,
and to address the engineering and design problems that must be solved
before commercial development is possible.
The Hygas process has an advantage because a pilot plant based on
this process has been operating since 1971, while the H-Coal pilot plant
is only now being constructed. Many successful tests have been run on
the Hygas pilot plant, although several problems remain to be solved,
including introduction of the high-pressure coal slurry into the
reaction vessel, maintaining proper reaction conditions in the
three-stage gasifier, and corrosion of vessel materials. In addition,
the construction and operation of the large, high-pressure reactors
envisioned for a commercial plant have never been carried out.
The H-Coal process faces similar problems of high-pressure slurry
operation and materials corrosion. In addition, the lifetime of the
hydrogenation catalyst may be limited and, if so, catalyst regeneration
techniques must be developed. Also, a reliable process for separating
the liquid products from unreacted char and ash has yet to be
demonstrated.
IX-43
-------
Although the Hygas and H-Coal processes were chosen for analysis in
Chapter IV, the implementation of the systems does not depend on the
successful development of those particular processes. Other technology
choices could provide the needed coal conversion. The Lurgi gasifi-
cation process, for example, is a commercially available technology that
could provide pipeline gas for residences and fuel-cell power plants.
In fact, that technology has been chosen for use in commercial coal
gasification plants proposed by several pipeline companies.
The SRC II process, for which a pilot plant is operating in
Ft. Lewis, Washington, is designed to produce low sulfur fuel oil along
with a naphtha by-product. Additional hydrotreating of those products
could probably be used to produce suitable turbine fuel or reformable
fuel-cell fuel, respectively.
Thus, other coal conversion technologies would enable the imple-
mentation of Systems 1 through 5, although at higher costs, lower effi-
ciencies, and possibly greater environmental impact than indicated in
Chapters V, VI, and VII. Overall, coal gasification is more likely than
coal liquefaction to be implemented on a commercial scale in the time
frame considered in this study, primarily because of the more advanced
state of coal gasification technology, the widespread demand for the
product, and the high cost of alternative sources (e.g., imported LNG).
Thus, Systems 1, 2, and 5, which are based on coal gasification, are
favored over Systems 3 and 4.
The electricity generation technologies are the other key com-
ponents of the systems. Of the four types of technologies analyzed,
coal-fired power plants clearly have advantages because of their ease of
implementation, reliability, and operational experience. However,
compared to combined-cycle power plants and fuel-cell power plants, they
have slow startup and shutdown and are not very suitable for quick-
response, load-following applications. Generally, gas turbines used as
spinning reserves must provide that capability.
IX-44
-------
Gas turbine/steam turbine combined-cycle power plants are by now a
well-established component of the utility power generation base. Gas
turbines are among the more reliable electricity-generating devices, and
the heat recovery systems and steam turbines that constitute the re-
mainder of the power plant are highly reliable and use well known tech-
nology. Advances in combined-cycle power plant performance depend on
developments in gas turbine technology. To achieve the operating tem-
peratures and concommitant efficiencies discussed in Chapter IV will
require gas turbines that use ceramic vanes and blades in the expander
that can withstand the thermal shock associated with cycling at high
temperatures. Because gas turbines are continuously undergoing develop-
ment for aircraft and industrial applications, as well as for power
plant use, it seems likely that higher temperature operation can be
achieved.
The use of coal-derived liquids in gas turbines is under investi-
gation by the Department of Energy. Although no actual tests have been
carried out, some coal liquids may be suitable turbine fuels, although
additional processing may be required in some cases to increase the
hydrogen-to-carbon ratio and reduce viscosity.
Because fuel cells are a new technology in power plant appli-
cations, they are at a disadvantage compared to coal-fired power plants
and combined-cycle power plants. Once implemented, however, they offer
a number of operational advantages, as discussed in Chapter II (e.g.,
ease of load-following, low maintenance). If the demonstration of
first-generation fuel-cell power plants in utility applications proves
successful, and if stack lifetime goals are achieved, then the oper-
ational basis for implementing fuel cells will have been established.
There would remain, of course, the accomplishment of a successful mar-
keting and commercialization strategy, the consideration of which is
beyond the scope of this study.
IX-45
-------
If first-generation (phosphoric acid) fuel cells can be success-
fully marketed, then the advantages inherent in second-generation
(molten carbonate) cells should lead to even more widespread utili-
zation. As discussed in Chapter II, the main technological problems to
be overcome are the stability of the stack materials under cycling
conditions at high temperatures, seal corrosion, and electrode sinter-
ing. These problems are being addressed by ongoing programs sponsored
by the Department of Energy and private groups.
The use of fuel cells in on-site power generation applications, as
envisioned in System 5, is attractive in many respects, but has certain
operational disadvantages, including the need for load management to
avoid having to oversize the power plant to meet all conceivable loads,
and the requirement for reasonably good matching between electrical and
thermal loads. The implementation of such systems depends largely on
consumer aceptance of the concept, as well as on finding conditions
under which they will be economical.
A final key component in the energy systems is the advanced heat
pump described in Chapter IV. Although heat pumps have been com-
mercially available for many years, only recently have they achieved a
level of reliability that will make them widely acceptable in resi-
dential heating and cooling applications. With wider markets, the R&D
required to achieve the advances described in Chapter IV should be
readily justifiable to companies that manufacture heat pumps. The
technological requirements are relatively simple. The successful de-
velopment and marketing of advanced heat pumps will make electrically
based residential energy systems considerably more attractive compared
to gas-based systems than they are now.
In summary, System 1 has the fewest technological barriers to
overcome, is the most likely to be implemented, and can provide the
needed energy requirements in a satisfactory and reliable manner.
Systems 2 and 4 are approximately comparable in their difficulties of
implementation, which center on the fuel cell and coal liquefaction
IX-46
-------
components, respectively. Once implemented, System 2 will have an
advantage because of the operational benefits of the fuel-cell power
plant. System 5 must rank somewhat lower than System 2 because of the
operational disadvantages of the on-site power plant, as discussed
previously. Finally, System 3 appears to have the greatest relative
difficulty of implementation because it contains both coal liquefaction
and fuel-cell components. Assuming this system were implemented, its
operational advantages would be similar to those of System 2. However,
those advantages would probably not outweigh the difficulties of imple-
mentation.
From the preceding discussion, the ranking of the systems based on
their performance characteristics are as follows, from highest to
lowest: Systems 1, 2, 4, 5, and 3.
IX-47
-------
E. References—Chapter IX
1. National Academy of Sciences, "Particulate Polycyclic Organic
Matter," (Washington D.C., 1972).
2. Electrical World, various issues.
3. General Electric Company, "Transmission Line Reference Book — 345
kV and Above," Electric Power Research Institute.
IX-48
-------
X. SUMMARY AND CONCLUSIONS
The comparative analyses carried out in Chapter IX enable the
relative advantages and disadvantages of the five systems to be
determined. A tabulation of ordinal rankings of the five systems in
each category examined in Chapter IX is shown in Table X-l. In the
table, a ranking of 1 indicates the most desirable system (i.e., the
lowest cost, highest efficiency, lowest environmental impact), a ranking
of 2 the next most desirable, and so on. Using Table X-l as a guide,
the relative advantages and disadvantages of each system are summarized
below.
A. Summary of Advantages and Disadvantages
1. System 1 (Coal-Fired Power Plant; SNG)
System 1 has the lowest heating and cooling costs, as well as the
lowest capital cost of any of the five systems. In addition, this
system is most likely to meet the required performance standards,
provide residential energy reliably, and be widely adopted by utilities,
primarily because it employs the fewest number of new or advanced
technologies.
On the other hand, System 1 is the least energy-efficient of the
five systems, requiring 83% more energy resources to provide the same
amount of heating and cooling than the most efficient system. In
addition, it has the largest environmental impact of any system, ranking
lowest in four out of six categories, including the important categories
of air pollution and solid waste.
X-l
-------
Table X-l
SYSTEM RANKINGS IN VARIOUS CATEGORIES
System 1 System 2 System 3 System 4 System 5
Economics
Operating
Cost
Capital
Efficiency
Environment
Air
Water
Solid Waste
Noise
Land Use
Aesthetics
System
Performance
5
4
5
3*
5
5
1
2
2*
2*
2
3
2
2
3
2*
2*
5
2
3
4
4
5
2*
3*
4
4
3
1
1
1
1
1
1
5
Rankings are essentially equal. Differences are too small to be
resolved.
X-2
-------
2. System 2 (26 MW Fuel Cell - SNG)
Although System 2 ranks about midway in its cost of heating and
cooling, it requires almost the highest initial capital investment. Its
overall system performance is second only to System 1, and it is also
second highest in energy efficiency. It also ranks highly in nearly all
environmental categories except land use.
3. System 3 (26 MW Fuel Cell-Naphtha)
Because of its similarity to System 2, System 3 ranks closely with
that system, although its rankings are somewhat lower in most
categories. It is somewhat less costly to install than System 2, but
somewhat more costly to operate. The most noticeable difference between
the two systems is that System 3 ranks considerably lower in the noise
and system performance categories.
4. System 4 (Combined Cycle Power Plant)
System 4 has advantageous capital and operating costs compared with
most other systems, and ranks midway with respect to system performance
criteria and solid, waste generation. However, it ranks next to last in
terms of energy efficiency, and has low ranking in four of six
environmental categories.
5. System 5 (100-kW Fuel Cell with Heat Recovery)
The rankings for this system present the most interesting picture
of the five systems, because its rankings occur only in the extreme
categories, 1 or 5. It ranks highest in all noneconomic categories
except system performance, in which it ranks last. It also ranks last
in both capital and operating cost, but as shown in Chapter IX, the
operating costs are sensitive to the electrical and thermal loads that
the system is required to meet.
X-3
-------
B. Conclusions
Although we cannot categorically state which system is "best" or
"worst" overall, several important implications result from our system
analyses, especially in regard to the desirability of the implementation
of energy systems based on fuel cells. However, those implications are
applicable only to coal-based, intermediate-load electricity generation
for residential energy use as covered in this report and should not be
considered necessarily applicable to other types of systems such as
those based on different fuel sources or different end uses.
First, economics is not a driving force for implementing the three
fuel-cell systems (Systems 2, 3, and 5). Even under optimistic
assumptions about the cost of fuel cells, those systems are not
competitive with the alternatives. When only the cost of heating and
cooling is considered, System 5 could be competitive with the next least
costly system (System 4) under the appropriate conditions (high
thermal-to-electrical demand ratio), but the cost of supplying all
residential energy requirements is still very high compared to the other
systems, and substantial optimization procedures would have to be
carried out to determine the most economical applications.
Fuel-cell systems are more energy-efficient than the alternatives,
partly because of the high efficiency of fuel cells and their potential
for heat recovery, and partly because of reduced transmission losses
resulting from dispersed siting. Thus, energy resources — in this
case, coal — are conserved. Although coal is not as limited a
resource as petroleum and natural gas, its conservation is clearly
beneficial because it minimizes social and political pressures resulting
from increased coal mining in the West, and it extends the lifetime of
the most accessible, lowest cost coal reserves. High system
efficiencies could convey economic benefits as well, but only at coal
prices considerably higher than those currently in effect for western
surface mining. For example, System 5 would have a lower cost of
heating and cooling than System 1 only if the price of coal were at
X-4
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least ten times higher than that derived in Chapter VII ($0.33/GJ or
$6.69/tonne).
In addition, the three fuel-cell systems have less environmental
impact, primarily because of the low emission rates of the fuel-cell
power plants, which particularly benefit areas where pollutant loadings
already approach or exceed those allowable by law. Recent environmental
legislation, such as the Clean Air Act Amendments of 1977, clearly
favors the siting of power generation facilities with the lowest pos-
sible pollutant emission rates in nonattainment and "prevention of
significant deterioration" areas. In areas removed from power plant
operation, such as coal resources areas where conversion plants are
located, lower pollutant outputs per unit of energy ultimately consumed
will also be beneficial. When pollutant loadings begin to exceed statu-
tory limits in those areas, new conversion facilities will have to be
located elsewhere, entailing greater costs for coal shipment, construc-
tion of additional rail lines, and so on.
Furthermore, other environmental attributes, such as lower land-use
impact of fuel-cell systems, generally mean that the siting of power
plants and related facilities (e.g., transmission lines) is easier than
for alternative systems.
A full quantitative assessment of the environmental benefits of
fuel-cell systems was not possible in this study, and indeed, such
benefits are very site-specific. They depend heavily on such factors as
the local pollutant loadings at the time of implementation, local land-
use characteristics, and the availability of suitable sites for solid-
waste disposal.
Finally, the fuel-cell systems considered here have a range of
system performance characteristics depending on fuel type and appli-
cation. If fuel-cell demonstration programs and early commercial use
show that fuel cells will perform as projected in terms of load-
following, reliability, and stack lifetime, then implementation of
X-5
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fuel-cell systems will be greatly enhanced. However, new energy
technologies are often justifiably met with some distrust and
skepticism, especially by utilities, who must be concerned with the
reliability and performance of the electric power system and who may not
be willing to take even small risks when older, more familiar
technologies are available.
Ultimately, the utilization of fuel-cell power plants in various
energy systems will be driven not by economic considerations, but
primarily by environmental and operational ones. Those utilities
constrained by environmental, siting, and other noneconomic factors
should find fuel-cell systems attractive alternatives to other methods
of power generation.
As is the case for most promising, but yet unproven, energy
technologies, the support of the federal government will be important to
the ultimate success of fuel cells as a commercially viable concept.
DOE, EPA, NASA, and other federal agencies have provided considerable
funding for fuel-cell development. This financial support, which has
increased substantially in recent years, will help to ensure the
technical success of fuel-cell R&D programs. However, to ensure success
in the marketplace, additional steps will have to be taken relatively
early in the commercialization process, to assure that momentum is not
lost and that companies manufacturing fuel cells have a market for their
first, more costly units. As production increases, and costs decline,
conventional market forces should result in wider market penetration.
Steps that the government could take to assist in early
commercialization, subsequent to successful demonstration of first
generation fuel cells, include:
o Purchase of fuel-cell power plants for use in government
installations such as military bases.
o Additional investment tax credits and/or loan guarantees for
utilities that purchase fuel cells.
X-6
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o Incentives for the use of on-site fuel-cell power plants with
heat recovery in federally-funded housing projects.
o Legislative initiatives to ensure that innovative electrical
generation technologies such as fuel cells will be allowed to
use natural gas and petroleum fuels until the time when
synthetic fuels become available.
Prior to implementation of these actions, extensive cost/benefit
analyses should be undertaken to ensure that the benefits that accrue
from the implementation of fuel cells (fuel savings, environmental and
operational) are justified in terms of the public and private expen-
ditures required to achieve them.
In the coming years, all new power sources will be subject to
intense scrutiny by the government, by environmental groups, and by the
general public. They will be required to meet strict environmental
standards, yet provide electric power efficiently, reliably, and at an
acceptable cost. It appears that energy systems based on fuel cells
will be among the most likely to meet those requirements.
X-7
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Appendix A
ENTHALPIES BASED ON THE GIRDLER CATALYSTS DATA HANDBOOK
The enthalpies given in Sections IV-B and IV-C of this report are
based on information tabulated in Girdler Catalysts, Physical and
Thermodynamic Properties of Elements and Compounds, published by the
Girdler Company, Louisville, Kentucky. This book is a standard
reference for process and reactor engineering.
The Girdler data use a reference state of zero for the enthalpy of
the elements at a temperature of absolute zero. This standard state is
different from that found in many other references, such as Perry\s
Chemical Engineer's Handbook, but it is extremely useful. The
tabulations allow rapid enthalpy calculations and intermediate
temperatures are easily interpolated. Enthalpy balances on reactants
and products give the heat of reaction directly. Furthermore, because
having a process stream below the standard state is impossible, many
confusing sign changes are avoided. It is important, however, that all
enthalpies in a given calculation are based on the standard state.
1. Naphtha Enthalpy Calculations
The enthalpy of the coal-derived naphtha feed for System 3 was
converted to the Girdler Catalysts basis after assuming the following
enthalpic properties:
AH = Heat of Combustion = 46.8 MJ/kg (20,100 Btu/lb)
CNa
AH^ = Heat of Vaporization = 326 kJ/kg (140 Btu/lb)
Na
C = Heat Capacity (gas) = 1.65 kJ/kg-°c (0.395 Btu/lb-op)
Na @ 16°C (60°F)
A-l
-------
Note that the heat capacity was varied with temperature proportional to
the heat capacity of toluene, as given in Girdler Catalysts. The
enthalpy of the naphtha at the standard state is given by:
AH =2^ AIL - 5^ AH
Na 1 products 1 reactants
where n. is the number of moles of products or reactants, and AH. is
the enthalpy of products or reactants.
Based on lOOg of naphtha: g atom C = 7.11
g atom H = 14.60
g atom 0 = negligible
The reaction equation is thus:
C7.11 H14.60 + 14'41 °2 ~7'U C°2 + 7'3° V-
Below is a tabulation summarizing the naphtha enthalpy calculations:
Enthalpy n^ (g mole) AH£ (kJ/g mole) n£AH? (kJ)
AHH20
AH&>2
AHO
°2
AHvH2o
AHC
7.30
7.11
14.41
7.30
100.00 g
-229.0
-384.0
8.4
-442.0
-46.8 kJ/g
-1670
-2730
121
-3230
-4680
(liq., 16°C) = -1.77 kJ/g -177 kJ/lOOg
In the tabulation above, AH^ is the total enthalpy of the stream or
component i, and AHy is the heat of vaporization of component i.
A-2
-------
Enthalpies of naphtha as a vapor at 16°C were calculated as follows:
(gas, 16°C) = AH^a (liq. 16°C) +
vNa
= -1.77 + 0.33 = -1.44 kJ/g
Enthalpies of naphtha as a vapor at other temperatures were calculated as
follows:
AH^a (gas, 38°C) = AHJJ (gas, 16°C) + (38°C - 16°C) x Cp (16°)
Na
= -1.44 + (22) (0.00165) = -1.40 kJ/g
Enthalpies at other temperatures were calculated by numerical integration,
using appropriate heat capacities.
2. SR-52 Enthalpy Program
A simple matrix program was written on a programmable hand
calculator to facilitate the rapid calculation of stream enthalpies.
The program calculates enthalpies at intermediate temperatures by a
straight line interpolation. The program requires that stream flow
rates, Girdler Catalysts enthalpies and the temperature of the stream be
entered into the calculator before each calculation, because the storage
capacity of the SR-52 is limited. The basic equation of the program is:
o , n0 v o o
AH = (ni ) ( AH (T) . . . H A(T))
stream \nn / 1 n
where n. is expressed in g mole/hr, and H.(T) is expressed in
kJ/g mole.
A-3
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Appendix B
MOLTEN CARBONATE FUEL-CELL PERFORMANCE
A study of molten carbonate fuel-cell performance was undertaken to
determine what factors contribute to cell power output. This study
developed a calculational model that can reproduce published data on
molten carbonate fuel-cell performance.
1. Cell Performance
The survey of the literature ~ indicated that at moderate
current densities (i.e., well removed from diffusion limits), cell
performance can be approximated by the equilibrium cell voltage between
the anode and cathode streams minus a term proportional to the current
density. This term is mostly internal resistance of the cell, although
at low current densitites, varous electrode and electrolyte
polarizations also can appear to be linear with current density. A
study of this model shows that:
o Cell voltage increases slightly with increased total pressures.
o Cell voltage is decreased by the presence of diluents.
o As the gas moves along the anode or cathode, the reactants are
consumed and the gas is less reactive, so that at constant
cell voltage the current density decreases down the length of
the cell.
o Increasing the electrolyte thickness decreases cell voltage by
increasing the internal resistance.
o H2 is the most active anode reactant. However, CO is
continuously shifted by 1^0 to form more H2 so that a mole
of CO is virtually equivalent to a mole of H2 in the anode.
B-l
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o CH^ is inert in the anode at these temperatures.
o At the cathode, CC>2 has a more dramatic effect on the
voltage than oxygen because the voltage is proportional to
In (C02) and In (C^)^. Therefore, both excess 02 and
C02 are necessary for good cathode performance.
The features of the model described above were computerized on a
programmable hand calculator. This program can predict the voltage and
current density of a molten carbonate fuel cell with varying anode and
cathode feeds, pressures, fuel utilizations, and cell resistances.
After the local activity of an electrode was reduced to a single
resistance parameter, it was still necessary to do extensive calculation
to determine the performance of a total cell. The anode is required to
run at high conversion levels of the total CO and H in the feed gas,
so that the equilibrium potential varies considerably with distance down
the length of the cell. Therefore, the calculation procedure described
in greater detail in Section 2 of this appendix was developed. It
consists of the following steps:
(1) The feed gas was equilibriated with respect to the water gas
shift reaction: CO + 1^0 5=^ H2 + C02
(2) The equilibrium voltage relative to all components at unit
activity was calculated:
AE = (RT/2F)jhi[(C02)(H20)/(H2)J .
(3) The local current density was calculated from the cell
polarization minus the local polarization via
i = (Tj-AE)/ (Rint + Rext^- Rint was set at
0.95 ohm-cm^ for present technology and Rext at 0.3
ohm-cm^ for a total of 1.25 ohm-cm^.
(4) Using this current density, the distance required to convert a
quantity of hydrogen equal to 10% of the total H2 and CO
remaining was calculated.
(5) Also computed was the change in pressures and flow rates due
to the production of steam and C02 via the electrochemical
reaction: H2 + 003 •- H20 + C02 + 2e. The
program then recycled to Step (1).
B-2
-------
The calculation was repeated for 2, 6, 12, and 18 cycles to obtain
19, 47, 72, and 85% conversion of the gases. The average current
density was calculated from the cumulative current densities and
distances. The computations were repeated at various polarizations to
obtain performance curves.
These detailed calculations were not repeated at the cathode
because cathode gases are run to only 50% conversion. A good
correlation could be obtained with the data reported by Ackerman on
methane reformate at 50% air conversion, using the mean of the cathode
polarizations at the inlet and outlet of the cell. Because the cathode
[m
(C02).(02) , the mean
polarization is the log mean gas pressure combination. At very low
current densities and low anode conversions, the model breaks down
slightly, but at higher conversions, and current densities between 50
2
and 200 mA/cm , the results seem to be useful and reliable.
2. High Conversion Performance of Molten Carbonate Fuel Cell
The first step in the calculation is the determination of the
extent of the water-gas shift reaction:
CO + H20 5=i H2 + C02
or, abbreviated: A + B ^=* C + D.
If N is the loss in pressure of the CO or H20 due to the shift,
then
(C + N) (D + N)_
(A - N)(B - N) K, the equilibrium constant
K was taken at 1.85 in this work, although more careful
interpolation shows that at 650°C (1,202°F) a value of 1.92 would be
more appropriate:
N = Y - N/Y2 - 4(K-lXKAB-CD)
where Y = K(A+B) + C+D.
B-3
-------
N was then subtracted from the pressures for CO and HO and added
to those of H_ and CO^ to obtain the equilibriated pressures.
Next the equilibrium "polarization" of the anode was calculated.
RT
(C02)(H20)
(H2)
The local current density was calculated via
U = (T7 -TJ)/R
Here 77 is the constant applied polarization and R is the
combined internal and external resistance.
The distance increment, AX, was not fixed at the start but was
calculated so as to consume a charge AQ equal to 10% of the remaining
combustibles, H and CO.
V
g
AQ =
10PTOT
V is the gas flow rate expressed as mA/cm where all gas
O
molecules are taken as containing 2 electrons per mole.
The starting gas flow rate can be chosen arbitrarily because the
cell length will vary accordingly and the calculated current density
will not change. However, for convenience, the inlet gas flow rate was
taken as 100 . PTOT/[(CO) + (H2>]. Then AQ reads directly as
percent conversion.
AX = AQ/U
AX and AQ are summed cumulatively into storage registers to give
the total cell length and total conversion, respectively. The average
current density at any point is given by SAQ/AX.
B-4
-------
After each increment of hydrogen conversion the various gas
pressures must be adjusted because of the consumption of hydrogen and
the formation of steam and CC>2, and the increase in total gas flow
rate, all due to the reaction:
H2+ C°3~^H2° + C°2+ 2e
Thus, first (H2) is decremented by AQ . PTQT/V while (H20)
and (C02) are incremented by the same quantity. Then V is adjusted
• 9
via V = V + AQ and all gas pressures are reduced by the factor
• 5
v;-
Finally, all gas pressures are fed back into the water-gas shift
subroutine and the whole process is repeated.
The process is halted after 2, 6, 12, and 18 cycles to give 19, 47,
72j and 85% conversion. At each point the corresponding average current
densities and gas compositions may be obtained. The whole process may
be repeated with other values of TJ . The cell voltage corresponding
to a value of TJ is given by
E cell (mV) = 1015 + TJ - TJ
c o
Here, 1,015 mV is the theoretical cell potential at 650 C
(1,202°F) and 101 kPa (1 atm) pressure of all reactant gases.
TJ is the mean cathode potential calculated from the average of
c f kl
(RT/2F)£n (COJ.CCL) at the cathode inlet and outlet.
B-5
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3. References—Appendix B
1. J. P. Ackennan, "Molten Carbonate Fuel Cell Systems - Status and
Potential," Paper No. 391, National Electrochemical Society, 151st
Meeting, Philadelphia, PA, May 8-13, 1977.
2. J. M. King, "Energy Conversion Alternatives Study - United
Technologies Phase II Final Report," NASA CR-134955 (October 1976).
3. H. Selman, et al., Abstract No. 393, Electrochemical Society, 151st
National Meeting, Philadelphia, PA, May 8-13, 1977.
4. Institute of Gas Technology, "Fuel Cell Research on
Second-Generation Molten Carbonate Systems," Project 8984,
Quarterly Status Report (Jan. 1 - March 31, 1977).
5. H. A. Liebhafsky and E. C. Cairns, Fuel Cells and Fuel Batteries,
Chapter 12 (Wiley, New York, 1968).
B-6
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Appendix C
ENERGY SUPPLY/DEMAND PROGRAM FOR RESIDENCES SUPPLIED BY
THE 100-kW FUEL-CELL POWER PLANT
A Texas Instruments SR-59 calculator was programmed to calculate
hourly average energy parameters associated with the use of a 100-kW
fuel-cell power plant to supply electricity and heat to townhouse
residences. The basic features of that system were described in Chapter
IV. For each residence, the program calculates the hourly average
electrical load, heat pump duty factor, and recovered fuel-cell heat
delivered to the space heating system.
The inputs to the program are the hourly average external
temperature, heating load, hot water load, and light and appliance
electrical load. Fuel-cell power plant, heat pump, and heat exchanger
performance parameters are stored internally.
The operation of the program is illustrated by the flow chart shown
in Figure C-l. The variables shown in the flow chart are defined below
(all parameters represent hourly averages).
T: External temperature, °F or °C.
Q: Space heating load, Btu/hr or kJ/hr.
HW: Domestic hot water (DHW) load, Btu/hr
or kJ/hr.
E: Light and appliance electrical load,
kW.
E1: Total electrical load, kW.
HF(E or E1): Fuel-cell heat recovered as a
function of electrical load, Btu/hr
or kJ/hr.
C-l
-------
1. ENTER T, Q, HW, E
2. HF HFIE+0.21)
3. HD HD(HF.O)
4.
AQ
Q--f^(H
F - HW)
6.
DF 1.0
DF 0
E' E + 0.21
HDN = -^- (HF HW)
7.
El
HO
EKT)
HO(T)
8.
E = E + El
9.
HF HF(E )
1 1a
13a.
14a.
HDN DF
10.
: - HW)
HD HD(HF.HO)
HDO HD(HF.O)
12a. A Q - HDN - DFXHO
Yes
DF = (Q— HDNl/HO
E' E + 0.21 + DFIEI - 0.21)
HDN = -T^T- (HF - HW)
H r
12b. A Q-HDN—DFXHO
Yes
13b.
14b.
DF (Q— HDNl/HO
E' " E + El + (DF- DHO/3413
15. PRINT E , DF, HF, HDN
FIGURE C-1. PROGRAM FOR ENERGY SUPPLY/DEMAND CALCULATIONS
C-2
-------
EI(T): Heat pump electrical load as a
function of temperature, kW.
HO(T): Heat pump output as a function of
temperature, Btu/hr or kJ/hr.
HD(HF, HO): Heat delivered to space heating
system through heat exchanger as a
function of recovered fuel-cell
heat and heat pump output, Btu/hr
or kJ/hr.
HDN: Net recovered fuel-cell heat
delivered to space heating system,
after DHW demand is satisfied,
Btu/hr or kJ/hr.
DF: Heat pump duty factor — ratio of
net space heating demand to heat
pump output.
The operation of the program, as displayed in Figure C-l, begins
with the specification of the key input variables in Step 1. Steps 2-4
then determine whether recovered fuel-cell heat is sufficient to meet
both DHW and space heating loads without operation of the heat pump. If
so, the program ends and values of the output parameters are printed
(the value of E is increased by 0.21 kW, which is the fan power
requirement in the space heating system). If not, the remaining
variables are initialized in Steps 6-8.
The iterative part of the program begins in Step 9. The program
proceeds through either one of two independent branches, depending on
whether DF is greater or less than 1. Physically, the heat pump duty
factor can never exceed 1.0. However, for purposes of the program it is
allowed to do so, simply indicating that the net space heating load
exceeds the capacity of the heat pump and that electric resistance
heating must be added. The program ceases to iterate when the heat
supply (net recovered fuel-cell heat plus heat pump heat plus electric
resistance heat, if required) equals the heat demand, Q. This balance
C-3
-------
is considered to have been achieved when the difference between supply
and demand is less than 100 kJ/hr. If the heat supply and demand do not
balance, a new duty factor and electrical load (E1) are calculated and
the program iterates again.
C-4
-------
TECHNICAL REPORT DATA
(Please read Instructions on the reverse before completing)
1. REPORT NO.
EPA-600/7-79-105b
2.
3. RECIPIENT'S ACCESSION NO.
4. TITLE AND SUBTITLE
Comparative Assessment of Residential Energy
Supply Systems That Use Fuel Cells (Technical
Report)
5. REPORT DATE
April 1979
6. PERFORMING ORGANIZATION CODE
7. AUTHORS Rt V. Steele, D. C. Bomberger ,K. M. Clark,
R.F. Goldstein, R.L. Hays, M.
R. J. Bellows*. H. H. Horowitz,
*»• • t—'wvjhvy .»_, , ^^ ^ j-*^r**i PtSW*. g^W A ••*.*.« ATA * ^/ AM.J. *». •
R. F. Goldstein,R. L. Hays ,M. E. Gray ,G. Ciprios*
~ ' ~ " - - C.W.Snyder*
8. PERFORMING ORGANIZATION REPORT NO.
and
9. PERFORMING ORGANIZATION NAME AND ADDRESS
SRI International
333 Ravens wood Avenue
Menlo Park, California 94025
10. PROGRAM ELEMENT NO.
EHB534
11. CONTRACT/GRANT NO.
68-02-2180
12. SPONSORING AGENCY NAME AND ADDRESS
EPA, Office of Research and Development
Industrial Environmental Research Laboratory
Research Triangle Park, NC 27711
13. TYPE OF REPORT AND P
Final; 9/76 - 1/79
D PERIOD COVERED
14. SPONSORING AGENCY CODE
EPA/600/13
is.SUPPLEMENTARY NOTES ffiRL-RTP project officer is Gary L. Johnson, MD-63, 919/541-
2745. (*) Coauthors are Exxon personnel.
16. ABSTRACT
The report gives results of a comparison of residential energy supply sys-
tems using fuel cells. Twelve energy systems, able to provide residential heating
and cooling using technologies projected to be available toward the end of this cen-
tury, were designed conceptually. Only a few systems used fuel cells. All systems
used Western coal as the primary energy source, and all residences were assumed
to have identical heating and cooling demands typical of the mid-continent U.S.
After screening, five systems were analyzed in detail. The entire energy cycle,
from coal mine to end use, was examined for costs, efficiency, environmental im-
pact, and applicability. .The five energy systems are: (1) a coal-fired power plant
supplying electricity and a coal gasification plant supplying SNG; (2) a 26-MW fuel-
cell power plant fueled by coal-derived SNG supplying electricity; (3) a 26-MW fuel-
cell power plant fueled by coal-derived naphtha supplying electricity; (4) a combined-
cycle power plant fueled by coal-derived fuel oil supplying electricity; and (5) a
100-kW fuel-cell power plant fueled by coal-derived SNG, sited in a housing com-
plex, supplying electricity to heat pumps, with heat recovered from the fuel cell
supplying supplemental space heating and hot water. Results indicate that the fuel
cell systems are most costly, most efficient, and have least environmental impact.
17.
KEY WORDS AND DOCUMENT ANALYSIS
DESCRIPTORS
b.lDENTIFIERS/OPEN ENDED TERMS
COSATI Field/Group
Pollution
Fuel Cells
Energy Conversion
Techniques
Residential Buildings
Heating
Cooline Systems
Assessments
Coal Gasification
Coal
Naphthas
Fuel Oil
Natural Gas
Heat Pumps
Pollution Control
Stationary Sources
Substitute Natural Gas
13B
10B
10A
13M
13A
14B
13H
21D
07C
18. DISTRIBUTION STATEMENT
Unlimited
19. SECURITY CLASS (ThisReport/
Unclassified
21. NO. OF PAGES
482
20. SECURITY CLASS (Thispage)
Unclassified
22. PRICE
EPA Form 2220-1 (9-73)
D-l
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